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
ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20152017
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 ClassName of Each Exchange on which Registered
Common units representing limited liability company interestsNew 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, or a non-accelerated filer.filer, or an emerging growth company. See definitionthe definitions of “accelerated filer"large accelerated filer", "accelerated filer", and large accelerated filer”"emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  xo
       Accelerated filer   oý   
       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”"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.
Identity of Directors, Senior Management and Advisers
1
Item 2.
Offer Statistics and Expected Timetable
1
Item 3.
Key Information
1
A.
Selected Financial Data
1
B.
Capitalization and Indebtedness
2
C.
Reasons for the Offer and Use of Proceeds
2
D.
Risk Factors
2
Item 4.
Information on the Company
2923
A.
History and Development of the Company
2924
B.
Business Overview
3226
C.
Organizational Structure
4335
D.
Property, Plant and Equipment
4335
Item 4A.
Unresolved Staff Comments
4335
Item 5.
Operating and Financial Review and Prospects
4436
A.
Operating Results
5240
B.
Liquidity and Capital Resources
5845
C.
Research and Development
6350
D.
Trend Information
6351
E.
Off-Balance Sheet Arrangements
6452
F.
Tabular Disclosure of Contractual Obligations
6552
G.
Safe Harbor
6552
Item 6.
Directors, Senior Management and Employees
6552
A.
Directors and Senior Management
6553
B.
Compensation
6754
C.
Board Practices
6755
D.
Employees
6856
E.
Unit Ownership
6956
Item 7.
Major Unitholders and Related Party Transactions
6957
A.
Major Unitholders
6957
B.
Related Party Transactions
7057
C.
Interests of Experts and Counsel
7662
Item 8.
Financial Information
7662
A.
Consolidated Statements and Other Financial Information
7662
B.
Significant Changes
7965
Item 9.
The Offer and Listing
7965
A.
Offer and Listing Details
7965
B.
Plan of distribution
8066
C.
Markets
8066
D.
Selling Shareholders
66
E.
Dilution
66
F.
Expenses of the issue
66
Item 10.
Additional Information
8066
A.
Share Capital
8066
B.
Memorandum and Articles of Association
8066
C.
Material Contracts
8067
D.
Exchange Controls
8370

E.
Taxation
8370
F.
Dividends and Paying Agents
8774
G.
Statements by Experts
8774

H.
Documents on Display
8774
I.
Subsidiary Information
8775
Item 11.
Quantitative and Qualitative Disclosures About Market Risk
8875
Item 12.
Description of Securities Other than Equity Securities
8975
   
PART II  
Item 13.
Defaults, Dividend Arrearages and Delinquencies
8975
Item 14.
Material Modifications to the Rights of Security Holders and Use of Proceeds
8975
Item 15.
Controls and Procedures
8975
Item 16A.
Audit Committee Financial Expert
9076
Item 16B.
Code of Ethics
9077
Item 16C.
Principal Accountant Fees and Services
9177
Item 16D.
Exemptions from the Listing Standards for Audit Committees
9177
Item 16E.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
9177
Item 16F.
Change in Registrants’ Certifying Accountant
9177
Item 16G.
Corporate Governance
9278
Item 16H.
Mine Safety Disclosure
9278
   
PART III  
Item 17.
Financial Statements
9278
Item 18.
Financial Statements
9378
Item 19.
Exhibits
9479





Presentation of Information in this Annual Report
This annual report on Form 20-F for the year ended December 31, 2015, or 2017, ("the annual report,report"), should be read in conjunction with the Consolidated and Combined Carve-Out Financial Statements and accompanying notes included in this report. Unless the context otherwise requires, references in this annual report to “Seadrill"Seadrill Partners LLC,” “Seadrill" "Seadrill Partners,”" the “Company,” “we,” “our,” “us”"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”"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”"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”"Seadrill Management" refer to Seadrill Management Ltd, Seadrill Management AS, and Seadrill UK Ltd, the entitiesentity that do or have providedprovides 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.”"OPCO."
All references in this annual report to “OPCO”"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”"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.LLC, a wholly owned subsidiary of Seadrill. Certain references to the “Seadrill Member”"Seadrill Member" refer to Seadrill Member LLC, as the context requires.
References in this annual report to “ExxonMobil,” “Chevron,” “Total”"ExxonMobil," "Chevron," "Total", “BP”"BP", "Tullow", "ConocoPhillips", "Petronas", "Statoil", "Hibernia" and "Petronas""Medco Energi" refer to subsidiaries of ExxonMobil Corporation, Chevron Corporation, Total S.A., BP Plc, Tullow Plc, and "PetroliamConocoPhillips Company, Petroliam Nasional Berhad (PETRONAS)", Statoil ASA, Hibernia Management and Development Ltd. and PT Medco Energi Internasional Tbk respectively, that are or were the Company’s customers.
customers.
Important Information Regarding Forward Looking Statements

Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements, which are other than statements of historical or present facts or conditions.

This annual report and any other written or oral statements made by us or on our behalf may include forward-looking statements which reflect our current views with respect to future events and financial performance. The words "believe," "anticipate," "intend," "estimate," "forecast," "project," "plan," "potential," "may," "should," "expect" and similar expressions identify forward-looking statements.

The forward-looking statements in this annual report are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management's examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections.
In addition to these important factors and matters discussed elsewhere in this annual report, and in the documents incorporated by reference in this annual report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include:

offshore drilling market conditions, including supply and demand;
the Company's distribution policy and the Company's ability to make cash distributions on the Company's units or any increases or decreases in distributions and the amount of such increases or decreases;
the Company's ability to borrow under the credit facility between OPCO, as borrower, and Seadrill, as lender;
the Company's future financial condition, liquidity or results of operations and future revenues and expenses;of the Company or Seadrill;
the repayment of debt;
the ability of the Company OPCO and SeadrillOPCO to comply with financing agreements and the effect of restrictive covenants in such agreements;
the ability of the Company's drilling units to perform satisfactorily or to the Company's expectations;
the financial condition of Seadrill, its comprehensive restructuring efforts and its ability to provide services to the Company under certain management, administrative and technical support agreements. This dependence on Seadrill has given rise to substantial doubt over the Company’s ability to continue as a going concern;
fluctuations in the price of oil;

i

the financial condition of Seadrill;
fluctuations in the international 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 of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward looking statement.




ii

PART I

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

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

A.     Selected Financial Data
The following table presents, in each case for the periods and as of the dates indicated, the Company's selected Consolidated and Combined Carve-Out financial and operating data, which includes, for periods prior to the completion of the Company's initial public offering, or the IPO, on October 24, 2012, selected Consolidated and Combined Carve-Out financial and operating data of the combined entity.
data. The following financial data should be read in conjunction with Item 5 “Operating"Operating and Financial Review and Prospects”Prospects" and the Company's historical Consolidated and Combined Carve-Out financial statementsFinancial 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".
The Company's financial position, results of operations and cash flows could differ from those that would
  Year Ended December 31,
  2017
2016
2015 2014
2013
  (in millions, except per unit data)
Statement of Operations Data:          
Total operating revenues (1)
 $1,128.4
 $1,600.3
 $1,741.6
 $1,342.6
 $1,064.3
Total other operating income 90.7
 —
 —
 —
 —
Total operating expenses (755.6) (782.2) (897.9) (727.8) (576.6)
Net operating income 463.5
 818.1
 843.7
 614.8
 487.7
Total financial items (187.9) (185.9) (254.7) (265.4) (39.1)
Income before income taxes 275.6
 632.2
 589.0
 349.4
 448.6
Income tax expense (40.3) (86.5) (100.6) (34.8) (33.2)
Net income $235.3
 $545.7
 $488.4
 $314.6
 $415.4
Earnings per unit (basic and diluted)          
Common unitholders $1.88
 $3.20
 $2.45
 $1.75
 $2.15
Subordinated unitholders $—
 $2.28
 $2.45
 $1.75
 $1.83
(1) Total operating revenues include amounts recognized as early termination fees under the offshore drilling contracts which have resulted if the Company operated autonomously or as an entity independent of Seadrill in the periodsbeen terminated prior to the Company's IPO for which historical financial data are presented below, and such data may not be indicativecontract end date.
(2) Total other operating income include gains resulting from a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the Company's future operating results or financial performance.
West Polaris in 2015 and gains on sale of assets. Please refer to Note 7 - "Other Operating Income" for further information.
  Year Ended December 31,
  2015
2014
2013 2012
2011
  (in millions, except per unit data)
Statement of Operations Data:          
Total operating revenues $1,741.6
 $1,342.6
 $1,064.3
 $911.8
 $678.9
Total operating expenses (897.9) (727.8) (576.6) (479.7) (330.9)
Net operating income 843.7
 614.8
 487.7
 432.1
 348.0
Total financial items (254.7) (265.4) (39.1) (99.6) (132.3)
Income before income taxes 589.0
 349.4
 448.6
 332.5
 215.7
Income taxes (100.6) (34.8) (33.2) (38.9) (34.7)
Net income $488.4
 $314.6
 $415.4
 $293.6
 $181.0
Earnings per unit (basic and diluted) (1)
          
Common unitholders $2.45
 $1.75
 $2.15
 $0.29
 $—
Subordinated unitholders $2.45
 $1.75
 $1.83
 $0.13
 $—

(1) Earnings per unit information has not been presented for any period prior to the Company’s initial public offering (“IPO”).  The equity holders of the Company subsequent to the IPO had no contractual rights over the earnings of the Company for periods prior to the IPO on October 24, 2012. Therefore the earnings per unit in 2012 only relates to the post IPO earnings.

  As at December 31,
  2015 2014 2013 2012 2011
  (in millions, except fleet and unit data)
Balance Sheet Data (at end of period):          
Cash and cash equivalents $319.0
 $242.7
 $89.7
 $21.2
 $15.5
Drilling units 5,547.3
 5,141.1
 3,448.3
 3,241.9
 1,837.0
Total assets 6,841.1
 6,268.1
 4,062.6
 3,754.9
 3,344.6
Total interest bearing debt (1)
 3,840.2
 3,572.0
 2,350.5
 2,057.0
 2,166.0
Total equity 2,097.4
 2,044.3
 1,254.6
 1,424.4
 1,252.5

(1) During the year ended December 31, 2015 the Company adopted Accounting Standards Update (ASU) 2015-03, Interest - Imputation of Interest, (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires the debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt

discounts and premiums. Accordingly the selected financial data has been retrospectively adjusted to reflect the adoption of this ASU. The following amounts have been presented in the balance sheet as a direct deduction from the carrying amount of the debt liability. Prior to the adoption of ASU 2015-03, these were presented as "Other current assets" or "Other non-current assets".
 As at December 31, As of December 31,
 2015 2014 2013 2012 2011 2017 2016 2015 2014 2013
 (in millions) (in millions)
Balance Sheet Data (at end of period):                    
Deferred charges - current and non-current portion $58.1
 $78.4
 $10.0
 $19.0
 $20.4
Cash and cash equivalents $848.6
 $767.6
 $319.0
 $242.7
 $89.7
Drilling units 5,170.9
 5,340.9
 5,547.3
 5,141.1
 3,448.3
Total assets 6,530.8
 6,780.7
 6,841.1
 6,268.1
 4,062.6
Total interest bearing debt 3,367.8
 3,600.6
 3,840.2
 3,572.0
 2,350.5
Total equity 2,701.8
 2,535.8
 2,097.4
 2,044.3
 1,254.6
Please also refer to "Note 2 - Accounting"Accounting policies" of the notes to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

 Year Ended December 31, Year Ended December 31,
 2015 2014 2013 2012 2011 2017 2016 2015 2014 2013
 (in millions, except fleet and unit data) (in millions, except fleet and unit data)
Cash Flow Data:                    
Net cash provided by operating activities $859.8
 $608.7
 $564.0
 $278.2
 $395.2
 $476.2
 $873.8
 $859.8
 $608.7
 $564.0
Net cash used in investing activities (376.3) (1,542.8) (159.3) (283.5) (1,010.8)
Net cash provided by / (used in) financing activities (407.6) 1,087.1
 (336.2) 11.0
 625.9
Net cash (used in)/provided by investing activities (11.1) 97.6
 (376.3) (1,542.8) (159.3)
Net cash (used in)/provided by financing activities (384.9) (522.1) (407.6) 1,087.1
 (336.2)
Net increase in cash and cash equivalents 76.3
 153.0
 68.5
 5.7
 10.3
 81.0
 448.6
 76.3
 153.0
 68.5
Fleet Data (1):
                    
Number of drilling units at end of period 11
 10
 8
 6
 5
 11
 11
 11
 10
 8
Average age of drilling units at end of period (years) 4.7
 3.6
 3.1
 2.9
 2.3
 6.7
 5.7
 4.7
 3.6
 3.1
Other Financial Data:                    
Capital expenditures(2) $(18.6) $(31.6) $(159.3) $(283.5) $(594.5) $121.6
 $61.1
 $68.4
 $70.7
 $185.8
Distributions declared per unit(3) 1.9525
 2.1700
 1.6775
 0.2906
 —
 0.4000
 0.5500
 1.9525
 2.1700
 1.6775
Members Capital:          
Members Capital (at end of period):          
Total members capital (excluding non-controlling interest) 964.3
 928.2
 299.0
 524.6
 946.2
 1,303.7
 1,192.6
 964.3
 928.2
 299.0
Common Unitholders—units 75,278,250
 75,278,250
 44,400,563
 24,815,000
 —
 75,278,250
 75,278,250
 75,278,250
 75,278,250
 44,400,563
Subordinated Unitholders—units 16,543,350
 16,543,350
 16,543,350
 16,543,350
 —
 16,543,350
 16,543,350
 16,543,350
 16,543,350
 16,543,350
(1)
During the year ended December 31, 2013, the Company acquired from Seadrill two tender rigs, the T-15 and the T-16, which the Company holds through a 100% limited liability company interest in Seadrill Partners Operating LLC, a 51% indirect interest in the semi-submersible drilling rig, the West Sirius, which the Company holds through its 51% interest in Seadrill Capricorn Holdings LLC, and a 30% indirect interest in the semi-submersible drilling rig, the West Leo, which the Company currently holds through its 58% interest in Seadrill Operating LP. These transactions were deemed to be a reorganization of entities under common control and therefore the fleet data has been retroactively adjusted as if the Company had acquired the interests in these units when they began operations under the ownership of Seadrill. As of January 2, 2014, the date of the Company’s first annual general meeting, Seadrill ceased to control the Company as defined by generally accepted accounting principles in the United States or GAAP,("GAAP") and, therefore, Seadrill Partners and Seadrill are no longer be deemed to be entities under common control. As such, acquisitions by the Company from Seadrill subsequent to this date are no longer accounted for under this method.

(2)Capital expenditures include long term maintenance.
(3)Distributions attributable to the year. Distributions were declared only with respect to the common units in 2017 and 2016.

B.     Capitalization and Indebtedness
Not applicable.

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

D.     Risk Factors

The Company'sOur 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 the Company'sour business, financial condition, results of operations, cash available for distributions or the trading price of the Company'sour common units.

Risks Inherent in the Company's Business
Because the Company's ownership interest in OPCO currently represents the Company's only cash-generating asset, the Company's cash flow depends completely on OPCO’s ability to make distributions to its owners, including the Company.
The Company's cash flow depends completely on OPCO’s distributions to the Company as oneoccurrence of its owners. The amount of cash OPCO can distribute to its owners principally depends upon the amount of cash it generates from its operations, which may fluctuate from quarter to quarter based on, among other things:
the dayrates it obtains under its drilling contracts;
the level of its rig operating costs, such as the cost of crews, repair, maintenance and insurance;
the levels of reimbursable revenues and expenses;
its ability to re-contract its drilling units upon expiration or termination of an existing drilling contract and the dayrates it can obtain under such contracts;
delays in the delivery of any new drilling units and the beginning of payments under drilling contracts relating to those drilling units;
the timeliness of payments from customers under drilling contracts;
earn-out payment obligations related to purchases of drilling units;
prevailing global and regional economic and political conditions, including the current decline in the price of oil and gas;
time spent mobilizing drilling units to the customer location;
changes in local income tax rates;
currency exchange rate fluctuations and currency controls; and
the effect of governmental regulations and maritime self-regulatory organization standards on the conduct of its business.
The actual amount of cash OPCO has available for distribution also depends on other factors, such as:
the level of capital and operating expenditures it makes, including for maintaining and replacing drilling units or modifying existing drilling units to meet customer requirements and complying with regulations or to upgrade technology on the Company’s drilling units;
its debt service requirements, including fluctuations in interest rates, and restrictions on distributions contained in its debt instruments;
fluctuations in its working capital needs;
number of days of rig downtime or less than full utilization, which would result in a reduction of revenues under a drilling contract;
whether the Company or OPCO exercises any options to purchase drilling units in the future that are required to be offered to the Company or OPCO by Seadrill pursuant to the terms of the Omnibus Agreement or otherwise;
restrictions under laws applicable to OPCO and its subsidiaries that affect their ability to pay distributions;
the ability to make working capital borrowings and availability under the sponsor credit facility; and
the amount of any cash reserves, including reserves for future maintenance and replacement capital expenditures, working capital and other matters, established by the Company's board of directors.
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 the Company's board of directors.
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.
The Company may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable the Company to pay the minimum quarterly distribution on its common units and subordinated units.
The source of the Company's earnings and cash flow consists exclusively of cash distributions from OPCO. Therefore, the amount of cash distributions the Company is able to make to the Company's unitholders fluctuates, based on the level of distributions made by OPCO to its owners, including the Company, 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 the Company to make distributions to the Company's common unitholders at the minimum quarterly distribution level or to increase the Company's quarterly distributions in the future. In addition, while the Company would expect to increase or decrease distributions to the Company's unitholders if OPCO increases or decreases distributions to the

Company, 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 the Company.
The Company's ability to distribute to its unitholders any cash it may receive from OPCO or any future operating subsidiaries is or may be limited by a number of factors, including, among others:
interest expense and principal payments on any indebtedness the Company may incur;
restrictions on distributions contained in any of the Company's current or future debt agreements;
feesevents described in this section could materially and expensesnegatively affect our business, financial condition, results of the Company, the Seadrill Member, its affiliates or third parties the Company is required to reimburse or pay, including expenses the Company incurs as a result of being a public company; and
reserves the Company's board of directors believes are prudent for the Company to maintain for the proper conduct of its business or to provide for future distributions.
Many of these factors will reduce the amount of cash the Company may otherwise have available for distribution. The Company may not be able to pay distributions, and any distributions the Company makes may not be at or above the Company's minimum quarterly distribution. For example, on February 12, 2016, the Company reduced its quarterly distribution to $0.25 per common unit for the quarter ended December 31, 2015. The actual amount of cash that is available for distribution to the Company's unitholders depends on several factors, many of which are beyond the Company's control.
The Company's ability to grow may be adversely affected by its cash distribution policy. OPCO’s ability to meet its financial needs and grow may be adversely affected by its cash distribution policy.
The Company's cash distribution policy, which is consistent with the Company's operating agreement, requires the Company to distribute all of the Company's available cash each quarter. Accordingly, the Company's growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.
In determining the amount of cash available for distribution by OPCO, the Company's board of directors will approve the amount of cash reserves to set aside for the Company and OPCO, including reserves for estimated maintenance and replacement capital expenditures, current and future debt service requirements, working capital, reserves required to comply with applicable law and financing or other agreements. OPCO will also rely upon external financing sources, including commercial borrowings, to fund its capital expenditures. Accordingly, to the extent OPCO does not have sufficient cash reserves or is unable to obtain financing, its cash distribution policy may significantly impair its ability to meet its financial needs or to grow.

The Company must make substantial capital and operating expenditures to maintain the operating capacity of its fleet, which will reduce cash available for distribution. In addition, each quarter the Company is required to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted.
The Company must make substantial capital and operating expenditures to maintain and replace, over the long-term, the operating capacity, of its fleet. Maintenance and replacement capital expenditures include capital expenditures for maintenance (including special classification surveys) and capital expenditures associated with modifying an existing drilling unit, including to upgrade its technology, acquiring a new drilling unit or otherwise replacing current drilling units at the end of their useful lives to the extent these expenditures are incurred to maintain or replace the operating capacity of the Company’s fleet. These expenditures could vary significantly from quarter to quarter and could increase as a result of changes in:
the cost of labor and materials;
customer requirements;
fleet size;
the cost of replacement drilling units;
the cost of replacement parts for existing drilling units;
the geographic location of the drilling units;
length of drilling contracts;
governmental regulations and maritime self-regulatory organization and technical standards relating to safety, security or the environment; and
industry standards.
The Company's operating agreement requires its board of directors to deduct estimated maintenance and replacement capital expenditures, instead of actual maintenance and replacement capital expenditures, from operating surplus each quarter in an effort to reduce fluctuations in operating surplus as a result of variations in actual maintenance and replacement capital expenditures each quarter. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by the conflicts committee of the Company's board of directors at least once a year. 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 from operating surplus. If the board of directors underestimates the appropriate level of estimated maintenance and replacement capital expenditures, the Company may have less cash available for distribution in future periods when actual capital expenditures exceed the Company's previous estimates.
If capital expenditures are financed through cash from operations, or by issuing debt or equity securities, the Company's ability to make cash distributions may be diminished, its financial leverage could increase or its unitholders could be diluted.
Use of cash from operations to expand or maintain the Company’s fleet will reduce cash available for the Company to distribute to its unitholders. The Company's ability to obtain bank financingpayment of distributions or to access debt and equity capital markets may be limited by the Company's financial condition at the time of any such financing or offering as well as by adverse market conditions resulting from, among other things, general economic conditions, fluctuations and current decline in thetrading price of oilour common units. Unless otherwise indicated, all information concerning our business and consequently our services, changes in the offshore drilling industry and contingenciesassets is as of December 31, 2017. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations.
Risks Relating to Our Reliance on Seadrill
We have close business ties to Seadrill, its affiliates and related companies. In the event that these companies are beyond the Company's control. Failureunable to obtain the funds for future capital expendituresmeet their obligations and liabilities, it could have a material adverse effect on our business.

We depend on certain subsidiaries of Seadrill, including Seadrill Management, to assist us in operating and expanding the Company'sbusiness.
Our ability to enter into new drilling contracts and expand our customer and supplier relationships will depend largely on our ability to leverage our relationship with Seadrill and its reputation and relationships in the offshore drilling industry. If Seadrill suffers material damage to its reputation or relationships, it may harm our ability to:
renew existing drilling contracts upon their expiration;
obtain new drilling contracts;
efficiently and productively carry out our drilling activities;
successfully interact with shipyards;
obtain financing and maintain insurance on commercially acceptable terms; or
maintain satisfactory relationships with suppliers and other third parties.
In addition, pursuant to the management and administrative services agreement, Seadrill Management provides us with significant management, administrative, financial and other support services and/or personnel. Subsidiaries of Seadrill also provide advisory, technical and administrative services to our fleet pursuant to advisory, technical and administrative services agreements. Our operational success and ability to execute our growth strategy depends significantly upon the satisfactory performance of these services. Our business may be harmed if Seadrill and its subsidiaries fail to perform these services satisfactorily, if they cancel their agreements with us or if they stop providing these services to us. Please read Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions".
For a description of the advisory, technical and administrative services agreements and the management and administrative services agreement, please read Item 7 “Major Unitholders and Related Party Transactions-Related Party Transactions.” The fees and expenses payable pursuant to the advisory, technical and administrative services agreements and the management and administrative services agreement will be payable without regard to our financial condition or results of operations. The payment of fees to and the reimbursement of expenses of Seadrill Management, and certain other subsidiaries of Seadrill could adversely affect our financial condition, our operational performance and our ability to pay cash distributions to unitholders.
The Company is currently dependent on obtaining management and technical support services from Seadrill .
On September 12, 2017, Seadrill, along with certain of its consolidated subsidiaries (the "Company Parties") entered into a restructuring support and lock-up agreement (RSA) with a group of their senior secured bank lenders, unsecured bondholders, certain other stakeholders and new-money providers. In connection with the RSA, the Company Parties entered into an investment agreement (the “Investment Agreement”) under which Hemen Investments Limited, an affiliate of Seadrill’s largest shareholder Hemen Holding Ltd. and a consortium of investors, including the bondholder parties to the RSA, committed to provide $1.06 billion in new cash commitments, subject to certain terms and conditions.
On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, Seadrill and the other Company Parties commenced prearranged reorganization proceedings under Chapter 11 of title XI of the United States Code in the Southern District of Texas [case number 17-60079]. During the course of the bankruptcy proceedings, the Debtors continue to operate their business as a debtor in possession.
Whilst we believe we have insulated the Company from events of default related to the Seadrill Chapter 11 proceedings, we remain operationally dependent on Seadrill on account of the management, administrative and technical support services provided by Seadrill to Seadrill Partners. In the event Seadrill is unable to provide these services as a result of its restructuring or otherwise, Seadrill Partners has the right to terminate these agreements and would seek to build these capabilities internally or determine a suitable third party contractor to replace the current manager. This may have an adverse effect on our operations and may negatively impact our cash flows and liquidity.
In addition, several of our credit facilities have clauses that require the current management, administrative and technical support agreements with Seadrill to remain in place. Our facilities also include certain change of control terms and other covenants. Whilst we are currently in compliance with all terms of our credit facilities, there is risk associated with remaining in compliance.
If Seadrill defaults on its indemnity obligations due to its financial condition, it could have a material adverse effect on us. 
Seadrill has agreed to indemnify us for certain liabilities under certain sale and purchase agreements relating to acquisitions from Seadrill subsequent to the IPO and certain of our financing agreements. Under the sale and purchase agreements, Seadrill has agreed to indemnify us against certain tax and toxic tort liabilities with respect to the assets that Seadrill contributed or sold to us to the extent arising prior to the time they were contributed or sold. Under certain of our financing agreements, Seadrill has agreed to indemnify us for any payments or obligations under these agreements that are related to drilling units owned by Seadrill.  If Seadrill is unable to indemnify us against claims under these agreements, it may adversely affect our business, financial position, results of operations or available cash.
We depend on officers and financial conditiondirectors who are associated with affiliated companies, which may create conflicts of interest.
Certain of our officers and ondirectors perform services for other companies, including Seadrill. For example, Mark Morris, who is our Chief Executive Officer, also acts as the Company's ability to make cash distributions. Even if the Company is successful in obtaining necessary funds, the terms of any debt financings could limit the Company’s ability to pay distributions to unitholders.Chief Financial Officer for Seadrill. In addition, incurring additional debt may significantly increaseJohn Roche, who is our Chief Financial Officer, also acts as Vice President of Investor Relations for Seadrill. These other companies conduct substantial businesses and activities of their own in which we have economic interest. As a result, there could be material competition for the Company's interest expensetime and financial leverage,effort of our officers and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash requireddirectors who also provide services to pay the minimum quarterly distribution to unitholders, both ofother companies, which could have a material adverse effect on the Company's ability to make cash distributions.
The Company’s debt levels may limit its flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions to unitholders.
As of December 31, 2015, the Company's consolidated debt was approximately $3,898.3 million. The Company has the ability to incur additional debt. Please read Item 5 “Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

The Company’s level of debt could have important consequences to it, including the following:
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be limited or such financing may not be available on favorable terms;
a substantial portion of the Company's cash flow will be required to make principal (including amortization payments as required by financing agreements) and interest payments on debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;
such debt may make the Company more vulnerable to competitive pressures or a downturn in its business or the economy generally than the Company's competitors with less debt; and
such debt may limit the Company’s flexibility in responding to changing business and economic conditions.
The Company's ability to service its consolidated debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If the Company's operating results are not sufficient to service its consolidated current or future indebtedness, the Company will be forced to take actions such as reducing distributions, reducing or delaying its business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing the Company's consolidated debt, or seeking additional equity capital or bankruptcy protection. The Company may not be able to effect any of these remedies on satisfactory terms, or at all.
Furthermore, certain of the Company’s financing agreements contain cross-default clauses which are linked to other indebtedness of Seadrill. In the event of a default by Seadrill under one of its financing agreements, the Company could be adversely affected by the cross-default clauses, even if Seadrill cures any such default.
Financing agreements containing operating and financial restrictions and other covenants may restrict the Company's business and financing activities.
The operating and financial restrictions and covenants in the financing agreements of Seadrill, or the Company and any future financing agreements of Seadrill or the Company, could adversely affect the Company's ability to finance future operations or capital needs or to engage, expand or pursue the Company's business activities. For example, subject to certain exceptions, the financing agreements may restrict the Company's ability to:
enter into other financing agreements;
incur additional indebtedness;
create or permit liens on the Company's assets;
sell drilling units or the capital stock of the Company's subsidiaries;
change the nature of the Company's business;
make investments;
pay distributions to the Company's unitholders or to the Company, respectively;
change the management and/or ownership of the drilling units;

make capital expenditures;
enter into transactions with Seadrill or its affiliates; and
compete effectively to the extent the Company's competitors are subject to less onerous restrictions.
For more information, please read Item 5 “Operating and Financial Review and Prospects—Liquidity and Capital Resources.”
The Company’s or Seadrill’s ability to comply with the restrictions and covenants, including financial ratios and tests, contained in any financing agreements of Seadrill or the Company is dependent on future performance and may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions continue to deteriorate, the Company’s or Seadrill’s ability to comply with these covenants may be impaired. If the Company or Seadrill is unable to comply with the restrictions and covenants in the agreements governing its indebtedness or in current or future debt financing agreements, there could be a default under the terms of those agreements. Seadrill’s obligations under its facilities in which the Company participates could exceed the indebtedness of the Company and its subsidiaries under such agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend and/or accelerate the outstanding loans and declare all amounts borrowed due and payable. The Company has pledged its drilling units as security either under the Company's financing facilities or under Seadrill’s financing facilities in which the Company participates. If the Company's or Seadrill’s lenders were to foreclose on the Company’s drilling units in the event of a default, this may adversely affect the Company’s ability to finance future operations or capital needs or to engage in, expand or pursue its business activities. In addition, some of the Company’s loan agreements contain cross-default provisions, meaning that if the Company is in default under one of its loan agreements, amounts outstanding under its other loan agreements may also be accelerated and become due and payable. If any of these events occur, the Company cannot guarantee that the Company’s assets will be sufficient to repay in full all of its outstanding indebtedness, and the Company may be unable to find alternative financing. Even if the Company could obtain alternative financing, that financing might not be on terms that are favorable or acceptable. Any of these events would adversely affect its ability to make distributions to the Company's unitholders and cause a decline in the market price of the Company's common units. Please read Item 5 “Operating and Financial Review and Prospects—Liquidity and Capital Resources.”
Restrictions in the Company’s debt agreements and Marshall Islands law may prevent the Company from paying distributions.
The payment of principal and interest on the Company’s debt will reduce cash available for distribution to the Company and to its unitholders. The Company’s and OPCO’s financing agreements contain restrictions on the ability of the Company or OPCO to pay distributions to the Company's unitholders or to the Company, respectively, under certain circumstances. In addition, the Company’s current 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 the Company from paying distributions to its unitholders. These events include, among others:
a failure to pay any principal, interest, fees, expenses or other amounts when due;
a violation of covenants requiring the Company to maintain certain levels of insurance coverage, minimum liquidity levels, minimum interest coverage ratios, maximum leverage ratios and minimum current ratios;
a default under any other provision of the financing agreements, as well as a default under any provision of related security documents;
a material breach of any representation or warranty contained in the applicable financing agreement;
a default under other indebtedness;
a failure to comply with a final legal judgment from a court of competent jurisdiction;
a bankruptcy or insolvency event;
a suspension or cessation of the Company's business;
the destruction or abandonment of the Company's assets, or the seizure or appropriation thereof by any governmental, regulatory or other authority if the lenders determine such occurrence could have a material adverse effect on the Company's business or the Company's ability to satisfy the Company's obligations under or otherwise comply with the applicable financing agreement;
the invalidity, unlawfulness or repudiation of any financing agreement or related security document;
an enforcement of any liens or other encumbrances covering the Company's assets; and
the occurrence of certain other events that the lenders believe is likely to have a material adverse effect on the Company's business or its ability to satisfy its obligations under or otherwise comply with the applicable financing agreement.
The Company or OPCO may also 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”), the Company may not make a distribution to the Company's unitholders if, after giving effect to the distribution, all the Company’s 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 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 members or partners, as applicable. Moreover, subsidiaries of the Company and OPCO not organized in the Marshall Islands are subject to certain restrictions on payment of distributions pursuant to the law of their jurisdictions of organization.

Seadrill’s failure to comply with covenants and other provisions in its existing or future financing agreements could result in cross-defaults under the Company’s existing financing agreements, which would have a material adverse effect on the Company.
Some of the Company’s existing financing agreements contain cross-default provisions that may be triggered if Seadrill defaults under the terms of its existing or future financing agreements. In turn, Seadrill’s existing financing arrangements contain cross-default provisions that may be triggered if any of its key subsidiaries default under the terms of their existing or future financing arrangements. On April 28, 2016, Seadrill executed amendment and waiver agreements in respect of all of its senior secured credit facilities, as part of its efforts to maintain liquidity. The amendment and waiver agreements, among other things, amend the equity ratio, leverage ratio, minimum value clauses and minimum liquidity requirements under Seadrill’s and certain of our secured credit facilities until June 30, 2017. The key terms and conditions related to the amendment and waiver agreements in respect of our credit facilities are set forth in Note 11-“Debt” to the audited Consolidated and Combined Carve-Out Financial Statements included elsewhere in this annual report. The amendment and waiver agreements are subject to, among other things, Seadrill’s compliance with the processes and undertakings set forth therein, including agreements in respect of progress milestones towards the agreement of, and implementation plan in respect of, a comprehensive financing package. There can be no assurance that Seadrill will maintain compliance with the covenants under its senior secured credit facilities and the processes and undertakings set forth in the amendment and waiver agreements, or that any potential debt restructuring, reorganization or recapitalization will be undertaken or be successful.
In addition Seadrill also consolidates certain Variable Interest Entities (VIEs) owned by Ship Finance International Limited (NYSE: SFL), or Ship Finance. Seadrill's cross-default provisions could also be triggered if Ship Finance or one of the consolidated VIEs breached the terms of their financing arrangements. In the event of a default by Seadrill under one of its financing agreements, the lenders under some of the Company’s existing financing agreements could determine that the Company is in default under its financing agreements. This could result in the acceleration of the maturity of such debt under these agreements and the lenders thereunder may foreclose upon any collateral securing that debt, including the Company’s drilling units, even if Seadrill were to subsequently cure its default. In the event of such acceleration and foreclosure, the Company might not have sufficient funds or other assets to satisfy all of its obligations, which would have a material adverse effect on the Company's business, results of operations and financial conditioncondition. Please see Item 6 "Directors, Senior Management and would significantly reduce its ability, or make it unable, to make distributions to the Company's unitholders for so long as such default is continuing.
The failure to consummate or integrate acquisitions in a timelyEmployees-Directors and cost-effective manner could have an adverse effect on the Company's financial condition and results of operations.
The Company believes that acquisition opportunities may arise from time to time, and any such acquisition could be significant. Under the Company's omnibus agreement with Seadrill, subject to certain exceptions, Seadrill is obligated to offer to the Company any of its drilling units acquired or placed under drilling contracts of five or more years. Although the Company is not obligated to purchase any of these drilling units offered by Seadrill, any acquisition could involve the payment by the Company 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, the Company may not be able to obtain acceptable terms for the required financing for any such acquisition or investment that arises. The Company cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of its common units. The Company's 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. The Company may also be subject to additional costs related to compliance with various international laws in connection with such acquisition. If the Company fails to consummate and integrate its acquisitions in a timely and cost-effective manner, its financial condition, results of operations and cash available for distribution could be adversely affected.Senior Management-Executive Officers".

Risks Relating to Our Company
The Company'ssuccess and growth of our business depends on the level of activity in the offshore oil and gas industry which is significantly affected by, among other things, volatile oilgenerally, and gas prices, and may be materially and adversely affected by a decline in the offshore oil and gas industry.
The offshore drilling industry isspecifically, which are both highly competitive and cyclical, and volatile. The Company's growth strategy focuses on expansion in the offshore drilling sector, whichwith intense price competition.
Our business depends on the level of activity in oil and gas exploration, development and production in offshore areas worldwide. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments affect customers’ drilling programs. Oilworldwide which is influenced by oil and gas prices and market expectations of potential changes in these prices also significantly affect this level of activity and demand for drilling units.prices.
Oil and gas prices are extremely volatile and are affected by numerousseveral factors beyond the Company'sour control, including, but not limited to, the following:
worldwide production and demand for oil and gas ;and geographical dislocations in supply and demand;
the cost of exploring for, developing, producing and delivering oil and gas;
expectations regardingof future energy prices and production;
advances in exploration, development and production technology;
the ability of the Organization of Petroleum Exporting Countries or OPEC,("OPEC"), to set and maintain levels and pricing;
the level of production in non-OPEC countries;
international sanctions on oil-producing countries, or the lifting of such sanctions;
government regulations, including restrictions on offshore transportation of oil and natural gas;
local and international political, economic and weather conditions;

domestic and foreign tax policies;
the development and exploitation of alternative fuels and non-conventionalunconventional hydrocarbon production, including shale;
worldwide economic and financial conditions and the effectcorresponding impact on the demand for oil and gas and, consequently, our services;
the policies of various governments regarding exploration and development of their oil and gas reserves;
reserves, accidents, severe weather, natural disasters and other similar incidents relating to the oil and gas industry; and
the worldwide political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, Easterneastern Europe or other geographic areas or further acts of terrorism in the United States, Europe or elsewhere.
Declines in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, have and could continue to negatively affect the Company'sour future growth. performance.
Sustained periods of low oil and gas prices have resulted in reduced exploration and drilling activities because oil and gas companies’ capital expenditure budgets are subject to cash flow from such activities and are therefore sensitive to changes in energy prices. These changes in commodity prices canconsequently have a dramatic effect on rig demand,demand. In addition, mergers among oil and gas exploration and production companies have reduced, and may further reduce the number of available customers, which would increase the ability of potential customers to achieve favorable pricing terms.
Continued periods of low demand can cause excess rig supply and intensify the competition in theour industry which often results in drilling rigs, particularly older and less technologically-advanced drilling rigs, being idle for long periods of time. The CompanyWe cannot predict the future level of demand for drilling rigs or future conditions of the oil and gas industry.industry with any degree of certainty. In response to the decrease in the prices of oil and gas, a number of the Company's oil and gas companyour 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 the Company'sour revenues and materially harm its business, results of operations and cash available for distribution.

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 competing offshore drilling rigs;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 environment of oil and gas reserve jurisdictions; and
regulatory restrictions on offshore drilling.
Any
The offshore drilling industry is highly competitive and fragmented and includes several large companies that compete in many of thesethe markets we serve, as well as numerous small companies that compete with us locally. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors could reduce demand forare pricing, rig availability, rig location, the condition and integrity of equipment, its record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. Our operations may be adversely affected if our current competitors or new market entrants introduce new drilling rigs with better features, performance, prices or other characteristics compared to our drilling rigs, or expand into service areas where we operate.
Competitive pressures and adversely affect the Company's business andother factors may result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations.

operations and financial condition.
The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.
The oil and gas drilling industry is cyclical, and the industry is currently in a downcycle. Crude oil prices have fallen significantly during the past two years. The price of Brent crude has fallenfell from over $100$115 per barrel in MarchJune 2014 to approximately $39.60a low of $30 per barrel asin January 2016. Although there has been some recovery in crude oil prices in recent months, this might not be sustainable and in any event remains significantly below 2014 highs. As of March 31, 2016.2018, the price of Brent crude was approximately $70 per barrel. The significant decrease in oil and natural gas prices is expected tomay continue to reduce many customers’ demand for drilling services. In responseour services in 2018 due 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.
Declines in capital spending levels, coupled with additional newbuild supply, have and are likely to continue to intensify price competition and put significant pressure on dayrates and utilization. The decline and the riskutilization of a continued decline or stagnation in oil and/or gas prices could cause oil and gas companies to further reduce their overall level of activity or spending, in which case demand for our services may further decline and revenues may continue to be adversely affected through lower drilling unit utilization and/or lower dayrates.rigs.
Historically, when drilling activity and spending decline, utilization and dayrates also decline and drilling has been reduced or discontinued, resulting in an oversupply of drilling units. The recent oversupply of drilling units will be exacerbated by the entry of newbuild rigs into the market. The supply of available uncontracted units has and is likely to further intensify price competition as scheduled delivery dates occur and additional contracts terminate without renewal and lead to a reduction in dayrates as the active fleet grows.
If we are unable to secure contracts for our drilling units upon the expiration of our existing contracts, we mayour units will become idle. When 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. Idle units are either "warm" stacked, which means the rig is kept operational and ready for redeployment, and maintains some of its crew, or "cold" stacked, which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is reassigned to an active rig or dismissed.
We currently have onefour idle unit,units, the West Sirius. Sirius, West Leo, West Polaris and West Vencedor.TheWest Sirius drilling contract was terminated early in April 2015 and the unit is currently "cold" stacked. In additionThe West Leo was contracted with Tullow until its contract was terminated in December 2016. We have disputed the grounds for termination and commenced litigation proceedings. Subsequently the unit has been stacked. The West Polaris drilling contract for thecompleted in December 2017. The West Vencedoris expected to expire during the third quarter of 2016, and this drilling unit could also be idled or stacked.contract completed in January 2018 . We have not yet secured a new contractcontracts for eitherany of these drilling units. If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing on terms acceptable to us
Our inability, or at all.
In general, drilling unit owners are bidding for available work extremely competitively with a focus on utilization over returns, which has and will likely continue to drive rates down to or below cash breakeven levels. To maintain the continued employmentinability of our units, we may also accept contracts at lower dayratescustomers to perform, under our or on less favorable terms due to market conditions. In addition, customers have already and may in the future request renegotiation of existing contracts to lower dayrates. In an over-supplied market, wetheir contractual obligations may have limited bargaining power to renegotiate on more favorable terms. Lower utilization and dayrates have and will adversely affect our revenues and profitability.
The effects of the downcycle may have other impactsa material adverse effect on our business as well. Prolonged periods of low utilization and dayrates could result in a reduction in the market value of our drilling units or goodwill. This could lead to the recognition of impairment charges on our drilling units

or goodwill if future cash flow estimates, based on information available to management at the time, indicate that the carrying value of these drilling units or goodwill may not be recoverable. In addition, if the market value of our drilling units decreases, and we sell any drilling unit at a time when prices for drilling units have fallen, such a sale may result in a loss, which would negatively affect ourfinancial position, results of operations.
Prolonged periods of low dayrates, the possible termination or loss of contractsoperations and reduced values of our drilling units could negatively impact our ability to comply with certain financial covenants under the terms of our debt agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, is dependent on our future performance and may be affected by events beyond our control. If a default occurs under these agreements, lenders could terminate their commitments to lend or in some circumstances accelerate the outstanding loans and declare all amounts borrowed due and payable. In addition, our existing debt agreements contain cross-default provisions. In the event of a default by us under one of our debt agreements, the lenders under our other existing debt agreements could determine that we are in default under our other financing agreements. This could lead to an acceleration and enforcement of such agreements by our lenders.cash flows.
We do not know when the market for offshore drilling units may recover, or the nature or extent of any future recovery. There can be no assurance that the current demand for drilling rigs will not further decline in future periods. The continued or future decline in demand for drilling rigs would adversely affect our financial position, operating results and cash flows.

The Company depends on certain subsidiaries of Seadrill, including Seadrill Management,Our customers may seek to assist the Company in operating and expanding the business.
The Company's abilitycancel or renegotiate their contracts to enter into new drilling contracts and expand its customer and supplier relationships will depend largely on its ability to leverage its relationship with Seadrill and its reputation and relationshipsinclude unfavorable terms such as unprofitable rates, particularly in the offshore drilling industry. If Seadrill suffers material damage to its reputationcircumstance that operations are suspended or relationships, it may harm the Company's ability to:
renew existing drilling contracts upon their expiration;
obtain new drilling contracts;
efficiently and productively carry out the Company's drilling activities;
successfully interact with shipyards;
obtain financing and maintain insurance on commercially acceptable terms;
maintain access to capital under the sponsor credit facility; or
maintain satisfactory relationships with suppliers and other third parties.
In addition, pursuant to the management and administrative services agreement, Seadrill Management provides the Company with significant management, administrative, financial and other support services and/or personnel. Subsidiaries of Seadrill also provide advisory, technical and administrative services to the Company’s fleet pursuant to advisory, technical and administrative services agreements. The Company's operational success and ability to execute the Company's growth strategy depends significantly upon the satisfactory performance of these services. The Company's business will be harmed if Seadrill and its subsidiaries fail to perform these services satisfactorily, if they cancel their agreements with the Company or if they stop providing these services to it. Please read Item 7 “Major Unitholders and Related Party Transactions—Related Party Transactions.”

The Company’s drilling contracts may not permit it to fully recoup its costs in the event of a rise in expenses.
The Company’s drilling contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from these term contracts, all of the Company’s drilling contracts, except for the West Leo include escalation provisions. These provisions allow the Company to adjust the dayrates based on certain published indices. These indices are designed to compensate the Company for certain 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 semi-annually, and therefore may be outdated at the time of adjustment. In addition, the adjustments are normally performed on a semi-annual or annual basis. For these reasons, the timing and amount received as a result of the adjustments may differ from the timing and amount of expenditures associated with actual cost increases, which could adversely affect the Company's cash flow and ability to make cash distributions.
An increase in operating and maintenance costs could materially and adversely affect the Company's financial performance.
The Company's 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 the Company's control and affect the entire offshore drilling industry. During periods after which a rig becomes idle, the Company may decide to “warm stack” the rig, which means the rig is kept fully operational and ready for redeployment, and maintains most of its crew. As a result, the Company's operating expenses during a warm stacking will not be substantially different than those the Company would incur if the rig remained active. The Company may also decide to “cold stack” the rig, which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is assigned to an active rig or dismissed. For example, the Company has cold stacked the West Sirius drilling unit following its early contract termination by BP. Reductions in costs following the decision to cold stack a rig may not be immediate, as a portion of the crew may be required to prepare the rig for such storage. Moreover, as the rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. 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 rigs and demand for contract drilling services, which in turn, affect dayrates, and the economic utilization and performance of the Company’s fleet of drilling rigs. However, operating costs are generally related to the number of drilling rigs in operation and the cost level in each country or region where such drilling rigs are located. In addition, equipment maintenance

costs fluctuate depending upon the type of activity that the drilling rig is performing and the age and condition of the equipment. Escalation provisions contained in the Company’s drilling contracts may not be adequate to substantially mitigate these increased operating and maintenance costs. In connection with new assignments, the Company might incur expenses relating to preparation for operations under a new contract. The 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. In situations where the Company’s drilling units incur idle time between assignments, the opportunity to reduce the size of its crews on those drilling units is limited as the crews will be engaged in preparing the drilling unit for its next contract. When a drilling 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 drilling units be idle for a longer period, the Company may not be successful in redeploying crew members, who are not required to maintain the drilling units, and therefore may not be successful in reducing the Company's costs in such cases.
Any limitation in the availability or operation of the Company’s drilling units could have a material adverse effect on the Company's business, results of operations and financial condition and could significantly reduce the Company's ability to make distributions to its unitholders.
As at March 31, 2016, the Company’s fleet consisted of four semi-submersible drilling rigs, four drillships and three tender rigs. If any of the Company’s drilling units are unable to generate revenues as a result of the expiration or termination of its drilling contracts or sustained periods of downtime, the Company's results of operations and financial condition could be materially adversely affected.intaerrupted
Some of the Company’sour customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. For example,The general principle is that such early termination fee shall compensate us for lost revenues less operating expenses for the West Siriusremaining contract permitted such a termination upon payment of $297,000 per day until July 2017.period. However, in some cases, such payments may not fully compensate the Companyus for the loss of the drilling contract.
Under certain circumstances the Company’sour contracts may permit customers to terminate contracts early without the payment of any termination fees, as a result of non-performance, total loss of the rigs, extended periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events beyond the Company’s control.majeure. During periods of challenging market conditions, the Companywe may be subject to an increased risk of itsour customers seeking to repudiate their contracts, including through claims of non-performance. The Company’s customers’
In the current environment our customers may seek to renegotiate our contracts. This may result in lower dayrates or the cancellation of contracts with or without any applicable early termination payments.
Reduced day rates in our customer contracts and cancellation of drilling contracts (with or without early termination payments) would lead to reduced revenues and adversely affect our financial condition, results of our operations and ability to perform theirmake distributions to unitholders.
We may not be able to refinance existing facilities or raise additional capital on acceptable terms, which may hinder or prevent us from meeting existing obligations under theirand expanding our business.
As of December 31, 2017, we had $3,381.1 million in principal amount of external interest-bearing debt and $24.7 million of related party debt, all of which was secured by, among other things, liens on our drilling contractsunits.
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 negatively impacted byavailable to us in the prevailing uncertainty surroundingfuture for refinancing or repayment of existing indebtedness. Refer to Item 5B "Operating and Financial Review - 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 developmentpayment of the world economyinterest and theprincipal on such debt and will not be available for other purposes.
The covenants in our credit markets. If a customer cancels its contract, and the Company is unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is suspended for an extended period of time or if a contract is renegotiated on different terms, it could adversely affect the Company's business, results of operationsfacilities impose operating and financial condition and may reduce the amountrestrictions on us, breach of cash the Company has available to distribute to the Company and that the Company has available for distribution to its unitholders. For more information regarding the termination provisions of the Company’s drilling contracts, please read Item 4 “Information on the Company—Business Overview—Drilling Contracts.”
The Company currently derives the vast majority of its revenue from four customers, and the loss of any of these customerswhich could result in a material lossdefault under the terms of revenuesthese agreements, which could accelerate the repayment of funds that we have borrowed.
Our debt agreements impose operating and cash flow.
The Company currently derives the vast majority of its revenues and cash flow from four customers. For the year ended December 31, 2015, BP accounted for 44.8%, ExxonMobil(*) accounted for 32.1%, Tullow accounted for 13.5%, and Chevron accounted for 8.5% of total revenues, respectively. Allfinancial restrictions on us. These restrictions may prohibit or otherwise limit our ability to undertake certain business activities without consent of the Company’slending banks. These restrictions include:
executing other financing arrangements;
incurring additional indebtedness;
creating or permitting liens on our assets;
selling our drilling contracts have fixed terms, butunits or the shares of our subsidiaries;
making investments;
changing the general nature of our business;
paying distributions to our unitholders;
changing the management and/or ownership of the drilling units; and
making capital expenditures.
Our lenders’ interests may be terminated earlydifferent from ours and we may not be able to obtain our lenders’ consent for requests that may be beneficial to our business. This may impact our performance.
In addition, several of our debt agreements require us to maintain specified financial ratios and to satisfy covenants, including ratios and covenants that pertain to, among other things, our liquidity and net leverage ratios under our secured credit facilities.
In the future, to the extent our operating results indicate that we may not meet the net leverage ratio of our secured credit facilities, there are a number of actions available which are under management’s control. We cannot provide any assurances that management’s actions will resolve compliance with the leverage ratio or any other financial covenant. In the event that we fail to comply with the covenants in our credit facilities, we would be considered in default, after any applicable notice from our lenders, which would enable applicable lenders to accelerate the repayment of amounts outstanding and exercise remedies, subject to applicable cure or grace periods, and we would need to seek an amendment or waiver from the applicable lender groups. 
Such amendments or waivers from our lenders may be subject to competing interests of the lending institutions. We cannot provide any assurances that we will be able to obtain such an amendment or waiver. If we are not able to obtain waivers or amendments, or if such waivers or amendments have onerous conditions attached, this may limit our ability to make decisions in the best interests of our business.
If we are unable to comply with any of the restrictions and covenants in our current or future debt financing agreements, and we are unable to obtain a waiver or amendment from our lenders for such noncompliance, a default could occur under the terms of those agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend or accelerate the outstanding loans and declare all amounts borrowed due and payable. Our drilling units and equity interests in our subsidiaries serve as security for our secured indebtedness. If our lenders were to certain eventsforeclose their liens on our drilling units or might nevertheless be lostthe equity interests in our subsidiaries in the event of unanticipated developments, such as the deteriorationa 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 the general business or financial conditiondefault under one of a customer, resultingour loan agreements, our other loan agreements also may be in its inability meet its obligationsdefault, which could result in amounts outstanding under its contracts with the Company. The Company's contract with Petronas Myanmar relatingthose loan agreements to the West Vencedor is expected to expire in the July 2016,be accelerated and no subsequent employment has been obtained for the West Vencedor.
* The West Aquarius was assigned to Hibernia Management for the duration of 2015.
Furthermore, the drilling contract for the West Sirius was terminated earlybecome due and ended in April 2015. No subsequent employment has been obtained for the West Sirius.
payable. If any of the Company’s drilling contracts are terminated, the Companythese 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 re-deploy the drilling unit subject to such terminated contractfind alternative financing. Even if we could obtain alternative financing, that financing might not be on terms asthat are favorable or acceptable. Any of these events would adversely affect our ability to it as its current drilling contracts. If the Company is unablemake distributions to re-deploy a drilling unit for which the drilling contract has been terminated, the Company may not receive any revenues from that drilling unit (other than termination fees), but it will be required to pay expenses necessary to maintain the drilling unit in proper operating condition. This willunitholders and cause the Company to receive decreased revenues and cash flows from having fewer drilling units operating in its fleet. The loss of any customers, drilling contracts or drilling units, or a decline in paymentsthe market price of our common units. For more information, please read Item 5 "Operating and Financial Review and Prospects-Liquidity and Capital Resources."
Our contract backlog for our fleet of drilling units may not be realized.
As of March 31, 2018, our contract backlog was approximately $1.4 billion. The contract backlog presented in this Annual Report and our other public disclosures is only an estimate. The actual amount of revenues earned and the actual periods during which revenues are earned will be different from the contract backlog projections due to various factors, including shipyard and maintenance projects, downtime and other events within or beyond our control. In addition, we or our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, such as the current environment, resulting in lower dayrates.
Our inability, or the inability of our customers to perform, under any of the Company’s drilling contracts, couldour or their contractual obligations may have a material adverse effect on the Company's business, results of operations,our financial condition and ability to make cash distributions to the Company's unitholders.
In addition, the Company's drilling contracts subject it to counterparty risks. The ability of each of the Company's counterparties to perform its obligations under a contract with the Company depend on a number of factors that are beyond the Company's control and may include, among other things, general economic conditions, the condition of the offshore drilling industry, prevailing prices for oil and gas, the overall financial condition of the counterparty, the dayrates received for specific types of drilling units and the level of expenses necessary to maintain drilling activities. In addition, in depressed market conditions, the Company's customers may no longer need a drilling unit that is currently under contract or may be able to obtain a comparable drilling unit at a lower dayrate. Should a counterparty fail to honor its obligations under an agreement with the Company, the Company could sustain losses, which could have a material adverse effect on the Company's business, financial condition,position, results of operations and cash available for distribution.flows.
The Company
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 expiringcurrently off-contract.
As of March 31, 2018, we have seven drilling units either on contract or are terminated, which could adversely affect its revenuesmobilizing for operations. Two of these contracts expire in 2018, three expire in 2019 and profitability.

The Company’stwo expire in 2020.Our ability to renew expiringthese contracts or obtain new contracts will depend on theour customers and prevailing market conditions, at the time which may vary among different geographic regions differentand types of drilling units,units. Customers may also choose not to award drilling contracts to us due to our links with Seadrill and specific conditions. its current Chapter 11 proceedings.
We estimate that approximately 52% of the global fleet of drillships and semi-submersible drilling rigs are off-contract and that the global order book for floaters is 42 rigs. We estimate the equivalent figures for tender rigs are 60% and 6 units.
If the Company iswe are not able to obtain new contracts in direct continuation with existing contracts, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared tothan existing contract terms, itsour revenues and profitability couldwould be adversely affected.
The offshore drilling markets We may also be required to accept more risk in which the Company competes experience fluctuations in the demand for drilling services, as measured by the level of explorationareas other than price to secure a contract and development expenditures and supply of capable drilling equipment. The Company's contract with Petronas Myanmar relating to the West Vencedor is expected to expire in the third quarter of 2016, and no subsequent employment has been obtained for the West Vencedor. The drilling contract for the West Sirius was terminated early in April 2015 and the unit is currently stacked. No subsequent employment has been obtained for the West Sirius.
The existing drilling contracts for the remainder of the Company's drilling units , are scheduled to expire from April 2017 through November 2020. The Company cannot guarantee that it will be able to obtain contracts for its drilling units upon the expiration or termination of their current contracts or that there will not be a gap in employment of the rigs between current contracts and subsequent contracts. In particular, if oil and gas prices remain as low as they are currently, or it is expected that such prices will remain low or decrease in the future, at a time when the Company is seeking to arrange contracts for the its drilling units, the Company may not be able to obtain drilling contracts at attractive dayratespass such additional risks onto our subcontractors, or at all.
If the dayrates which the Company receives for the reemployment of the Company's current drilling units are less favorable, the Company will recognize less revenue from their operations. The Company's ability to meet its cash flow obligations will depend on the Company's ability to consistently secure drilling contracts for the Company's drilling units at sufficiently high dayrates. The Company cannot predict the future level of demand for the Company's services or future conditions in the oil and gas industry. If current market conditions continue and oil and gas companies do not increase exploration, development and production expenditures, the Company may have difficulty securing drilling contracts, or the Company may be forced to enter into contracts at unattractive dayrates, which would adversely affect the Company's ability to make distributions to the Company's unitholders.
Competition within the offshore drilling industry may adversely affect us.
The offshore drilling industry is highly competitive and fragmented and includes several large companies that compete in the markets the Company serves, as well as smaller companies. 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, its record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. The Company’s operations may be adversely affected if its current competitors or new market entrants introduce new drilling units with better features, performance, price or other characteristics in comparison to the Company’s drilling units, or expand into service areas where the Company operates. In addition, mergers among oil and gas exploration and production companies have reduced, and may from time to time further reduce, the number of available customers, which would increase the ability of potential customers to achieve pricing terms favorable to them.
The offshore drilling industry has historically been cyclical and is impacted by oil and gas price levels and volatility. There have been periods of high demand, short rig supply and high dayrates, followed by periods of low demand, excess rig supply and low dayrates, such as the downturn that we are currently experiencing. Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply may intensify competition in the industry and result in the idling of older and less technologically advanced equipment. The Company may in the future idle or stack rigs or enter into lower dayrate drilling contracts in response to market conditions. The Company cannot predict when or if any idled or stacked rigs will return to service.
Competitive pressures and other factors may result in significant price competition, particularly during the current industry downturn and any future downturn, which could have a material adverse effect on the Company's financial position, results of operations, cash flows and ability to make distributions to the Company's unitholders.
A continued economic downturn in the world economy could have a material adverse effect on the Company's revenue, profitability and financial position.
The Company depends on its 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 demand for energy, including oil and gas. The world economy is currently facing a number of challenges. Concerns persist regarding the debt burden of certain Eurozone countries and their ability to meet future financial obligations and the overall stability of the euro. An extended period of adverse development in the outlook for European countries could reduce the overall demand for oil and gas and for the Company's services. These potential developments, or market perceptions concerning these and related issues, could affect the Company's financial position, results of operations and cash available for distribution. This includes uncertainty surrounding the sovereign debt and credit crises in certain European countries. In addition, turmoil and hostilities in Korea, Ukraine, the Middle East, North Africa and other geographic areas and countries are adding to overall risk. In addition, worldwide financial and economic conditions could severely restrict the Company's ability to access the capital markets at a time when the Company would like, or need, to access such markets, which could impact the Company's ability to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, the lenders participating in the Company's credit facilities. Such economic conditions could also impact lenders participating in the credit facilities of the Company's customers, causing those customers to fail to meet their obligations to the Company. In addition, a portion of the credit under the Company's credit facilities is provided by European banking institutions. If economic conditions in Europe preclude or limit financing from these banking institutions, the Company may not be able to obtain financing from other institutions on terms that are acceptable, or at all, even

if conditions outside Europe remain favorable for lending.An extended period of adverse development in the outlook for the world economy could reduce the overall demand for oil and gas and for the Company's services. Such changes could adversely affect the Company's financial condition, results of operations and ability to make distributions to the Company's unitholders.
The current state of global financial markets and current economic conditions may adversely impact the Company's ability to obtain additional financing on acceptable terms which may hinder or prevent the Company from expanding the Company's business.
Global financial markets and economic conditions have been, and continue to be, volatile. The current state of global financial markets and current economic conditions might adversely impact the Company's ability to issue additional equity at prices which will not be dilutive to the Company's existing unitholders or preclude the Company from issuing equity at all. The Company cannot be certain that additional financing will be available if needed and to the extent required, on acceptable terms or at all. If additional financing is not available when needed, or is available only on unfavorable terms, the Company may be unable to meet the Company's obligations as they come due or the Company may be unable to expand the Company's existing business, complete drilling unit acquisitions or otherwise take advantage of business opportunities as they arise.

The Company's current backlog of contract drilling revenue may not be ultimately realized.
As of March 31, 2016, the Company's backlog of contract drilling revenues under firm commitments was approximately $4.1 billion. The actual amount of revenues earned and the actual periods during which revenues are earned may differ from the stated amounts and periods due to shipyard and maintenance projects, downtime and other events within or beyond the Company’s control. In addition, the Company's customers may seek to cancel or renegotiate the Company's contracts for various reasons, including adverse conditions in the industry. In addition, some of the Company's customers could experience liquidity issues or could otherwise be unable or unwilling to perform underinsure ourselves against any additional risk at competitive prices. This could lead to us being unable to meet our liabilities in the contract, which could ultimately leadevent of a customer to go into bankruptcy or to otherwise encourage a customer to seek to repudiate, cancel or renegotiate a contract. The Company's inability or the inabilitycatastrophic event on one of the Company's customers to perform under the Company's or their contractual obligations could adversely affect the Company's financial position, results of operations and cash available for distribution.
Failure to obtain or retain highly skilled personnel could adversely affect the Company’s operations.our rigs.
The Company believes that competition for skilled and other labor required for the Company’smarket value of our drilling operations has increased in recent years as the numberunits may further decrease.
The market values of rigs activated or added to worldwide fleets has increased. The number of rigs in operation may grow in the future as newdrilling units are delivered. Notwithstanding the general downturn in the drilling industry, in some regions such as Angola and Nigeria, limited availability of qualified personnel, in combination with local regulations focusing on crew composition, are expected to further increase demand for qualified offshore drilling crews, which may increase costs. Further expansion of the rig fleet, or improved demand for drilling services in general, coupled with shortages of qualified personnel could further create and intensify upward pressure on wages and make it more difficult or costly for the Company to staff and service its rigs, or do so on economically viable terms. The current industry downturn may not provide relief from such pressures. Further, if substantial numbers of workers seek employment outside the offshore drilling industryhave declined as a result of the downturn,recent continued decline in the competition for workersprice 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:
the general economic and market conditions affecting the offshore drilling industry, could increase, during including competition from other offshore contract drilling companies;
the downturn. Such developmentstypes, sizes and ages of drilling units;
the supply and demand for drilling units;
the costs of newbuild drilling units;
the prevailing level of drilling services contract dayrates;
governmental or other regulations; and
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 Company's financial position, results of operations, cash flows and ability to make distributions tosale price may be less than the Company's unitholders. Furthermore, as a result of any increased competition for people and risk for higher turnover, the Company may experiencedrilling unit’s carrying value in our Consolidated Financial Statements, resulting in a reduction in the experience level of its personnel, which could lead to higher downtime and more operating incidents.earnings.
Certain work stoppages or maintenance or repair work may cause the Company’s customers to suspend or reduce payment of dayrates until operation of the respective drilling unit is resumed, which may lead to termination or renegotiation of the drilling contract.
Compensation under the Company’s drilling contracts is based on daily performance and/or availability of each drilling unit in accordance with the requirements specified in the applicable drilling contract agreement. For instance, when the Company's drilling units are idle, but available for operation, the Company’s customers are entitled to pay a waiting rate lower than the operational rate.
Several factors could cause an interruption of operations, including:
breakdowns of equipment and other unforeseen engineering problems;
work stoppages, including labor strikes;
shortages of material and skilled labor;
delays in repairs by suppliers;
surveys by government and maritime authorities;
periodic classification surveys;
severe weather, strong ocean currents or harsh operating conditions; and
force majeure events.
In addition, if the Company’s drilling units are taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in its drilling contracts, the Company will not be entitled to payment of dayrates until the relevant rig is available for deployment. If the interruption of operations were to exceed a determined period due to an event of force majeure, the Company’s customers have the right to pay a rate (the “force majeure rate”) that is significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject rig. For more details on the Company’s drilling contracts, see Item 4 “Information on the Company—Business Overview—Drilling Contracts” and Item 5 “Operating and Financial Review and Prospects—Important Financial and

Operational Terms and Concepts—Contracted Revenues and Dayrates.” Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract agreements as a result of an interruption of operations as described herein could materially adversely affect the Company's financial condition, results of operations and ability to make distributions to the Company's unitholders.
Labor costs and operating restrictions that apply to the Company could increase as a result of collective bargaining negotiations and changes in labor laws and regulations.
A significant portion of the Company’s employees are represented by collective bargaining agreements. The majority of these employees work in Canada, Nigeria and Angola. As part of the legal obligations in some of these agreements, the Company is 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 the Company's financial condition, results of operations and ability to pay distributions.
An inability to obtain visas and work permits for drilling unit personnel on a timely basis could hurt its operations and have an adverse effect on the Company's business.
The Company’s ability to operate worldwide depends on obtaining the necessary visas and work permits for the personnel on its drilling units to travel in and out of, and to work in, the jurisdictions in which it operates. Governmental actions in some of the jurisdictions in which the Company operates may make it difficult to move personnel in and out of these jurisdictions by delaying or withholding the approval of these visa and work permits. If visas and work permits cannot be obtained for the employees needed for operating the Company’s rigs on a timely basis or for third-party technicians needed for maintenance or repairs, the Company might not be able to perform its obligations under its drilling contracts, which could lead to periods of prolonged downtime or allow the Company’s customers to cancel the contracts. Any such downtime or cancellation could adversely affect the Company's financial condition, results of operations and ability to make distributions to the Company's unitholders.
The Company’sOur business and operations involve numerous operating hazards, and its insurancein the current market we are increasingly required to take additional contractual risk in our customer contracts and indemnities from its customerswe may not be adequateable to procure insurance to adequately cover potential losses from its operations.losses.
The Company’sOur operations are subject to hazards inherent in the offshore drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, craterings,punch-through, cratering, fires, explosions and pollution. Contract drilling and well servicing requires the use of heavy equipment and exposure to hazardous conditions, which may subject the Companyus 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. The Company’s
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, piracy, 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. The CompanyWe customarily providesprovide contract indemnity to itsour customers for claims that could be asserted by the Companyus relating to damage to or loss of the Company'sour equipment, including rigs and claims that could be asserted by the Companyus or itsour employees relating to personal injury or loss of life.
Damage to the environment could also result from the Company’sour operations, particularly through spillage of hydrocarbons, fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. The CompanyWe may also be subject to property, damage, environmental indemnity and other damage claims by oil and gas companies. The Company’s
Our insurance policies and drilling contracts containcontractual rights to indemnity that may not adequately cover its losses, and the Company doeswe do not have insurance coverage or rights to indemnity for all risks. ThereConsistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are certain risks, including risks associated with the loss of control of a well, (suchsuch as blowout or cratering, the cost to regain control of or re-drill the well and remediation of associated pollution), against which the Company’spollution. However, there can be no assurances that these customers maywill be unablewilling or unwillingfinancially able to indemnify the Company. us against all these risks.

In addition, a court may decide that certain indemnities in the Company’sour current or future contracts are not enforceable. For example, in a 2012 case related to the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the U.S. Gulf of Mexico in April 2010, or the Deepwater Horizon Incident (to which the Company waswe were not a party), the U.S. District Court infor the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the USU.S. Clean Water Act under a drilling contract governed by U.S. maritime law as a matter of public policy. For example, in 2011, a U.S. District Court in the Southern District of Texas invalidated certain contractual indemnities for gross negligence in a drilling master services agreement governed by U.S. maritime law as a matter of public policy. The Company maintains insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities (except as described below with respect to drilling units and equipment in the U.S. Gulf of Mexico). However,Further, pollution and environmental risks generally are not totally insurable.
If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect our financial condition, results of our operations, cash flows and ability to make distributions to unitholders.
The Company’samount recoverable under insurance may also be less than the related impact on enterprise value after a loss. Our insurance policies may not cover all potential consequences of an incident and include annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. Any such lack of reimbursement may cause us to incur substantial costs.
Our insurance provides for deductibles for damage to its offshore drilling equipment and third-party liabilities. With respect to hull and machinery, the Company’sour insurance provides for a deductible per occurrence of $5 million for all of its fleet.million. However, in the event of a total loss or a constructive total loss of a drilling unit, such loss is fully covered by its insurance with no deductible. For general and marine third-party liabilities the Company’sour insurance provides for up to a $500,000$0.5 million deductible per occurrence on personal injury liability for crew claims as well as non-crew claims and per occurrence on third-party property damage.
If a significant accident or other event occurs that is not fully covered by the Company’s insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect the Company's financial position, results of operations or cash available for distribution. The amount of the Company’s insurance may also be less than the related impact on enterprise value after a loss. The Company’s insurance coverage will not in all situations provide sufficient funds to protect it from all liabilities that could result from its drilling operations. The Company’s coverage includes annual aggregate policy limits. As a result, the Company retains the risk for any losses in excess of these limits.

Any such lack of reimbursement may cause the Company to incur substantial costs. In addition, the CompanyWe 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, thatwhich are not covered by third-party insurance contracts. Specifically, the Company has at times in the past elected to not insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico due to the substantial costs associated with such coverage. The Company has 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 for the period from May 1, 2016 through April 30, 2017.
If the Company elects not to insure such risks in the future, and such windstorms cause significant damage to any rig and equipment the Company has in the U.S. Gulf of Mexico, it could have a material adverse effect on the Company's financial position, results of operations or cash flows. Moreover, noNo assurance can be made that the Companywe will be able to maintain adequate insurance in the future at rates that the Company considerswe consider reasonable, or that we will be able to obtain insurance against certain risks.
An over-supplyWe derive the majority of drilling units may lead toour revenue from a reductionsmall number of customers, and the loss of any of these customers could result in dayratesa material loss of revenues and therefore may materially impact the Company’s profitability.cash flow.
PriorWe are subject to the current downturn, duringrisks associated with having a limited number of customers for our services. We currently derive the recent periodmajority of high utilizationour revenues and high dayrates, industry participants have increasedcash flow from a small number of customers. For the supplyyear ended December 31, 2017, BP accounted for 56.8%, ExxonMobil accounted for 22.2% and Chevron accounted for 7.9% of our total revenues, respectively. Our results of operations could be materially adversely affected if any of our major customers fail to compensate us for our services, or cancel or re-negotiate our contracts.
We are subject to risks of loss resulting from non-payment or non-performance by our customers and certain other third parties. Some of these customers and other parties may be highly leveraged and subject to their own operating and regulatory risks. If any key customers or other parties default on their obligations to us, our financial results and condition could be adversely affected. Any material non-payment or non-performance by these entities, other key customers or certain other third parties could adversely affect our financial position, results of operations and cash flows.
Our drilling units by ordering construction of new drilling units. Historically, this has resulted in an over-supply of drilling unitscontracts contain fixed terms and has caused a subsequent decline in utilizationday-rates, and dayrates when the drilling units have entered the market, sometimes for extended periods of time until the new units have been absorbed into the active fleet. As of March 31, 2016, the worldwide fleet of tender rigs, semi-submersible rigs and drillships consisted of 343 units, comprising 37 tender rigs, 185 semi-submersible rigs and 121 drillships. In addition there are 8 tender rigs, 23 semi-submersible rigs and 46 drillships were under construction or on order, which would bring the total fleet to 420 units, assuming no reductionconsequently we may not fully recoup our costs in the total fleet size through retirementevent of drilling units or otherwise. A relatively large number ofa rise in expenses, including operating and maintenance costs.
Our operating costs are generally related to the drilling units currently under construction have not been contracted for future work, and a number of units in operation and the existing worldwide fleetcost level in each country or region where the units are currently off contract.
The supplylocated. A significant portion of available uncontracted units is likely to intensify price competition as scheduled delivery dates occur and additional contracts terminate without renewal, and lead to a reduction in dayrates as the active fleet grows. Any further increase in construction of new units may increase the negative impact on dayrates and utilization. In addition, drilling unitsour operating costs may be relocatedfixed over the short term.
The majority of our contracts have dayrates that are fixed over the contract term. In order to markets in whichmitigate the Company operates, which could exacerbate excess drilling unit supplyeffects 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 lower dayrates in those markets. If a large number of drilling units become available aroundmaintenance 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 expiration of the Company's drilling contracts, it could depress the dayrate the Company is able to obtain under a renewed or new contract with respect to the Company's drilling units. In addition, customers may demand renegotiation of existing contracts to lower dayrates. In an over-supplied market, the Company may have limited bargaining power to renegotiate on more favorable terms. Lower utilization and dayrates could adversely affect the Company’s revenues and profitability and ability to make distributions to its unitholders.
In addition, prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on the Company’s drilling units if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these drilling units may not be recoverable.

adjustment. The market value of the Company’s existing drilling units has decreased and drilling units the Company may acquire in the future could decrease, which could cause the Company to incur losses if the Company decides to sell them following a decline in their market values.

During 2015, the estimated fair value of the Company's drilling units, based upon various broker valuations, decreased by approximately 16%. If the offshore contract drilling industry suffers adverse developments in the future, the fair market value of the Company's 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 dependingadjustments are typically performed on a number of factors, including:
general economicsemi-annual or annual basis. For these reasons, the timing and market conditions affecting the offshore drilling industry, including competition from other offshore contract drilling companies and the price of oil and gas;
types, sizes and ages of drilling units;
supply and demand for drilling units;
costs of newbuildings;
prevailing level of drilling services contract dayrates;
governmental or other regulations; and
technological advances.
If the Company sells any drilling unit at a time when prices for drilling units have fallen, such a sale may result in a loss. Such a loss could materially and adversely affect the Company's business prospects, financial condition, liquidity, results of operations and ability to make distributions to its unitholders.
If the market value of our drilling units falls, we may also be required to make prepayments on our outstanding indebtedness to remain in compliance with minimum loan to value requirements in certain of our financing agreements.
The Company may incur impairment chargesamount received as a result of reduced demandsuch 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 drilling serviceseither fixed or other factorsdayrate 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 future,scope and length of such required preparations and the Companyduration 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 record impairment chargesprepare drilling units for stacking and maintenance in the stacking period. Should units be idle for a longer period, we will seek to goodwill or other assets. Such impairment charges could haveredeploy 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 material adverse effectfunction 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 Company's financial performancelevel 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 results ofrenegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted" and its ability"We may not be able to pay distributions. In addition, such

impairment chargesrenew or obtain new and favorable contracts for our drilling units whose contracts which have expired or been terminated". This could adversely impact the Company's ability to comply with the restrictions and covenants in the Company's debt agreements, including meeting financial ratios and tests in those agreements. If the Company is unable to comply with the restrictions and covenants in the agreements governing its indebtedness or in current or future debt financing agreements, a default could occur under the terms of those agreements.affect our revenue from operations.
Consolidation and governmental regulation of suppliers may increase the cost of obtaining supplies or restrict the Company’sour ability to obtain needed supplies which may have a material adverse effect on the Company's results of operations and financial condition.
The Company reliesWe rely on certain third parties to provide supplies and services necessary for itsour 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 the Company is("BOPs"), we are dependent uponon 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. SimilarThese cost increases or delays could have a material adverse effect on the Company’sour results of operations and result in rig downtime, and delays in the repair and maintenance of itsour 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.
Furthermore, mostEvery 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 Company's suppliersclassification 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 U.S. companies, which means thatrequired 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 eventcountries 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 U.S. supplier was debarred or otherwise restricted bymaterial adverse impact on the U.S. government from delivering its products the Company's ability to supply and service its operations in areasresults of the U.S. Gulf of Mexico subject to federal lease could be severely impacted.operations.
The Company’s international nature of our operations involveinvolves additional risks which could adversely affectincluding foreign government intervention in relevant markets.
We operate in various regions throughout the Company's business.
world. As a result of the Company’sour international operations, the Companywe may be exposed to political and other uncertainties, particular in less developed jurisdictions, including risks of:
terrorist acts, armed hostilities, war and civil disturbances;
acts of piracy, which have historically affected ocean-going drilling units trading in regions of the world such as the South China Sea, the Gulf of Aden off the coast of Somalia, where piracy has increased significantly in frequency since 2008, and off the west coast of Africa;vessels;
significant governmental influence over many aspects of local economies;
the seizure, nationalization or expropriation of property or equipment;
uncertainty of outcome in foreign court proceedings;
the repudiation, nullification, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
political unrest;
foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
the inability to repatriate income or capital;
complications associated with repairing and replacing equipment in remote locations;
import-export quotas, wage and price controls, and the imposition of trade barriers;
U.S. and foreign sanctions or trade embargoes;
compliance with various jurisdictional regulatory or financial requirements to complyrequirements;
compliance with foreign bureaucratic actions;
changing taxation policies, including confiscatoryand changes in taxation;
other forms of government regulation and economic conditions that are beyond the Company'sour control; and
governmental corruption.

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

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

If the Company’s business activities involveour drilling units are located in countries entities and individuals that are subject to or targeted by economic sanctions, export restrictions, or other operating restrictions imposed by the U.S.United States or other governments, the Company could be subject to enforcement action and the Company'sour reputation and the market for the Company'sour debt and common units could be adversely affected.
The U.S. and other governments impose economic sanctions against certain countries, persons and other entities that restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions in particular are targeted against countries (such as Russia, Venezuela, Iran, and others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities. U.S. and other economic sanctions change frequently and enforcement of economic sanctions worldwide is increasing.
In 2010, the U.S.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 the Company,ours, and introducesintroduced 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 (essentially making the U.S. sanctions against Iran as expansive as U.S. sanctions against Cuba). These new sanctions were codified within the Iranian Transactions Regulations on or about December 26, 2012.person. The other major provision in the Iran Threat Reduction Act is that issuers of securities must disclose to the SEC 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. The disclosure must describe the nature and extent of the activity in detail and the SEC will publish the disclosure on its website. The President must then initiate an investigation and determine whether sanctions on the issuer or its affiliate will be imposed. Such negative publicity and the possibility that sanctions could be imposed would present a risk for any issuer that is knowingly engaged in sanctioned conduct or that has an affiliate that is knowingly engaged in such conduct. At this time, the Company iswe are not aware of any sanctionable activity,violation conducted by ourselvesus or by any affiliate, of Seadrill thatwhich is likely to trigger an SECsuch a disclosure requirement.
Sanctions affecting non-U.S. companies likeOn November 24, 2013, the Company were expanded yet againP5+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 2013 National Defense Authorization Act,JPOA.
The JPOA was subsequently extended twice. On July 14, 2015, the P5+1 and the European Union announced that they reached a landmark agreement with Iran titled the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran’s Nuclear Program, or the JCPOA, to significantly restrict Iran’s ability to develop and produce nuclear weapons for 10 years while simultaneously easing sanctions directed toward non-U.S. persons for conduct involving Iran, but taking place outside of U.S. jurisdiction and not involving U.S. persons. On January 16, 2016, or the Implementation Day, the United States joined the European Union and the U.N. in lifting a significant number of their nuclear-related sanctions on Iran following an announcement by the International Atomic Energy Agency, or the IAEA, that Iran had satisfied its respective obligations under the JCPOA.
U.S. sanctions prohibiting certain conduct that is now permitted under the JCPOA have not actually been repealed or permanently terminated at this time. Rather, the U.S. government has implemented changes to the sanctions regime by: (1) issuing waivers of certain statutory sanctions provisions; (2) committing to refrain from exercising certain discretionary sanctions authorities; (3) removing certain individuals and entities from OFAC's sanctions lists; and (4) revoking certain Executive Orders and specified sections of Executive Orders. These sanctions will not be permanently "lifted" until the earlier of “Transition Day,” set to occur on October 20, 2023, or upon a report from the IAEA stating that all nuclear material in Iran is being used for peaceful activities.
On October 13, 2017, the current U.S administration announced it would not certify Iran's compliance with the passageJCPOA. This did not withdraw the U.S. from the JCPOA or re-instate any sanctions. However, they have criticized the JCPOA and threatened to withdraw the U.S. from the JCPOA. Further, the administration must periodically renew sanctions waivers and his refusal to do so could result in the reinstatement of certain sanctions currently suspended under the JCPOA.
OFAC acted several times in 2017 to add Iranian individuals and entities to its list of Specially Designated Nationals whose assets are blocked and with whom U.S. persons are generally prohibited from dealing. Moreover, in August 2017, the U.S. passed the “Countering America’s Adversaries Through Sanctions Act” (Public Law 115-44) (CAATSA), which authorizes imposition of new sanctions on Iran, Russia, and North Korea. The CAATSA sanctions with respect to Russia create heightened sanctions risks for companies operating in the oil and gas sector, including companies that are based outside of the Iran FreedomUnited States. OFAC sanctions targeting Venezuela have likewise increased in the past year, and Counter-Proliferation Act, and the Company believes that theseany new sanctions will continuetargeting Venezuela could further restrict our ability to become more restrictive for the foreseeable future.do business in such country. In addition to the sanctions against Iran, subject to certain limited exceptions, U.S. law continues to restrict U.S. owned or controlled entities from doing business with Cuba and various U.S. sanctions have certain other extraterritorial effects that need to be considered by non-U.S. companies. Moreover, any U.S. persons who serve as officers, directors or employees of the Companyour 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. It should be noted that the U.S. and various other nations entered
From time to time, we may enter into a Joint Comprehensive Plan of Action (JCPOA) with Iran that provides for phased sanctions relief. On January 16, 2016, following verification that Iran had satisfied its commitments under the JCPOA, the United States lifted its nuclear-related “secondary” sanctions and the European Union also took action to lift its sanctions.  As a result of sanctions relief non-U.S. persons will be able to engage in business with Iran. Sanctions relief will not impact the SEC reporting requirements discussed above.

With the exception of Myanmar, the Company does not currently have any drilling contracts or plans to initiate any drilling contracts involving operations inwith 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. With respect to Myanmar, transactions byterrorism where entering into such contracts would not violate U.S. persons,law, or in or involving the United States, are prohibited if they involve property or interests in property of an entity or individual listed on the list of Specially Designated Nationals and Blocked Persons or entities that are 50 percent or more owned, whether individually or in the aggregate, directly or indirectly, by one or more persons listed on the list of Specially Designated Nationals and Blocked Persons. Furthermore, certain investment transactions and exports of financial services by U.S. persons, or from the United States, in or to Myanmar, are prohibited, although the U.S. government has issued broad general licenses authorizing this conduct. Finally, certain imports of items originating in Myanmar into the United States are prohibited. As a non-U.S. entity, none of the Company’s operations in Myanmar directly implicate these prohibitions, but to the extent the Company employs U.S. persons who are involved in the Company’s operations in Myanmar, their activities would be authorized by general license. From time to time, the Company 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 in cases 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 may become subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism. ThisHowever, this could negatively affect the Company'sour 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 the Company'sour reputation and the market for our units. We do not currently have any drilling contracts or plans to initiate any drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the Company's common units.U.S. government and/or identified by the U.S. government as state sponsors of terrorism.

Certain parties with whom we have entered into contracts may be the subject of sanctions imposed by the United States, the European Union or other international bodies as a result of the annexation of Crimea by Russia in March 2014 and the subsequent conflict in eastern Ukraine, or may be affiliated with persons or entities that are the subject of such sanctions. If we determine that such sanctions require us to terminate existing contracts or if we are found to be in violation of such applicable sanctions, our results of operations may be adversely affected or we may suffer reputational harm. We may also lose business opportunities to companies that are not required to comply with these sanctions.
As stated above, the Company believeswe believe that it iswe are in compliance with all applicable economic sanctions and embargo laws and regulations, and intendsintend to maintain such compliance. However, there can be no assurance that the Companywe will be in compliance in the future, particularly as such laws are subject to frequent changes, the scope of certain laws may be unclear and may be subject to changing interpretations. For instance, newRapid changes in the scope of global sanctions were announcedmay also make it more difficult for us to remain in March 2014 in relation to certain individuals in Russia and Ukraine, and subsequently modified in August and September 2014.compliance. Any such 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 the Company's commonour units. Additionally, some investors may decide to divest their interest, or not to invest, in the Company's commonour units simply because the Companywe may do business with companies that do business in sanctioned countries. Moreover, the Company’sour drilling contracts may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve the Companyus, or itsour drilling units,rigs, and those violations could in turn negatively affect the Company'sour reputation. Investor perception of the value of the Company's commonour 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.

Local content policies may impair the Company’s ability to compete in local jurisdictions, and changes in these policies may adversely affect the Company's financial conditions and results of operations.
Certain foreign governments, such as those of Nigeria and Angola, favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling units 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. For example, the local content policy in Angola requires the Company's customers to develop and implement a plan to increase local Angolan content, including specific goals. In addition, Nigerian laws required one of the Company's subsidiaries to enter into a joint venture with Nigerian investors to own the West Capella. These regulations may adversely affect the Company’s ability to compete in these contract drilling markets. Further, local content policies may be subject to significant and unpredictable changes, which may lead to greater uncertainty in operational planning in those jurisdictions.

If the Company's drilling units fail to maintain their class certification or fail any required survey, that drilling unit would be unable to operate, thereby reducing the Company's revenues and profitability.
Every offshore drilling unit is a registered marine vessel and must be “classed” by a classification society. 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. If any drilling unit does not maintain its class and/or fails any annual survey or special survey, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable, which could cause the Company to be in violation of certain covenantsContinuing challenges in the Company's credit facilities. Any such inability to carry on operations or be employed,world economy could have a material adverse effect on our revenue, profitability and financial position.
We depend on our customers’ willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and the demand for energy, including oil and gas. The world economy is currently facing a number of challenges. Concerns persist regarding the debt burden of certain eurozone countries and their ability to meet future financial obligations and the overall stability of the euro. An extended period of adverse development in the outlook for European countries could reduce the overall demand for oil and natural gas and for our services. These potential developments, or market perceptions concerning these and related issues, could affect our financial position, results of operations and cash available for distribution. In addition, turmoil and hostilities in Ukraine, Korea, the Middle East, North Africa and other geographic areas and countries are adding to the overall risk picture.
In addition, worldwide financial and economic conditions could cause our ability to access the capital markets to be severely restricted at a time when we would like, or need, to access such markets, which could impact our ability to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, the lenders participating in our credit facilities and our customers, causing them to fail to meet their obligations to us.
A portion of the credit under our credit facilities is provided by European banking institutions. If economic conditions in Europe preclude or limit financing from these banking institutions, we may not be able to obtain financing from other institutions on terms that are acceptable to us, or at all, even if conditions outside Europe remain favorable for lending.
In June 2016, the Company'sUK voted to exit from the E.U. (commonly referred to as "Brexit"). The impact of Brexit and the resulting UK/ EU relationship are uncertain for companies doing business both in the UK and the overall global economy.
An extended period of adverse development in the outlook for the world economy could reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our financial condition, results of operations, cash flows and our ability to make distributions to our unitholders.
Our business is capital intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund our capital expenditures. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations or interpretations thereof and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.
Any reductions in drilling activity by our customers may not be uniform across different geographic regions. Locations where costs of drilling and production are relatively higher, such as Arctic or deepwater locations, may be subject to greater reductions in activity. Such reductions in high cost regions may lead to the relocation of drilling units, concentrating drilling units in regions with relatively fewer reductions in activity leading to greater competition.
If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing on terms acceptable to us or at all for the remaining installment payments we are obligated to make before the delivery of our remaining newbuildings and our other capital requirements, including principal repayments.
Failure to obtain or retain highly skilled personnel, and to ensure they have the correct visas and permits to work in the locations in which they are required, could adversely affect our operations.
We require highly skilled personnel in the right locations to operate and provide support for our business.
Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased, and this may continue to rise. Notwithstanding the general downturn in the drilling industry, in some regions, such as Western Africa, the limited availability of qualified personnel in combination with local regulations focusing on crew composition, are expected to further increase the demand for qualified offshore drilling crews, which may increase our costs. These factors could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for qualified personnel, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents.

Our ability to operate worldwide depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate. Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. If we are not able to obtain visas and work permits for the employees we need for operating our rigs on a timely basis, or for third-party technicians needed for maintenance or repairs, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts. Any such downtime or cancellation could adversely affect our financial condition, results of operations and ability to make distributions to our unitholders.
Labor costs and operating restrictions that apply could increase following collective bargaining negotiations and changes in labor laws and regulations.
Some of our employees are represented by collective bargaining agreements. The majority of these employees work in Nigeria and Angola. As part of the Company's unitholders.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 or exchange controlsand the non-convertibility of currencies could result in losses to us.
As a result of the Company’sour international operations, the Company iswe are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. Dollars.dollars. Accordingly, the Companywe may experience currency exchange losses if the Company haswe have not fully hedged the Company'sour exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. The CompanyWe may also be unable to collect revenues because of a shortage of convertible currency available toin the country of operation, controls over currency exchange or controls over the repatriation of income or capital or controls over currency exchange. The Company doescapital. We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.
The Company and the majority of its subsidiariesWe use the U.S. Dollardollar as theirour functional currency because the majority of theirour revenues and expenses are denominated in U.S. Dollars.dollars. Accordingly, the Company'sour reporting currency is also U.S. Dollars. The Company does,dollars. We do, however, earn revenuerevenues and incur expenses in other currencies, and there is a risk that currency fluctuations could have an adverse effect on the Company'sour statements of operations and cash flows.
The Company may be unable to obtain, maintain, and/Brexit, or renew permits necessary for the Company's operations or experience delays in obtaining such permits, which could have a material effect on the Company's operations.
The operation of the Company’s drilling units are subject to certain governmental approvals and permits. The permitting rules in most jurisdictions are complex and subject to change, including their interpretations by regulators, all of which may make compliance more difficult or impractical, and may increase the length of time it takes to receive regulatory approval for offshore drilling operations. In many jurisdictions, substantive requirements under environmental laws are implemented through permits and permit renewals. If the Company fails to timely secure the necessary approvals or permits, the Company’s customers may have the right to terminate or seek to renegotiate their drilling contracts to the Company’s detriment. In the future, 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 or increasing the time needed to obtain necessary environmental permits, could have a material adverse effect on the Company's business, operating results or financial condition.
The Company is subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
The Company’s operations are subject to numerous environmental laws and regulations in the form of international conventions and treaties, and national, state and local laws and regulations in force in the jurisdictions in which its drilling units operate or are registered, which can significantly affect the operation of its drilling units. The offshore drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and, accordingly, the Company is directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, may curtail exploration and development drilling for oil and gas. Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or operational changes and may affect the resale value or useful lifetime of the Company’s drilling units.
The Company may also incur additional costs in order to comply with other existing and future regulatory obligations, including, but not limited to, costs relating to air emissions, including greenhouse gases, the management of ballast waters, maintenance and inspection, development and implementation of emergency procedures and insurance coverage or other financial assurance of its ability to address pollution incidents. These costs could have a material adverse effect on the Company's 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 the Company’s operations.

Environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject the Company to liability without regard to whether it was negligent or at fault. Under the U.S. Oil Pollution Act of 1990, or 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 the Company is deemed a responsible party, could result in significant liability, including fines, penalties and criminal liability and remediation costs for natural resource damages under other international and U.S. federal, state and local laws, as well as third-party damages, which could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows. Furthermore, the 2010 explosion of the Deepwater Horizon well and the subsequent release of oil into the Gulf of Mexico, or other similar events may result in further regulation of the shipping industry, and modifications to statutory liability schemes, thus exposing the Company to further potential financial risk in the event of any such oil or chemical spill.
The Company is required by various governmental and quasi-governmental agencies to obtain certain permits, licenses, and certificates with respect to the Company's operations, and satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents. Although the Company has 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 its business, results of operations, cash flows and financial condition and its ability to pay distributions, if any, in the future.
Although the Company's drilling units are separately owned by the Company's subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venturejurisdictions, 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 the Company could be subject to liability upon a judgment against the Company or any one of the Company's subsidiaries.
The Company’s drilling units could cause the release of oil or hazardous substances, especially as its drilling units age. Any releases may be large in quantity, above the Company's 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 the Company, such as costs to upgrade its drilling units, clean up the releases, and comply with more stringent requirements in its discharge permits. Moreover, these releases may result in the Company’s customers or governmental authorities suspending or terminating its operations in the affected area,impact global markets, which could have a material adverse effect on the Company's business, results of operation and financial condition.
If the Company is able to obtain from the Company's customers some degree of contractual indemnification against pollution and environmental damages, the indemnification may not be applicable in all instances or the customer may not be financially able to comply with its indemnity obligations. In the future, the Company may not be able to obtain contractual indemnification against pollution and environmental damages.
In addition, the Company is required to satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents. The Company's insurance coverage may not be available in the future, or the Company may not obtain certain insurance coverage. Even if insurance is available and the Company has obtained the coverage, the insurance coverage may not be adequate to satisfy the Company's liabilities or its 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 the Company's business, operating results and financial condition.
To the extent new laws are enacted or other governmental actions are taken 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 the offshore drilling industry, in particular, the Company's business or prospects could be materially adversely affected. Future earnings and cash available for distribution may be negatively affected by compliance with any such new legislation or regulations.
Climate change and regulation of greenhouse gases 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 Company'sworld. Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, regulations and treaties in and between the countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, regulations or treaties, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, which is beyond our control, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings. For example, Nigeria announced in 2015 that the tax regime was to change from a deemed profit percentage of revenue to an actual profit regime, the calculation of which is broadly based on 30% of income before tax. Other such changes may include measures enacted in response to the ongoing initiatives in relation to fiscal legislation at an international level, such as the Action Plan on Base Erosion and Profit Shifting of the Organization for Economic Co-operation and Development. In addition, the United States in December 2017 enacted major tax reform legislation.  This could lead to a material increase in the amount of overall U.S. tax liabilities of the group if it reduces the tax deductions for certain payments our U.S. operating companies make to non-U.S. rig owners. The extent of the impact is still being analyzed especially given a number of subsequent regulations which may be issued and will need to be interpreted with advisers as necessary.
A loss of a major tax dispute or a successful tax challenge to our tax positions, including our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.
Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions that we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges any of our tax positions, including our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.

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 United Nations’ International Maritime Organization, or the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, norwhich entered into force in 2005 and pursuant to the recently announcedwhich adopting countries have been required to implement national programs to reduce greenhouse gas emissions. The 2015 United Nations Climate Change Conference in Paris Agreement.did not result in an agreement that directly limits greenhouse gas emissions from ships. As of January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted by the IMO’s Maritime Environment Protection Committee or MEPC,(the "MEPC") in July 2011, relating to greenhouse gas emissions.
All ships are required to follow the Ship Energy Efficiency Management Plans, or SEEMP, and minimum energy efficiency levels per capacity mile, outlined in the Energy Efficiency Design Index, or EEDI, applies to all new ships. These requirements could cause the Company to incur additional compliance costs. The IMO is planning to implement market-based mechanisms to reduce greenhouse gas emissions from ships at an upcoming MEPC session. The European Union is pursuing a strategyhas indicated that it intends to integrate maritime emissions intopropose an expansion of the overall European Union strategyexisting EU Emissions Trading Scheme to reduce greenhouse gas emissions. In accordance with this strategy, in April 2015 the European Parliament and Council adopted regulations requiring large vessels using European Union ports to monitor, report and verify their carbon dioxide emissions beginning in January 2018. In the United States, 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, such regulation of drilling units is foreseeable, and the EPA has in recent years received petitions from the California Attorney General and various environmental groups seeking such regulation. In June 2014, the Supreme Court overturned the EPA “Tailoring Rule,” which required a Title V permit for statutory sources based on potentialinclude emissions of greenhouse gases. The Supreme Court also ruled, however, that EPA properly determined that Best Available Control Technology requirements for greenhouse gases would apply to sources that require Title V permits based on potential to emit conventional pollutants.

from marine vessels.
Compliance with changes in laws, regulations and obligations relating to climate change could increase the Company'sour costs related to operating and maintaining the Company'sour assets, and might also require the Companyus to install new emission controls, acquire allowances or pay taxes related to the Company'sour greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. Any passage of climate control legislation or other regulatory initiatives by the IMO, the European Union, the United States or other countries in which we operate, or any treaty adopted at the international level, which restricts emissions of greenhouse gases, could require us to make significant financial expenditures which we cannot predict with certainty at this time.
Additionally, adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also adversely affect demand for the Company'sour services. For example, the recent Paris Agreement could lead to increased regulation of greenhouse gases or other concerns relating to climate change which may in turn reduce the demand for oil and gas in the future or create greater incentives for the use of alternative energy sources. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on the Company'sour business, including capital expenditures to upgrade the Company'sour drilling units, that the Companyrigs, which we cannot predict with certainty at this time.
The aftermathIn addition, some scientists have concluded that increasing concentrations of the moratorium on offshore drillinggreenhouse gases in the U.S. Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout, could negatively impact us.
In the near-term aftermath of the Deepwater Horizon Incident, in which the Company was not involved,Earth's atmosphere may produce climate changes that led to the Macondo well blow out situation, the U.S. government on May 30, 2010 imposed a six-month moratorium on certain drilling activities in water deeper than 500 feet in the U.S. Gulf of Mexico and subsequently implemented Notices to Lessees 2010-N05 and 2010-N06, providing enhanced safety requirements applicable to all drilling activity in the U.S. Gulf of Mexico, including drilling activities in water shallower than 500 feet. On October 12, 2010, the U.S. government lifted the moratorium subject to compliance with the requirements set forth in Notices to Lessees 2010-N05 and 2010-N06. Additionally, all drilling in the U.S. Gulf of Mexico must comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management Systems and various requirements imposed through Notices to Lessees and Operators (SEMS). Operators were required to implement a SEMS program by November 15, 2011 and submit their first completed SEMS audit to the Bureau of Safety and Environmental Enforcement, or BSEE, by November 15, 2013. The original SEMS rule was later modified by the SEMS II final rule which became effective June 4, 2013. SEMS II enhanced and supplemented operators' SEMS programs with employee training, empowering field level personnel with safety management decisions and strengthening auditing procedures by requiring them to be completed by independent third parties. Operators had until June 4, 2014 to comply with SEMS II, except for certain auditing requirements. All SEMS audits must comply with SEMS II by June 4, 2015. The U.S. Occupational Safety and Health Act (OSHA) imposes additional recordkeeping obligations concerning occupational injuries and illnesses for MODUs attached to the outer continental shelf.
In addition, 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,significant physical effects, such as the American Petroleum Institute Standard 53 relating to the installationincreased frequency and testingseverity of well control equipment. Likewise, in August 2014, BSEE proposed an Advanced Notice of Proposed Rulemaking proposing variations to the permitting program that would bolster the offshore financial assurance and bonding program. In addition, BOEM and BSEE have announced several proposed rules and programs in 2015 intended to prevent releases and better protect human safety and the environment. In April 2016, the BSEE issued a final rule on well control regulations that set new and revised safety and operational standards for owners and operators of offshore wells and facilities. Among other requirements, the new regulation sets standards for blow-out preventers that include baseline requirements for their design, manufacture, inspection and repair, requires third-party verification of the equipment, and calls for real-time monitoring of certain drilling activities, to name just a few of the many requirements. For further details on new safety requirements, see Item 4 “Information on the Company-Business Overview-Environmentalstorms, floods and other Regulations in the Offshore Drilling Industry-Safety Requirements.” These new and proposed guidelines and standards for safety, environmental and financial assurance andclimate events. If any other new guidelines or standards the U.S. government or industry may issue or any other steps the U.S. government or industry may take, are anticipated by many in industrysuch effects were to significantly increase the costs of exploration and production offshore and are likely to, 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.
The Company continues to evaluate these new measures to ensure that its drilling units and equipment are in full compliance, where applicable. As new standards and procedures are being integrated into the existing framework of offshore regulatory programs, the Company anticipates that there may be increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as recompletions, workovers and abandonment activities.
Additional requirements could be forthcoming based on further recommendations by regulatory agencies investigating the Macondo incident. The Company is 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 operation and the technical specification required for offshore rigs to operate in the U.S. Gulf of Mexico. It is possible that short-term potential migration of rigs from the U.S. Gulf of Mexico could adversely impact dayrates levels and fleet utilization in other regions. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of the Company’s operations, and escalating costs borne by its customers, along with permitting delays, could reduce exploration and development activity in the U.S. Gulf of Mexico and, therefore, reduce demand for the Company’s services. In addition, insurance costs across the industry have increased as a result of the Macondo incident and, in the future, certain insurance coverage is likely to become more costly, and may become less available or not available at all. The Company cannot predict if the U.S. government will issue new drilling permits in a timely manner, nor can the Company predict the potential impact of new regulations that may be forthcoming as the investigation into the Macondo well incident continues. Nor can the Company predict if implementation of additional regulations might subject the Company to increased costs of operating and/or a reduction in the area of operation in the U.S. Gulf of Mexico. As such, the Company's

cash available for distribution and financial position could be adversely affected if the Company's drilling unit operating in the U.S. Gulf of Mexico became subject to the risks mentioned above.
The Company's ability to operate its drilling units in the U.S. Gulf of Mexico could be restricted by governmental regulation
Hurricanes have from time to time caused damage to a number of unaffiliated drilling units in the U.S. Gulf of Mexico. The Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, formerly the Minerals Management Service of the U.S. Department of the Interior, effective October 1, 2011, reorganized into two new organizations, the Bureau of Ocean Energy Management, or BOEM, and BSEE, and issued guidelines for tie-downs on drilling units and permanent equipment and facilities attached to outer continental shelf production platforms, and moored drilling unit fitness. BSEE subsequently issued additional guidelines requiring Mobile Offshore Drilling Units (MODUs) to be outfitted with Global Positioning Systems (GPS) and to provide BSEE with real-time GPS location data for MODUs effective March 19, 2013.These guidelines effectively impose new requirements on the offshore oil and gas industry in an attempt to increase the likelihood of survival of offshore drilling units during a hurricane. The guidelines also provide for enhanced information and data requirements from oil and gas companies that operate properties in the U.S. Gulf of Mexico region of the Outer Continental Shelf. BOEM and BSEE may issue similar guidelines for future hurricane seasons and may take other steps that could increase the cost of operations or reduce the area of operations for the Company’s ultra-deepwater drilling units, thereby reducing their marketability. Implementation of new guidelines or regulations that may apply to ultra-deepwater drilling units may subject the Company to increased costs and limit the operational capabilities of its drilling units, although such risks to the extent possible should rest with the Company’s customers.
The Company cannot guarantee that the use of the Company’s drilling units will not infringe the intellectual property rights of others.
The majority of the intellectual property rights relating to the Company’s drilling units and related equipment are owned by its suppliers. In the event that one of the Company’s suppliers becomes involved in a dispute over infringement of intellectual property rights relating to equipment owned by the Company, it may lose access to repair services, replacement parts, or could be required to cease use of some equipment. In addition, the Company’s competitors may assert claims for infringement of intellectual property rights related to certain equipment on its drilling units and the Company may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of technology disputes involving the Company’s suppliers or competitorsoccur, they could adversely affect its financial results, operationsor delay demand for oil or gas, and cash available for distribution. The Company has provisions in some of its supply contracts which provide indemnity from the supplier against intellectual property lawsuits. However, the Company cannot be assured that these suppliers will be willing or financially able to honor their indemnity obligations, or guarantee that the indemnities will fully protect the Company from the adverse consequences of such technology disputes. The Company also has provisions in some of its customer contracts to require the customer to share some of these risks on a limited basis, but the Company cannot provide assurance that these provisions will fully protect the Company from the adverse consequences of such technology disputes.

Failure to comply with the U.S. Foreign Corrupt Practices Act or the UK Bribery Act could result in fines, criminal penalties, drilling contract terminations and an adverse effect on the Company's business.
The Company currently operates its drilling units in a number of countries throughout the world, including some with developing economies. Also, the Company's business with national oil companies and state or government-owned shipbuilding enterprises and financing agencies puts the Company in contact with persons who may be considered “foreign officials” or “foreign public officials” under the U.S. Foreign Corrupt Practices Act of 1977, or the FCPA, and the Bribery Act 2010 of the Parliament of the United Kingdom, or the UK Bribery Act, respectively. The Company is subject to the risk that the Company, the Company's affiliated entities or their respective officers, directors, employees and agents may take actions determined to be in violation of such anti-corruption laws, including the FCPA and the UK Bribery Act. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of the Company’s operations in certain jurisdictions, and mightthereby adversely affect the Company's business, results of operationsdemand for our services, or financial condition. In addition, actualcause us to incur significant costs in preparing for or alleged violations could damage the Company's reputation and abilityresponding to do business. Furthermore, detecting, investigating and resolving actual or alleged violations would be expensive and consume significant time and attention of the Company's senior management.
In order to effectively compete in some foreign jurisdictions, the Company utilizes local agents and/or establishes joint ventures with local operators or strategic partners. For example, in Nigeria, Nigerian investors have invested in a subsidiary of Seadrill Operating LP that is fully controlled and approximately 56% owned by Seadrill Operating LP, and has resulted in a Nigerian joint venture partner owning an effective 1% interest in the West Capella. Seadrill owns the remaining ownership interest in the joint venture. All of these activities involve interaction by the Company's agents with non-U.S. government officials. Even though some of the Company's agents and partners may not themselves be subject to the FCPA, the UK Bribery Act or other anti-bribery laws to which the Company may be subject, if the Company's agents or partners make improper payments to non-U.S. government officials in connection with engagements or partnerships with the Company, the Company could be investigated and potentially found liable for violation of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on the Company's business, financial position, results of operations and cash flows.those effects.
Acts of terrorism, piracy, andcyber-attack, political and social unrest could affect the Company specifically or, more generally, the markets for drilling services, which may have a material adverse effect on the Company'sour 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. the Company’sOur drilling operations maycould also be targeted by acts of terrorism, piracy, or acts of vandalism or 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 political 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. The Company’s insuranceInsurance premiums could also increase as a result of these events, and coverage may be unavailable in the future. Increased insurance costs or increased costs of compliance with applicable regulations may have a material adverse effect on our results of operations.
We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.
We are currently involved in various litigation matters, and we anticipate that we will be involved in litigation matters from time to time in the future. For example, we are currently involved in litigation regarding the West Leo in which the customer is withholding payment for our services. This has adversely affected and may continue to adversely affect our revenues. Also, the operating hazards inherent in our business expose us to litigation, including personal injury litigation, environmental litigation, contractual litigation with customers, intellectual property litigation, tax or securities litigation and maritime lawsuits, including the possible arrest of our drilling units. We may be subject to significant legal costs in defending any legal actions, which we may or may not be able to recoup depending on the results of such claim. We cannot predict with certainty the outcome or effect of any claim or other litigation matter, or a combination of these. If we are involved in any future litigation, or if our positions concerning current disputes are found to be incorrect, there may be an adverse effect on our business, financial position, results of operations and available cash, because of potential negative outcomes, the costs associated with asserting our claims or defending such lawsuits, and the diversion of management’s attention to these matters.
For additional information regarding litigation matters that we are currently involved in, please see "Item 8. Financial Information-A. Consolidated Statements and Other Financial Information-Legal Proceedings".

Any failureWe 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 comply withour drilling units and related equipment are owned by our suppliers. In the complex lawsevent 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 regulations governing international tradewe 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 Company'ssupplier against intellectual property lawsuits. However, we cannot make any assurances that these suppliers will have sufficient financial standing to honor their indemnity obligations, or guarantee that the indemnities will fully protect us from the adverse consequences of such technology disputes. We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but we cannot provide assurance that these provisions will fully protect us from the adverse consequences of such technology disputes. For information on certain intellectual property litigation that we are currently involved in, please see “Item 8. Financial Information-A. Consolidated Statements and Other Financial Information-Legal Proceedings".
The failure to consummate or integrate acquisitions in a timely and cost-effective manner could have an adverse effect on our financial condition and results of operations.
The shipmentWe 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 goods, servicesits 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 technology across international borders subjectsinvestment opportunities may not result in the Company's businessconsummation of a transaction. In addition, we may not be able to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in eachobtain 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 countriestrading price of operation. Moreover, many countries,its common units. Our future acquisitions could present a number of risks, including the United States, controlrisk of incorrect assumptions regarding the exportfuture 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 re-exporttimely integrate the operations or management of certain goods, servicesany acquired businesses or assets and technologythe 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 impose related export record keeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions, in particular, are targeted against countries (such as Russia, Venezuela, Iran, Myanmar and Sudan, among others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.
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 interpretedintegrate its acquisitions in a timely and cost-effective manner, materially impacting the Company's operations. Shipments canits financial condition, results of operations and cash available for distribution could be delayed and denied export or entry for a variety of reasons, some of which are outside the Company's control and some of which may result from 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, and seizure of shipments and loss of import and export privileges.adversely affected.
Public health threats could have an adverse effect on the Company'sour operations and the Company's financial results.
Public health threats, such as ebola,Ebola, influenza, Severe Acute Respiratory SyndromeSARS, 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 the Company operates,we operate, could adversely impact the Company'sour operations, and the operations of the Company'sour customers. In addition, public health threats in any area, including areas where the Company doeswe do not operate, could disrupt international transportation. The Company'sOur 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 the Company'sour crews, and possibly impact the Company'sour ability to maintain a full crew on all rigs.rigs at a given time. Any of these public health threats and related consequences could adversely affect the Company'sour financial results.
A cyber-attackData 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 disruptand 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 Company'sjurisdictions 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 Company relies on information technology systemsmarket price of our common units has fluctuated widely and networks,may fluctuate widely in the majorityfuture
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 provided by Seadrill, in its operations and administration of its business. The Company's drilling operations or other business operations, or those of Seadrill, could be targeted by individuals or groups seeking to sabotage or disrupt the Company's or Seadrill's information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt the Company's operations, including the safety of its operations, or lead to unauthorized release of information or alteration of information on its systems. Any such attack or other breach of the Company's information technology systems could have a material adverse effect on the Company's business and results of operations.
Webeyond our control. Further, there may be subjectno 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 litigation, arbitration and other proceedings thatcomplete a transaction in the common units, which could have an adverse effect on the realized price of the common units. In addition, an adverse development in the market price for our common units could negatively affect our ability to issue new equity to fund our activities. For our common unit price history, refer Item 9A "Offer and Listing Details".
Increases in interest rates may cause the market price of our common units to decline.
An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline.
Because our ownership interest in OPCO currently represents our only cash-generating asset, our cash flow depends completely on OPCO’s ability to make distributions to its owners, including us.
Our cash flow depends completely on OPCO’s distributions to us. The amount of cash OPCO distributes may fluctuate from quarter to quarter based on our operational and financial performance which is subject to the risk factors set out above, "Risks Relating to our Company".
The Companyactual amount of cash OPCO has available for distribution also depends on our cash flow which is currently involvedsubject 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 various litigation matters, nonethe 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:
interest expense and principal payments on any indebtedness we may incur;
restrictions on distributions contained in any of our current or future debt agreements;
fees and expenses of us, the Seadrill Member, its affiliates or third parties we are required to reimburse or pay; and
reserves the Board believes are prudent for us to maintain for the proper conduct of our business or to provide for future distributions.
Many of these factors will reduce the amount of cash we may otherwise have available for distribution. We may not be able to pay distributions, and any distributions we make may not be at or above the minimum quarterly distribution. For example, beginning in February 2016, we ceased paying distributions on the subordinated units and reduced our quarterly distribution to common units below the minimum quarterly distribution. The actual amount of cash that is available for distribution to our unitholders depends on several factors, many of which are expectedbeyond 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 haveus 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 material adversedistribution 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 Company's financial condition. The Company anticipatespayment of distributions by OPCO to its equityholders. Moreover, our subsidiaries that it will be involved in litigation matters from time to timeare not organized in the future. The operating hazards inherent in the Company's business expose itMarshall Islands and are subject to litigation, including personal injury litigation, environmental litigation, contractual litigation with clients, intellectual property litigation, tax or securities litigation, and maritime lawsuits, including the possible arrestcertain restrictions on payment of the Company's drilling units. The Company cannot predict with certainty the outcome or effect of any claim or other litigation matter, or a combination of these. If the Company is involved in any future litigation, or if the Company's positions concerning current disputes are found to be incorrect, this may have an adverse effect on the Company's business, financial position, results of operations and available cash, because of potential negative outcomes, the costs associated with asserting the Company's claims or defending such lawsuits, and the diversion of management’s attention to these matters.

Risks Inherent in an Investment in Us
Seadrill and its affiliates may compete with us.
Pursuantdistributions pursuant to the Company's omnibus agreement, Seadrill and its controlled affiliates generally have agreed not to acquire, own, operate or contract for certain drilling units operating under drilling contractslaw of five or more years, unless Seadrill offers to sell such drilling units to us. The omnibus agreement, however, contains significant exceptions that may allow Seadrill or anytheir jurisdictions of its controlled affiliates to compete with the Company, which could harm the Company's business. Please read Item 7 “Major Unitholders and Related Party Transactions—Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Noncompetition.”organization.
UnitholdersOur common unitholders have limited voting rights and the Company's operating agreement restricts the voting rights of the unitholders owning more than 5% of the Company's common units.
Unlike the holders of common stock in a corporation, holders of common units have only limited voting rights on matters affecting the Company's business. The Company holds a meeting of the members every yearcompared to elect one or more members of the Company's board of directors 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 Company's board of directors. 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 the Company's 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 Memberwho 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 andfavor its affiliates, voting together as a single class.
The Company's 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 Company's 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 Company's board of directors are not be subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.
The Seadrill Member and its other affiliates own a substantial interest in the Company and have conflicts of interest and limited duties to the Company and the Company's common unitholders, which may permit them to favor their own interests to the detriment of the Company'scommon unitholders.
As of March 31, 2016,2018, Seadrill owned a 46.6% limited liability company interest in the Company,34.9% of our common units and 100% of our subordinated units, and owned and controlled the Seadrill Member. Certain of the Company'sour 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 the Companyus or the Company'sour unitholders. Conflicts of interest may arise between Seadrill and its subsidiaries on the one hand, and the Companyus and the Company'sour unitholders, on the other hand. AsAlthough a resultmajority of these conflicts, Seadrill and its subsidiaries may favor their own interests over the interests of the Company's unitholders. Please read “—The Company's operating agreement limits the dutiesour Board is elected by common unitholders, the Seadrill Member and the Company's directors and officers maywill likely have to the Company's unitholders and restricts the remedies available to unitholders for actions takensubstantial influence on decisions made by the Seadrill Member or the Company's directorsBoard. Refer to Item 7 "Major Unitholders and officers.” Related Party Transactions-Related Party Transactions".
These conflicts include, among others, the following situations:
neither the Company'sour operating agreement nor any other agreement requires the Seadrill Member or Seadrill or its affiliates to pursue a business strategy that favors the Companyus or utilizes the Company'sour 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 the Company'sour interests;
the Company'sour operating agreement provides that the Seadrill Member may make determinations to take or decline to take actions without regard to the Company'sinterests of us or the Company's unitholders’ interests.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 the company,us, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to the Company'sour operating agreement that require a vote of the outstanding units, voluntarily withdraw from the company,us, transfer (to the extent permitted under the Company'sour operating agreement) or refrain from transferring its units, the Seadrill Member interest or incentive distribution rights or vote upon the dissolution of the company;our dissolution;
the Seadrill Member and the Company'sour 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 the Company'sour 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 the Company'sour directors and officers, all as set forth in the operating agreement;
the Seadrill Member is entitled to reimbursement of all costs incurred by it and its affiliates for the Company'sour benefit;
the Company'sour operating agreement does not restrict the Companyus from paying the Seadrill Member or its affiliates for any services rendered to the Companyus on terms that are fair and reasonable or entering into additional contractual arrangements with any of these entities on the Company's behalf;entities;
the Seadrill Member may exercise its right to call and purchase the Company'sour common units if it and its affiliates own more than 80% of the Company'sour common units; and
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.
Although a majorityThe resolution of these conflicts may conflict with our interests and the Company's directors are elected by common unitholders, the Seadrill Member will likely have substantial influence on decisions made by the Company's boardinterests of directors. Please read Item 7 “Major Unitholders and Related Party Transactions—Related Party Transactions”our unitholders.
Although the Company controlswe control OPCO, the Company oweswe owe duties to OPCO and its other owner, Seadrill, which may conflict with our interests and the interests of the Company and the Company'sour unitholders.
Conflicts of interest may arise as a resultbecause of the relationships between the Companyus and the Company'sour 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. The Company'sOur directors have duties to manage OPCO in a manner beneficial to us. At the same time, the Company'sour directors have a duty to manage OPCO in a manner beneficial to OPCO’s owners, including Seadrill. The Company's board of directors may resolve any such conflict and has broad

latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in the best interest of the Company or the Company's unitholders.
For example, conflicts of interest may arise in the following situations:
the allocation of shared overhead expenses to OPCObetween us and us;OPCO;
the interpretation and enforcement of contractual obligations between the Companyus and the Company'sour affiliates,
on the one hand, and OPCO or its subsidiaries, on the other hand;
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;
the decision as to whether OPCO should make asset or business acquisitions or dispositions, and on what terms;
the determination of the amount and timing of OPCO’s capital expenditures;

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
any decision the Company makeswe make to engage in business activities independent of, or in competition with, OPCO.
CertainThe resolution of the Company's officers facethese conflicts in the allocation of their time to the Company's business.
Certain of the Company's officers are not required to work full-time on the Company's affairs and also perform services for other companies, including Seadrill. For example, Mark Morris, who is the Company's Chief Executive Officer, also acts as the Chief Financial Officer for Seadrill. In addition, John Roche, who is the Company's 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 the Company has no economic interest. As a result, there could be material competition for the time and effort of the Company's officers who also provide services to other companies, which could have a material adverse effect on the Company's business, results of operations and financial condition. Please read Item 6 “Directors, Senior Management and Employees—Directors and Senior Management—Executive Officers—Allocation of Executive Officers’ Time.”
The Company's operating agreement limits the duties the Seadrill Membermay conflict with our interests and the Company's directors and officers may have to the Company's unitholders and restricts the remedies available to unitholders for actions taken by the Seadrill Member or the Company's directors and officers.
The Company's operating agreement provides that the Company's boardinterests of directors has the authority to oversee and direct the Company's 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, the Company's operating agreement contains provisions that reduce the standards to which the Seadrill Member and the Company's directors and the Company's officers may otherwise be held by Marshall Islands law. For example, the Company's operating agreement:
provides that the Seadrill Member may make determinations or take or decline to take actions without regard to the Company's or the Company's unitholders’ interests. 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 the Company, the Company's affiliates or the Company's 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 of the company, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to the Company's operating agreement that require a vote of the outstanding units, voluntarily withdraw from the company, transfer (to the extent permitted under the Company's operating agreement) or refrain from transferring its units, the Seadrill Member interest or incentive distribution rights or vote upon the dissolution of the company;
provides that the Company's directors and officers are entitled to make other decisions in “good faith,” meaning they believe that the decision is in the Company's best interests;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Company's board of directors and not involving a vote of unitholders must be on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to the Company and that, in determining whether a transaction or resolution is “fair and reasonable,” the Company's board of directors 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 the Company's officers or the Company's directors will be liable for monetary damages to the Company, the Company's 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, the Company's 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 an officer or director of us. The fact that an officer or director of the Company 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 of the Company with such individual’s duty to the Company should not result in a violation of such individual’s duties to Seadrill.

In order to become a member of the Company, a common unitholder is required to agree to be bound by the provisions in the operating agreement, including the provisions discussed above.
Fees and cost reimbursements, which Seadrill Management and certain other subsidiaries of Seadrill determine for services provided to the Company, OPCO, and its subsidiaries, will be substantial, will be payable regardless of the Company's profitability and will reduce the Company's cash available for distribution to the Company'sour unitholders.
Pursuant to the advisory, technical and administrative services agreements, OPCO pays fees for services provided to OPCO and its subsidiaries by certain subsidiaries of Seadrill, and the Company and its subsidiaries reimburse these entities for all expenses they incur on their behalf. These fees and expenses include all costs and expenses incurred in providing certain advisory, technical and administrative services to the OPCO’s subsidiaries.
In addition, pursuant to the management and administrative services agreement Seadrill Management provides the Company with significant management, administrative, financial and other support services and/or personnel. The Company reimburses Seadrill Management for the reasonable costs and expenses incurred in connection with the provision of these services. In addition, the Company pays Seadrill Management a management fee.
There is no cap on the amount of fees and cost reimbursements that OPCO and its subsidiaries may be required to pay such subsidiaries of Seadrill pursuant to the advisory, technical and administrative service agreements, or that the Company may be required to pay under the management and administrative services agreement. For a description of the advisory, technical and administrative services agreements and the management and administrative services agreements, please read Item 7 “Major Unitholder and Related Party Transactions—Related Party Transactions.” The fees and expenses payable pursuant to the advisory, technical and administrative service agreements and the management and administrative services agreement will be payable without regard to the Company's 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 the Company's ability to pay cash distributions the Company's unitholders.
The Company'sOur operating agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove the Company'sour 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 the Companyus is decreased; all of which could diminish the trading price of the Company'sour common units.
The Company'sOur operating agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove the Company'sour current management or the Seadrill Member.
•
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 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove the Seadrill Member. As of March 31, 2016,
The unitholders are unable to remove the Seadrill Member without its consent because the Seadrill Member and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units voting together as a single class is required to remove the Seadrill Member. As of March 31, 2018, Seadrill owned 46.6% of the outstanding common and subordinated units.
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 the Company haswe 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 the Companyus or itsour 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 the Company'sour 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.
Common unitholders are entitled to elect onlyup to four of the seven members of the Company's board of directors.Board. The Seadrill Member in its sole discretion appoints the remaining three directors.
Election of the four directors elected by unitholders is staggered, meaning that the members of only one of three classes of the Company'sour elected directors are selected each year. In addition, the directors appointed by the Seadrill Member serve for terms determined by the Seadrill Member.
The Company'sOur operating agreement contains provisions limiting the ability of unitholders to call meetings of unitholders, to nominate directors and to acquire information about the Company'sour operations as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
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 Company's board)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 Company's board of directorsBoard are not subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.
There are no restrictions in the Company'sour operating agreement on the Company'sour 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 agreements provide that we approve the amount of reserves from OPCO’s cash flow that will be retained by OPCO to fund its future operating and capital expenditures. Our operating agreement requires the Board to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating and capital expenditures. These reserves also affect the amount of cash available for distribution by OPCO to us, and by us to unitholders. In addition, the Board may establish reserves for distributions on the subordinated units, but only if those reserves do not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters. Our operating agreement requires the Board each quarter to deduct from operating surplus estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, which could reduce the amount of available cash for distribution. The controlamount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by the Board at least once a year, provided that any change must be approved by the conflicts committee of the Board.
Unitholders have limited voting rights, and our operating agreement restricts the voting rights of the unitholders owning more than 5% of our common units.
Unlike the holders of common stock in a corporation, holders of common units have only limited voting rights on matters affecting our business. We hold a meeting of the members every year to elect one or more members of the Board and to vote on any other matters that are properly brought before the meeting. Common unitholders are entitled to elect only four of the seven members of the Board. The elected directors are elected on a staggered basis and serve for three year terms. The Seadrill Member in its sole discretion appoints the remaining three directors and sets the terms for which those directors will serve. The operating agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Unitholders have no right to elect the Seadrill Member, and the Seadrill Member may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding common and subordinated units, including any units owned by the Seadrill Member and its affiliates, voting together as a single class.
Our operating agreement further restricts unitholders’ voting rights by providing that if any person or group owns beneficially more than 5% of any class of units then outstanding, any such units owned by that person or group in excess of 5% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to the Board), determining the presence of a quorum or for other similar purposes, unless required by law. The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of all classes of units entitled to vote. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of the Board are not be subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.
Our operating agreement may limit the duties of the Seadrill Member and our directors and officers to our unitholders and restricts the remedies available to our unitholders for actions taken by the Seadrill Member or our directors and officers.
Our operating agreement provides that the Board has the authority to oversee and direct our operations, management and policies on an exclusive basis. The Marshall Islands Act states that a member's or manager’s "duties and liabilities may be transferredexpanded 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;
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.
Seadrill’s ownership interest in us could decrease, and substantial future sales of our common units, could lead to a third party without unitholder consent.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, the Company'sour 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.

If the Companyceases to control OPCO, the Company may be deemed to be an investment company under the Investment Company Act of 1940.
If the Company ceases to manage and control OPCO and is deemed to be an investment company under the Investment Company Act of 1940 because of the Company's ownership of OPCO interests, the Company would eitherWe have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify the Company's organizational structure or the Company's contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit the Company's ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from the Company's affiliates, restrict the Company's ability to borrow funds or engage in other transactions involving leverage, and require the Company to add additional directors who are independent of the Company or the Company's affiliates.
Substantial future sales of the Company's common units in the public market could cause the price of the Company's common units to fall.
The Company has granted registration rights to Seadrill and certain of its affiliates. These unitholders have the right, subject to some conditions, to require the Companyus to file registration statements covering any of the Company'sour common, subordinated or other equity securities owned by them or to include those securities in registration statements that the Companywe may file for the Company or other unitholders.file. As of March 31, 2016,2018, Seadrill owned 26,275,750 common units and 16,543,350 subordinated units and all of the incentive distribution rights (through its ownership of the Seadrill Member). Following their registration and sale under an applicable registration statement, those securities will become freely tradable. By exercising their registration rights and selling a large number of common units or other securities, these unitholders could cause the price of the Company'sour 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 the Companyus 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 Company's board of directorsBoard or holders of the Company'sour common units and subordinated units. This may result in lower distributions to holders of the Company's 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. The Company anticipatesWe 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 Company's 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 Company's common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had the Companywe 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.


The CompanyWe may issue additional equity securities, including securities senior to the common units, without the approval of the Company'sour unitholders, which wouldcould dilute the ownership interests of the Company'sour existing unitholders.
The CompanyWe may, without the approval of the Company'sour unitholders, issue an unlimited number of additional units or other equity securities. In addition, the Companywe may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. TheOur issuance by the Company of additional common units or other equity securities of equal or senior rank will have the following effects:
the Company'sour unitholders’ proportionate ownership interest in the Company will decrease;
the amount of cash available for distribution on each unit may decrease;
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 the Company'sour common unitholders will increase;
the relative voting strength of each previously outstanding unit may be diminished; and

the market price of the common units may decline.
Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.
During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3875$0.3875 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units. Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash. For a description of the subordination period, please seerefer Item 8. “Financial Information- Consolidated8A "Consolidated Statements and Other Financial Information-The Company's Cash Distribution Policy- Subordination Period.”
In establishing cash reserves, the Company's board of directors may reduce the amount of cash available for distribution to the Company's unitholders.
The OPCO’s operating agreements provide that the Company's board of directors approves the amount of reserves from the OPCO’s cash flow that will be retained by OPCO to fund its future operating and capital expenditures. The Company's operating agreement requires the Company's board of directors to deduct from operating surplus cash reserves that it determines are necessary to fund the Company's future operating and capital expenditures. These reserves also affect the amount of cash available for distribution by OPCO to the Company, and by the Company to the Company's unitholders. In addition, the Company's board of directors may establish reserves for distributions on the subordinated units, but only if those reserves do not prevent the Company from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters. As described above in “—Risks Inherent in The Company's Business— the Company must make substantial capital and operating expenditures to maintain the operating capacity of its fleet, which will reduce cash available for distribution. In addition, each quarter the Company is required to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted,” the Company's operating agreement requires the Company's board of directors 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 Company's board of directors at least once a year, provided that any change must be approved by the conflicts committee of the Company's board of directors.

Policy-Subordination Period".
The Seadrill Member has a limited call right that may require the Company'sour 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 the Company,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 the Company'sour 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 the Company'sour common units may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such common unitholders may also incur a tax liability upon a sale of their common units.
As of March 31, 2016,2018, Seadrill, which owns and controls the Seadrill Member, owned 34.9% of the Company'sour common units. At the end of the subordination period, assuming no additional issuances of common units and the conversion of the Company'sour subordinated units into common units, Seadrill would own 46.6% of the Company'sour common units.
The Company can borrow money to pay distributions, which would reduce the amount of credit available to operate the Company's business.
The Company's operating agreement allows the Company to make working capital borrowings to pay distributions. Accordingly, if the Company has available borrowing capacity, the Company can make distributions on all the Company's units even though cash generated by the Company's operations may not be sufficient to pay such distributions. Any working capital borrowings by the Company to make distributions will reduce the amount of working capital borrowings the Company can make for operating the Company's business. For more information, please read Item 5 “Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

Increases in interest rates may cause the market price of the Company's 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 the Company's common units. Any such increase in interest rates or reduction in demand for the Company's common units resulting from other relatively more attractive investment opportunities may cause the trading price of the Company's common units to decline.
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, the Companywe may not make a distribution to the Company'sour unitholders if at the time of the distribution, after giving effect to the distribution, all the Company’sour 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, of the Company, exceed the fair value of theour 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 theour assets of the Company 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 the companyus 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.
The Company has been organized asBecause 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 the RepublicMarshall 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 which does not haveand of other jurisdictions may prevent or restrict you from enforcing a well-developed bodyjudgment against our assets or the assets of limited liability company law.our directors or officers.
The Company's limited liability company affairs are governed by the Company's operating agreement and by the Marshall Islands Act. 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 such as the Company 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 stateState 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, the Companywe cannot predict whether Marshall Islands courts would reach the same conclusions as the courts in Delaware. For example, the rights of the Company'sour unitholders and the duties of the Seadrill Member and the Company'sour 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 the Company'sour officers and directors than would unitholders of a similarly organized limited liability company in the United States.
Because the Company is organized under the laws of the Marshall Islands, it may be difficult to serve the Company with legal process or enforce judgments against the Company, the Company's directors or the Company's management.
The Company is organized under the laws of the Marshall Islands, and substantially all of the Company's assets are located outside of the United States. In addition, the Seadrill Member is a Marshall Islands limited liability company, and the Company's 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 the Company 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 the Marshall Islands and of other jurisdictions may prevent or restrict you from enforcing a judgment against the Company's assets or the assets of the Seadrill Member or the Company's directors or officers.
The market price of our common units has recently declined significantly.  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 activitymaking-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.

Tax Risks
In additionThe delisting of our common units from the NYSE could lead to the following risk factors, you should read Item 4 “Information on the Company—Business Overview—Taxation of the Company,” and Item 10 “Additional Information—Taxation” for a more complete discussion of the expected material U.S. federal and non-U.S. income tax considerations relating to the Company and the ownership and disposition of the Company's common units.

The Company will be subject to taxes, which will reduce the Company's cash available for distribution to the Company's unitholders.
Some of the Company's subsidiaries will be subject to taxincrease in the jurisdictions in which they are organized or operate, reducing the amount of cash availableour U.S. federal income tax liability.
Our common units are currently listed on the NYSE. In order for distribution. In computingour common units to continue to be listed on the Company's tax obligation in these jurisdictions, the Company isNYSE, we are required to takecomply with various tax accounting and reporting positions on matters that are not entirely free from doubt and for whichlisting standards, including the Company has not received rulings frommaintenance 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 governing authorities. The Company cannot assure you that upon reviewclosing price of these positions the applicable authorities will agree with the Company's positions. A successful challenge by a tax authority could result in additional tax imposedour common units on the Company's subsidiaries, further reducing the cash available for distribution. In addition, changes in the Company's operations could result in additional tax being imposed on the Company or its subsidiaries in jurisdictions in which operations are conducted. Please read Item 4 “Information on the Company—Business Overview—Taxation of the Company.”
A change in tax laws in any country in which the Company operates could result in higher tax expense.
The Company conducts its operations through various subsidiaries. Tax laws and regulations are highly complex and subject to interpretation. Consequently, the Company is subject to changing tax laws, treaties and regulations in and between countries in which the Company operates. The Company's income tax expense is based on the Company's interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, treaties or regulations, or in the interpretation thereof,NYSE could result in a materially higher tax expensebreach of these requirements. Although we would have an opportunity to take action to cure such a breach, if we did not succeed, the NYSE could commence suspension or delisting procedures in respect of our common units. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. Under certain circumstances, a higher effective tax rate on the Company's earnings. For example, the Nigerian tax regime was recently changed from a deemed profit percentage of revenue to an actual profit regime, using 30% of net income. This change required the Company to book a deferred tax liability in the third quarter of 2015 which is expected to reverse in approximately 2020. Other such changes may include measures enacted in response to the ongoing initiatives in relation to fiscal legislation at an international level, such as the Action Plan on Base Erosion and Profit Shifting of the Organization for Economic Co-operation and Development.
The Company files periodic tax returns that are subject to review and audit by various revenue agencies in the jurisdictions in which the Company operates. Taxing authorities may challenge any of the Company's tax positions, at which time the Company will contest such assessments where the Company believes the assessments are in error. Determinations by such authorities that differ materially from the Company's recorded estimates, favorably or unfavorably, may have a material impact on the Company's results of operations, financial position or cash available for distribution.
A loss of a major tax dispute or a successful tax challenge to the Company's operating structure, intercompany pricing policies or the taxable presence of the Company's subsidiaries in certain countriesdelisting could result in a highermaterial increase in the amount of our U.S. federal income tax rate on the Company's worldwide earnings,liability, which could result in a significant negative impact on the Company's earningswould adversely affect our financial position, results of operations and cash flows from operations.
The Company's income tax returns are subject to review and examination. The Company does not recognize the benefit of income tax positions the Company believes are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges the Company's operational structure, intercompany pricing policies or the taxable presence of the Company's subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to the Company's structure; or if the Company loses a material tax dispute in any country, the Company's effective tax rate on the Company's worldwide earnings could increase substantially and the Company's earnings and cash flows from operations could be materially adversely affected.flows.
U.S. tax authorities couldmay treat the Companyus as a “passive"passive foreign investment company,” which would have adverse U.S. federal income tax consequences to U.S. unitholders.
A non-U.S. entity treated as a corporationcompany" 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"passive foreign investment company,” or PFIC,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 “passive income”certain types of "passive income" or (2) at least 50% of the average value of itsthe corporation’s assets for any taxable year produce or are held for the production of “passivethose types of "passive income.”" For purposes of these tests, “passive income”"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.”"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 interestsunits in the PFIC.
Based on the Company's current and projected methodanticipated valuation of operation, the Company believesour assets, including goodwill, and composition of our income and assets, we believe that it was not a PFIC for the Company's 2015 taxable year, and the Company expects that the Companywe will not be treated as a PFIC for theU.S. federal income tax purposes for our current or any future taxable year. The Company expects that more than 25% of the Company's gross income for the Company's 2015 taxable year arose and for the current and each future years 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 nonpassive income. Assuming the composition of the Company's income and assets is consistent with these expectations, the Company believes that the Company should not be a PFIC for the Company's 2015 taxable year or in the Company's current or any future year.

The conclusions that the Company has reached areforeseeable 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 freecontinue to be accurate. Moreover, as we have not sought a ruling from doubt and the U.S. Internal Revenue Service or(the "IRS"), on this matter, the IRS or a court could disagree with the Company'sour position. In addition, although the Company intendswe intend to conduct the Company'sour affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the Company cannot assure you that the nature of the Company'sour operations will notmay change in the future, or that the Company willand if so, we may not be aable to avoid PFIC status in the future.
If the IRS were to find that the Company iswe are or hashave been a PFIC for any taxable year (and regardless of whether the Company remainswe remain a PFIC for any subsequent taxable year), the Company'sour U.S. unitholders wouldmay face adverse U.S. federal income tax consequences.  Please readUnder 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—Material10E "Taxation"), such unitholders would be liable to pay U.S. Federal Income Tax Considerations—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 Taxationfederal income tax consequences as a result of U.S. Holders—PFIC Status and Significant Tax Consequences”investing in common units, this could adversely affect our ability to raise additional capital through the equity markets. See Item 10E "Taxation" for a more detailedcomprehensive discussion of the U.S. federal income tax consequences to U.S. unitholders if the Company iswe are treated as a PFIC.

Investors are encouraged to consult their own tax advisers concerning the overall tax consequences of the ownership of the common units arising in an investor’s particular situation under U.S. federal, state, local or foreign law.

Item 4.         Information on the Company


A.     History and Development of the Company
GeneralOverview
Seadrill Partners, LLC is a publicly traded limited liability companywas formed in the Marshall Islands on June 28, 2012 as limited liability company and a wholly owned subsidiary of Seadrill, Limited. to own, operate and acquire offshore drilling units. The Company completed its IPO and listed its common units on the New York Stock Exchange in October 2012 under the ticker symbol "SDLP". The company's principal executive headquarters are maintained at 2nd Floor, Building 11, Chiswick Businesses Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom. The Company's telephone number at that address is +44 20 8811 4700. The Company's agent for service of process in the United States is Watson Farley & Williams LLP and its address is 250 West 55th Street New York, New York 10019.
In connection with the Company's IPO, in October 2012, the Company acquired (i) a 30% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through the Company's 100% ownership of its general partner, Seadrill Operating GP LLC, and (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Immediately following the Company's IPO, Seadrill Operating LP owned (i) a 100% interest in the entities that own the West Aquarius and the West Vencedor and (ii) an approximate 56% interest in the entity that owns and operates the West Capella. In addition, immediately following the Company's IPO, Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn.
During Subsequent to the year ended December 31, 2013,IPO (i) the CompanyCompany’s wholly-owned subsidiary, Seadrill Partners Operating LLC, acquired from Seadrill (i) a 100% interest in two tender rigs,the entities that own the T-15 and the T-16, which the Company owns through its wholly owned subsidiary Seadrill Partners Operating LLC, (ii) a 51% indirect interest in the semi-submersible drilling rig the West Sirius, which the Company owns through Seadrill Capricorn Holdings LLC and (iii) a 30% indirect interest in the semi-submersible drilling rig, the West Leo, which the Company owns through Seadrill Operating LP.
As of January 2, 2014, the date of the date of the Company’s first annual general meeting, Seadrill ceased to control the Company as defined by generally accepted accounting principles in the United States, or GAAP, and, therefore, Seadrill Partners and Seadrill are no longer deemed to be entities under common control. As such, acquisitions by the Company from Seadrill subsequent to this date are no longer accounted for as transactions between parties under common control.

During the year ended December 31, 2014, the Company acquired from Seadrill (i) a 51% indirect interest in two drillships,the entities that own the West Auriga and West Vela, which(iii) Seadrill Operating LP acquired from Seadrill the entity that owns the West Polaris and (iv) the Company owns throughacquired from Seadrill Capricorn Holdings LLC, and (ii) an additional 28% limited partner interest in Seadrill Operating LP, bringing its total ownership in LP.
Seadrill Operating LP, to 58%.

During the year ended December 31, 2015, Seadrill Operating LP, a subsidiary in which the Company owns a 58% limited partner interest, acquired from Seadrill all of the shares of Seadrill Polaris Ltd. ("Seadrill Polaris"), the entity that owns and operates the drillship the West Polaris from Seadrill.

Overview
The Company is a limited liability company formed by Seadrill to own, operate and acquire offshore drilling units. The Company's drilling units are under contracts with major oil companies such as Chevron, Tullow, BP and ExxonMobil with an average remaining term of 2.4 years as of March 31, 2016.
On October 24, 2012, the Company completed its IPO and in connection with the Company's IPO, the Company issued 10,062,500 common units to the public (including 1,312,500 common units pursuant the underwriter’s option to purchase additional common unit in full) at a price of $22.00 per common unit and issued to Seadrill 14,752,525 common units and 16,543,350 subordinated units. In addition, the Company 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.
In connection with the Company's IPO, the Company acquired (i) a 30% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through the Company's 100% ownership of its general partner, Seadrill Operating GP LLC, and (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. The Company controls Seadrill Operating LP through the Company's ownership of its general partner and Seadrill Capricorn Holdings LLC through the Company's ownership of the majority of the limited liability company interests.
On May 17, 2013, the Company's wholly-owned subsidiary,and Seadrill Partners Operating LLC acquired from Seadrill a 100% ownership interest in the entities that own and operate the tender rig the T-15. On October 18, 2013, Seadrill Partners Operating LLC, acquired from Seadrill a 100% ownership interest in the entity that owns the tender rig the T-16. As consideration for the purchase of the T-16, the Company issued 3,310,622 common unitsare collectively referred to Seadrill.
On December 13, 2013, Seadrill Operating LP acquired (the “Leo Acquisition”) all of the ownership interests in each of the entities that own, operate and manage the semi-submersible drilling rig, West Leo (the “Leo Business”) and Seadrill Capricorn Holdings LLC acquired (the “Sirius

Acquisition”) all of the ownership interests in each of the entities that own and operate the semi-submersible drilling rig, West Sirius (the “Sirius Business”). The Leo Acquisition and the Sirius Acquisition were accomplished through a series of purchases and contributions. The implied purchase prices of the Leo Acquisition and the Sirius Acquisition were $1.250 billion and $1.035 billion, respectively, in each case, including working capital. The Company's portion of the purchase price after debt financing at the OPCO level for the Leo Acquisition was $229.4 million. In addition, the owner of the West Leo, Seadrill Leo Ltd., entered into a $485.5 million intercompany loan agreement with Seadrill, which was repaid in full in February 2014. The Company's portion of the purchase price after debt financing at the OPCO level for the Sirius Acquisition was $298.4 million. The Company funded $70 million of the $298.4 million purchase price by issuing a zero coupon discount note to Seadrill which was repaid in full in March 2014. Seadrill Hungary Kft., the owner of the West Sirius, entered into a $220.1 million intercompany loan agreement with Seadrill which was repaid in full in February 2014. In addition, Seadrill Capricorn Holdings LLC financed $229.9 million of the purchase price of the Sirius Acquisition by issuing a zero coupon discount note to Seadrill which was repaid in full in February 2014. As a result of these transactions, the Company acquired a (i) 30% indirect interest in the Leo Business and (ii) 51% indirect interest in the Sirius Business.
In order to fund the Company's portion of the purchase price for the Sirius Acquisition and Leo Acquisition, on December 9, 2013, the Company sold an aggregate of (i) 12,880,000 common units to the public at a price of $29.50 per unit and (ii) 3,394,916 common units to Seadrill in a concurrent private placement at a price of $29.50 per unit. The aggregate net proceeds from these offerings were approximately $464.8 million.
The transactions described above that occurred through December 31, 2013, have been reflected as a reorganization of entities under common control and, therefore, the assets and liabilities acquired from Seadrill have been recorded at historical cost by the Company and the historical operating results have been retrospectively adjusted to include the results of the combined entities during the periods they were under common control of Seadrill."OPCO".
As of January 2, 2014, the date of the Company’s first annual general meeting, Seadrill ceased to control the Company in accordance with US GAAP and, therefore, the Company and Seadrill are no longer deemed to be entities under common control.
On February 21, 2014, Seadrill Operating LP,owns the remaining interests in OPCO. As of March 31, 2018, Seadrill Capricorn Holdingsowned 34.9% of our common units and all of our subordinated units as well as Seadrill Member LLC, which owns the Seadrill Member interest, a non-economic interest in the Company, and all of our incentive distribution rights.
Management of the Company's new subsidiary,Company
Overall responsibility for the management of the Company and its subsidiaries rests with the Board. We are managed on a day to day basis by our executive officers, Mark Morris and John Roche, who are employees of Seadrill Partners Finco LLC (the “Borrowers”), entered into Senior Secured Credit Facilities (the “Senior Secured Credit Facilities”). The Senior Secured Credit Facilities consistand provide services to us under the terms of (i) a $100.0 million revolving credit facility (the “revolving facility”) availablemanagement and administrative services agreement. Seadrill also provides operational support and technical supervision services for borrowingour fleet and certain other management and administrative services.
Significant developments for the period from time to time by any Borrower, and (ii) a $1.8 billion term loan (the “term loan”) which was borrowed by Seadrill Operating LP in full on February 21, 2014. The proceeds from the transaction were used to (a) refinance debt secured by the January 1, 2015 through December 31, 2017
Acquisition of West Aquarius, West Capella, West Leo and West Sirius, (b) repay in part the Company's unsecured loans from Seadrill, (c) add cash to the balance sheet in support of general company purposes and (d) pay all fees and expenses associated therewith.Polaris
On March 24, 2014, Seadrill Capricorn Holdings LLC acquired from Seadrill allJune 19, 2015, we completed the purchase of 100% of the ownership interests in each of Seadrill Auriga Hungary Kft., a Hungarian company which owns the drillship, the West Auriga, and Seadrill Gulf Operations Auriga LLC, a Delaware limited liability company which operates the West Auriga (the "Auriga Acquisition"). The Auriga Acquisition was accomplished through a series of purchases and contributions. As a result of these transactions, the Company acquired a 51% indirect interest in the ownership and operations of the West Auriga. The implied purchase price of the Auriga Acquisition was $1.24 billion. The Company's portion of the purchase price for the Auriga Acquisition, after debt financing at the OPCO level, was $355.4 million. In addition, Seadrill Capricorn Holdings LLC financed $100.0 million of the purchase price by issuing a zero coupon limited recourse discount note to Seadrill that matured in September 2015. Upon maturity of such note, Seadrill Capricorn Holdings LLC was due to repay $103.7 million to Seadrill. This note was repaid in June 2014 with the proceeds of the Amended Senior Secured Credit Facilities. The purchase price was subsequently adjusted by a working capital adjustment of $330.4 million. The working capital adjustment predominately arose as a result of related party payable balances which remained in the acquired entities. These payable balances related to funding provided by Seadrill to the acquired entities for the construction, equipping and mobilization of the West Auriga.
Seadrill Auriga Hungary Kft. was a borrower under the $1.45 billion credit facility (the “Auriga Facility”) used to finance the West Auriga. As of the closing date of the Auriga Acquisition, Seadrill Auriga Hungary owed $443.1 million in principal under the Auriga Facility. In June 2014, this facility was refinanced with proceeds from the Amended Senior Secured Credit Facilities.
In order to fund the Company's portion of the cash purchase price of the Auriga Acquisition, on March 17, 2014, the Company issued an aggregate of 11,960,000 common units to the public and 1,633,987 common units to Seadrill at a price of $30.60 per unit.

On June 24, 2014, the Company issued 6,100,000 common units to the public and 3,183,700 common units to Seadrill at a price of $31.41 per unit.

On June 26, 2014, the Borrowers amended and restated their senior secured credit facilities (as amended and restated, the “Amended Senior Secured Credit Facilities”) to provide for the borrowing by Seadrill Operating LP of $1.1 billion of additional term loans, in addition to the $1.8 billion term loan already outstanding under the Senior Secured Credit Facilities. Thus, following the amendment and restatement, the Amended Senior Secured Credit Facilities consisted of (i) a $100.0 million revolving credit facility (the “revolving facility”) available for borrowing from time to time by any Borrower, and (ii) a $2.9 billion term loan (the “term loan”). The proceeds from the additional $1.1 billion of term loans were used to (a) refinance debt secured by the West Auriga of $443.1 million and the West Capricorn of $426.3 million, (b) repay in part certain of our unsecured loans from Seadrill in the amount of $100.0 million, (c) add cash to the Company’s balance sheet for general company purposes, (d) pay all fees and expenses associated with the Amended Senior Secured Credit Facilities and (e) partially fund the acquisition of an additional interest in Seadrill Operating LP discussed below.


On July 21, 2014, the Company acquired an additional 28% interest in Seadrill Operating LP from Seadrill Limited for $373 million, bringing its total ownership interest in Seadrill Operating LP to 58%.

On September 23, 2014, the Company issued 8,000,000 common units to the public at a price of $30.68 per unit.
On November 4, 2014, Seadrill Capricorn Holdings LLC acquired from Seadrill all of the ownership interests in each of Seadrill Vela Hungary Kft., a Hungarian company which owns the drillship, the West Vela, and Seadrill Gulf Operations Vela LLC, a Delaware limited liability company which operates the West Vela (the "Vela Acquisition"). The Vela Acquisition was accomplished through a series of purchases and contributions. As a result of these transactions, the Company acquired a 51% indirect interest in the ownership and operations of the West Vela. The implied initial purchase price of the Vela Acquisition was $900 million. The Company's portion of the initial purchase price for the Vela Acquisition, after debt financing at the OPCO level, was $238 million. Under the terms of the West Vela contract, the customer is paying a daily rate of $565,000, plus approximately $44,000 per day as a mobilization fee paid over the term of the contract. In addition to the initial purchase price, Seadrill Capricorn Holdings LLC will pay Seadrill $40,000 per day of day rate revenue actually received, as well as the $44,000 per day mobilization fee. These payments to Seadrill will cease at the end of the current contract. Thus, the total consideration included deferred consideration payable to Seadrill of $73.7 million and contingent consideration of $65.7 million. The purchase price was subsequently adjusted by a working capital adjustment of $6.0 million. The acquisition was financed with debt and $238 million in cash for the Company’s 51% equity share.

As of the closing date of the Vela Acquisition, Seadrill Vela Hungary Kft owed $433.1 million in principal under the Vela Facility. Seadrill Vela Hungary’s liability to repay debt under the Vela Facility that relates to the other rigs owned by Seadrill remains. However, Seadrill indemnified Seadrill Vela Hungary Kft. against any liability it may incur under the Vela Facility in respect of such debt. Unless the context requires otherwise, references in this section to the “Company” include OPCO and its subsidiaries.

On March 31, 2015 the Company received a notice of termination from BP for the contract for the West Sirius which became effective after having completed a well and demobilization in early May 2015. Prior to the cancellation notice, the dayrate and term for the West Sirius and West Capricorn contracts were swapped. The West Sirius dayrate was decreased by $40,000 per day and the term was decreased by two years to expire in July 2017 while the dayrate for the West Capricorn was increased by $40,000 per day and the term was extended by two years to expire in July 2019. Amortized payments for the West Capricorn such as mobilization and upgrades will continue on the original schedule ending in July 2017.  In accordance with the cancellation provisions in the West Sirius contract, the Company will receive termination payments over the remaining contract term, now expiring in July 2017.

On June 16, 2015, Seadrill Operating LP, a subsidiary in which the Company owns a 58% limited partner interest, entered into an agreement with Seadrill to acquire all of the shares of Seadrill Polaris Ltd. (“("Seadrill Polaris”Polaris"), the entity that owns and operates the drillship, the West Polaris (the “Polaris Acquisition”) from Seadrill. The Polaris Acquisition was completed on June 19, 2015. The West Polaris is a 6th generation, dynamically positioned drillship delivered from (the Samsung shipyard in 2008. The West Polaris is expected to carry out operations in Angola until the end of its contract with ExxonMobil in March 2018.

"Polaris Acquisition"). The consideration for the Polaris Acquisitionacquisition included both upfront and contingent elements. The upfront consideration was comprised of $204$204.0 million inof cash and $336$336.0 million of debt outstanding under the existing credit facility financing the West Polaris. In addition Seadrill Operating LP issuedPolaris.
The contingent consideration included a note (the “Seller’s credit”)payable to Seadrill of $50 million to Seadrill, repayment("Seller's Credit"), payment of which is contingent on the future re-contracted dayrate for the West Polaris. The Seller's credit is due in 2021 Polaris, and bears an interest rate of 6.5% per annum. During the three-year period following the completiona share of the current drillingdayrate earned by the West Polaris over its contract with ExxonMobil ("Initial Earn-Out") and on subsequent contracts until March 2025 ("Subsequent Earn-Out").
Refer to Note 3 "Business acquisitions" to the Sellers's credit may be reduced ifConsolidated Financial Statements included in this annual report for more information on the average contracted dayrate (netPolaris Acquisition.
Drilling Contracts
The below table shows the status of commissions)our drilling contracts at March 31, 2018.

RigBuiltStatus at December 31, 2017CustomerContractual operating rate per day ($'000)Contracted until
Semi-submersible   
West Sirius2008Stacked---
West Aquarius2009Future contractBP$260.0Jul 2018
West Capricorn2011ContractedBP$525.0Jul 2019
West Leo2012Stacked---
      
Drillship     
West Capella2008Future contractRepsolNot disclosedJul 2018
West Polaris2008Stacked---
West Auriga2013ContractedBP$562.0Oct 2020
West Vela2013ContractedBP$564.0Nov 2020
      
Tender Rig     
West Vencedor2009Stacked---
T-152013ContractedChevron$110.0Jul 2019
T-162013ContractedChevron$110.0Aug 2019
The West Sirius operated under a contract with BP in the Gulf of Mexico until 2015, when it received a notice of termination. In accordance with the cancellation provisions in the contract, we received termination payments over the remaining contract term, which expired in July 2017.
The West Aquarius was on contract with Hibernia in Canada until April 2017. After a short period of idle time the rig then operated under a one-well contract with Statoil in Canada from May 2017 to July 2017. The rig has been warm stacked since July 2017 but has secured a one-well contract with BP Canada which commenced in April 2018.
The West Capricorn has been on contract with BP in the Gulf of Mexico since July 2012. The unit was placed on an extended standby rate of $315k per day from May 2016 to June 2017. In April 2017, we received a notification from BP for the period, adjustedunit to start preparing for utilization,a return to operations. The unit returned to normal contractual day rates in July 2017.
The West Leo operated under any replacementa contract is below $450,000with Tullow in Ghana until October 2016, when it received a notice of termination for force majeure. We have disputed the Seller’s credit’s maturitygrounds for termination and litigation proceedings are ongoing.
The West Capella was on contract with ExxonMobil in 2021. ShouldNigeria until May 2016, when it received a notice of termination. In accordance with the average dayratecancellation provisions in the contract, we received a termination fee of approximately $125 million, which was paid in two equal installments, plus other direct costs incurred as a result of the replacementtermination. In March 2017, we secured a one-well contract be above $450,000,for the entire $50 million Seller's credit must be paidWest Capella with Total in Cyprus, which operated from July 2017 to Seadrill upon maturitySeptember 2017. In May 2017, we secured a one-well contract plus the option for a further three optional wells with Petronas in Gabon. This contract started in October 2017 and completed in March 2018. In March 2018 we secured a one well contract with Repsol in Aruba which is expected to commence in June 2018.
The West Polaris was on contact with ExxonMobil in Angola until December 2017, when the rig completed its operations and demobilized. The rig is now stacked.
The West Auriga and West Vela have been on contract with BP in the Gulf of Mexico since October 2013 and November 2013 respectively.
The West Vencedor started work on a contract with ConocoPhillips in Indonesia in March 2017. In May 2017 Medco Energi acquired ConocoPhillips ownership interests in the Seller's creditoperating area and assumed the drilling contract. Medco Energi exercised 2 of a potential 7 optional wells under the contract. The contract ended in 2021.January 2018.

The T-15 and T-16 have been on contract with Chevron in Thailand since July 2013 and August 2013 respectively.
In addition, Seadrill Polaris may make further contingent payments to Seadrill based uponLitigation with Tullow for the West Polaris's operating dayrate. In FebruaryLeo
As set out above, we received a notice of force majeure in October 2016 for the West Leo 's contract with Tullow in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the West Polaris with ExxonMobil was amended to reducealternative, frustration of contract, or (c) in the dayrate to $490,000, effective January 1, 2016. Underfurther alternative, for convenience.
We do not accept that the contract has been terminated by the occurrence of force majeure under the terms of the acquisitiondrilling contract and/or that the contract has been discharged by frustration. Accordingly, we amended our claim in the English High Court to reflect this. In the event of termination for convenience, we are entitled to an early termination fee of 60% of the remaining contract backlog, subject to an upward or downward adjustment depending on the work secured for the West Leo over the remainder of the contract term, plus other direct costs incurred as a result of the early termination.

The total amount that we are seeking to recover is $278 million plus interest. The case is scheduled to be heard on May 8, 2018.
Seadrill restructuring
In September 2017, our largest unitholder, Seadrill, entered into a restructuring agreement with its secured lenders, bondholders and a consortium of investors. The agreement defers the maturity of Seadrill's secured bank debt by five years, delays amortization payments until 2020, converts bonds to equity and delivers new capital to Seadrill. To implement the restructuring agreement, Seadrill and certain of its subsidiaries (the "Debtors") have filed prearranged Chapter 11 cases in the Southern District of Texas together with a restructuring plan.  As part of the Chapter 11 cases, "first day" motions were granted that enabled Seadrill's day-to-day operations to continue as usual, including the provision of management services to the Company.
On February 26, 2018, the Debtors filed a proposed second amended plan of reorganization with the bankruptcy court. On April 9, 2018, Seadrill announced that the plan had received approval from each class of creditor and holder of interests that were entitled to vote on the plan. To become effective, the plan will now have to be approved by the bankruptcy court on a confirmation hearing scheduled for April 17, 2018. If the plan is confirmed at this hearing then it would become effective once all conditions precedent have been satisfied or waived. The Debtors would then emerge from Chapter 11 proceedings.
Insulation from events of default related to Seadrill's Chapter 11 filing
In August 2017, we completed amendments to our West Polaris, West Vela and Tender Rig facilities which insulated us from events of default related to Seadrill's use of Chapter 11 proceedings. We did not file any Chapter 11 cases. Our business operations have been largely unaffected by Seadrill's Chapter 11 filings.
Term Loan B covenant waiver
In February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). In connection with the waiver, the Company has agreed to pay Seadrill (a) any dayrate it receivescertain amendments, including but not limited to, increasing the applicable margin by 3%, a par prepayment contingent on the successful outcome of certain ongoing litigation, adding the West Vencedor as collateral and certain amendments relating to cash movements outside the TLB collateral group. Please read Note 11 "Debt" to the Consolidated Financial Statements included in excess of $450,000 per day, adjustedthis annual report for daily utilization, through the remaining term, without extension, of the ExxonMobil contract (the "Initial Earn-Out"), and (b) after the expiration of the term of the existing contract until March 2025, 50% of any such excess dayrate, adjusted for daily utilization. tax and agency commission (the "Subsequent Earn-Out").

The Company's interests in OPCO represent its only cash-generating assets. The Company manages its business and analyzes and reports its results of operations in a single global segment. The Company’s fleet is reviewed by the Chief Operating Decision Maker, which is the board of directors, as an aggregated sum of assets, liabilities and activities generating distributable cash to meet minimum quarterly distributions.

further details.
Capital Expenditures

We had total capitalCapital expenditures ofwere approximately $18.6$121.6 million, $31.6$61.1 million and $159.3$68.4 million in the years ended 2015, 20142017, 2016 and 20132015 respectively. Our capital expenditures relate primarily to capital additions andadditional equipment tofor our existing drilling units and payments for long term maintenance. We financed thisthese capital expenditureexpenditures through cash generated from operations and secured and unsecured debt arrangements and the sale of partial ownership interests in certain subsidiaries. Please refer to "Item 4.B "Information on the Company - Business Overview" for further information on the Company's fleet.

The Company listed its common units on the New York Stock Exchange in October 2012 under the ticker symbol “SDLP.”
The Company was formed under the laws of the Marshall Islands and maintain the Company's principal executive headquarters at 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom. The Company's telephone number at that address is +44 20 8811 4700. The Company's agent for service of process in the United States is Watson Farley & Williams LLP and its address is 250 West 55th Street New York, New York 10019.arrangements.

B.     Business Overview
General
The Company is
We are a limited liability company formed on June 28, 2012 by Seadrill Limited (NYSE: SDRL) to own, operate and acquire offshore drilling units. The Company'sOur fleet consists of drillships, semi-submersible rigs and tender rigs operating in benign and harsh environments. We contract our drilling units are under contracts with majorprimarily on a dayrate basis to oil companies such as Chevron, BP ExxonMobil and TullowChevron.
As of March 31, 2018, we owned and operated a fleet of four semi-submersible drilling rigs, four drillships and three tender rigs. We have one of the youngest rig fleets in the industry with an average remaining termfleet age of 2.4 years asapproximately 6.7 years.
Our Fleet
We believe that we have one of March 31, 2016.the most modern fleets in the offshore drilling industry. Details regarding the types of rigs we own and the contracts under which they operate are set forth below.
Semi-submersible drilling rigs
Semi-submersibles are self-propelled drilling rigs consisting of an upper working and living quarters deck connected to a lower hull consisting of columns and pontoons. Such rigs operate in a "semi-submerged" floating position, in which the lower hull is below the waterline and the upper deck protrudes above the surface. The Company’srig 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.
The following table provides additional information about our fleet as of March 31, 2016 consisted of:
2018:
the semi-submersible West Aquarius, which was delivered from the shipyard in 2009 and is currently operating under a drilling contract with ExxonMobil that expires in April 2017;
Rig
Seadrill Partners Ownership Interest (2)
Year BuiltWater
Depth
(feet)		Drilling
Depth
(feet)
Semi-submersible    
West Sirius51%200810,000
35,000
West Aquarius58%200910,000
35,000
West Capricorn51%201110,000
35,000
West Leo58%201210,000
35,000
     
Drillship    
West Capella (1)
33%200810,000
35,000
West Polaris58%200810,000
35,000
West Auriga51%201312,000
40,000
West Vela51%201312,000
40,000
     
Tender Rig    
West Vencedor58%20096,500
30,000
T-15100%20136,500
30,000
T-16100%20136,500
30,000
(1) We own 58% of Seadrill Operating LP, which controls and owns 56% of the semi-submersible West Capricorn, which was delivered fromentity that owns the shipyard in 2011 and is currently operating under a drilling contract with BP that expires in July 2019;
the semi-submersible West Leo, which was delivered from the shipyard in 2012 and is currently operating under a drilling contract with Tullow that expires in July 2018;
the semi-submersible West Sirius, which was delivered from the shipyard in 2008 and operated under a drilling contract with BP, which was terminated early in April 2015. The West Sirius is currently earning early termination fees until July 2017;
the semi-tender rig West Vencedor, which was delivered from the shipyard in 2010 and is currently operating under a drilling contract with Petronas that expires in July 2016;
the tender rig T-15, which was delivered from the shipyard in 2013 and is currently operating under a 5-year drilling contract with Chevron that expires in July 2019;
the tender rig T-16, which was delivered from the shipyard in 2013 and is currently operating under a 5-year drilling contract with Chevron that expires in August 2019;
the drillship West Auriga, which was delivered from the shipyard in 2013 and is currently operating under a drilling contract with BP that expires in October 2020;
the drillship West Vela, which was delivered from the shipyard in 2013 and is currently operating under a drilling contract with BP that expires in November 2020;
the drillship West Capella, which was delivered from.
(2) Seadrill owns the shipyard in 2008 and is currently operating under a drilling contract with ExxonMobil that expires in April 2017; and
the drillship West Polaris, which was delivered from the shipyard in 2008 and is currently operating under a drilling contract with ExxonMobil that expires in March 2018.
For more information about the Company's fleet, including the Company's ownership interestsremaining interest in each of theour rigs.
Our Competitive Strengths
We believe that our competitive strengths include:
Technologically advanced and young fleet
Our drilling units please see " - Fleetare among the most technologically advanced in the world. The majority of our rigs were built after 2008, and Customers" below.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.

Business Strategies

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
Continue cost-cuttingOver the past year, we have insulated ourselves from potential events of default related to Seadrill's use of Chapter 11 proceedings, extended the maturities of three credit facilities and deliver steady, stable cash flow

achieved a leverage covenant waiver on our $2.8 billion Term Loan B. We intendbelieve these agreements leave us well positioned to continue to implementoptimize our cost savings programof funding and drive operational efficiencies in order to reduce our cost base while maintaining our excellent operating performance. We made significant progress in 2015 in reducing capital and operating expenditures. In 2016, we will continue to focus on headcount reductions, insurance savings, supplier discounts, travel costs and compensation adjustments.

structure.
Longer term, the Company intends to accomplishwe have the following objectives:
• Grow Through Strategic and Accretive Acquisitions. The Company intendsWe intend to capitalize on opportunities to grow the Company'sour fleet of drilling units through further acquisitions of offshore drilling unitsunits. This may include further purchases from Seadrill either by the Company or by OPCO, and acquisitions of offshore drilling unitspurchases from third parties.
• Pursue Long-term Contracts and Maintain Stable Cash Flow. The Company seeksWe will continue to pursue long-term contracts to maintain stable cash flows by continuing to pursue long-term contracts. The Company's focus on long-term contracts improves the stability and predictability of the

Company'spredictable operating cash flows, which the Company believesflows. We believe that this focus will enable the Companyus to access equity and debt capital markets on attractive terms and, therefore, facilitate the Company'sour growth strategy.
• Provide Excellent Customer Service and Continue to Prioritize Safety as a Key Element of The Company's Operations. The Company believesWe believe that Seadrill has developed a reputation as a preferred offshore drilling contractor and that the Companywe can capitalize on this reputation by continuing to provide excellent customer service. The Company seeksWe seek to deliver exceptional performance to the Company'sfor 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. The Company hasWe have one of the youngest and most technologically advanced fleets in the industry, and plans to maintain a modern and reliable fleet.
The CompanyWe can provide no assurance, however, that the Companywe will be able to implement itsour business strategiesobjectives described above, particularly in the current challenging low oil price market environment.
For further discussion of the risks that the Company faces, please read “Item 3—Key Information—Risk Factors”.

Offshore Drilling Industry
The offshore drilling industry provides drilling, workover and well construction services to oil and gas exploration and production, or E&P, companies using jack-up rigs, tender rigs, semi-submersible rigs, drillships and other types of drilling units. Although terminology can differ across the industry, the depths at which offshore drilling units operate can be generally divided into four categories: ultra-deepwater, deepwater, midwater and shallow water. The Company generally considers ultra-deepwater to be depths of between 7,500 feet and 12,000 feet. The Company considers deepwater to cover depths between 4,500 and 7,500 feet, midwater to cover depths between 500 and 4,500 feet and shallow water to cover depths less than 500 feet.
E&P companies generally contract with drilling companies through agreements that set forth the contractual rate to be received each day, which is referred to as the dayrate. These rates generally cover chartering and operational services associated with the drilling unit and vary based on the type of rig contracted, the geographic location of the well, the duration of the work, the amount and type of service provided, market conditions and other variables. Contracts are entered into through various procedures including private and public tenders, market inquiries and requests for proposals. A dayrate drilling contract generally covers either the drilling of a single well or group of wells or has a stated term. Contracts may also grant the customer renewal options at either a fixed dayrate or at a rate to be determined based on market conditions at the time of exercise of the renewal option.
The dayrates that E&P companies are willing to pay also depend on the supply of and demand for offshore rigs as well as the outlook for investment in the exploration and development of oil and gas reservoirs, which in turn is affected by forecasts of oil and gas prices, the availability of acreage for exploration and the cash flow of E&P companies. These related matters are, in turn, affected by various political and economic factors, such as global production levels, government policies, political stability in oil producing countries, particularly in OPEC nations, and prices of alternative energy sources, among others.

Types of Offshore Drilling Units
Offshore drilling units are generally divided into four main categories of rigs:
Jack-Up Rig Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor. A jack-up rig is either towed to the drill site with its hull riding in the sea as a vessel, or transported on the back of a heavy lift vessel, with its legs raised. At the drill site, the legs are lowered until they penetrate the sea bed and the hull is elevated until it is above the surface of the water. After completion of the drilling operations, the hull is lowered, the legs are raised and the rig can be relocated to another drill site. Jack-ups generally operate with crews of 40 to 60 people.
Tender Rig Self-erecting tender rigs 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-tender's semi-submersible hull structure allows the unit to operate in rougher weather conditions. Self-erecting 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.
Semi-Submersible Rig Semi-submersible drilling rigs (which include cylindrical designed units) consist of an upper working and living quarters deck connected to a lower hull, such as 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.
There are two types of semi-submersible rigs, moored and dynamically positioned. Moored semi-submersible rigs are positioned over the wellhead location with anchors, while the dynamically positioned semi-submersible rigs are positioned over the wellhead location by a computer-controlled thruster system. Depending on country of operation, semi-submersible rigs generally operate with crews of 65 to 100 people.

Drillship Drillships are self-propelled ships equipped for drilling in deep waters, and are positioned over the well through a computer-controlled thruster system similar to that used on dynamically positioned 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.

Market Overview
We provide operations in oil and gas exploration and development in regions throughout the world and our customers include integratedhave 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, the offshore drilling market is encounteringthere has been a significant reduction in demand.


demand in the offshore drilling market.
The Global Fleet of Drilling Units
Seadrill Partners currently operates drillships, semi-submersible rigs and tender rigs. The existing worldwide fleet of these units as of March 31, 20162018, totals 343289 units including 121116 drillships, 185143 semi-submersible rigs, and 3730 tender rigs. In addition, there are 4628 drillships, 2314 semi-submersible rigs and 86 tender rigs under construction. The water depth capacities for the various drilling rig types depend on rig specifications, capabilities and equipment outfitting. Semi-submersible rigs and drillships can work in water depths up to 12,000ft12,000 feet and tender rigs work in water depths up to 410ft410 feet for tender barges and up to 6,000ft6,000 feet for semi-tenders. All offshore rigs are capable of workingcan work in benign environment but there are certain additional requirements for rigs to operate in harsh environments due to extreme marine and climatic conditions. The number of units outfitted for such operations are limited and the present number of rigs capable of operating in harsh environments total 153146 units.

This includes 7 drillships, 62 semi-submersible rigs and 77 jack-up rigs.
Semi-submersible rigs and drillships

The worldwide fleet of semi-submersible rigs and drillships currently totals 306259 units. Of the total delivered fleet, 165166 units are capable of operations in ultra-deepwater, 5131 classed for deepwater operations up to 7500 feet and the remainder62 classed for operations 4500 feet and below. Overall, the average global floater fleet is 1715 years old. The average age of ultra-deepwater units is 78 years, 2725 years for units classed for deepwater operations and 3129 years for units classed for operations below 4500 feet.

Included in the global floater fleet are units classed for operations in harsh environments. The global harsh environment floater fleet is comprised of 7869 units and is 2019 years old on average.

OilWhilst oil companies continue to prefer newer and more capable equipment, demonstrated by thewe are currently seeing a higher utilization rates of different asset classes.for mid-water drilling units. Ultra-deepwater units are currently experiencing 65%46% capacity utilization versus 41%42% for deepwater and 46%56% for mid water floaters. Utilization for harsh environment floaters is 54%51%. Older units are believed to be at a competitive disadvantage due to the customer preferences and the availability of more modern and efficient equipment.

Based on the level of current activity and the aging floater fleet, accelerated stacking and scrapping activity is expected to continue. A total of 49103 floaters have been been scrapped or retired since the endbeginning of 2013,2014, equivalent to 14%32% of the total fleet, and currently there are 5528 cold or warm stacked units with no follow-on work identified that are 1530 years old or older, which are prime scrapping candidates. In the next 18 months, 37a further 22 units that are 1530 years old or older will be coming off contactcontract with no follow onfollow-on work identified which represents additional scrapping candidates. A key rational for scrapping is the 15 year35-year classing expenditures that can cost upwards of $100 million. Many rig owners will choose to retire the unit rather than incur this cost without a visible recovery in demand on the horizon.

Currently the orderbookorder book stands at approximately 6942 units, comprised of 4628 drillships and 23 semis. 2614 semi-submersible rigs. 12 are scheduled for delivery in 2016, 182018, 17 in 20172019 and 2513 in 20182020 and beyond. Due to the subdued level of contracting activity, it is likely that a significant number of newbuild orders will be delayed or cancelledcanceled until an improved market justifies taking delivery.

Tender rigs
The worldwide fleet of tender rigs currently totals 3730 units, of which 2212 are contracted representing 59%40% capacity utilization. Overall, the global fleet is 1412 years old on average. Currently the orderbookorder book stands at approximately 86 units. 52 are scheduled for delivery in 2016,2018 and 34 in 2017.

2020.
Activity in the tender rig market is focused primarily in South-east Asia and West Africa. Tendering activity is typically more stable in this market due to these types of units being employed on development projects, however capacity utilization and dayrates have remained under pressure, similar to the worldwide floater market.

pressure.
The above overview of the various offshore drilling sectors is based on previous market developments and current market conditions. Future markets conditions and developments cannot be predicted and may well differ from our current expectations.

Seasonality

FleetIn 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 Customers
The following table provides additional information about OPCO’s fleet as of March 31, 2016:
Rig NameSeadrill Partners Ownership Interest Year Built 
Water
Depth
(feet)
 
Drilling
Depth
(feet)
 Location Customer
Semi-submersible           
West Aquarius58% 2009 10,000
 35,000
 Canada ExxonMobil/Hibernia Management (1)
West Capricorn51% 2011 10,000
 35,000
 USA (Gulf of Mexico) BP
West Leo58% 2012 10,000
 35,000
 Ghana Tullow
West Sirius51% 2008 10,000
 35,000
 USA (Gulf of Mexico) BP
            
Drillship           
West Capella (2)33% 2008 10,000
 35,000
 Nigeria ExxonMobil
West Polaris58% 2008 10,000
 35,000
 Angola ExxonMobil
West Auriga51% 2013 12,000
 40,000
 USA (Gulf of Mexico) BP
West Vela51% 2013 12,000
 40,000
 USA (Gulf of Mexico) BP
            
Tender Rig           
West Vencedor58% 2010 6,500
 30,000
 Myanmar Petronas
T-15100% 2013 6,500
 30,000
 Thailand Chevron
T-16100% 2013 6,500
 30,000
 Thailand Chevron

(1)
For each country where the West Aquarius operates under its drilling contract, a specific local contract and corresponding dayrate is agreed between the local ExxonMobil operating company and the local Seadrill subsidiary. In addition, the drilling contract permits ExxonMobil to assign the contract to third parties in certain circumstances. The West Aquarius drilling contract was assigned to Hibernia Management and Development Co. Ltd as of March 31, 2016.
(2)
The Company owns 58% of Seadrill Operating LP, which controls and owns 56% of the entity that owns the West Capella. Pursuant to Nigerian law, a Nigerian partner owns an effective 1% interest in the West Capella. Seadrill owns the remaining ownership interest in the entity that owns the West Capella.

the monsoon season in Southeast Asia.
Customers
Offshore exploration and production is a capital intensive, high-risk industry. Operating and pursuing opportunities in deepwater basins significantly increases the amount of capital required to effectively conduct such operations. As a result, aA 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. The Company’s
In 2017, our largest current customers arewere BP ExxonMobil, Tullow and Chevron.ExxonMobil. For the year ended December 31, 20152017, BP accounted for 44.8%, ExxonMobil(*)56.8% and ExxonMobil accounted for 32.1%, Tullow accounted for 13.5%, and Chevron accounted for 8.5%22.2%, of the Company’s total revenues, respectively. (* During 2015 and 2014 the ExxonMobil drilling contract for the West Aquarius was assigned to Hibernia Management and Development Co. Ltd.).

The following table represents the break-down of contract and reimbursable revenues by customer (excluding related party and other revenues) and geography for the years ended December 31, 2015, 2014 and 2013:
    2015 2014 2013
CustomerCountryRig Name ($ in millions) % ($ in millions) % ($ in millions) %
ExxonMobilNigeriaWest Capella $236.7
 14.3% $228.5
 17.0% $207.5
 19.6%
ExxonMobil (1)CanadaWest Aquarius 190.9
 11.5% 126.1
 9.4% 153.5
 14.5%
ExxonMobilAngolaWest Polaris 131.6
 8.0% —
 —% —
 —%
BPUSAWest Capricorn 209.7
 12.7% 176.3
 13.1% 183.5
 17.3%
ChevronAngolaWest Vencedor 47.8
 2.9% 92.4
 6.9% 87.9
 8.3%
PetronasMyanmarWest Vencedor 5.6
 0.3% —
 —% —
 —%
BPUSAWest Sirius 57.2
 3.5% 179.8
 13.4% 186.9
 17.7%
TullowGhanaWest Leo 234.7
 14.2% 233.5
 17.4% 198.6
 18.8%
ChevronThailandT-15 49.4
 3.0% 54.4
 4.1% 24.5
 2.3%
ChevronThailandT-16 50.4
 3.0% 51.2
 3.8% 16.1
 1.5%
BPUSAWest Auriga 219.8
 13.3% 167.5
 12.5% —
 —%
BPUSAWest Vela 219.7
 13.3% 32.9
 2.5% —
 —%
Total   $1,653.5
 100% $1,342.6
 100% $1,058.5
 100%
(1)
For each country where the West Aquarius operates under its drilling contract, a specific local contract and corresponding dayrate is agreed between the local ExxonMobil operating company and the local Seadrill subsidiary. In addition, the drilling contract permits ExxonMobil to assign the contract to third parties in certain circumstances. The ExxonMobil drilling contract for the West Aquarius was assigned to Hibernia Management and Development Co. Ltd during 2015, 2014 and part of 2013 and to Statoil Canada Ltd. during part of 2013.

Contract Backlog
The Company’s drilling units are contracted to customers for an average remaining term of 2.4 yearsOur contract backlog as of March 31, 2016. 2018 totals $1.4 billion. The backlog figure does not include any termination payments in relation to the termination of the West Leo.
Backlog is calculated as the full operating dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization and demobilization, contract preparation, and customer reimbursables. Backlog also includes, in the case of contracts for which we have received a notice of termination, an amount equal to the termination fee per day multiplied by the number of days for which the termination fee is payable under the terms of the contract.
The actual amounts of revenues earned and the actual periods during which revenues are earned may differ from the backlog amounts and periods shown in the table below due to various factors, including shipyard and maintenance projects, downtime and other factors. Downtime, caused by unscheduled repairs, maintenance, weather and other operating factors, may result in lower applicable dayrates than the full contractual operating dayrate.
In addition, the Company’sour contracts often provide for termination at the election of the customer with an “early termination payment” to be paid to the Companyus 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 the Companyus 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.

The Company’sOur contract backlog as of March 31, 2016 totals $4.1 billion and2018 is as follows:

RigContracted
Location		 Customer Contract
Backlog(1)
(US $ millions)		 Contractual
Dayrate
(US $)		 
Contract
Commencement		 Contract
Termination
Date		Contracted
Location		CustomerContractual
Dayrate
(US $)
Contract
Backlog(1)
(US $ 
millions)
Contract
Start		Contract End
Semi-submersible 
West SiriusStacked--
West AquariusCanada ExxonMobil/Hibernia Management $237
 $615,000
(2)Oct 2015 Apr 2017CanadaBP$260,000$31.2Apr 2018Jul 2018
West CapricornUSA BP $635
 $526,000
(3)Apr 2015 Jul 2019USABP$525,000$251.5Jul 2017Jul 2019
West LeoGhana Tullow $497
 $605,000
(4)Jun 2013 Jul 2018
West SiriusUSA BP $143
 $297,000
(5)May 2015 Jul 2017
West Leo (2)
Stacked--
 
Drillship 
West CapellaNigeria ExxonMobil $232
 $627,500
 Apr 2014 Apr 2017ArubaRepsolNot disclosedJun 2018Jul 2018
West PolarisAngola ExxonMobil $315
 $450,000
(6)Mar 2013 Mar 2018Stacked--
West AurigaUSA BP $924
 $562,000
(7)Oct 2013 Oct 2020USABP$562,000$529.4Oct 2013Oct 2020
West VelaUSA BP $886
 $525,000
(8)Nov 2013 Nov 2020USABP$564,000$510.4Nov 2013Nov 2020
 
Tender Rig 
West VencedorMyanmar Petronas $10
 $100,000
 Dec 2015 Jul 2016Stacked--
T-15Thailand Chevron $131
 $110,000
 Jul 2013 Jul 2019ThailandChevron$110,000$50.9Jul 2013Jul 2019
T-16Thailand Chevron $134
 $110,000
 Aug 2013 Aug 2019ThailandChevron$110,000$54.8Aug 2013Aug 2019
(1)
(1) Expressed in millions. Based on executed drilling contracts.
(2) Tullow terminated the drilling contracts.
(2)
Dayrate includes a mobilization fee of $30 million that is being amortized over the contract period. The West Aquarius drilling contract was assigned to Hibernia Management and Development Co. Ltd.
(3)BP has an option to extend the expiration date of the contract for up to two years from July 2019.
(4)The base dayrate is $590,000 for operations in Ghana and will be adjusted for operations in Côte d’Ivoire and Guinea. The dayrate shown above for Ghana includes a performance bonus based on achievement of 95% utilization. A mobilization fee of $18 million is being amortized into income over the period of the term of this contract.
(5)
The signed drilling contract was terminated early by BP and ended in April 2015. The backlog of $143 million consists of $297,000 per day from April 2016 until July 2017, to be received by the Company in accordance with the termination provisions in the West Sirius contract. The average remaining contract term of 2.4 years as of March 31, 2016 for the fleet does not include this period for the West Sirius.
(6)
Under the terms of the acquisition agreement for the West Polaris, Seadrill Polaris has agreed to pay Seadrill (a) any dayrate received in excess of $450,000 per day, adjusted for daily utilization, through the remaining term, without extension, of the ExxonMobil contract and (b) after the expiration of the term of the existing contract until March 2025, 50% of any such excess dayrate, adjusted for daily utilization.
(7) A mobilization fee payable daily over the term of the contract of $37.5 million is being amortized into income over the period of the term of this contract.
(8)A mobilization fee payable daily over the term of the contract of $37.5 million is being amortized into income over the period of the term of this contract. This amount is payable to Seadrill for the remainder of the contract under the terms of the West Vela acquisition agreement.


Drilling Contracts
The Company provides drilling services on a “dayrate” contract basis. The Company does not provide “turnkey” or other risk-based drilling services to the customer. Under dayrate contracts, the drilling contractor provides a drilling unit and rig crews and charges the customer a fixed amount per day regardless of the number of days needed to drill the well. The customer bears substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, dayrate contracts usually provide for a lump sum amount or dayrate for mobilizing the rig to the initial operating location, which is usually lower than the contractual dayrate for uptime services, and a reduced dayrate when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond the contractor’s control. A dayrate drilling contract generally covers either the drilling of a single well or a number of wells or has a stated term regardless of the number of wells. These 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 of time as a result of a breakdown of equipment, “force majeure” events beyond the control of either party or upon the occurrence of other specified conditions. In some instances, the dayrate contract term may be extended by the customer exercising options for the drilling of additional wells or for an additional length of time at fixed or mutually agreed terms, including dayrates.
The Company’s drilling contracts are the result of negotiations with its customers. The Company’s existing drilling contracts generally contain, among other things, the following commercial terms: (i) contract duration extending over a specific period of time; (ii) term extension options in favor of its customer, generally upon advance notice to the Company, at mutually agreed, indexed or fixed rates; (iii) provisions permitting early termination of the contract if the drilling unit is lost or destroyed, if operations are suspended for an extended period of time due to breakdown of major rig equipment or “force majeure” events beyond the Company’s control and the control of the customer; (iv) provisions allowing early termination of the contract by the customer without cause with a specified early termination fee in the form of a reduced rate for a specified period of time; (v) payment of compensation to the Company (generally in U.S. Dollars although some contracts require a portion of the compensation to be paid in local currency) on a dayrate basis (lower rates or no compensation generally apply during periods of equipment breakdown and repair or in the event operations are suspended or interrupted by other specified conditions, some of which may be beyond the Company’s control); (vi) payment by the Company of the operating expenses of the drilling unit, including crew labor and incidental rig supply costs; (vii) provisions entitling the Company to adjustments of dayrates (or revenue escalation payments) in accordance with published indices or otherwise; (viii) provisions requiring the Company or Seadrill to provide a performance guarantee; (ix) indemnity provisions between the Company and its customers in respect of third-party claims and risk allocations between the Company and its customers relating to damages,

claims or losses to the Company, its customers, or third parties; and (x) provisions permitting the assignment to a third party with the Company’s prior consent, such consent not to be unreasonably withheld. The Company’s indemnification may not cover all damages, claims or losses to the Company or third parties, and the indemnifying party may not have sufficient resources to cover its indemnification obligations.
See also Item 3 “Key Information—Risk Factors—Risks Inherent in The Company's Business—the Company’s customers may be unable or unwilling to indemnify the Company.” In addition, the Company’s drilling contracts typically provide for situations where the drilling unit would operate at reduced operating dayrates. See Item 5 “Operating and Financial Review and Prospects—Important Financial and Operational Terms and Concepts—Economic Utilization.”

Joint Venture, Agency and Sponsorship Relationships
In some areas of the world, local customs and practice or governmental requirements necessitate the formation of joint ventures with local participation. Local laws or customs in some areas of the world also effectively mandate establishment of a relationship with a local agent or sponsor. When appropriate in these areas, the Company will enter into agency or sponsorship agreements. For more information regarding the regulations in the countries in which the Company currently are contracted to operate, please see “—Environmental and Other Regulations in the Offshore Drilling Industry.”
Nigerian investors have invested in a subsidiary of Seadrill Operating LP. The entity is fully controlled and approximately 56% owned by Seadrill Operating LP, resulting in the Nigerian joint venture partner owning an effective 1% interest in the West Capella. Seadrill owns the remaining ownership interest in the joint venture. The joint venture agreement provides the joint venture partner with the right to purchase up to an approximate effective 25%Leo interest in December 2016. We have disputed the West Capella at a fair market value price over the course of five years, subject to additional mutually agreed upon terms. Any such purchase is expected to be from Seadrill’s ownership interestgrounds for termination and not from Seadrill Operating LP.

Seasonality
In general, seasonal factors do not have a significant direct effect on the Company’s business. The Company has operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operation of its rigs, but generally such operational interruptions do not have a significant impact on the Company’s revenues. Please read “—Drilling Contracts.” Such adverse weather could include the hurricane season for the Company’s operations in the U.S. Gulf of Mexico and the monsoon season of Southeast Asia.

commenced litigation proceedings.
Competition
The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to smaller companies with fewer than five drilling units.
The demand for offshore drilling services is driven by oil and gas companies’ exploration and development drilling programs. These drilling programs are affected by oil and gas companies’ expectations regarding oil and gas prices, anticipated production levels, worldwide demand for oil and gas products and many other factors. The availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect customers’ drilling programs. Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by customers for drilling services. VariationsWe are affected by variations in market conditions impact the Company 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.
CompetitionFurthermore, 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.
The Company believesWe believe that whilst the market for drilling contracts will continue to be highly competitive, for the foreseeable future. The Company believes that the Company’sour modern fleet of recently constructed technologically advanced drilling units provides itus with a competitive advantage over competitors with older fleets, as the Company’sfleets. Our drilling units are generally better suited to meet the requirements of customers for drilling in deepwater. However, certainsome of our competitors may have greater financial resources than the Company does,us, which may enable them to better withstand periods of low utilization, and compete more effectively on the basis of price.
For further information on current market conditions and global offshore drilling fleet, please see "Market Overview" and Item 5 "Operating and Financial Review and Prospects-Trend Information".

Principal Suppliers
The Company sourcesWe source the equipment used on itsour drilling units from well-established suppliers, including: Cameron International Corp. and National Oilwell Varco, Inc. ("NOV"), or 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, each of the Company’sour customers are responsible for providing the fuel to be used by thea drilling unit thatwhen it contracts from the Company,is under contract to them, at such customer’stheir own cost.

We are not dependent on any one supplier.
Risk of Loss and Insurance
The Company’sOur operations are subject to hazards inherent in the drilling of oil and gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, destroy the equipment involved or cause serious environmental damage. Offshore drilling contractors such as the CompanyWe are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. The Company’s marineOur energy insurance package policy provides insurance coverage for physical damage to the Company’sour drilling units, loss of hire for some of itsour rigs and third-party liability.
The Company’sOur insurance claims are subject to a deductible, or non-recoverable, amount. The CompanyWe currently maintainsmaintain a deductible per occurrence of up to $5$5 million related to physical damage to its rigs. However, a total loss of, or a constructive total loss of, a drilling unit is recoverable without being subject to a deductible. For general and marine third-party liabilities, the Companywe generally maintainsmaintain a deductible of up to $500,000$0.5 million per occurrence on personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units. Furthermore, the Company purchaseswe buy insurance for certain of its drilling units to cover loss due to the drilling unit being wholly or partially deprived of income as a consequence of damage to the unit. TheThis loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, insurance policies are limited to 290 days.days. If the repair period for any physical damage exceeds the number of days permitted under the Company’sour loss of hire policy, itwe will be responsible for the costs in such period. The Company doesWe do not have loss of hire insurance on the Company'sfor our tender rigs with the exception of the semi-tender rig the West Vencedor,.while the rig is in operation.
The Company hasWe have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a Combined Single Limitcombined single limit of $100 million in the annual aggregate, which includes loss of hirehire. We intend to renew our policy to insure a limited part of this windstorm risk for thea further period fromstarting May 1, 20162018 through April 30, 2017.2019.

Environmental and Other Regulations in the Offshore Drilling Industry
The Company'sOur 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 the Company'sour drilling units operate or are registered, which can significantly affect the ownership and operation of the Company'sour drilling units. See Item 3. Key Information "Risk Factors - Risks Inherent in The Company's Business". Governmental3 "Key Information-Risk Factors-Risks Relating to our Company- Compliance with, and breach of, the complex laws and regulations including environmental lawsgoverning international trade could be costly, expose us to liability and regulations, may add to the Company's costs or limit the Company's drilling activity.”adversely affect our operations”.
Flag State Requirements
All of the Company'sour drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered. These include engineering, safety and other requirements related to the drilling industry and to maritime vessels in general. In addition, each of itsour 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. The Company'sOur drilling units must generally undergo a class survey once every five years.
International Maritime Regimes
These requirementsRequirements of international maritime regimes, such as the United Nation's International Maritime Organization ("the IMO"), include, but are not limited to, MARPOL,the International Convention for the Prevention of Pollution from Ships (“MARPOL”), the International Convention on Civil Liability for Oil Pollution Damage of 1969 or the CLC,(the “CLC”), the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008), or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974 or SOLAS,(“SOLAS”), the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or the ISM Code, the International Convention of Load Line in 1966, as from time to time amended, and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004 or the(the “BWM Convention.Convention”). These various conventions regulate air emissions and other discharges to the environment from the Company'sour drilling units worldwide, and the Companywe may incur costs to comply with these regimes and continue to comply towith 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 Inherent in The Company's Business". The Company is"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, recent amendments to Annex VI require the imposition of progressively stricter limitations on sulfur emissions from ships. Since January 1, 2015, these limitations have required that fuels of vessels in covered Emission Control Areas (“ECAs”) contain no more than 0.1% sulfur, including the Baltic Sea, North Sea, North America and United States Sea ECAs. For non- ECA areas, the sulfur limit in marine fuel is currently capped at 3.5%, which will then decrease to 0.5% on January 1, 2020 subject to feasibility review. The amendments also establish new tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation.
The BWM Convention calls for a phased introduction of mandatory ballast water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The BWM Convention entered into force on September 8, 2017. Under its requirements, for units with ballast water capacity more than 5,000 cubic meters that were constructed in 2011 or before, only ballast water treatment will be accepted by the BWM Convention.
Environmental Laws and Regulations
TheseApplicable environment laws and regulations include the U.S. Oil Pollution Act of 1990 or OPA,(“OPA”), the rules and regulations of the U.S Environmental Protection Agency (the "EPA"), the Comprehensive Environmental Response, Compensation and Liability Act or CERCLA”("CERCLA"), the U.S. Clean Water Act, the U.S. Clean Air Act, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002 or the(the “MTSA"), and European Union regulations, including the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations, and Brazil’s National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Law (9966/2000) relating to pollution in Brazilian waters.Operations. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection. In certain circumstances, these laws may impose strict liability, rendering the Company liable for environmental and natural resource damages without regard to negligence or fault on the Company's part. Implementation of new environmental laws or regulations that may apply to ultra deepwater drilling units may subject the Companyus to increased costs or limit the operational capabilities of the Company'sour drilling units and could materially and adversely affect the Company'sour operations and financial condition. For instance, certain Annex VI Regulations under MARPOL which took effect on January 1, 2015 set a 0.1% sulphur limit on marine gas oil and marine diesel in the Baltic Sea, North Sea, North America and the United States Sea Emission Control Areas. See Item 3. Key3 “Key Information "Risk- Risk Factors - Risks Inherent in The Company's Business". The Company isRelating to Our Company-We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.”business".
Safety Requirements
The Company'sOur operations are subject to special safety regulations relating to drilling and to the oil and gas industry in many of the countries where the Company operates.we operate. The United States undertook substantial revision of the safety regulations applicable to the Company's industry following the 2010 Deepwater Horizon Incident,incident, in which the Company was not involved, that led to the Macondo well blow out situation, in 2010.situation. Other countries are also undertaking a review of their safety regulations related to the Company's industry. These safety regulations may impact the Company'sour operations and financial results.results by adding to the costs of exploring for, developing and producing oil and gas in offshore settings. For instance, in April 2016, BSEEthe U.S. Department of the Interior’s Bureau of Safety and Environmental Enforcement (“BSEE”) published a final rule that among other things, setsets more stringent design requirements and operational procedures for critical well control equipment used in offshore oil and gas drilling. These new regulations grow out of the findings made in connection with the Deepwater Horizon incident and include a number of requirements that will add to the costs of exploring for, developing and producing of oil and gas in offshore settings. These new rules addThe rule adds new requirements and amendamends existing ones to, among other things, set new baseline standards for the design, manufacture, inspection, repair and maintenance of blow-out preventers including their inspection and the use of double shear rams. These rules containThe 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. It is too soonIn December 2017, BSEE proposed to tell whether industry will challenge somerevise or alleliminate certain of the requirements under the rule. To the extent these requirements or what the outcome of any such challenge will be. These regulationsremain 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 September 2015, BOEMJuly 2016, U.S. Department of the Interior’s Bureau of Ocean Energy Management (“BOEM”) issued draft guidance that would bolstera 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 expected to issue the draft guidance in the forma substantial risk of a final Notice to Lessees and Operators during the summernon-performance of 2016.such obligations. In addition, in December 2015, BSEE announced that it is launching a pilot risk-based inspection program for offshore facilities. SuchNew requirements resulting from the program may cause the Companyus to incur costs and may result in additional downtime for the Company'sour 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 furtheradditional safety and environmental laws and regulations regarding offshore oil and gas exploration and development. See Item 3. “Key Information - Risk Factors - Risks Inherent in The Company's Business". 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, could negatively impact us.” The EU has also recently undertaken a significant revision of its safety requirements for offshore oil and gas activity through the issuance of the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations.
Navigation and Operating Permit Requirements
Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Some of these laws contain criminal sanctions in addition to civil penalties.
Local Content Requirements
Governments in some countries have become increasingly active in local content requirements on the ownership of drilling companies, local content requirements for equipment utilized in the Company'sour operations, and other aspects of the oil and gas industries in their countries. These regulations include requirements for participation of local investors in the Company'sour local operating subsidiaries in countries such as Angola and Nigeria. Although these requirements have not had material impact on itsour operations in the past, they could have a material impact on the Company'sour earnings, operations and financial condition in the future.

Other Laws and Regulations
In addition to the requirements described above, the Company'sour international operations in the offshore drilling segment are subject to various other international conventions and laws and regulations in countries in which the Company operates,we operate, including laws and regulations relating to the importation of and operation of drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, Important laws and regulations in countries other than the United States where the Company currently operates are described below.development. There is no assurance that compliance with current laws and regulations or amended or newly adopted laws and regulations can be maintained in the future or that future expenditures required to comply with all such laws and regulations in the future will not be material.

Canada
The main legislation for oil and gas operations is the Canada Oil and Gas Operations Act, or COGOA. This Act regulates exploration for resources and operations of offshore activities. COGOA describes the responsibility of the operator to ensure worker safety and protection of the environment and outlines requirements to obtain a well approval.
The Company's operations are also subject to the requirements for oil spill planning and preparedness under the Canadian Environmental Protection Act, the Canadian Environmental Assessment Act, the Emergencies Act and the Emergency Preparedness Act.
In Eastern Canada, the Canada–Nova Scotia Offshore Petroleum Board and the Canada–Newfoundland and Labrador Offshore Petroleum Board regulate drilling and production off the coasts of Nova Scotia and Newfoundland and Labrador, respectively.
The Canadian Environmental Protection Act, or CEPA, regulates water pollution, including disposal at sea and the management of hazardous waste. Insofar as the offshore drilling industry is concerned, CEPA prohibits the disposal or incineration of substances at sea except with a permit issued under CEPA, the importation or exportation of a substance for disposal at sea without a permit, and the loading on a ship of a substance for disposal at sea without a permit.
Nigeria
The Petroleum Act is the key Nigerian legislation that governs the oil and gas industry in Nigeria. The Company is also subject to Petroleum (Drilling and Production) Amendment Regulations 1988, Environmental Guidelines and Standards for the Petroleum Industry of Nigeria, and the Environmental Impact Assessment Act.
Thailand
The Company is subject to contractor licensing requirements in Thailand administered by the Bureau of Foreign Business Registration.  These licensing requirements regulate the activities that the Company’s affiliates may undertake in Thailand.
Angola
The Petroleum Activities Law, as implemented by the Petroleum Operations Regulations approved in 2009, is the key Angolan legislation that covers the oil and gas industry. The Company is also subject to the Environmental Framework Law, the Regulations on Liability for Environmental Damages, Decree 39/00 (setting forth specific rules on environmental protection in the performance of petroleum operations), and Executive Decree 12/05 (setting out procedures for reporting of the occurrence of oil spills).
Ghana
The Company is required to obtain a permit to operate in Ghana from the Petroleum Commission. Further, the Company is subject to the Local Content and Local Participation regulations.
Ivory Coast
The principal legal and regulatory regime applicable to the Company's operations in Ivory Coast is the petroleum code and implementing legislation.
Myanmar
Offshore oil and gas drilling activity in Myanmar is subject to the Environmental Conservation Law of 2012 and the Environmental Conservation Rules (2014) of the Republic of the Union of Myanmar. Under the relevant provisions, operators of proposed projects must consult with the Ministry of Environmental Conservation and Forestry (MOECAF) to complete an environmental assessment process. Myanmar is in the process of updating these requirements, however, and MOECAF is currently drafting procedures and guidelines for environmental impact assessments.
Other laws that may be applicable to offshore drilling activity include The Protection of Wildlife and Conservation of Natural Areas Law (1994), which provides penalties for water and air pollution, and Myanmar’s Marine Fisheries Law (1990), which defines and prohibits water pollution.

Legal Proceedings
From time to time the Company has been, and expects that in the future it will be, subject to legal proceedings and claims in the ordinary course of business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources. The Company is not aware of any legal proceedings or claims that the Company believes will have, individually or in the aggregate, a material adverse effect on the Company. Please also see Note 15, “Commitments and Contingencies—Legal Proceedings” to the audited Consolidated and Combined Carve-Out Financial Statements included elsewhere in this annual report.

Taxation of the Company
The CompanySeadrill Partners LLC is organized as a limited liability company under the laws of the Republic of the Marshall Islands and the Company is resident in the United Kingdom for taxation purposes by virtue of being centrally managed and controlled in the United Kingdom. Certain of the Company'sour controlled affiliates are subject to taxation in the jurisdictions in which they are organized, conduct business or own assets. The Company intendsWe intend that the Company'sour business and the business of the Company's controlled affiliates will be conducted and operated in a tax efficient manner. However, the Companywe cannot assure this result as tax laws in these or other jurisdictions may change or the Companywe may enter into new business transactions, which could affect the Company'sour tax liabilities.

Marshall Islands
Because the CompanySeadrill Partners LLC and the Company'sits controlled affiliates do not carry on business or conduct businesstransactions or operations in the Republic of the Marshall Islands, neither the Companyit nor the Company'sits controlled affiliates will be subject to income, capital gains, profits or other taxation under current Marshall Islands law, and the Company doeswe do not expect this to change in the future.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 Company's controlled affiliates of Seadrill Partners LLC, and distributions the CompanySeadrill Partners LLC receives from OPCO, are not expected to be subject to Marshall Islands taxation.
United Kingdom
The CompanySeadrill Partners LLC is a resident of the United Kingdom for taxation purposes. Nonetheless, the Company expectswe expect that the distributions the Companyit receives from OPCO, generally will be exempt from taxation in the United Kingdom under applicable exemptions for distributions from subsidiaries. As a result, the Company doeswe 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 Company's United Kingdom residency for taxation purposes.
United States
The Company hasWe have elected to be treated as a corporation for U.S. federal income tax purposes. As a result, the Company iswe are subject to U.S. federal income tax to the extent the Company earnsthat 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. The Company doesWe do not expect to earn a material amount of such taxable net income; however, the Company haswe 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.
Other JurisdictionsUS Tax Reform
In December 2017, the U.S. enacted the Tax Cuts and Additional InformationJobs Act (the “2017 Tax Act”), which includes a number of changes to existing U.S. tax laws that may have an impact on our income tax provision in future years but with some one-off adjustments in 2017. The most notable immediate impact on the group is a reduction of the U.S. corporate income tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017.  The 2017 Tax Act also makes prospective changes beginning in 2018, including a base erosion and anti‑abuse tax (“BEAT”), limitations on the deductibility of interest and repeal of the domestic manufacturing deduction.  We are still evaluating the impact and its prospective effect on future periods.
The Company directlyReduction of the U.S. corporate income tax rate-At December 31, 2017, we recalculated our deferred tax assets and indirectly ownsliabilities to reflect the reduction in the U.S. corporate income tax rate from 35 percent to 21 percent. This has resulted in a $3 million increase in income tax expense for the year ended December 31, 2017 and a corresponding $3 million decrease in net deferred tax assets as of December 31, 2017.  
Taxation of rig owning entities
A number of our drilling rigs are owned in tax-free jurisdictions such as Bermuda or controls various additional subsidiaries that are subject to taxation in other jurisdictions. For additional information regarding the Cayman Islands. There is no taxation of the Company’s subsidiaries, please read "Note 5 - Taxation"rig owners’ income in these jurisdictions. The remaining drilling rigs are owned in jurisdictions with income taxation of the Company's Consolidatedrig owners’ income, being Hungary and Combined Carve-Out Financial Statements included elsewhereLuxembourg. There may also be income tax in this annual report.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.
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 arig. 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 rigduring 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.


C.     Organizational Structure
A simplified organizational structure as of March 31, 20162018 is shown below.
sdlpgroupstructure2017a02.jpg
Seadrill owned 34.9% of the common units of Seadrill Partners LLC and 100% of the subordinated units of Seadrill Partners LLC, and owned and controlled the Seadrill Member.
A full list of the Company's significant operating and rig-owning subsidiaries is included in Exhibit 8.1.

D.     Property, Plant and Equipment
The Company owns a modernOther than our fleet of drilling units. The units, in the Company'swe do not have any material property. Information regarding our fleet areof drilling units is set out in Item 4.4 "Information on the Company - Business Overview".
 

Item 4A.     Unresolved Staff Comments

None.


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 Item 3A “Key Information—Selected Financial Data,” Item 4 “Information on the Company” and the Company's Consolidated and Combined Carve-Out Financial Statements and Notesnotes 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 and Combined Carve-Out Financial Statements have been prepared in accordance with U.S. GAAP and are presented in U.S. Dollars.
The following discussion assumes that the Company's business was operated as a separate entity prior We refer you to the Company's IPOnotes to our Consolidated Financial Statements for a discussion of the basis on October 24, 2012. References in this annual reportwhich our Consolidated Financial Statements are prepared, and we draw your attention to the Company’s “initial fleet” refer to the statement regarding going concern as described in Note 1 "General information".
Our Drilling Contracts
West Aquarius, the West Capricorn, the West CapellaPlease read Item 4 "History and the West Vencedor, interests in eachDevelopment of which were contributed to the Company at or prior to the Company's IPO.-
The Company's financial position, results of operations and cash flows reflected in the Company's Consolidated and Combined Carve-Out Financial Statements include all expenses allocable to the Company's business, but may not be indicative of future results.
Overview
The Company is a limited liability company formed by Seadrill to own, operate and acquire offshore drilling units. The Company's drilling units are under contracts with major oil companies such as Chevron, Total, BP and ExxonMobil with an average remaining term of 2.4 years as of March 31, 2016.
On October 24, 2012, the Company completed its IPO and in connection with the Company's IPO, the Company issued 10,062,500 common units to the public (including 1,312,500 common units pursuant the underwriter’s option to purchase additional common unit in full) at a price of $22.00 per common unit and issued to Seadrill 14,752,525 common units and 16,543,350 subordinated units. In addition, the Company 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.
In connection with the Company's IPO, the Company acquired (i) a 30% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through the Company's 100% ownership of its general partner, Seadrill Operating GP LLC, and (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. The Company controls Seadrill Operating LP through the Company's ownership of its general partner and Seadrill Capricorn Holdings LLC through the Company's ownership of the majority of the limited liability company interests.
On May 17, 2013, the Company's wholly-owned subsidiary, Seadrill Partners Operating LLC, acquired from Seadrill a 100% ownership interest in the entities that own and operate the tender rig the T-15. On October 18, 2013, Seadrill Partners Operating LLC, acquired from Seadrill a 100% ownership interest in the entity that owns the tender rig the T-16. As considerationSignificant Developments for the purchase of the T-16, the Company issued 3,310,622 common units to Seadrill.
On December 13, 2013, Seadrill Operating LP acquired (the “Leo Acquisition”) all of the ownership interests in each of the entities that own, operate and manage the semi-submersible drilling rig, West Leo (the “Leo Business”) and Seadrill Capricorn Holdings LLC acquired (the “Sirius Acquisition”) all of the ownership interests in each of the entities that own and operate the semi-submersible drilling rig, West Sirius (the “Sirius Business”). The Leo Acquisition and the Sirius Acquisition were accomplished through a series of purchases and contributions. The implied purchase prices of the Leo Acquisition and the Sirius Acquisition were $1.250 billion and $1.035 billion, respectively, in each case, including working capital. The Company's portion of the purchase price after debt financing at the OPCO level for the Leo Acquisition was $229.4 million. In addition, the owner of the West Leo, Seadrill Leo Ltd., entered into a $485.5 million intercompany loan agreement with Seadrill, which was repaid in full in February 2014. The Company's portion of the purchase price after debt financing at the OPCO level for the Sirius Acquisition was $298.4 million. The Company funded $70 million of the $298.4 million purchase price by issuing a zero coupon discount note to Seadrill which was repaid in full in March 2014. Seadrill Hungary Kft., the owner of the West Sirius, entered into a $220.1 million intercompany loan agreement with Seadrill which was repaid in full in February 2014. In addition, Seadrill Capricorn Holdings LLC financed $229.9 million of the purchase price of the Sirius Acquisition by issuing a zero coupon discount note to Seadrill which was repaid in full in February 2014. As a result of these transactions, the Company acquired a (i) 30% indirect interest in the Leo Business and (ii) 51% indirect interest in the Sirius Business.
In order to fund the Company's portion of the purchase price for the Sirius Acquisition and Leo Acquisition, on December 9, 2013, the Company issued an aggregate of (i) 12,880,000 common units to the public at a price of $29.50 per unit and (ii) 3,394,916 common units to Seadrill in a concurrent private placement at a price of $29.50 per unit. The aggregate net proceedsPeriod from these offerings were approximately $464.8 million.
The transactions described above that occurredJanuary 1, 2015 through December 31, 2013, have been reflected as2017 - Drilling Contracts" for a reorganizationsummary of entities under common control and, therefore, the assets and liabilities acquired from Seadrill have been recorded at historical cost by the Company and the historical operating results have been retrospectively adjusted to include the results of the combined entities during the periods they were under common control of Seadrill.
As of January 2, 2014, the date of the Company’s first annual general meeting, Seadrill ceased to control the Company in accordance with US GAAP and, therefore, the Company and Seadrill are no longer deemed to be entities under common control.
On February 21, 2014, Seadrill Operating LP, Seadrill Capricorn Holdings LLC and the Company's new subsidiary, Seadrill Partners Finco LLC (the “Borrowers”), entered into Senior Secured Credit Facilities (the “Senior Secured Credit Facilities”). The Senior Secured Credit Facilities consist of (i) a $100.0 million revolving credit facility (the “revolving facility”) available for borrowing from time to time by any Borrower, and (ii) a $1.8 billion term loan (the “term loan”) which was borrowed by Seadrill Operating LP in full on February 21, 2014. The proceeds from the transaction were used to (a) refinance debt secured by the West Aquarius, West Capella, West Leo and West Sirius, (b) repay in part the

Company's unsecured loans from Seadrill, (c) add cash to the balance sheet in support of general company purposes and (d) pay all fees and expenses associated therewith.
On March 24, 2014, Seadrill Capricorn Holdings LLC acquired from Seadrill all of the ownership interests in each of Seadrill Auriga Hungary Kft., a Hungarian company which owns the drillship, the West Auriga, and Seadrill Gulf Operations Auriga LLC, a Delaware limited liability company which operates the West Auriga (the "Auriga Acquisition"). The Auriga Acquisition was accomplished through a series of purchases and contributions. As a result of these transactions, the Company acquired a 51% indirect interest in the ownership and operations of the West Auriga. The implied purchase price of the Auriga Acquisition was $1.24 billion. The Company's portion of the purchase price for the Auriga Acquisition, after debt financing at the OPCO level, was $355.4 million. In addition, Seadrill Capricorn Holdings LLC financed $100.0 million of the purchase price by issuing a zero coupon limited recourse discount note to Seadrill. Upon maturity of such note, Seadrill Capricorn Holdings LLC was due to repay $103.7 million to Seadrill. This note was repaid in June 2014 with the proceeds of the Amended Senior Secured Credit Facilities. The purchase price of the Auriga Acquisition was subsequently adjusted by a working capital adjustment of $330.4 million. The working capital adjustment predominately arose as a result of related party payable balances which remained in the acquired entities. These payable balances related to funding provided by Seadrill to the acquired entities for the construction, equipping and mobilization of the West Auriga. Seadrill Auriga Hungary Kft. was a borrower under the $1.45 billion credit facility (the “Auriga Facility”) used to finance the West Auriga. As of the closing date of the Auriga Acquisition, Seadrill Auriga Hungary owed $443.1 million in principal under the Auriga Facility. In June 2014, this facility was refinanced with proceeds from the Amended Senior Secured Credit Facilities.
In order to fund the Company's portion of the cash purchase price of the Auriga Acquisition, on March 17, 2014, the Company issued an aggregate of 11,960,000 common units to the public and 1,633,987 common units to Seadrill at a price of $30.60 per unit.

On June 24, 2014, the Company issued 6,100,000 common units to the public and 3,183,700 common units to Seadrill at a price of $31.41 per unit.

On June 26, 2014, the Borrowers amended and restated their senior secured credit facilities (as amended and restated, the “Amended Senior Secured Credit Facilities”) to provide for the borrowing by Seadrill Operating LP of $1.1 billion of additional term loans, in addition to the $1.8 billion term loan already outstanding under the Senior Secured Credit Facilities. Thus, following the amendment and restatement, the Amended Senior Secured Credit Facilities consisted of (i) a $100.0 million revolving credit facility (the “revolving facility”) available for borrowing from time to time by any Borrower, and (ii) a $2.9 billion term loan (the “term loan”). The proceeds from the additional $1.1 billion of term loans were used to (a) refinance debt secured by the West Auriga of $443.1 million and the West Capricorn of $426.3 million, (b) repay in part certain of our unsecured loans from Seadrill in the amount of $100.0 million, (c) add cash to the Company’s balance sheet for general company purposes, (d) pay all fees and expenses associated with the Amended Senior Secured Credit Facilities and (e) partially fund the acquisition of an additional interest in Seadrill Operating LP discussed below.

On July 21, 2014, the Company acquired an additional 28% interest in Seadrill Operating LP from Seadrill for $373 million, bringing its total ownership interest in Seadrill Operating LP to 58%.

On September 23, 2014, the Company issued 8,000,000 common units to the public at a price of $30.68 per unit.
On November 4, 2014, Seadrill Capricorn Holdings LLC acquired from Seadrill all of the ownership interests in each of Seadrill Vela Hungary Kft., a Hungarian company which owns the drillship, the West Vela, and Seadrill Gulf Operations Vela LLC, a Delaware limited liability company which operates the West Vela (the "Vela Acquisition"). The Vela Acquisition was accomplished through a series of purchases and contributions. As a result of these transactions, the Company acquired a 51% indirect interest in the ownership and operations of the West Vela. The implied initial purchase price of the Vela Acquisition was $900 million. The Company's portion of the initial purchase price for the Vela Acquisition, after debt financing at the OPCO level, was $238 million. Under the terms of the West Velaour drilling contract, the customer is payingcontracts and a daily rate of $565,000, plus approximately $44,000 per day as a mobilization fee paid over the termsummary of the contract. In addition to the initial purchase price, Seadrill Capricorn Holdings LLC will pay Seadrill $40,000 per daystatus of day rate revenue actually received, as well as the $44,000 per day mobilization fee. These payments to Seadrill will cease at the end of the current contract. Thus, the total consideration included deferred consideration payable to Seadrill of $73.7 million and contingent consideration of $65.7 million. The purchase price was subsequently adjusted by a working capital adjustment of $6.0 million. The Vela Acquisition was financed with debt and $238 million in cash for the Company’s 51% equity share.

As of the closing date of the Vela Acquisition, Seadrill Vela Hungary Kft owed $433.1 million in principal under the $1,450 million senior secured credit facility relating to the West Vela and the West Tellus, another drilling unit which is owned by Seadrill (the “$1,450 Million Senior Secured Credit Facility”). Seadrill Vela Hungary’s liability to repay debt under the $1,450 Million Senior Secured Credit Facility that relates to the other rigs owned by Seadrill remains. However, Seadrill indemnified Seadrill Vela Hungary Kft. against any liability it may incur under the Vela Facility in respect of such debt.

On March 31, 2015 the Company received a notice of termination from BP for the contract for the West Sirius which became effective after having completed a well and demobilization in early May 2015. Prior to the cancellation notice, the dayrate and term for the West Sirius and West Capricorn contracts were swapped. The West Sirius dayrate was decreased by $40,000 per day and the term was decreased by two years to expire in July 2017 while the dayrate for the West Capricorn was increased by $40,000 per day and the term was extended by two years to expire in July 2019. Amortized payments for the West Capricorn such as mobilization and upgrades will continue on the original schedule ending

in July 2017.  In accordance with the cancellation provisions in the West Sirius contract, the Company will receive termination payments over the remaining contract term, now expiring in July 2017.

On June 16, 2015, Seadrill Operating LP, a subsidiary in which the Company owns a 58% limited partner interest, entered into an agreement with Seadrill to acquire all of the shares of Seadrill Polaris Ltd. (“Seadrill Polaris”), the entity that owns and operates the drillship the West Polaris (the “Polaris Acquisition”) from Seadrill. The Polaris Acquisition was completed on June 19, 2015. The West Polaris is a 6th generation, dynamically positioned drillship delivered from the Samsung shipyard in 2008. The West Polaris is expected to carry out operations in Angola until the end of its contract with ExxonMobil in March 2018.

The consideration for the Polaris Acquisition was comprised of $204 million in cash and $336 million of debt outstanding under the existing facility financing the West Polaris. In addition Seadrill Operating LP issued a note (the “Seller’s Credit”) of $50 million to Seadrill, repayment of which is contingent on the future re-contracted dayrate for the West Polaris. The Seller's Credit is due in 2021 and bears an interest rate of 6.5% per annum. During the three-year period following the completion of the current drilling contract with ExxonMobil, the Sellers's credit may be reduced if the average contracted dayrate (net of commissions) for the period, adjusted for utilization, under any replacement contract is below $450,000 until the Seller’s Credit’s maturity in 2021. Should the average dayrate of the replacement contract be above $450,000, the entire $50 million Seller's Credit must be paid to Seadrill upon maturity of the Seller's Credit in 2021.

In addition, Seadrill Polaris may make further contingent payments to Seadrill based upon the West Polaris's operating dayrate. In February 2016, the drilling contract for the West Polaris with ExxonMobil was amended to reduce the dayrate to $490,000, effective January 1, 2016. Under the terms of the acquisition agreement, Seadrill Polaris has agreed to pay Seadrill (a) any dayrate it receives in excess of $450,000 per day, adjusted for daily utilization, through the remaining term, without extension, of the ExxonMobil contract (the "Initial Earn-Out"), and (b) after the expiration of the term of the existing contract until March 2025, 50% of any such excess dayrate, adjusted for daily utilization. tax and agency commission (the "Subsequent Earn-Out").

The Company's interests in OPCO represent its only cash-generating assets. The Company manages its business and analyzes and reports its results of operations in a single global segment. The Company’s fleet is reviewed by the Chief Operating Decision Maker, which is the board of directors, as an aggregated sum of assets, liabilities and activities.

The Company’s Drilling Contracts
In general, each of the Company’sour drilling units is contracted to an oil and gas company to provide offshore drilling services at an agreed dayrate and for a fixed time period. Dayrates can vary, depending on the type of drilling unit and its capabilities, operating expenses, taxes and other factors, including contract length, geographical location and prevailing economic conditions.
An important factor in understanding the Company's revenue is the economic utilization of the drilling unit. For a description of how the Company determines economic utilization, see “—Important Financial and Operational Terms and Concepts—Economic Utilization” below.
In addition to contracted daily revenue, customers may pay mobilization and demobilization fees for drilling units before and after their drilling assignments, and may also reimburse costs incurred by the Company at their request for additional supplies, personnel and other services, not covered by the contractual dayrate. Customers may also pay termination fees.

contracts.
Factors Affecting the Comparability of Future Results
You should consider the following facts when evaluating the Company's historical results of operations and assessing its future prospects:
The Company does not own all of the interests in OPCO. As a result, the Company's cash flow does not include distributions on Seadrill’s interest in OPCO. 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 its 100% ownership of its general partner, Seadrill Operating GP LLC, and (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. The Company controls Seadrill Operating LP through its ownership of Seadrill Operating LP's general partner and Seadrill Capricorn Holdings LLC through its ownership of the majority of its limited liability company interests. Seadrill owns the remaining 42% limited partner interest in Seadrill Operating LP and the remaining 49% limited liability company interest in Seadrill Capricorn Holdings LLC. In July 2014 the Company acquired an additional 28% limited partner interest in Seadrill Operating LP from Seadrill bringing its total ownership interest in Seadrill Operating LP from 30% to 58%. The operating agreements of OPCO require it to distribute all of its available cash each quarter. In determining the amount of cash available for distribution by the Company to its unitholders, the Company's board of directors must approve the amount of cash reserves to be set aside, including reserves for future maintenance and replacement capital expenditures, working capital and other matters. Distributions by OPCO to Seadrill in respect of its ownership interest in OPCO are not available for distribution to unitholders of the Company.
Business combinations between entities under common control. Reorganization of entities under common control is accounted for as if the transfer occurred from the date that both the combining entity and combined entity were both under the common control of Seadrill. Therefore, the Company’s financial statements prior to the date the interests in the combining entity were actually acquired are retroactively adjusted to include the results of the combined entities during the period it was under common control of Seadrill. The acquisitions of the entities that own and operate the T-15, T-16, West Leo and West Sirius in 2013 from Seadrill were accounted for under this method. As of January 2, 2014, the date of the Company's first annual general meeting, Seadrill ceased to control the Company as

defined by GAAP and therefore Seadrill Partners and Seadrill are no longer deemed to be entities under common control. As such acquisitions by the Company from Seadrill subsequent to this date are no longer accounted for under this method.
The size of the Company’s fleet continues to change. The Company's financial statements reflect changes in the size and composition of the Company’s fleet due to certain rig deliveries and contract commencement dates. For instance, the West Capricorn was delivered from the shipyard at the end of 2011, and the contract commencement date occurred in July 2012. Furthermore, during 2013 the Company acquired the T-15, T-16, West Leo and West Sirius, and during 2014 the Company acquired the West Auriga and West Vela, and during 2015 the Company acquired the West Polaris. The Company expects the Company’s fleet will continue to change over time. Furthermore, the Company may grow in the future through the acquisition of additional drilling units as part of the Company's growth strategy.
The Company may enter into different financing agreements. The financing agreements, including the interest expense relating thereto, currently in place may not be representative of the agreements that will be in place in the future. For example, the Company may amend its existing credit facilities or enter into new financing agreements and such new agreements may not be on the same terms as Seadrill’s financing agreements. In connection with the closing of the Company's IPO, the Company entered into a $300 million revolving credit facility with Seadrill as the lender, which the Company refers to as the "sponsor credit facility". In 2014 the sponsor credit facility was reduced to $100 million. In addition, in February 2014, the Company entered into the Senior Secured Credit Facilities and refinanced its debt secured by the West Aquarius, West Capella, West Leo and West Sirius, and in June 2014 entered into the Amended Senior Secured Credit Facilities and refinanced its debt secured by the West Capricorn and the West Auriga and in November 2014, refinanced its debt secured by the WestVela. For descriptions of the Company's current financing agreements, please read "Liquidity and Capital Resources—Borrowing Activities.”

Factors Affecting the Company'sour Results of Operations
The Company believesWe believe the principal factors that will affect itsour future results of operations include:include the following.
the Company’sOur ability to successfully employ itsour drilling units at economically attractive dayrates as contracts expire or are otherwise terminated;terminated.
theOur ability to maintain good relationships with the Company’sour existing customers and to increase the number of customer relationships;relationships.
theThe number and availability of the Company's drilling units in our fleet, including the Company'sour ability to exercise any options to purchase additional drilling units that may arise under the omnibus agreementOmnibus Agreement or otherwise;otherwise.
changesChanges in the Company'sSeadrill Partners LLC's ownership of OPCO;OPCO.
fluctuations and current declineFluctuations in the price of oil and gas, which influence the demand for offshore drilling services;services.
theThe effective and efficient technical management of our drilling units;units.
The Company’sOur ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards;standards.
economic,Economic, regulatory, political and governmental conditions that affect the offshore drilling industry;industry.
accidents,Accidents, natural disasters, adverse weather, equipment failure or other events outside of itsour control that may result in downtime;downtime.
theThe financial condition of Seadrill, its restructuring and its ability to provide services to the Company under certain management, administrative and technical support agreements;
TheOur ability of the Company/OPCO and Seadrill to comply with financing agreements and the effect of the restrictive covenants in such agreementsagreements.
mark-to-market changesChanges in the fair value of our interest rate swaps;swaps.
foreignForeign currency exchange gains and losses;losses.
the Company'sOur access to capital required to acquire additional drilling units or equity interests in OPCO and/or to implement itsour business strategy;strategy.
increasesIncreases in crewing and insurance costs and other operating costs;costs.
theThe level of debt and the related interest expense and amortization of principal; anddeferred loan fees.
theThe level of any distribution on the Company'sSeadrill Partners LLC's common units.
Please read Item 3 “Key"Key Information—Risk Factors”Factors" for a discussion of certain risks inherent in the Company's business.

Important Financial and Operational Terms and Concepts
The Company usesWe use a variety of financial and operational terms and concepts when analyzing itsour performance. These include the following:
ContractedContract Revenues and Dayrates.
In general, each of the Company’swe contract our drilling units is contracted for a fixed term to an oil and gas companycompanies to provide offshore drilling services at an agreed dayrate. dayrate for a specified contact term. Dayrates can vary, depending on the type of drilling unit and its capabilities, contract length, geographical location, operating expenses, taxes and other factors such as prevailing economic conditions. We do not provide "turnkey" or other risk-based drilling services to the customer. Instead, we provide a drilling unit and rig crews and charge the customer a fixed amount per day regardless of the number of days needed to drill the well. The customer bears substantially all the ancillary costs of constructing the well and supporting drilling operations, as well as most of the economic risk relative to the success of the well.
Where operations are interrupted or restricted due to equipment breakdown or operational failures, we do not generally receive dayrate compensation for the period of the interruption in excess of contractual allowances. Furthermore, the dayrate we receive can be reduced in

instances of interrupted or suspended service due to, among other things, repairs, upgrades, weather, maintenance, force majeure or requested suspension of services by the customer and other operating factors.
However, contracts normally allow for compensation when factors beyond our control, including weather conditions, influence the drilling operations and, in some cases, for compensation when we perform planned maintenance activities. In some of our contracts, we are entitled to cost escalation to compensate for industry specific cost increases as reflected in publicly available cost indexes.
We may receive lump sum or dayrate based fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to the start of drilling services. In some cases, we may also receive lump sum or dayrate based fees for demobilization upon completion of a drilling contract. We recognize revenue for mobilization, capital upgrades and non-contingent demobilization fees on a straight-line basis over the expected contract term. We recognize revenue for contingent demobilization fees as earned upon completion of the contract.
Our contracts may generally be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for an extended period because of a breakdown of major rig equipment, "force majeure" or upon the occurrence of other specified conditions. Some contracts include provisions that allow the customer to terminate the contract without cause for a specified early termination fee.
A drilling unit willmay be “stacked”"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 operational and typically retains most of its crew and 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.
To the extent that the Company’s operations are interrupted due to equipment breakdown or operational failures, the Company does not generally receive dayrate compensation for the period of the interruption in excess of contractual allowances. Furthermore, the Company’s dayrates 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.
The Company's 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 of time as a result of a breakdown of major rig equipment, “force majeure” or upon the occurrence of other specified conditions.
The terms and conditions of the contracts allow for compensation when factors beyond the Company’s control, including weather conditions, influence the drilling operations and, in some cases, for compensation when the Company performs planned maintenance activities. In many of the Company’s contracts, the Company is entitled to cost escalation to compensate for industry specific cost increases as reflected in publicly available cost indices. In connection with drilling contracts, the Company may receive lump sum fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to commencement of drilling services. These up-front fees are recognized as revenue over the original contract term, excluding any extension option periods.
In some cases, the Company may receive lump sum non-contingent fees or dayrate based fees from customers for demobilization upon completion of a drilling contract. Non-contingent demobilization fees are recognized as revenue on a straight line basis over the original contract term, excluding any extension option periods. Contingent demobilization fees are recognized as earned upon completion of the drilling contract.
Fees received from customers under drilling contracts for capital upgrades are deferred and recognized over the remaining contract term, excluding any extension option periods not exercised.
In certain countries, in which the Company operates, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on the Company'sour revenues. The Company generally recordsWe record tax-assessed revenue transactions on a net basis in the consolidated and combined carve-out statement of income.
Other revenues. 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 associated with the Company's rights to receive are resolved. Other revenues also include revenues earned within the Company's Nigerian service company relatingoperation support fees charged to certainSeadrill for onshore support services including the provision of onshore and offshore personnel.provided in Nigeria.
Economic Utilization.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. In arriving at economic utilization, the Company has taken into account certain contractual elements that generally exist in
If a drilling unit earns its drilling contracts. For example, drilling contracts generally provide for a repair allowance for preventive maintenance or repair of equipment, which could range between 18 to 48 hours per month. Such allowance varies from contract to contract, and the Company may be compensated at the full operating dayrate or atthroughout a reducedreporting 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 dayrate forrate. In such general repair allowance.instances economic utilization reduces below 100%.
In addition, drilling contracts typically provide forExamples of situations where the drilling unit would operate at reduced operating dayrates, such as,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. Operating at these reduced rates impacts the economic utilization of the rig. The Company then use this metric to determine if changes in the operations of a rig should be implemented to increase economic utilization.
Vessel and Rig Operating Expenses. 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 as well as costs related to onshore personnel in various locations where the Company operates the rigs and are expensed as incurred.
Amortization of Favorable Contracts. Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition less accumulated amortization. The amortization is recognized in the statement of operations under "amortization of favorable contracts". The amounts of these assets are amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.
Reimbursable Revenues and Expenses.Expenses
Reimbursable revenues are revenues that constitute reimbursements from the Company’sour customers for reimbursable expenses. Reimbursable expenses are expenses the Company incurswe 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.
MobilizationOther Operating Income
Other operating income primarily relates to revaluation of contingent consideration and Demobilization Expenses. Mobilization costs incurredgains on sale of assets.
Revaluation of contingent consideration relates to changes in the estimated fair value of deferred consideration liabilities. These estimates may increase or decrease as partnew market information becomes available.
Gains on sale of a contractassets occur where proceeds received from the transaction are capitalized and recognized as an expense over the original contract term, excluding any extension option periods. Costs related to first time mobilization are capitalized and depreciated over the lifetimein excess of the carrying value of the asset.
Operating Expenses
Operating expenses consist primarily of vessel and rig operating expenses, amortization of favorable contracts, reimbursable expenses, depreciation and amortization and general and administrative expenses.
Vessel and rig operating expenses are costs associated with operating a drilling unit. Theunit that is either in operation or stacked. This includes the personnel costs of relocating drilling unitsoffshore crews, running costs of the rigs, expenditures for repairs and maintenance activities and costs for onshore personnel that are not under contract are expensed as incurred. Demobilization costs are costs relatedprovide operational support to the transferrigs.
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 rigbusiness combination we record an intangible asset equal to its fair value on the date of acquisition. The asset is then amortized on a safe harbor or different geographic area and are expensed as incurred.straight-line basis over its estimated remaining contract term.
General and Administrative Expenses.General and administrative expenses are composed of general overhead, including personnel costs,include management charges from Seadrill, legal and professional fees property costs and other general administration expenses. For the historical periods presented, certain administrative expenses have been carved out from the administrative expenses of Seadrill and allocated or charged to the Company based on rig type, with a greater portion of costs allocated or charged to the larger drilling units compared to the smaller drilling units.

Depreciation and Amortization.Depreciation and amortization costs are based on the historical cost of the Company’sour 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 the Company’sour rigs, when new, is thirty30 years. Costs related to periodic surveys of drilling unitsand other major maintenance projects are capitalized as part of drilling units and amortized over the anticipated period between surveys,covered by the survey or maintenance project, which is generallyup to five years. These costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic surveys and other major maintenance projects are included in depreciation and amortization expense.
Financial Items
Our financial items and other income/expense consist primarily of interest income, interest expense, gain/loss on derivative financial instruments, foreign exchange gain/loss and gain/loss on bargain purchase.
Interest income relates to the amortization of mobilization revenue, interest on cash deposits and interest on insurance receivables.
Interest Expense. The Company's interest expense depends on the overall level of debt, and may significantly increase if the Companywe incursincur 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.
Interest expense may be reduced as a consequence of capitalization of interest expenses relating to drilling units under construction. Interest expense is capitalized during construction of newbuildings basedGains and losses recognized on accumulated expenditures for the applicable project at its current rate of borrowing. The amount of interest expense capitalized in an accounting period is determined by applying an interest rate (“the capitalization rate”)derivative financial instruments reflect various mark-to-market and counter party credit risk adjustments to the average amount of accumulated expenditures for the asset during the period. The capitalization rates used in an accounting period are based on the rates applicable to borrowings outstanding during the period. Amounts beyond the actual interest expense incurred in the period are not capitalized.
The Combined Carve-Out Financial Statements include an allocation of interest expense on Seadrill’s general corporate debt, based upon the fair value of the Company’s fleet in proportion to the fair value of Seadrill’s fleet for periods prior to the Company's IPO. This allocation has not occurred for periods subsequent to its IPO and actual interest expense is included in the consolidated financial statements.
Deferred Charges. Loan related costs, including debt arrangement fees, are capitalized and amortized over the term of the related loan and are included in interest expense.
Impairment of Long-Lived Assets. The carrying value of long-lived assets that are held and used by the Company are reviewed for impairment whenever certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and fair value.
Gain/loss on Interest Rate Swaps. A portion of Seadrill’s mark-to-market adjustments forour interest rate swap derivatives were allocatedagreements, 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 Combined Carve-Out StatementU.S. dollar.
Income Taxes
Income tax expense consists of Operations for periods priortaxes currently payable and changes in deferred taxes assets and liabilities related to our ownership and operation of drilling units and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the Company's IPO on the basiscalculation of the Company’s portion of Seadrill’s floating rate debt. Post IPO any mark-to-market adjustments for interest rate swap derivatives aretaxes is based on specific swaps thatnet income or deemed income, the Company entered into with Seadrill.latter generally being a function of gross revenue.
Cost Inflation
As of March 31, 2016, the average remaining term of the Company's contracts was 2.4 years. The majority of theseour contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of cost inflation on revenues from long termlong-term contracts, most of the Company’sour long term contracts include escalation provisions. These provisions allow the Company to adjust the contractual dayrates each year based on stipulated cost increases, including wages, insurance and maintenance cost. However, because these escalations are normally performed on an annual basis, the timing and amount awarded as a result of such adjustments may differ from actual cost increases, which could adversely affect the stability of the Company's cash flow and ability to make cash distributions.
Critical Accounting Estimates
The preparation of the Consolidated and Combined Carve-Out Financial Statements requires the Companyus to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. The Company basesWe base these estimates and assumptions on historical experience and on various other information and assumptions that the Company believeswe 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 the Companyus 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”"General information", and Note 2 “Accounting Policies”,"Accounting policies" to the Company's Consolidated and Combined Carve-Out Financial Statements included in this annual report. The Company believes
We believe that the following are the critical accounting estimates used in the preparation of the Consolidated and Combined Carve-Out Financial Statements. In addition, there are other items within the Consolidated and Combined Carve-Out 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 the Company'sour 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.
The Company determinesWe determine the carrying value of theseour assets based on policies that incorporate its estimates, assumptions and judgments relative to the carrying value, remaining useful lives and residual values. TheThese assumptions and judgments the Company uses in determining the estimated useful lives of its drilling units 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 materiallysignificantly different net bookcarrying values of itsfor our drilling units andwhich 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. The Company re-evaluatesWe re-evaluate the remaining useful lives of itsour drilling units as and when certain events occur which may directly impact itsour assessment of their remaining useful lives and includelives. This includes changes inthe operating condition or functional capability andof our rigs as well as market and economic factors.
The carrying values of the Company'sour long-lived assets are reviewed for impairment wheneverwhen certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. The Company assessesrecoverable. We assess recoverability of the carrying value of thean 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 analyses areanalysis is based on expected costs, utilization and dayrates for the estimated remaining useful lives of the asset or group of assets being assessed. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not recoverable.
During the years ended December 31, 2017, 2016, and 2015, we identified indicators that the carrying value of our drilling units may not be recoverable. Such indicators included the reduction in new contract opportunities, fall in market dayrates and contract terminations. We assessed recoverability of our drilling units by first evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilizations of the units. The estimated undiscounted future net cash flows were found to be greater than the carrying value of our drilling units, with sufficient headroom. As a result, we did not need to proceed to assess the fair values of our drilling units, and no impairment charges were recorded for the years ended December 31, 2017, 2016, and 2015.
Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by the Company'sour assets, and reflect management’sour 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 itsour assets andwhich could materially affect itsour 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. The Company doesWe do not conduct business or operate in the Republic of the Marshall Islands, and iswe are 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 iswe 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. The Company recognizesWe recognize tax liabilities based on itsour assessment of whether its tax positions are more likely than not sustainable, based on the technical merits and considerations of the relevant taxing authority’sauthorities widely understood administrative practices and precedence.
Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Recently Adopted and Issued Accounting Standards
The Company has recognizedFor a deferred tax liability due to a change in tax legislation in Nigeria which required a retrospective adjustment in 2015. The Nigerian tax regime has changed from a deemed profit percentagediscussion of revenue to an actual profit regime using 30% of net income. As such, a deferred tax liability arises on the difference between book valuerecently adopted and the assumed tax write-down value of the West Capella, the Company's drilling unit operating in Nigeria. The deferred tax liability is expected to reverse in approximately 2020. The Company has interpreted the legislation retrospectively when calculating the tax basis of the West Capella drilling unit, and estimates have been used in the calculations. No formal guidance however has been provided by the Nigerian tax authorities in this regard. Therefore, if a different interpretation were to berecently issued it may have a material impact on the deferred tax liability recognized.

Business Combinations

The Company accounts for business combinations using the acquisition method of accounting which requires that the assets acquired and liabilities assumed be recorded at the date of acquisition at their respective fair values. Any excess of the fair value of consideration given and the fair value of any non-controlling interest over the fair values of the identifiable assets and liabilities acquired is recorded as goodwill. When the fair value of the identifiable assets and liabilities acquired is in excess of the fair value of consideration given and the fair value of any non- controlling interest, the Company recognizes in earnings a gain on bargain purchase. Before recognizing any gain on bargain purchase, the Company reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed, and recognizes any additional assets or liabilities that are identified in that review. The determination of the estimated fair values of acquired tangible and intangible assets, as well as the useful economic life ascribed to finite lived assets, requires the use of significant judgment.

When acquiring drilling units with attached customer contracts the Company has recognized the value of the drilling unit separately from the associated contract. The drilling unit has been valued at fair value which was estimated using an income approach based upon market participant assumptions and prevailing market conditions. The fair value of the drilling contract has been also been assessed separately using an 'excess earnings' technique where the terms of the contract are assessed relative to current prevailing market rates. The assumptions and judgments made by management are subjective and derived from unobservable inputs. The use of different judgments and assumptions to those used by the Company could result in a materially different valuation of acquired assets, which could have a material effect on the Company’s results of operations.

The following critical accounting estimates regarding business combinations significantly impacted the Company's business during the year ended December 31, 2015 relatestandards, please see Note 2 "Accounting policies" to the Polaris Acquisition which closed on June 19, 2015.

During the year ended December 31, 2015, the Company recognized a gain on bargain purchase from the Polaris Acquisition of $9.3 million, which is the excess of the total identifiable net assets acquired over the consideration transferred. The key accounting estimates in regards to this transaction are (i) valuation of the drilling unit; (ii) valuation of the drilling contract; and (iii) valuation of the deferred and contingent considerations recognized.

(i) The West Polaris drilling unit has been valued at fair value separately from the related drilling contract. The estimated fair value of the drilling unit was derived using an income approach with market participant based assumptions, including the Company's expectations around dayrates, drilling unit utilization, operating costs, capital and long term maintenance expenditures and applicable tax rates. The cash flows were estimated over the remaining useful economic life of the drilling unit. At the acquisition date, cash flows were discounted using an estimated market participant weighted average cost of capital of 8.5%. At the acquisition date, the fair value of the drilling unit recognized is $575.3 million. As detailed below, if a larger/(smaller) value was attributed to the drilling unit, then a larger/(smaller) gain on bargain purchase would have been recognized on acquisition, and there would be higher/(lower) depreciation expenses recognized in future periods.

(ii) The fair value of the drilling contract has been assessed separately. The contract was valued using an “excess earnings” technique where the terms of the contract are assessed relative to current market conditions. The value of the contract related intangible was determined by means of calculating the incremental cash flows arising over the life of the contract compared with a contract with terms at prevailing market rates. The fair value of the favorable contract has been recognized as an intangible asset totaling $124.3 million. This intangible asset will be amortized over the remaining contract period until March 2018. As detailed below, if a larger/(smaller) value was attributed to this intangible asset, then a larger/(smaller) gain on bargain purchase would have been recognized on acquisition, and there would be higher/(lower) amortization expenses recognized in future periods.

(iii) At the time of acquisition, the fair value of contingent consideration consisted of the fair value of the Initial Earn-Out of $61.8 million, the fair value of the Subsequent Earn-Out of $33.5 million and the fair value of the Seller's Credit of $44.6 million. The fair value was determined using future estimated contract revenues based upon estimates of re-contracted dayrate, average utilization, less any expected commissions and taxes. The contingent consideration has been discounted to present value using a weighted average cost of capital of 8.5%.

At the time of acquisition, the Initial Earn-Out has a maximum possible outcome (based on undiscounted cash flows) of $67.6 million, assuming the West Polarisachieves 100% utilization for the remainder of the ExxonMobil contract and the contracted dayrate was not re-negotiated. The lowest possible outcome of the Initial Earn-Out is nil, assuming the utilization for the West Polaris is 0% and or the contracted dayrate is re-negotiated to less than $450 thousand per day. It is not possible to calculate a range of possible outcomes for the Subsequent Earn-Out as it is impossible to determine a maximum possible re-contract dayrate and as such the maximum amount of the payment is unlimited. The lowest possible outcome for the subsequent earn-out is nil, assuming the utilization for the West Polaris is 0%, and or the re-contracted dayrate is less than $450 thousand per day. The range of undiscounted outcomes for the Seller's Credit varies from nil to $50.0 million.

If the fair value recognized for the deferred contingent consideration was higher/(lower), then a lower/(higher) gain on bargain purchase would have been recognized on acquisition.

The fair value of the deferred contingent consideration is reassessed at each period end. At the acquisition date, the Company initially recognized a gain on bargain purchase from the Polaris Acquisition of $39.6 million, which was the excess of the total identifiable net assets acquired over the consideration transferred. In February 2016, customer negotiations were concluded and the customer contract for the West Polaris was adjusted to $490 thousand per day. This adjustment provided further information regarding the value of the favorable contract intangible asset and the Initial Earn-Out. The information is further evidence of a condition that existed at the time of the acquisition and therefore should be accounted for as a measurement period adjustment. The favorable contract intangible asset and the Initial Earn-Out liability were reduced by $47.9 million and $17.6 million, respectively. If the fair value of the deferred contingent consideration is determined to be higher/(lower) in the future, then an equivalent loss/(gain) will be recognized in the statement of operations.

An approximate impact of a 5% variation in long term dayrate and a 0.5% variation in the discount factor, on the valuation and resulting variation in the gain on bargain purchase relating to the Polaris acquisition is tabled below:
(In $ millions)Fair Value of Drilling UnitFavorable ContractDeferred Contingent ConsiderationGain on Bargain Purchase
Long term dayrate +5%57.7
—
9.2
48.5
Long term dayrate -5%(57.7)—
(31.2)(26.5)
Discount factor + 0.5%(22.4)(0.3)(2.3)(20.2)
Discount factor - 0.5%23.9
0.3
2.3
21.6

New Accounting Pronouncements
Refer to Note 2 “Accounting policies” of the Consolidated and Combined Carve-Out Financial Statements included elsewhere in this annual report.


A.     Operating Results

Year Ended December 31, 20152017 Compared to Year Ended December 31, 2014

2016
The following table summarizes the Company'sour operating results for the years ended December 31, 20152017 and 2014:2016:
Year Ended December 31, Increase/DecreaseYear Ended December 31, Increase/(Decrease)
2015 2014 $ %2017 2016 $ %
(US$ in millions)          
Operating revenues:              
Contract revenues$1,603.6
 $1,302.7
 $300.9
 23.1 %$1,007.7
 $1,356.4
 $(348.7) (25.7)%
Reimbursable revenues49.9
 39.9
 10.0
 25.1 %17.7
 32.8
 (15.1) (46.0)%
Other revenues88.1
 —
 88.1
 100.0 %103.0
 211.1
 (108.1) (51.2)%
Total operating revenues1,741.6
 1,342.6
 399.0
 29.7 %1,128.4
 1,600.3
 (471.9) (29.5)%
              
Other operating income:       
Revaluation of contingent consideration89.9
 —
 89.9
 — %
Gain on sale of assets0.8
 —
 0.8
 — %
Total other operating income90.7
 —
 90.7
 — %
       
Operating expenses:              
Vessel and rig operating expenses495.5
 425.0
 70.5
 16.6 %(345.4) (373.9) 28.5
 7.6 %
Amortization of favorable contracts66.9
 14.8
 52.1
 352.0 %(74.4) (70.6) (3.8) (5.4)%
Reimbursable expenses45.7
 37.9
 7.8
 20.6 %(16.1) (30.2) 14.1
 46.7 %
Depreciation and amortization237.5
 198.7
 38.8
 19.5 %(274.9) (266.3) (8.6) (3.2)%
General and administrative expenses52.3
 51.4
 0.9
 1.8 %(44.8) (41.2) (3.6) (8.7)%
Total operating expenses897.9
 727.8
 170.1
 23.4 %(755.6) (782.2) 26.6
 3.4 %
Net operating income$843.7
 $614.8
 $228.9
 37.2 %
Operating income$463.5
 $818.1
 $(354.6) (43.3)%
              
Financial items:              
Interest income9.8
 3.7
 6.1
 164.9 %15.7
 11.5
 4.2
 36.5 %
Interest expense(192.5) (140.9) (51.6) 36.6 %(179.1) (180.0) 0.9
 0.5 %
(Loss) / gain on derivative financial instruments(82.9) (124.9) 42.0
 (33.6)%
Currency exchange gain / (loss)1.6
 (3.3) 4.9
 (148)%
Gain on bargain purchase9.3
 —
 9.3
 100.0 %
Loss on derivative financial instruments(13.9) (18.0) 4.1
 22.8 %
Currency exchange gain0.9
 0.6
 0.3
 50.0 %
Other financial items(11.5) —
 (11.5) — %
Total financial items(254.7) (265.4) 10.7
 (4.0)%(187.9) (185.9) (2.0) (1.1)%
Income before income taxes589.0
 349.4
 239.6
 68.6 %275.6
 632.2
 (356.6) (56.4)%
Income taxes(100.6) (34.8) (65.8) 189.1 %(40.3) (86.5) 46.2
 53.4 %
Net Income$488.4
 $314.6
 $173.8
 55.2 %$235.3
 $545.7
 $(310.4) (56.9)%
Net income attributable to the non-controlling interest$(231.2) $(176.4) $(54.8) 31.1 %$(94.1) $(264.7) $(170.6) (64.5)%
Net income attributable to Seadrill Partners LLC$257.2
 $138.2
 $119.0
 86.1 %$141.2
 $281.0
 $(139.8) (49.8)%
Contract revenues
Contract revenues increased by $300.9 million, or 23.1%, to $1,603.6were $1,007.7 million for the year ended December 31, 2015, from $1,302.72017 (December 31, 2016: $1,356.4 million).
The $348.7 million in the year ended December 31, 2014. The increaseor 25.7% decrease, was primarily due to contract revenues from the West AurigaLeo whichbeing 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 acquireddue to improved economic utilization on March 21, 2014, contract revenues from the West Vela, which was acquired on November 4, 2014, and contract revenues from the West Polaris, which was acquired on June 19, 2015. The acquisitions of the West Auriga, T-15 and T-16 , West Vela and West Polaris contributed approximately $56.4 million, $183.4 million and $123.3 million respectively to the increase compared to the year ended December 31, 2014. Lower downtime on the West Aquarius in thethe year ended December 31, 2015 compared to the year ended December 31, 2014 also contributed to an increase of approximately $65.7 million. Lower downtime on the West Capricorn contributed to the increase in revenues by approximately $33.5 million. The increase was partly offset by a decrease in contract revenues of approximately $122.2 million relating to the West Sirius which came off contract in April 2015, and is now receiving a termination fee rather than the full dayrate. The termination fee is included in "Other revenues"($16 million). Also offsetting

the increase was a decrease of approximately $38.5 million in initial contractContract revenues from the West Vencedor, which was stacked after its contract ended in June 2015, before commencing a short-term contract in Myanmar in late 2015. The remaining movementsdo not include early termination payments, these are due to variations in the operations of the drilling units.classified within "other revenues" (see below).

The following table summarizes our fleet's average daily revenues and economic utilization percentage by drilling unit type of the Company’s fleet for the periods presented:
Year Ended December 31,Year Ended December 31,
2015 20142017 2016
Average
Daily Revenues (1)
 
Economic
Utilization (2)
 
Average
Daily Revenues (1)
 
Economic
Utilization (2)
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)
$551,590
 93.0% $444,149
 83.2%2 $459,164
 97.3% 3 $555,193
 99.3%
Drillship$608,444
 98.7% $578,856
 98.3%4 $521,487
 98.6% 4 $531,620
 94.5%
Tender rigs$148,634
 98.5% $154,611
 98.0%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, for each unit of that type, 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.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.Sirius and ExxonMobil for the West Capella.


Reimbursable revenues
Reimbursable revenues increased by $10.0 million, or 25.1%, to $49.9were $17.7 million for the year ended December 31, 2015, from $39.92017 (December 31, 2016: $32.8 million). The decrease of $15.1 million for the year ended December 31, 2014. The increase isor 46.0%, was due to additionalless equipment purchased on behalf of customers, for which we have been reimbursed.

Other revenues
Other revenues were $88.1$103.0 million for the year ended December 31, 2015, compared2017 (December 31, 2016: $211.1 million).
The $108.1 million or 51.2% decrease was primarily due to nilthe conclusion of early termination payments for the year ended December 31, 2014. DuringWest Sirius in July 2017 ($48 million) and for the year ended December 31, 2015, we earned otherWest Capella in April 2017 ($55 million). The residual decrease was due to lower revenues for services provided to Seadrill within our Nigerian service company, billed toas Seadrill for certain services, including the provision of onshore and offshore personnel, which we provided to Seadrill’shad fewer rigs operating in Nigeria ($5 million).
The West JupiterSirius previously had a contract in Gulf of Mexico which was terminated by BP in July 2015 and West Saturn drilling rigs, amounting the termination period was from July 2015 to approximately $13.4 million. There were no such services providedJuly 2017. We therefore received a full year of early termination revenue in the year ended December 31, 2014. In addition2016 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 fee relatingperiod 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.West Sirius
Revaluation of $297,000 per day, or $74.7contingent consideration
There was gain on revaluation of contingent consideration of $89.9 million for the year ended December 31, 20152017 (December 31, 2016: $nil).
The gain is classified within other revenues.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
RigVessel and rig operating expenses increased by $70.5 million, or 16.6%, to $495.5were $345.4 million in the year ended December 31, 2015, from $425.02017 (December 31, 2016: $373.9 million).
The $28.5 million in the year ended December 31, 2014. This increaseor 7.6% decrease was primarily due to operating expenses ofidle time on the West Auriga,Leo which was acquired on March 21, 2014, operating expenses of($28 million) and the West VelaAquarius, which was acquired ($4 million).
These decreases were offset by higher costs on November 4, 2014,the West Capricorn as it returned to operations in the second half of the year ($6 million) and operating expenses ofon the West Polaris, which was acquired on June 19, 2015. The acquisitions as a result of the West Auriga, West Velarig move from Angola to Equatorial Guinea and early demobilization ($6 million).West Polaris contributed approximately $7.1 million, $43.9 million and $36.3 million respectively
The remaining decrease is related to the increasea reduction in vessel and rig operating expenses for the year ended December 31, 2015, compared to the year ended December 31, 2014. This was partially offset by the decrease in operating costs of $21.3 million relating to the West Sirius, which was stacked beginning in April 2015 after its drilling contract was cancelled. Lower operating costs across the restother operating rigs as a result of the fleet as part of the Seadrill cost reduction plan also contributed to the offset in increased rig operating expenses for the year ended December 31, 2015, compared to the year ended December 31, 2014.

saving initiatives ($9 million).
Amortization of favorable contracts
Amortization of favorable contracts increased to $66.9was $74.4 million for the year ended December 31, 2015 from $14.82017 (December 31, 2016: $70.6 million).
The $3.8 million in the year ended December 31, 2014. Theor 5.4% increase was duerelated to the favorable contracts recognized on the purchase of the WestAuriga in March 2014, and the acquisition of the West Vela Polarisin November 2014, and the acquisition of the West Polaris in June 2015, each of which contributed $1.7 million, $28.7 million and $21.7 million, respectively. The favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition. These intangibles are amortized on a straight-line basis over the remaining completing its contract period.sooner than expected.

Reimbursable expenses

Reimbursable expenses increased by $7.8 million, or 20.6%, to $45.7were $16.1 million for the year ended December 31, 2015 from $37.92017 (December 31, 2016: $30.2 million). The $14.1 million or 46.7% decrease is in line with the year ended December 31, 2014. The increase was due to additional equipment purchased on behalf of customers, for which we have been reimbursed.reduction in reimbursable revenue.

Depreciation and amortization
Depreciation and amortization expenses increased by $38.8 million, or 19.5%, to $237.5were $274.9 million for the year ended December 31, 2015, from $198.72017 (December 31, 2016: $266.3 million). The $8.6 million for the year ended December 31, 2014. Theor 3.2% increase was primarily due to drilling unit upgrades and maintenance projects capitalized and depreciated during the acquisitions of the West Auriga and West Vela in 2014, which contributed approximately $7.2 million and $17.1 million to the increase respectively. The West Polaris also contributed to the increase by $14.6 million, as it was acquired on June 19, 2015.

year.
General and administrative expenses
General and administrative expenses increased by $0.9 million, or 1.8%, to $52.3were $44.8 million for the year ended December 31, 2015, from $51.42017 (December 31, 2016: $41.2 million). The $3.6 million or 8.7% increase was primarily due to higher legal and professional costs not related to the credit facility amendments.
Interest income
Interest income was $15.7 million for the year ended December 31, 2014.2017 (December 31, 2016: $11.5 million). The $4.2 million or 36.5% increase wasis due to higher administrative management fees charged by Seadrill due to thecash balances and increased size of the Company's fleet, offset in part by reductions in recharges due to cost efficiencies achieved and passed through by Seadrill.

interest rates.
Interest expense
Interest expense increased by $51.6 million, or 36.6%, to $192.5was $179.1 million for the year ended December 31, 2015, compared to $140.92017 (December 31, 2016: $180.0 million). The impact of a reduction in average amount of debt outstanding during 2017 was was offset by higher LIBOR rates and increased margins on our bank facilities following the insulation transaction in August 2017.
Derivative financial instruments
Derivative financial items resulted in an expense of $13.9 million for the year ended December 31, 2014.2017 (December 31, 2016: expense of $18.0 million). The increase$4.1 million or 22.8% decrease in the expense was primarily due to thea smaller increase in the average outstanding debt, resulting from the acquisition of the West Vela forward interest rate curve in November 2014, the acquisition of the West Polaris2017 than in June 2015, and the debt issued under the Company's Amended Senior Secured Credit Facilities, consisting of a $1002016.
Currency exchange gain
Gain on foreign currency exchange was $0.9 million revolving credit facility and $2.8 billion term loan in February and June 2014.

Loss on derivative financial instruments
Infor the year ended December 31, 2015, the Company recognized losses from derivative financial instruments of $82.9 million compared to losses of $124.9 million2017 (December 31, 2016: $0.6 million). The gain is broadly in 2014. The loss on the derivatives during 2015 was due to a decrease in short and long term interest rates which reduced the mark to market value of the interest rate swap liabilities. The corresponding fair market value of the interest rate swaps was an $82.0 million liability as at December 31, 2015 compared to a liability of $50.1 million as at December 31, 2014. The unrealized portion of the loss on the derivatives during the year was $31.9 million and the realized portion of the loss on derivatives during the year was $51.1 million. Inline with the prior year the unrealized loss was $99.1 million and the realized loss was $25.8 million.

Gain on bargain purchase
A gain on bargain purchase of $9.3 million was recognizedpredominantly occurred from foreign currency denominated transactions in the year ended December 31, 2015 as a result of the acquisition of the West Polaris in June 2015. The gain has been attributed to the Company's belief that Seadrill may obtain additional value through the transaction, over and above the consideration transferred.  This may include, but is not limited to, the potential future realization of value through Seadrill's investments in Seadrill Partners. These investments include direct ownership interests, common and subordinated units and incentive distribution rights.  As a result of these investments Seadrill has a continuing interest in the growth and success of Seadrill Partners. Please refer to "Note 2 - Accounting policies" and "Note 3 - Business Acquisitions" of the notes to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

Africa.
Other financial items
Other financial items reported in the income statement include the following items:
  
Year Ended December 31,
(US$ millions)2015 2014
Interest income$9.8
 $3.7
Currency exchange gain (loss)1.6
 (3.3)
Total other financial items$11.4
 $0.4
Other financial items increased by $11.0 million to $11.4were an expense of $11.5 million for the year ended December 31, 2015, compared2017 (December 31, 2016: nil). The increase was due to $0.4debt 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, 2014. The increase is related to an increase in interest earned on receivables relating to the West Vela 2017 (December 31, 2016: $86.5 million) and an increase in the gains of foreign currency translation.

Income taxes

Income tax expense was $100.6 million and $34.8 million, and the Company'sour effective income tax rate was 17.1%14.6% and 10.0%13.7% for the years ended December 31, 20152017 and 20142016 respectively. The increase in the Company's effective income tax rate was partiallydecrease is primarily due to the changelower operating income in taxing jurisdictions in which the Company generated taxable profits. The increase was also due to the recognition of a deferred tax liability of $43.7 million during the year ended December 31, 2015 due to a change in tax legislation in Nigeria which required retrospective adjustment in 2015. The Nigerian tax regime has changed from a deemed profit percentage of revenue to an actual profit regime taxing 30% of net income. As such a deferred tax liability arises on the difference between the book value and the assumed tax write-down value of the West Capella, our drilling unit operating in Nigeria. The deferred tax liability is expected to reverse in approximately 2020. This was partially offset by an increase of $18.2 million within deferred tax assets relating2017 compared to the termination of the bareboat agreement for the West Sirius, whereby the termination payment revenue is taxable upon signing the termination agreement but recognized as revenue rateably under U.S. GAAP.year ended December 31, 2016. Please refer to "Note 2 - Accounting policies" and "Note 5 – Taxation" of the notes "Taxation" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
Net income attributable to non-controlling interest
Net income attributable to non-controlling interest increased by $54.8 million, or 31.1%, to $231.2 million for the year ended December 31, 2015, which represents 47.3% of net income. For the year ended December 31, 2014 net income attributable to non-controlling interest was $176.4 million, or 56.1% of net income. The decrease in the relative proportion of net income which is attributable to the non-controlling interest is as a result of the acquisition of an additional 28% of the limited partner interests in Seadrill Operating by Seadrill Partners on July 21, 2014. There is an equal and opposite impact on net income attributable to Seadrill Partners LLC Members.
As a result of the acquisition, the Company’s limited partner interest in Seadrill Operating increased from 30% to 58%, decreasing the net income attributable to non-controlling interest.

Year Ended December 31, 20142016 Compared to Year Ended December 31, 20132015
The following table summarizes the Company'sour operating results for the years ended December 31, 20142016 and 2013:
2015:
($US in millions)Year Ended December 31, Increase/DecreaseYear Ended December 31, Increase/(Decrease)
2014 2013 $ %2016 2015 $ %
Operating revenues:              
Contract revenues$1,302.7
 $1,047.1
 $255.6
 24.4 %$1,356.4
 $1,603.6
 $(247.2) (15.4)%
Reimbursable revenues39.9
 11.4
 28.5
 250.0 %32.8
 49.9
 (17.1) (34.3)%
Other revenues—
 5.8
 (5.8) (100.0)%211.1
 88.1
 123.0
 139.6 %
Total operating revenues1,342.6
 1,064.3
 278.3
 26.1 %1,600.3
 1,741.6
 (141.3) (8.1)%
              
Operating expenses:              
Vessel and rig operating expenses425.0
 375.2
 49.8
 13.3 %(373.9) (495.5) 121.6
 24.5 %
Amortization of favorable contracts14.8
 —
 14.8
 100.0 %(70.6) (66.9) (3.7) (5.5)%
Reimbursable expenses37.9
 10.6
 27.3
 257.5 %(30.2) (45.7) 15.5
 33.9 %
Depreciation and amortization198.7
 141.2
 57.5
 40.7 %(266.3) (237.5) (28.8) (12.1)%
General and administrative expenses51.4
 49.6
 1.8
 3.6 %(41.2) (52.3) 11.1
 21.2 %
Total operating expenses727.8
 576.6
 151.2
 26.2 %(782.2) (897.9) 115.7
 12.9 %
Net operating income$614.8
 $487.7
 $127.1
 26.1 %$818.1
 $843.7
 $(25.6) (3.0)%
              
Financial items:              
Interest income3.7
 4.4
 (0.7) (15.9)%11.5
 9.8
 1.7
 17.3 %
Interest expense(140.9) (92.2) (48.7) 52.8 %(180.0) (192.5) 12.5
 6.5 %
Loss / (Gain) on derivative financial instruments(124.9) 49.9
 (174.8) (350.3)%
Currency exchange loss(3.3) (1.2) (2.1) 175.0 %
Loss on derivative financial instruments(18.0) (82.9) 64.9
 78.3 %
Currency exchange gain0.6
 1.6
 (1.0) 62.5 %
Gain on bargain purchase—
 9.3
 (9.3) 100.0 %
Total financial items(265.4) (39.1) (226.3) 578.8 %(185.9) (254.7) 68.8
 27.0 %
Income before income taxes349.4
 448.6
 (99.2) (22.1)%632.2
 589.0
 43.2
 7.3 %
Income taxes(34.8) (33.2) (1.6) 4.8 %(86.5) (100.6) 14.1
 14.0 %
Net Income$314.6
 $415.4
 $(100.8) (24.3)%$545.7
 $488.4
 $57.3
 11.7 %
Net income attributable to the non-controlling interest$(176.4) $(271.0) $94.6
 (34.9)%$(264.7) $(231.2) $33.5
 14.5 %
Net income attributable to Seadrill Partners LLC$138.2
 $144.4
 $(6.2) (4.3)%$281.0
 $257.2
 $23.8
 9.3 %
Contract revenues
Contract revenues increased by $255.6 million, or 24.4%, to $1,302.7were $1,356.4 million, for the year ended December 31, 2014, from $1,047.12016 (December 31, 2015: $1,603.6 million). The $247.2 million for the same period in 2013. The increaseor 15.4% decrease was primarily due to the results ofadditional idle units ($300.3 million) and lower dayrates ($13.3 million). The decrease was partially offset by contract revenues from the West AurigaPolaris which was acquired by the Companyon June 19, 2015 ($49.5 million) and higher economic utilization for rigs in March2014 and contributed contractoperation ($17.0 million). Contract revenues of $158.3 million since acquisition, and the results of the West Vela which was acquired in November 2014 and contributed contract revenues of $32.3 million since acquisition. The T-15 and T-16 commenced operations in July 2013 and September 2013, and therefore their full year impact contributed additional contract revenues. An increase in the day rate on the West Capella also contributed to increased contract revenues. This was partly offset by a decrease in contract revenues compared to 2013 for the West Aquarius attributable to the downtime of the rig in the first and fourth quarters of 2014.do not include early termination payments, these are recognized as "other revenues".

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,Year Ended December 31,
2014 20132016 2015
Average Daily
Revenues
 
Economic
Utilization
 
Average Daily
Revenues
 
Economic
Utilization
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)$444,149
 83.2% $464,300
 90.4%3 $555,193
 99.3% 4 $551,590
 93.0%
Drillship$578,856
 98.3% $541,800
 96.9%4 $531,620
 94.5% 4 $608,444
 98.7%
Tender rigs$154,611
 98.0% $154,967
 100.0%3 $116,634
 98.6% 3 $148,634
 98.5%
(1)Average daily revenues are the average revenues for each type of unit, based on the actual days available, for each unit of that type, 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.period for rigs on contract.

(3)
Average daily revenue excludes the termination payments received as part of the termination of the drilling contract by BP for the West Sirius.
Reimbursable revenues
Reimbursable revenues increased by $28.5 million, or 250.0%, to $39.9were $32.8 million, for the year ended December 31, 2014, from $11.42016 (December 31, 2015: $49.9 million). The $17.1 million for the same period in 2013. The increase isor 34.3% decrease was due to additionalless equipment purchased on behalf of customers, for which we have been reimbursed.

Other revenues
During the year ended December 31, 2013, the Company earned otherOther revenues within its Nigerian service company of $5.8 million. The revenues relate to certain services, including the provision of onshore and offshore personnel, which the Company provided to Seadrill’s West Polaris drilling rig while it operated in Nigeria during that period. There were no such services provided$211.1 million for the year ended December 31, 2014.2016 (December 31, 2015: $88.1 million). The $123.0 million or 139.6% increase was primarily due to early termination payments received for the

West Sirius which was terminated in April 2015 ($34.0 million) and the West Capella contract which was terminated in May 2016 ($90.1 million). This increase was partially offset by lower revenues for services provided to Seadrill within our Nigerian service company ($0.9 million).
Vessel and rig operating expenses
RigVessel and rig operating expenses increased by $49.8 million, or 13.3%, to $425.0were $373.9 million, for the year ended December 31, 2014, from $375.22016 (December 31, 2015: $495.5 million). The $121.6 million for the year ended December 31, 2013. The increaseor 24.5% decrease was primarily due to additional idle units ($69.5 million), reduced costs on West Capricorn while on standby rate ($23.9 million) and lower operating costs for vessels in operation ($36.3 million). The decrease was partially offset by the acquisitioninclusion of a full year of operating expenses for the WestAuriga Polaris in March 2014, the acquisition of the West Vela in November 2014, and the full year of expenses of the T-15 and T-16,($8.5 million) which commenced operations in the third quarter of 2013. The increases were partly offset by lower operating costs of thewas acquired on June 19, 2015. West Aquarius due to downtime.

Amortization of favorable contracts
Amortization of favorable contracts increased to $14.8was $70.6 million for the year ended December 31, 2014 from nil in the2016 (December 31, 2015: $66.9 million). The $3.7 million or 5.5% increase relates to a full year ended December 31, 2013. The increase was due to the favorable contracts recognized on the purchaseof amortization of the WestAuriga Polaris in March 2014, and the acquisition of the West Vela in November 2014. The favorable contract. Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition. These intangibles are amortized on a straight-line basis over the remaining contract period.

Reimbursable expenses
Reimbursable expenses increased by $27.3 million, or 257.5%, to $37.9were $30.2 million for the year ended December 31, 2014, from $10.62016 (December 31, 2015: $45.7 million). The $15.5 million in the year ended December 31, 2013. The increaseor 33.9% decrease was due to additionala reduction in equipment purchased on behalf of customers, for which we have been reimbursed.

Depreciation and amortization
Depreciation and amortization increased by $57.5 million, or 40.7%, to $198.7was $266.3 million for the year ended December 31, 2014, from $141.22016 (December 31, 2015: $237.5 million). The $28.8 million in the year ended December 31, 2013. Theor 12.1% increase was primarily due to the acquisition of the West AurigaPolaris in March 2014, the acquisition of the on June 19, 2015.West Vela in November 2014, and depreciation relating to the T-15 and T-16, which had a lower expense in the comparative period as they commenced operations during the third quarter of 2013.


General and administrative expenses
General and administrative expenses increased by $1.8 million, or 3.6%, to $51.4were $41.2 million for the year ended December 31, 2014, from $49.62016 (December 31, 2015: $52.3 million. The $11.1 million or 21.2% decrease was due to a reduction in management fees and overhead costs as part of our cost efficiency program. The decrease was partially offset by the acquisition of the West Polaris on June 19, 2015 ($1.2 million).
Interest income
Interest income was $11.5 million for the year ended December 31, 2013.2016 (December 31, 2015: $9.8 million). The 1.7 million or 17.3% increase was due to higher administrative management fees charged by Seadrill dueis related to the increased size ofinterest earned on insurance receivables relating to the Company's fleet.

West Aquarius.
Interest expense
Interest expense increased by $48.7 million, or 52.8%, to $140.9was $180.0 million for the year ended December 31, 2014, compared to interest expense of $92.22016 (December 31, 2015: $192.5 million). The $12.5 million in the year ended December 31, 2013. The increase in the interest expenseor 6.5% decrease was primarily due to lower debt balances following the increaserepayments in the outstandingyear ($17.0 million) offset by a full year of interest on the debt which was driven byassociated with the acquisition of the West AurigaPolaris in March 2014, the acquisition of the West Vela in November 2014, and the debt issued under the new Amended Senior Secured Credit Facilities.($4.3 million).

Loss/gainLoss on derivative financial instruments
In the year ended December 31, 2014, the Company recognized losses from derivative instruments of $124.9 million compared to gains of $49.9 million in 2013. The loss on the derivatives during 2014derivative financial instruments was due to adverse movements in future expected interest rates which impact the interest rate swaps, compared to favorable movements in 2013. The corresponding fair market value of the interest rate swaps was a $50.1 million liability as at December 31, 2014 compared to an asset of $42.4 million as at December 31, 2013. The unrealized portion of the loss on the derivatives during 2014 was $99.1 million and the realized portion of the loss on derivatives during 2014 was $25.8 million. In 2013, the unrealized gain was $60.2 million and the realized loss was $10.3 million.
The decrease was related to an interest rate swap gain incurred by Seadrill in 2013, which was charged to the Company on a back to back basis under the agreements with Seadrill.

Other financial items
Other financial items reported in the income statement include the following items:
  
Year Ended December 31,
(US$ millions)2014 2013
Interest income3.7
 4.4
Currency exchange loss(3.3) (1.2)
Total other financial items0.4
 3.2

Other financial items decreased by $2.8 million, or 87.5%, to $0.4$18.0 million for the year ended December 31, 2014, compared2016 (December 31, 2015: $82.9 million). The $64.9 million or 78.3% decrease relates to $3.2movements in the mark to market valuation of the Company's interest rate swaps on variable rate debt. Included in the $18.0 million loss for the year ended December 31, 2016 is an out of period gain of $21.4 million recognized in relation to the inclusion of counterparty credit risk in the determination of the fair value of these interest rate swap agreements. Please refer to Item 11 "Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risks," for further information.
Currency exchange gain
Gain on foreign currency exchange was $0.6 million for the year ended December 31, 2013.2016 (December 31, 2015: gains of $1.6 million). The $1.0 million or 62.5% decrease is relateddue to a decrease in interest earnedthe devaluation of the U.S. Dollar relative to foreign currencies.
Gain on cash balances and an increasebargain purchase
A $9.3 million gain on bargain purchase was recognized in the lossesyear ended December 31, 2015 as a result of foreign currency translation, primarily relating tothe acquisition of the West CapellaPolaris in June 2015. Please refer to Note 2 "Accounting policies" and West Leo operatingNote 3 "Business acquisitions" to the Consolidated Financial Statements included in Nigeria and Ghana respectively.this annual report.

Income taxes
Income tax expense was $34.8$86.5 million and $33.2 million,for the year ended December 31, 2016 (December 31, 2015: $100.6 million) and the Company's effective income tax rate was 10.0%13.7% and 7.5%17.1% for the years ended December 31, 20142016 and 20132015, respectively. The increasedecrease in the Company's effective income tax rateexpense was primarily due to a deferred tax benefit arising from the change in taxing jurisdictions in whichreversal of deferred tax liability related to the Company's drilling units operated and/or were owned.

Net income attributable to non-controlling interest
Net income attributable to non-controlling interest decreased West Capella. The decrease is partially offset by $94.6 million, or 34.9%, from $271.0 million forthe additional uncertain tax position recorded during the year ended December 31, 2013,2016. Please refer to $176.4 million for the year ended December 31, 2014. This was due primarily dueNote 5 "Taxation" to the acquisition by the Company of an additional 28% limited partner interestConsolidated Financial Statements included in Seadrill Operating LP.
Net income attributable to Seadrill Partners LLC Members
Net income attributable to Seadrill Partners LLC decreased by $6.2 million, or 4.3%, to $138.2 million, primarily due to a reduction in net income of $100.8 million offset by a reduction in the proportion of income attributable to non-controlling interest as a result of the Company's purchase of an additional 28% limited partner interest in Seadrill Operating LP on July 21, 2014.this annual report.




B.     Liquidity and Capital Resources

Overview
The Company operatesWe operate in a capital-intensive industry, and itsour primary liquidity needs are to finance the purchase of additional drilling units, maintenance and ongoing capital expenditure on drilling units, service its significantour 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 theour liquidity and capital resources, of the Company, including:
Liquidity requirements
Estimated maintenance and replacement capital expenditures
Analysis of cash flows for the years ending December 31, 2015, 20142017, 2016 and 2013
Estimated maintenance and replacement capital expenditures2015
Borrowing activities
Restrictive covenants
Liquidity requirements
Derivative instruments and hedging activities

activities.
AnalysisLiquidity 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 Cash Flows for the years endingliquidity include bank balances, undrawn amounts under our revolving credit facility, contract and other revenues. As of December 31, 2015, 2014 and 2013
The following table summarizes the Company's net cash flows from operating, investing and financing activities and our2017, we had cash and cash equivalents of $848.6 million, compared to $767.6 million as of December 31, 2016.
Short-term outlook and going concern assessment
The financial information in this report has been prepared on the basis that we will continue as a going concern, which presumes that we will be able to realize our assets and discharge our liabilities in the normal course of business as they come due. Therefore, financial information in this report does not reflect the adjustments to the carrying values of assets and liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations. Such adjustments could be material.
Our financial projections indicate that the cash flows we will generate from our current contract backlog, together with our available cash and other resources will allow us to meet our obligations as they fall due for at least the periods presented:
($ in millions)Year Ended December 31,
 2015 2014 2013
Net cash provided by operating activities$859.8
 $608.7
 $564.0
Net cash used in investing activities(376.3) (1,542.8) (159.3)
Net cash (used in) / provided by financing activities(407.6) 1,087.1
 (336.2)
Effect of exchange rate changes on cash0.4
 —
 —
Net increase in cash and cash equivalents76.3
 153.0
 68.5
Cash and cash equivalents at beginning of period242.7
 89.7
 21.2
Cash and cash equivalents at end of period319.0
 242.7
 89.7
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.

Net Cash Provided by Operating Activities
Net cashHowever, whilst we have taken steps to insulate the Company from events of default related to Seadrill's Chapter 11 proceedings, we remain operationally dependent on Seadrill on account of the management, administrative and technical support services provided by operating activities was $859.8 million and $608.7 million for the years ended December 31, 2015 and 2014, respectively, an increase of $251.1 million or 41.3%. The increase was primarily due to higher operating income due to the acquisitions of the West Polaris in June 2015, the West Auriga in March 2014 and the West Vela in November 2014. The decrease in downtime on the West Aquarius and West Capricorn and improved cash collections from customers also contributed to the increase in net cash provided by operating activities.
Net cash provided by operating activities was $608.7 million and $564.0 million for the years ended December 31, 2014 and 2013, respectively. The increase was $44.7 million or 7.9%. The increase was primarily due to an increase in operating income for the year due to a larger fleet, offset by increased interest expenses and realized losses on derivative financial instruments.

Net Cash Used in Investing Activities
Net cash used in investing activities of $376.3 million in 2015 was primarily due to the Company's acquisition of the entity that owns and operates the West Polaris from Seadrill. The cash consideration, net of cash acquired, paid to acquire the West Polaris was $214.7 million. The Company also made a loan to a subsidiary of Seadrill of $143.0 million in order to restore Seadrill's liquidity following a loan made by a subsidiary of Seadrill to an operating subsidiary ofSeadrill Partners. In the Company.
Net cash used in investing activities of $1,542.8 million in 2014 was dueevent Seadrill is unable to the Company's acquisitions of the entities that own and operate the West Auriga and the West Vela from Seadrill. The cash consideration, net of cash acquired, paid to acquire the West Auriga and the West Vela was $672.6 million and $465.1 million respectively. The Company also purchased from Seadrill an additional 28% limited partner interest in Seadrill Operating LP for $373.5 million. Asprovide these services, as a result of its restructuring or otherwise, Seadrill Partners has the acquisition,right to terminate these agreements and would seek to build these capabilities internally or determine a suitable third party contractor to replace Seadrill. This may have an adverse effect on operations and may negatively impact our cash flows and liquidity.
Until Seadrill emerges from Chapter 11, uncertainty remains and the Company’s limited partner interest incondition gives rise to substantial doubt over our ability to continue as a going concern. To the extent Seadrill Operating LP increasedemerges from 30%Chapter 11,we expect this substantial doubt to 58%. Additions to drilling units were $31.6 million, relating mainly tobe mitigated.
Long-term outlook
Our long-term liquidity requirements include theWest Aquarius.
Net cash used in investing activities of $159.3 million in 2013 was mainly due to the costs of construction of the T-15 and T-16.


Net Cash (Used in) / Provided by Financing Activities
Net cash used for financing activities was $407.6 million during the year ended December 31, 2015. Net cash used fin financing activities was impacted by (i) net proceeds from the revolving credit facility of $50.0 million, (ii) repayments of debt of $97.6 million, (iii) repayments of related party debt with Seadrill of $40.3 million, (iv) payment of contingent consideration to Seadrill of $26.6 million, (v) proceeds from a loan from Seadrill of $143.0 million, and (vi) cash distributions totaling $435.3 million.
Net cash provided by financing activities was $1,087.1 million during the year ended December 31, 2014. Net cash provided by financing activities was impacted by (i) net proceeds from long term debt of $2,825.4 million due to the new Amended Senior Secured Credit Facility (Term Loan B), (ii) repayments of debt of $472.1 million, (iii) repayments of related party debt with Seadrill of $1,588.3 million, (iv) repayment of the revolving credit facility with Seadrilllong-term debt balances, and funding any potential purchases of $125.9 million, (v) repaymentsdrilling units. Generally, our long-term sources of related party discount notes with Seadrillfunds will be a combination of $399.9 million, (vi)borrowings from commercial banks, cash distributions totaling $660.2 million, (vii) proceedsgenerated 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 common unitsdebt 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 $937.8 million, and (viii) proceedsour Term Loan B ("TLB"). In connection with the waiver, we agreed not to grow our quarterly distributions from the issuance of units by Seadrill Capricorn Holdings LLC of $570.3 million.
Net cash used in financing activities was $336.2 millioncurrent 10 cents per common unit unless the consolidated net leverage ratio is below 4x during the year ended December 31, 2013. Net cash used in financing activities of $336.2 million was impacted by (i) repayments of debt of $348.8 million, (ii) a repayment of the revolving credit facility with Seadrill of $43.7 million, (iii) cash distributions totaling $140.9 million, (iv) $112.4 million relating to changes in invested equity2018 and (v) $939.2 million relating to distributions to Seadrill for the acquisition of T-15, T-16, West Leo and West Sirius. This was offset by $98.0 million from the proceeds of debt, $169.6 million relating to proceeds from borrowings under the revolving credit facility with Seadrill, $409.5 million relating to proceeds from related party vendor financing, $464.8 million relating to proceeds from issuing equity relatingbelow 5x thereafter. Please read Note 11 "Debt" to the acquisition of the T-16, West Leo and West Sirius and $106.9 million relating to proceeds from issuing equity to related parties.

Net IncreaseConsolidated Financial Statements included in Cash and Cash Equivalents
As a result of the foregoing, cash and cash equivalents increased in 2015 by $76.3 million, increased in 2014 by $153 million, and increased in 2013 by $68.5 million.

this annual report for further details.
Estimated Maintenance and Replacement Capital Reserves
The Company'sOur operating agreement requires itus to distribute itsour available cash each quarter. In determining the amount of cash available for distribution, the Company's board of directorsBoard 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, the Company iswe are required to make to maintain itsour fleet, the Company’sour current annual estimated maintenance and replacement capital reserves will be $201are $207 million per year, which is comprised of $75 million for long term maintenance and society classification surveys and $126$132 million, including financing costs, for replacing the Company'sour 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 the Company’sour drilling units, a net investment rate applied on reserves, replacement values of the Company’sour existing rigs based on current market conditions, and the residual value of the rigs. The actual cost of replacing the drilling units in the Company’sour 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. The Company'sOur operating agreement requires its board of directorsthe 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 Company's board of directors,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 of directorsBoard to increase the amount of estimated maintenance and replacement capital reserves. The CompanyWe may elect to finance some or all of itsour actual maintenance and replacement capital expenditures through the issuance of additional common units which could be dilutive to existing unitholders. As the Company’sour fleet matures and expands, estimated long-term maintenance reserves will likely increase.

Please read Item 3 “Key Information—Risk Factors—Risks Inherent inAnalysis of Cash Flows for the Company's Business - years ending December 31, 2017, 2016 and 2015
The Company must make substantial capital and operating expenditures to maintain and replace the operating capacity of its fleet, which will reduce itsfollowing table summarizes our net cash available for distribution. In addition, each quarter the Company is required to deduct estimated maintenance and replacement capital expendituresflows from operating, surplus,investing and financing activities and our cash and cash equivalents for the periods presented:
($ in millions)Year Ended December 31,
 2017 2016 2015
Net cash provided by operating activities$476.2
 $873.8
 $859.8
Net cash (used in) provided by investing activities(11.1) 97.6
 (376.3)
Net cash used in financing activities(384.9) (522.1) (407.6)
Effect of exchange rate changes on cash0.8
 (0.7) 0.4
Net increase in cash and cash equivalents81.0
 448.6
 76.3
Cash and cash equivalents at beginning of period767.6
 319.0
 242.7
Cash and cash equivalents at end of period848.6
 767.6
 319.0
Net Cash Provided by Operating Activities
Net cash provided by operating activities was $476.2 million and $873.8 million for the year ended December 31, 2017 and December 31, 2016 respectively.
The decrease of $397.6 million was primarily due to lower net income, which may resultdecreased 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 lessworking capital.
Net cash availableprovided by operating activities was $873.8 million and $859.8 million for the years ended December 31, 2016 and December 31, 2015 respectively. The increase of $14.0 million was primarily due to unitholders than if actual maintenancea favorable change in working capital offset by a decrease in operating income.

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

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

Principal outstanding at Dec 31, 2016 ($millions)

Debt repayments in 2017 ($millions)

Debt repayments in 2016             ($millions)

External facilities    
Term loan B
See below (1)
Feb-20212,786.9
2,815.9
29.0
29.1
$100m RCF
See below (1)
Feb-201950.0
50.0
—
—
West Vela facility (2)
West VelaOct-2020255.3
342.2
86.9
40.2
West Polaris (2)
West PolarisJul-2020205.6
279.0
73.4
36.0
Tender Rig facility (2)
T-15 & T-16Jun-202083.3
—
25.7
—
   3,381.1
3,487.1
215.0
105.3
Related party debt      
Tender Rig facility (2)
T-15 & T-16Jun-2020—
119.1
10.1
19.9
West Vencedor facilityWest VencedorJun-201824.7
41.2
16.5
16.5
West Sirius loan (3)
NoneApr-2017—
39.4
39.4
103.6
Vendor financing loanNoneMay-2016—
—
—
109.5
   24.7
199.7
66.0
249.5
       
Total  3,405.8
3,686.8
281.0
354.8
(1) The collateral vessels for the Term Loan B and linked revolving credit facility are the West Sirius, West Aquarius, West Capricorn, West Leo, West Capella and West Auriga.
(2) The Tender Rig facility was classified as a related party debt facility until the facility was amended in August 2017.
(3) The West Sirius loan has been classified within related party payable on the consolidated balance sheet as at December 31, 2016.
Key changes to borrowing facilities from January 1, 2015 to December 31, 2017
On April 14, 2015, we amended the terms and extended the maturity of the West Vencedor facility with Seadrill. Following this amendment, the maturity date was extended to June 25, 2018 with a balloon payment of $20.6 million due at maturity.
On June 19, 2015, we completed the purchase of the entities that owned and operated the drillship West Polaris (from Seadrill). As part of the purchase price, we acquired the liability for $336 million of debt outstanding under the facility used by Seadrill to finance the West Polaris (the "West Polaris facility"). We also drew down $50 million of the $100 million revolving credit facility available under our Term Loan B to finance a proportion the upfront cash consideration we paid for the West Polaris.
Effective as of December 17, 2015, we borrowed $143.0 million from Seadrill to provide sufficient immediate liquidity to meet the terms of a bareboat charter termination payment we were required to make for the West Sirius contract termination (the "West Sirius loan). Concurrently, Seadrill borrowed $143.0 million (the “Seadrill loan”) from one of our rig owning subsidiaries to restore its liquidity with respect to the West Sirius loan. Each of the loan parties understood and agreed that the loan agreements act in parallel with each other. Each loan bore an interest rate of one-month LIBOR plus 0.56% and matured in August 2017.
On August 11, 2017, we agreed to an amendment and an extension to the maturities of the West Vela, West Polaris and Tender Rig facilities. These amendments insulated us from events of default related to Seadrill's use of Chapter 11 proceedings and addressed near-term refinancing requirements.
The facilities were amended as follows:
1.
The secured credit facility relating to both the West Vela drillship (owned by Seadrill Partners) and the West Tellus drillship (owned by Seadrill), was split into two separate facilities, the “West Vela facility” and the “West Tellus facility”. Recourse of the West Vela facility is now only to Seadrill Partners consolidated entities and recourse of the West Tellus facility is now only to Seadrill consolidated entities. The maturity date of the West Vela facility was extended until October 2020.

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

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

As part of this transaction we agreed to make a prepayment of $100 million on closing and two subsequent prepayments of $25 million in February 2018 and August 2018, in each case distributed pro rata across the West Vela, West Polaris and Tender Rig facilities. We also agreed to a 1% increase in margin, certain covenant and security amendments and to cancel a $100 million revolver provided by Seadrill.
In February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). In connection with the waiver, the Company has agreed to certain amendments, including but not limited to, increasing the applicable margin by 3%, a par prepayment contingent on the successful outcome of certain ongoing litigation, adding the West Vencedor as collateral and certain amendments relating to cash movements outside the TLB collateral group. Please read Note 11 "Debt" to the Consolidated Financial Statements included in this annual report for further details.
Debt repayments by year
The outstanding debt as of December 31, 2017 is repayable as follows: 
(In US$ millions)December 31, 2017
2018$199.8
2019175.1
2020331.1
20212,699.8
Total external and related party debt$3,405.8
Debt issuance costs
In our Consolidated Balance Sheet we present debt balances net of debt issuance costs. This is set out in the below table:
  Outstanding debt as of December 31, 2017
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $175.1
$(12.2)$162.9
Long-term external debt 3,206.0
(25.8)3,180.2
Total external debt $3,381.1
$(38.0)$3,343.1
Current portion of long term related party debt $24.7
$—
$24.7
Total interest bearing debt $3,405.8
$(38.0)$3,367.8
  Outstanding debt as of December 31, 2016
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $105.3
$(11.5)$93.8
Long-term external debt 3,381.8
(35.3)3,346.5
Total external debt $3,487.1
$(46.8)$3,440.3
Current portion of long term related party debt $135.6
$—
$135.6
Long term related party debt $24.7
$—
$24.7
West Sirius loan - included within line item "related party payable" $39.4
$—
$39.4
Total interest bearing debt $3,686.8
$(46.8)$3,640.0
Further information
Please refer to Note 11 - “Debt”"Debt" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report for detailed information on our borrowings and credit facilities.

AsRestrictive Covenants
Details of December 31, 2015, we had total outstanding borrowings under our credit facilitiescovenants, terms of $3,592.3 million, compared to $3,303.9 million as at December 31, 2014. In addition, we had interest bearing debt under loan agreements with related parties of $306.0 million, compared to $346.5 million as at December 31, 2014.


We have issued a variety of secureddefault and unsecured borrowings. The secured debt is secured by, among other things, liens on our drilling units. In addition, some of our loan agreements contain cross-default provisions, meaning that if we are in default under one of our loan agreements, amounts outstanding under our other loan agreements may also be in default, accelerated and become due and payable. Our unsecured debt consists of related party borrowings from Seadrill to fund the acquisitions of drilling units from Seadrill.Some of the Company’s existing financing agreements contain cross-default provisions thatrestrictions may be triggered if Seadrill defaults underfound in the termsdebt agreement and subsequent amendments which have been filed as exhibits to this 20-F report. Please refer to Item 19 - "Exhibits".
We were not in breach of its existing or future financing agreements. In turn, Seadrill’s existing financing arrangements contain cross-default provisions that may be triggered if its key subsidiaries, including North Atlantic Drilling Ltd. and Sevan Drilling ASA, default under the terms of their existing or future financing arrangements.

Some of the Company’s existing financing agreements contain cross-default provisions that may be triggered if Seadrill defaults under the terms of its existing or future financing agreements. In turn, Seadrill’s existing financing arrangements contain cross-default provisions that may be triggered if any of its key subsidiaries default under the terms of their existing or future financing arrangements. In addition Seadrill also consolidates certain Variable Interest Entities (VIEs) owned by Ship Finance International Limited (NYSE: SFL), or Ship Finance. Seadrill's cross-default provisions could also be triggered if Ship Finance or one of the consolidated VIEs breached the terms of their financing arrangements.

Effectiveapplicable covenants as of December 31, 2015, an operating subsidiary of the Company borrowed $143.0 million (the “West Sirius loan”) from Seadrill in order to provide sufficient immediate liquidity to meet the terms of its bareboat charter termination payment in connection with the West Sirius contract termination. Concurrently, Seadrill borrowed $143.0 million (the “Seadrill loan”) from a rig owning subsidiary of the Company in order to restore its liquidity with respect2017. Please read Note 11 "Debt" to the West Sirius loan. Each loan bears an interest rate of one-month LIBOR plus 0.56% and matures in August 2017. Each of the loan parties understand and agree that the loan agreements act in parallel with each other. As of December 31, 2015, $143.0 million was outstanding under each such loan (December 31, 2014: nil).

During the year ended December 31, 2015, in connection with the completion of the Polaris Acquisition, Seadrill Polaris as borrower, entered into an amendment and restatement of the $420.0 million term loan facility, (the “West Polaris Facility”) secured by the West Polaris. Upon closing of the Polaris Acquisition the outstanding debt of the West Polaris Facility was $336.0 million. Refer to "Note 3 - Business Acquisitions" of the notes to the Consolidated and Combined Carve-Out Financial Statements included in this annual report. During the year ended December 31, 2015, the Company also drew down $50 million under the revolving credit tranche of the Amended Senior Secured Credit Facilities. The outstanding balance under the West Polaris Facility as of December 31, 2015 was $315.0 million.

The senior secured credit facility relating the West Vencedor was repaid in full by Seadrill in June 2014, and subsequently the related party agreement between the Company's subsidiary, Seadrill Vencedor Ltd., and Seadrill was amended to carry on this facility on the same terms, referred to as the West Vencedor Loan Agreement. The West Vencedor Loan Agreement was scheduled to mature in June 2015 and all outstanding amounts thereunder would be due and payable, including a balloon payment of $69.9 million. On April 14, 2015 the Loan Agreement was amended and the maturity date was extended to June 25, 2018. The West Vencedor Loan Agreement bears a margin of 2.25%, a guarantee fee of 1.4% and a balloon payment of $20.6 million due at maturity in June 2018. As at December 31, 2015 the total net book value of the West Vencedor pledged as security was $178.4 million. The outstanding balance under the West Vencedor Loan Agreement due to Seadrill was $57.5 million as of December 31, 2015.

During the year ended December 31, 2014, we raised a total of $2.9 billion under our new Amended Senior Secured Credit Facilities, which are secured by the West Capella, West Aquarius, West Sirius, West Leo, West Auriga, and West Capricorn. In 2014, in connection with the completion of the Vela Acquisition. We acquired Seadrill Vela Hungary Kft, a borrower under the $1,450 Million Senior Secured Credit Facility secured by the West Vela and one other drilling unit owned by Seadrill. Under the terms of such facility, certain subsidiaries of Seadrill and Seadrill Vela Hungary Kft are jointly and severally liablereport for their own debt and obligations under the facility and the debt and obligations of other borrowers who are also party to such facility.  These obligations are continuing and extend to amounts payable by any borrower under the facility. The total amount owed by all parties under this facility as of December 31, 2015 is $775.6 million. The Company has not recognized any amounts that are related to amounts owed under the facility by other borrowers.  Seadrill has provided an indemnity to the Company for any payments or obligations related to this facility that are not related to the West Vela. As of December 31, 2015, the outstanding balance relating to the West Vela was $382.6 million. Refer to "Note 3 - Business Acquisitions" of the notes to the Consolidated and Combined Carve-Out Financial Statements included herein.

During the year ended December 31, 2015 we made external debt repayments of $97.6 million, compared to $472.1 million in 2014. In addition, during the year ended December 31, 2015 we made related party debt repayments of $40.3 million compared to $1,588.3 million in 2014. In 2015 this included the normal debt amortizations on secured debt, whereas in 2014 we repaid existing loans with proceeds from our new Amended Senior Secured Credit Facilities.

As at December 31, 2015 we had a total of $50 million of undrawn borrowing capacity under our the Amended Senior Secured Credit Facilities, and a further $100 million of undrawn borrowing capacity under the Sponsor Revolving Credit Facility with Seadrill.


As of December 31, 2015 and December 31, 2014, the Company had the following debt amounts outstanding:
 (In US$ millions)
December 31, 2015
 December 31, 2014
External debt agreements   
Amended Senior Secured Credit Facilities2,894.7
 2,881.0
$1,450 Senior Secured Credit Facility382.6
 422.9
   $420 West Polaris Facility315.0
 —
Sub-total external debt3,592.3
 3,303.9
Less current portion long term external debt(105.3) (76.5)
Long-term external debt3,487.0
 3,227.4
    
Related party debt agreements   
 Rig Financing and Loan Agreements   
   West Vencedor Loan Agreement (previously $1,200 facility)
57.5
 78.2
  $440 Rig Financing Agreement139.0
 158.8
Sub-total Rig Financing Agreements196.5
 237.0
    
 Other related party debt   
$109.5 T-15 vendor financing facility109.5
 109.5
Total related party debt306.0
 346.5
Less current portion of related party debt(145.8) (40.4)
Long-term related party debt and related party loan notes160.2
 306.1
    
Total external and related party debt3,898.3
 3,650.4

The outstanding debt as of December 31, 2015 is repayable as follows: 
(In US$ millions)As at December 31,
2016251.1
2017240.8
2018598.8
201929.0
202029.0
2021 and thereafter2,749.6
Total external and related party debt3,898.3

As discussed in Note 2-Accounting policies, the Company has adopted Accounting Standards Update (ASU) 2015-03, Interest - Imputation of Interest, (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs as of June 30, 2015. As a result, the consolidated balance sheet as of December 31, 2014 has been restated to reflect this change in accounting principle. Details of the debt issuance costs netted against the current and long-term debt for each of the period presented are shown below.

  Outstanding debt as of December 31, 2015
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $105.3
$(11.5)$93.8
Long-term external debt 3,487.0
(46.6)3,440.4
Total external debt $3,592.3
$(58.1)$3,534.2


  Outstanding debt as of December 31, 2014
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $76.5
$(7.6)$68.9
Long-term external debt 3,227.4
(70.8)3,156.6
Total external debt $3,303.9
$(78.4)$3,225.5


Restrictive Covenants
For a list of financial and non-financial covenants for the Company’s financing agreements please refer to “Note 11 - Debt” of the notes to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

Some of the Company’s existing financing agreements contain cross-default provisions that may be triggered if the Company defaults on any of its indebtedness or if the terms of its existing or future financing agreements. In turn, Seadrill’s existing financing arrangements contain cross-default provisions that may be triggered if its key subsidiaries default under the terms of their existing or future financing arrangements. Further, because the Company's drilling units are pledged as security for Seadrill’s obligations under these financing agreements, lenders thereunder could foreclose on the Company’s drilling units in the event of a default thereunder. Seadrill’s failure to comply with covenants and other provisions in its existing or future financing agreements could result in cross-defaults under the Company’s other existing financing agreements, which could have a material adverse effect on us.

On April 28, 2016, Seadrill executed amendment and waiver agreements in respect of all of its senior secured credit facilities, as part of its efforts to maintain liquidity. The amendment and waiver agreements, among other things, amend the equity ratio, leverage ratio, minimum value clauses and minimum liquidity requirements under Seadrill’s and some of our secured credit facilities until June 30, 2017. The key terms and conditions related to the amendment and waiver agreements in respect of our credit facilities are set forth in “Note 11-Debt” of the notes to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

The Company and Seadrill were in compliance with applicable covenants as of December 31, 2015. The Company and Seadrill expects to remain in compliance with the amended covenants in 2016.

Liquidity Requirements
Our short-term liquidity requirements relate to servicing our debt amortizations, interest payments, funding working capital requirements, and making distributions. Sources of liquidity include existing cash balances, restricted cash balances for certain debt, short-term investments, amounts available under revolving credit facilities and contract and other revenues. As of December 31, 2015, the Company's cash and cash equivalents were $319.0 million, compared to $242.7 million as of December 31, 2014. We have historically relied on our cash generated from operations to meet our working capital needs. The Company believes its current resources, including the potential borrowings under the revolving credit facilities, and cash generated from operations, provided by our current contract backlog, are sufficient to meet its working capital requirements and other obligations as they fall due for at least the next twelve months.

The amendment and waiver agreements are subject to, among other things, Seadrill’s compliance with the processes and undertakings set forth therein, including agreements in respect of progress milestones towards the agreement of, and implementation plan in respect of, a comprehensive financing package. There can be no assurance that Seadrill will maintain compliance with the processes and undertakings set forth in the amendment and waiver agreements, or that any potential debt restructuring, reorganization or recapitalization will be undertaken or be successful. In the event of a default by Seadrill under one of its financing agreements, the cross-default clauses described above that are in some of our existing financing agreements could cause us to be unable to make additional borrowings under our credit facilities and amounts outstanding under our loan agreements to be accelerated and become due and payable.

Our long-term liquidity requirements include the repayment of long-term debt balances, and funding any potential purchases of drilling units. Generally, the Company's long-term sources of funds will be a combination of borrowings from and leasing arrangements with commercial banks, cash generated from operations and debt and equity financing. Because the Company distributes all of its available cash, the Company expects that it will rely upon financing from external financing sources and related parties, including bank borrowings and the issuance of debt and equity securities, to fund acquisitions and other expansion capital expenditures.

Under the Marshall Islands Act or the Marshall Islands Limited Partnership Act, as applicable, OPCO may be prohibited from making distributions to the Company. OPCO may not make a distribution to its members or partners if, after giving effect to the distribution, all of the distributing entity’s liabilities, other than liabilities to its members or partners on account of their interests in the entity and liabilities for which the recourse of creditors is limited to specified property of the entity, exceed the fair value of the assets of the entity, 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 entity only to the extent that the fair value of that property exceeds that liability. Moreover, subsidiaries of the Company and OPCO not organized in the Marshall Islands are subject to certain restrictions on payment of distributions pursuant to the law of their jurisdictions of organization.

details.
Derivative Instruments and Hedging Activities
The Company usesWe may use financial instruments to reduce the risk associated with fluctuations in interest and foreign exchange rates. These agreements do not qualify for hedge accounting and anyOur 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 fair values ofgain or loss on interest rate swap agreements are included inswaps within the Consolidated and Combined Carve-Out Statement of Operations within "Loss/(gain)line item "Loss on derivative financial instruments". in the consolidated statement of operations.
Total realized and unrealized losslosses on interest-rate swap agreements not qualified for hedge accounting, amounted to $82.9$13.9 million for the year ended December 31, 2015.2017 (December 31, 2016: loss of $18.0 million).
As of December 31, 2015, the Company and its consolidated subsidiaries had entered into2017, our interest rate swap contracts with Seadrill withhad a combined outstanding principal amount of $655.3$2,793.9 million swapping LIBOR for fixed rates between 1.10% per annum and 1.93% per annum.
As of December(December 31, 2015, the Company and its consolidated subsidiaries had entered into interest rate swap contracts with external parties with a combined outstanding principal amount of $2,851.9 million,2016: $2,822.9 million), swapping LIBOR for an average fixed rate of 2.49% per annum.
As of December 31, 2015, the Company's2017, our net exposure to short term fluctuations in interest rates on itsour outstanding debt was $391.1$611.9 million (December 31, 2016: $204.2 million), based on its total net interest bearing debt of $3,898.3$3,405.8 million (December 31, 2016: $3,647.4 million), including related party debt agreements, less the $3,507.2$2,793.9 million (December 31, 2016: $3,443.2 million) outstanding balance of fixed interest rate swaps.

We previously held related party interest rate swaps with Seadrill which were canceled on September 12, 2017 as a result of Seadrill entering a Chapter 11 restructuring. The settlement value of these interest rate swaps at the point they were canceled was $1.9 million. This amount was classified as a related party receivable in our Consolidated Balance Sheet. We expect this receivable to be recovered in full.
The Company's funding and treasury activities are intended to maintain appropriate liquidity. CashForeign 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, Euros, Thai Baht, and Nigerian Naira. The Company has not entered into any foreign currency derivatives related to the Canadian Dollar, Euro, Thai Baht or Nigerian Naira in the periods presented, and, therefore, the Consolidated and Combined Carve-Out Financial Statements
We do not include any unrealized gains or losses on foreign currency derivatives. The Company receives part of its revenue in the Euro, Canadian dollar and Nigerian Naira. Because the Company incurs operating costs related to the West Capella in Nigerian Naira, the Company is able to offset a portion of its foreign currency exposure with respect to revenues earned in Nigerian Naira. Depending on the level of the Company's currency exposure, the Company may in the future enter intocurrently 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
The Company doesWe do not undertake any significant expenditures on research and development, and hashave no significant interests in patents or licenses.


D.     Trend Information

As a result of the decline in oil prices and reductions in oil company expenditures, theThe offshore drilling market is currently entering its thirdthe fifth year of a downturn. Rig owners are bidding for available work extremely competitively with adownturn and the timing of recovery remains uncertain. The below table show the average oil price over the period 2013 to 2017.
 20132014201520162017
Average Brent oil price$108.70$99.49$53.60$45.13$54.74
Brent oil prices have been in the range of $45-$55 throughout most of 2017 before increasing in the last quarter of 2017 and in early 2018. The Brent oil price on March 31, 2018 was $70.
Oil and gas companies have responded to the decrease in oil price over the downturn by decreasing their upstream expenditures. During 2017, oil and gas companies have continued to focus on preserving cash, in some cases consciously allowing the production decline rate on producing fields to accelerate as a result of reduced infill drilling and well intervention. Based on the decreased level of investment since 2014, we expect that production decline rates will increase. Further, the longer the period that lower investment persists, the greater the number of new projects and infill drilling that will be required to replace the lost production.
The below table shows the global number of rigs on contract at March 31, 2018 and for each of the four preceding years.
 Mar-2014
Mar-2015
Mar-2016Mar-2017
Mar-2018
Contracted floating rigs260
237
170135
125
Contracted tender rigs25
24
2115
12
During 2017, we have seen an increase in the activity level in the floater market, albeit primarily for short term work at extremely competitive dayrates. This improvement was from a low base and we still expect utilization over returns, whichin the floater market to get worse before it improves. Whether the recent increase in oil prices will likely drive dayrates downlead to or below cash breakeven levels.

a recovery in offshore exploration and development expenditure in 2018 remains uncertain. It is important to recognize that the resetting of costs across the value chain may facilitate increased activity with only a marginal increase in oil prices.
The offshore drilling market continuesremains oversupplied. Offshore drilling contractors have continued to be oversupplied with multiple drillingaggressively market their rigs, chasingoften focusing on utilization over returns. The below table shows the few opportunitiesutilization of the global fleet at March 31, 2018 and for each of the four proceeding years.
 Mar-2014Mar-2015Mar-2016
Mar-2017
Mar-2018
Global fleet - floaters320313303
282
259
Global fleet - tenders393834
33
30
Utilization - floaters81%76%56%48%48%
Utilization - tenders64%63%62%45%40%
Older units that roll off contract may require significant capital expenditure to return to the working fleet and so are available and contracting activity is at the lowest levels since the 1980’s. Oil company capital expenditures are expected to decline further in 2016 following two consecutive years of decline. It is expected that the majority of rigs with contracts expiring in 2016 will be unable to find suitable follow on work and many aremore likely to be idle for a protracted period. Consequently, cold stackingstacked and ultimately scrapped. We expect the combination of increased production decline rates and accelerated scrapping activity will likely accelerate.

Oil companies continue to work on managing their existing rig capacity. They are in many cases overcommitted based on reduced activity levels and there is very little appetite for adding new units. Near term budgetary constraints are the primary focus of many oil companies, with short term cash conservation ranking ahead of long term value generation. However, the near term cost cutting neededlead to support dividend payments can be expected to negatively impact the long term production profiles of existing development projects.

At today’s oil prices the full cycle cost of many of the hydrocarbon provinces globally are uneconomic. A supply response is inevitable, however it may take some time due to the high degree of sunk costs in producing projects. When also considering the eventual demand response to low prices a rebalancing in the oil markets is expectedbalanced market at some point. Offshore oil fields representBased on the expected level of scrapping activity and the number of units that are anticipated to be cold stacked, a material portionrelatively small increase in spending could meaningfully tighten the floater and tender markets.
Floaters - outlook
Based on the level of most major oil company’s reservescurrent activity and their production remains a cost competitive sourcethe aging floater fleet, we expect scrapping activity to continue. A total of hydrocarbons.

Floaters

It is likely that the majority of103 floaters with contracts expiring in 2016 will be unable to find reasonable follow on work. It will be important to observe how rig owners react when faced with idle time on their units and face the choice to warm stack, cold stack or scrap units. For the most part, customer conversations remain focused on extending existing contracted assets or trade-offs between existing assets and newer assets rather than contracting new units for work.

In light of the current environment, the Company is encountering and may in the future encounter situations where counterparties request relief to contracted dayrates or seek early contract termination. In the event of early termination for the customer's convenience, an early termination amount is typically payable to the Company, in accordance with the terms of the drilling contract. While the Company believes that its contract terms are enforceable, it may be willing to engage in discussions to modify such contracts if there is a commercial agreement that is beneficial to both parties.

Over the past 18 months 70 units have been scrapped representing more retirements than overor retired since the prior 9beginning of 2014, equivalent to 32% of the total fleet, and currently there are 28 cold or warm stacked units with no follow-on work identified that are 30 years combined, and more than any other 18 month period in history. Overold or older, which are prime scrapping candidates. In the next 6 quarters, 26 of the 72 rigs rolling18 months, a further 22 units that are 30 years old or older will be coming off contract are 5th generation or below unitswith no follow-on work identified which represents additional scrapping candidates. A key rational for scrapping is the 35-year classing expenditures that will be challenged to find work for the foreseeable future as they are priced outcan cost upwards of the market by more capable units. 15 or 20 year old assets require significant capital investments to remain part of the active fleet and very few$100 million. Many rig owners will find economic justificationchoose to keep these old assets working.

retire the unit rather than incur this cost without a visible recovery in demand on the horizon.
Larger drilling companies with diversified fleets will find it easier to make sound economic decisions and cold stack idle rigs as each individual unit represents a smaller percentage of the overall fleet. Cold stacked units will generally require an improvement in dayrates sufficient to overcome reactivation costs before they are reintroduced into marketed supply. Significant cold stacking activity would represent a positive development in the market, effectively reducing marketed supply and helping to stabilize utilization and pricing until a more fundamental recovery is in place.

Currently 170125 floaters out of 259 floaters are contracted,under contract, representing 56%48% marketed utilization. It is estimated that 180-200 rigs are needed in the floater fleet to maintain currentlong-term average production decline curves.

Currently the orderbookglobal floater order book stands at approximately 69 units. A42 units, comprised of 28 drillships and 14 semi-submersible rigs. 12 are scheduled for delivery in 2018, 17 in 2019 and 13 in 2020 and beyond. Due to the subdued level of contracting activity, it is likely that a significant number of these newbuild orders have beenwill be delayed or cancelled and we expect this trend to continue. Delayed or cancelled newbuildings will ultimately be added to the fleet, howevercanceled until an improved market justifies taking deliveries, the vast majority will likely remain in the shipyards. Between now and 2018 there is a high likelihood that there will be overall contraction in the floater fleet due to delivery delays and scrapping activity.delivery.

Tender Rigs

rigs - outlook
The worldwide fleet of tender rigs currently totals 37 units.30 units, of which 12 are contracted representing 40% capacity utilization. Overall, the global fleet is 1412 years old on average. Currently the orderbookorder book stands at approximately 86 units. 52 are scheduled for delivery in 2016,2018 and 34 in 2017.

2020.
Activity in the tender rig market is focused primarily in South-east Asia and West Africa. Tendering activity is typically more stable in this market due to these types of units being employed on development projects, however capacityCapacity utilization and dayrates have remained under pressure, similar to the worldwide floater market. Currently 22 tender rigs are contracted, representing 59% utilization.

E.     Off-Balance Sheet Arrangements
The CompanyWe had no off-balance sheet arrangements as of December 31, 20152017 or 2014,2016, other than operating lease obligations and other commitments in the ordinary course of business that it is are 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 the Company'sour drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these guarantees are not normally called, as the Companywe typically compliescomply with the underlying performance requirement. As of December 31, 2015, the Company2017, we had not been required to make collateral deposits with respect to these agreements.
The maximum potential future payments are summarized in Note 16 -“Commitments15 "Commitments and contingencies”contingencies" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.



F.     Tabular Disclosure of Contractual Obligations
The following table summarizes the Company'sour long-term contractual obligations as of December 31, 2015:
2017:
Payments Due by PeriodPayments Due by Period
($ in millions)
Total 
Less than
1 Year
 1-3 Years 4-5 Years 
More than
5 Years
Total 
Less than
1 Year
 1-3 Years 4-5 Years 
More than
5 Years
Long-term debt obligations$3,898.3
 $251.1
 $839.6
 $58.0
 $2,749.6
$3,381.1
 $175.1
 $506.2
 $2,699.8
 $—
Related Party debt obligations24.7
 24.7
 —
 —
 —
Interest expense commitments on long-term debt obligations (1)
585.7
 120.3
 217.2
 200.6
 47.6
785.9
 243.4
 484.3
 58.2
 —
Commitment fee on undrawn facility (2)
16.1
 2.3
 4.6
 4.6
 4.6
Deferred consideration payable (3)(2)
290.5
 35.8
 74.3
 73.4
 107.0
84.7
 29.8
 54.9
 —
 —
Total$4,790.6
 $409.5
 $1,135.7
 $336.6
 $2,908.8
$4,276.4
 $473.0
 $1,045.4
 $2,758.0
 $—
(1)The Company'sOur interest commitment on long-term debt is calculated based on the applicable interest rates contained in itsour loan agreements as of December 31, 2015 and2017, the associated interest rate swap rates.rates and the 3% increase in margin due on the TLB following the amendment in February 2018.
(2)The $100 million revolving credit facility with Seadrill and the $100.0 million revolving credit facility under the Amended Senior Secured Credit Facilities incur commitment fees on the undrawn balance of 2% per annum and 0.5% per annum respectively.
(3)
The CompanyWe 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 and the West Polaris on June 19, 2015.2014. 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 313 - Business Acquisitions" of the notes"Related Party Transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(3)In addition to the above, we have recognized liabilities for uncertain tax positions at December 31, 2017 of $43.7 million.

G.     Safe Harbor

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

Item 6.         Directors, Senior Management and Employees


A.     Directors and Senior Management
Directors
The following provides information about each of the Company's directors. The business address through which the boardBoard can be contacted is 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom.
NameAgePosition
Graham Robjohns5153Director
Bert Bekker7779Director and Audit Committee Member
Kate Blankenship5153Director and Audit Committee Member
Harald Thorstein3638Director and Chairman
Andrew Cumming6163Director and Conflicts Committee Member
Keith MacDonald5760Director, Audit Committee Member and Conflicts Committee Member

Certain biographical information about each of our directors and executive officers is set forth below.
Graham Robjohns was appointed to the Board by Seadrill Member and has served as a Directordirector since SeptemberJuly 2012. Mr. Robjohns currently serves as a director of Seadrill UK Ltd., a wholly owned subsidiary of Seadrill, and has served in such position since June 2010. Mr. Robojohns has served as the deputy Chief Executive Officer and Chief Financial Officer of Golar LNG Limited since March 2018. Mr. Robjohns was also the Chief Executive Officer of the Company from June 2012 to August 2015. Mr. Robjohns has also served as Principal Executive Officer of Golar LNG Partners LP sincefrom July 2011 until March 2018 and, prior to that, served as its Chief Executive Officer and Chief Financial Officer from April 2011 to July 2011. Mr. Robjohns served as the Chief Financial Officer of Golar Management Limited ("Golar Management") from November 2005 until June 2011. Mr. Robjohns also served as Chief Executive Officer of Golar LNG Management from November 2009 until July 2011. Mr. Robjohns served as Group Financial Controller of Golar Management from May 2001 to November 2005 and as Chief Accounting Officer of Golar Management from June 2003 until November 2005. He was the Financial Controller of Osprey Maritime (Europe) Ltd from March 2000 to May 2001. From 1992 to March 2000 he worked for Associated British Foods Plc. and then Case Technology Ltd (Case), both manufacturing businesses, in various financial management positions and as a director of Case. Prior to 1992, Mr. Robjohns worked for PricewaterhouseCoopers in their corporation tax department. He is a member of the Institute of Chartered Accountants in England and Wales.

Bert Bekkerhas 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 has served as a director of Wilh. Wilhelmsen Netherlands B.V., part of the Wilh. Wilhelmsen ASA Group, sincefrom July 2003.2003 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 SeadrillShip Finance International since April 2013.

May 2015.
Kate Blankenship was appointed to the Board by the Seadrill Member and has served as a director of the Company since June 2012, and serves on the Company's audit committee. Mrs. Blankenship has served as a director of Seadrill since its inception in May 2005. Mrs. Blankenship has also served as a director of Frontline since 2003. Mrs. Blankenship joined Frontline in 1994 and served as its Chief Accounting Officer and Company Secretary until October 2005. Mrs. Blankenship has been a director of Ship Finance since October 2003, North Atlantic Drilling Limited since February 2011, Independent Tankers Corporation Limited since February 2008, Golden Ocean Group Limited since November 2004, Archer since its incorporation in 2007 and Avance Gas Holding Limited since October 2013. Mrs. Blankenship served as a director of Golar LNG Limited from July 2003 until September 2015 and Golar LNG Partners LP from September 2007 until September 2015. She is a member of the Institute of Chartered Accountants in England and Wales.

Harald Thorstein has served as a director of the Company since September 2012. Mr. Thorstein has beenis currently employed by Seatankers Consultancy Services (UK) Limited (previously Frontline Corporate Services since 2011,Services) in London, prior to which he was employed in the Corporate Finance division of DnB NOR Markets, from 2008 to 2011, 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. Mr. Thorstein has served as a director of Archer since 2015, Ship Finance since 2011, North Atlantic Drilling Limited since September 2013 and Northern Offshore Limited since 2012, Golden Ocean Group Limited since 2014, Frontline 2012 since 2014 and has served as the Chairman of the Board of Directors Deep Sea Supply PLC since May 2013.

Andrew Cumming was originally appointed by the remaining elected directors to replace Bart Veldhuizen as a Class III elected director in June 2015.2015 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 seven7 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.  MrMr. Cumming also currently acts as a director of a UK hotels company, MacDonald Hotel Group, a mortgage company, Bluestone Holdings Group, and a private equity company, Lloyds Development Capital. Mr. Cumming also serves on the Company’s conflicts committee.


Keith MacDonaldwas 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 a number of 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 two assetthree aircraft finance entities AABS Limited and RISE Limited and is a Non-Executive Director of First Derivatives plc, a financial technologyFinTech 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 member of the Institute of Directors.Chartered Director.

Executive Officers
The Company currently does not employ any of the Company'sits executive officers and relies solely on Seadrill Management to provide the Company with personnel who perform executive officer services for the Company's benefit pursuant to the management and administrative services agreementsagreement and who are responsible for the Company's day-to-day management subject to the direction of the Company's board of directors. Seadrill Management also provides certain advisory, technical management services to the Company’s fleet and administrative services to the Company pursuant to the management and administrative services agreement.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.
NameAgePosition
Mark Morris (1)5254Chief Executive Officer
John T. Roche (2)3638Chief Financial Officer
(1)Mark Morris replaced Graham Robjohns as Chief Executive Officer of the Company in September 2015. Mr. Robjohns had     served as Chief Executive Officer since June 2012
(2)John Roche replaced Rune Magnus Lundetræ as Chief Financial Officer of the Company in June 2015. Mr. Lundetræ had served as Chief Financial Officer since June 2012

Mark Morris replaced Graham Robjohnshas served as the Chief Executive Officer of the Company commencingsince September 1, 2015. Effective September 1, 2015, MarkMr. Morris also began servinghas served as the Chief Financial Officer of Seadrill.Seadrill since September 2015. Prior to joining Seadrill Partners and Seadrill, Mr. Morris was most recently Chief Financial Officer for Rolls-Royce Group plc. During his 28 year career at Rolls Royce, amongstamong other roles, Mark

served as Group Treasurer, Managing Director, Rolls-Royce Capital and Treasurer of International Aero Engines, a Rolls-Royce Joint Venture. Mr. Morris is employed by Seadrill Management Ltd.
John T. Roche replaced Rune Magnus Lundetraehas served as the Chief Financial Officer of the Company effectivesince June 1, 2015. Since 2013, Mr. Roche is also currentlyhas served as Vice President of Investor Relations for Seadrill and will continue with this responsibility on a part time basis.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
ReimbursementExecutive Compensation
We are managed on a day to day basis by our executive officers, Mark Morris and John Roche, who are employees of Expenses
The Seadrill Member does not receive compensation fromand provide services to us under the Company for any services it may provide on the Company's behalf, although it is entitled to reimbursement for expenses incurred on the Company's behalf. In addition, the Company reimburses Seadrill Management for expenses incurred pursuant toterms of the management and administrative services agreement that the Company entered into with Seadrill Management in connection with the closing of the Company's IPO.agreement. Please read Item 7 “Major"Major Unitholders and Related Party Transactions—RelatedTransactions-Related Party Transactions—ManagementTransactions-Management and Administrative Services Agreement.”Agreement" for further details on this agreement.
Executive Compensation
Under the management and administrative services agreements, the Company is obligated to reimburse Seadrill Management for its reasonable costs and expenses incurred in connection with the provision of executive officer and other administrative services to us. In addition, the Company is obligated to pay Seadrill Management a management fee equal to 5% of the costs and expenses incurred on the Company's behalf. For the year endedyear-ended December 31, 2015, the Company incurred total costs, expenses and fees under these agreements of approximately $0.5 million. During the year ended December 31, 2015, the Company also paid a management fee to2017, we were charged $0.3 million by Seadrill UK Ltd. equal to 5% of its costs and expenses pursuant to an additional management and administrative services agreement in connection with the provision of services by Graham Robjohns as Chief Executive Officer of the Company. This agreement was terminated concurrently with the end of Mr. Robjohns’ service as an officer of the Company. The amount of the Company's reimbursement to Seadrill Management for the timeservices of the Company's officers depends on an estimate of the percentage of time the Company's officers spend on the Company's business and is based upon a percentage of the salary and benefits Seadrill Management, as applicable, pays to such officers. Seadrill Management Ltd. provides for the compensation of Mr.Mark Morris and Mr.John Roche in accordance with its own policies and procedures. The Company doesunder this agreement. We do not pay any additional compensation to the Company'seither of our executive officers. Officers and employees of affiliates of Seadrill may participate in employee benefit plans and arrangements sponsored
Directors Appointed by Seadrill or its affiliates, including plans that may be established in
Two of our Directors, Kate Blankenship and Graham Robjohns were appointed to the future. Please read Item 7 “Major Unitholders and Related Party Transactions—Related Party Transactions—Management and Administrative Services Agreement.”

Compensation ofBoard by Seadrill. We pay these Directors
The Company's officers or officers of Seadrill who also serve as the Company's directors receive additional compensation for their service as directors. AdditionallyDirectors, and we reimburse them for out-of-pocket expenses incurred attending meetings of the Company's directors receiveBoard or its committees.
For the year-ended December 31, 2017, the two Directors appointed by Seadrill received aggregate compensation for their service as directors and membersservices of $0.1 million. In addition, we reimbursed each of these Directors for out-of-pocket expenses incurred attending meetings of the audit committeeBoard or its committees.

Directors Elected by Common Unit Holders

Four of our Directors, Bert Bekker, Harold Thorstein, Andrew Cumming and conflicts committee receive additional compensationKeith MacDonald were elected by our common unit holders. We pay these Directors, and we reimbursed them for their services on theseout-of-pocket expenses incurred attending meetings of the Board or its committees. During

For the year endedyear-ended December 31, 2015,2017, the Company's directorsDirectors elected by common unitholders received aggregate compensation for services of $0.3 million. In addition,

Indemnification
We fully indemnify each director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by the CompanyDirector for actions associated with being a directorDirector to the extent permitted under Marshall Islands law.

C.     Board Practices
General
The Company'sOur operating agreement provides that the Company's board of directorsBoard has authority to oversee and direct the Company'sour operations, management and policies on an exclusive basis. The Company's executive officers manage the Company'sour day-to-day activities consistent with the policies and procedures adopted by the Company's board of directors.Board. Certain of the Company's current executive officers and directors are also executive officers or directors of Seadrill or its subsidiaries.Seadrill.
The Company's current board of directorsBoard consists of six members: Kate Blankenship, Graham Robjohns, Bert Bekker, Harald Thorstein, Andrew Cumming, and Keith MacDonald. The Company's boardBoard has determined that each of Mrs.Ms. Blankenship, Mr. Bekker, Mr. Cumming and Mr. MacDonald satisfies the independence standards established by The New York Stock Exchange, or NYSE and Rule 10A-3 of the Exchange Act as applicable to the Company. Ms. Blankenship Mr. Robjohns and Mr. MacDonald,Robjohns were appointed by the Seadrill Member in its sole discretion and will serve as directors for terms determined by the Seadrill Member.Seadrill. Mr. Bekker, Mr. Thorstein, Mr. Cumming and Mr. BekkerMacDonald were elected by the Company'sour common unitholders. Mr. Cumming was appointed by the remaining elected directors pursuant to our operating agreement to replace Bart Veldhuizen upon his resignation from our board of directors in June 2015.
Directors elected by itsour common unitholders are divided into three classes serving staggered three-year terms. HaraldMr. Thorstein is designated as the Class I elected director and will serve until the Company's annual meeting of unitholders in 2017, Bert2020. Mr. Bekker is designated as the Class II elected director and will serve until the Company's annual meeting of unitholders in 2018,2018. Each of Mr. MacDonald and AndrewMr. Cumming is designated as a Class III elected director and will serve until the Company's annual meeting of unitholders in 2016. 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 Company's common unitholders will be nominated by the board of directorsBoard or by any member or group of members that holds at least 10% of the outstanding common units.
On November 3, 2015, the Company announced that Mr. Tony Curry, a Class III elected director, passed away following a period of illness. Mr. Curry served as a director since April 2013 and was a member of the conflicts committee. The remaining elected directors of the Company are entitled to elect Mr. Curry’s replacement to serve the remainder of Mr. Curry’s term, which expires at the 2016 annual meeting of members of the Company.
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)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
The Company hasWe have an audit committee that, among other things, reviews the Company'sour external financial reporting, engages external auditors and oversees its internal audit activities and procedures and the adequacy of its internal accounting controls. The Company's audit committee is currently composed of three directors, Ms.Mrs. Blankenship, Mr. Bekker and Mr. MacDonald. The Company's board has determined that each of Ms.Mrs. Blankenship Mr. Bekker and Mr. MacDonald satisfies the independence standards established by the NYSE. Ms. Blankenship qualifiesqualify as an “audit"audit committee expert”experts" for purposes of SEC rules and regulations.

The CompanyWe also hashave a conflicts committee composed of two members of its board of directors.the Board. The conflicts committee is available at the board’sBoard’s discretion to review specific matters that the boardBoard believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to the Company.Seadrill Partners. The members of the conflicts committee may not be officers or employees of the CompanySeadrill Partners or directors, officers or employees of the Seadrill Member 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 the Company,Seadrill Partners, approved by all of its members, and not a breach by its directors, the Seadrill Member or its affiliates of any duties any of them may owe the Company or its unitholders. The current members of the Company's conflicts committee are Mr. Cumming and Mr. MacDonald.
Exemption from NYSE Corporate Governance Rules
Because the CompanySeadrill Partners qualifies as a foreign private issuer under SEC rules, the Company iswe are permitted to follow the corporate governance practices of the Marshall Islands (the jurisdiction in which the CompanySeadrill Partners is organized) in lieu of certain NYSE corporate governance requirements that would otherwise be applicable to U.S. companies. NYSE rules do not require a listed company that is a foreign private issuer to have a board of directors that is composed of a majority of independent directors. Under Marshall Islands law, the Company iswe are not required to have a board of directors composed of a majority of directors meeting the independence standards described in NYSE rules. NYSE rules do not require foreign private issuers like us to establish a compensation committee or a nominating/corporate governance committee. Similarly, under Marshall Islands law, the Company iswe are not required to have a compensation committee or a nominating/corporate governance committee. Accordingly, the Company doeswe do not have a compensation committee or a nominating/corporate governance committee. For a listing and further discussion of how the Company'sour corporate governance practices differ from those required of U.S. companies listed on the NYSE, please see Item 16G or visit the corporate governance section of our website at www.seadrillpartners.com.
Management of OPCO
The Company'sOur wholly owned subsidiary, Seadrill Operating GP LLC, the general partner of Seadrill Operating LP, manages Seadrill Operating LP’s operations and activities. The Company's board of directors hasWe 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 Company's directors and officers of Seadrill Partners also serve as directors or executive officers of Seadrill Operating GP LLC. The partnership agreement of Seadrill Operating LP provides that certain actions relating to Seadrill Operating LP must be approved by its board of directors. These actions include, among other things, establishing maintenance and replacement capital and other cash reserves and the determination of the amount of quarterly distributions by Seadrill Operating LP to its partners, including us. In addition, the Company ownswe own 51% of the limited liability company interests in Seadrill Capricorn Holdings LLC and controlscontrol its operations and activities. The CompanyWe also ownsown 100% of the limited liability company interests in Seadrill Partners Operating LLC and controlscontrol its operations and activities. Please read Item 7 “Major Unitholders and Related Party Transactions—Related Party Transactions—OPCO Operating Agreements.Agreements for Seadrill Operating LP and Seadrill Capricorn Holdings LLC.”

D.     Employees
The Company'sOur Chief Executive Officer and Chief Financial Officer provide their services to us pursuant to the management and administrative services agreement.
As of December 31, 2015,2017, approximately 1,5071,153 offshore staff served on the Company’sour offshore drilling units and approximately 8846 staff served onshore in technical, commercial and administrative roles in various countries. Certain subsidiaries of Seadrill provide onshore advisory, operational and administrative support to the Company’sour operating subsidiaries pursuant to service agreements. Please read Item 7 “Major

"Major Unitholders and Related Party Transactions—Related Party Transactions—Advisory, Technical and Administrative Services Agreement,”Agreements", and “Major"Major Unitholders and Related Party Transactions—Related Party Transactions—Management and Administrative Services Agreement”Agreement".
Some of Seadrill’s employees that provide services for the Companyto us and the Company’ssome 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, for the Company, other increased costs or increased operating restrictions that could adversely affect itsour financial performance. Seadrill considers itsWe consider our and Seadrill's relationships with the various unions as stable, productive and professional.

E.     Unit Ownership
See Item 7 “Major"Major Unitholders and Related Party Transactions—Major Unitholders.”Unitholders".


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 April 28, 2016:March 31, 2018:
 
Name of Beneficial Owner
Common Units
Beneficially Owned
 
Subordinated Units
Beneficially Owned
 Percentage of Total Common and Subordinated Units Beneficially Owned
Common Units
Beneficially Owned
 
Subordinated Units
Beneficially Owned
 Percentage of Total Common and Subordinated Units Beneficially Owned
Number Percent Number Percent  Number Percent Number Percent  
Seadrill Limited (1)
26,275,750
 34.9% 16,543,350
 100.0% 46.6%26,275,750
 34.9% 16,543,350
 100.0% 46.6%
OppenheimerFunds, Inc. and Oppenheimer SteelPath MLP Alpha Fund (2)
6,802,915
 9.0% —
 —% 7.4%
Mark Morris (Chief Executive Officer)—
 —% —
 —% —
—
 —% —
��—% —
John Roche (Chief Financial Officer)—
 —% —
 —% —
—
 —% —
 —% —
Graham Robjohns (Director)*
 *
 —
 —% —%*
 *
 —
 —% *
Bert Bekker (Director)—
 —% —
 —% —%—
 —% —
 —% —%
Kate Blankenship (Director)*
 *
 —
 —% *
*
 *
 —
 —% *
Harald Thorstein (Director)—
 —% —
 —% —%—
 —% —
 —% —%
Andrew Cumming (Director)—
 —% —
 —% —%—
 —% —
 —% —%
Keith MacDonald (Director)*
 *
 —
 —% —%*
 *
 —
 —% *
All directors and executive officers as a group (8 persons)*
 *
 —
 —% *
*
 *
 —
 —% *
 * Less than 1%.

(1)Seadrill’s principal shareholder is Hemen Holdings Limited. Hemen Holding Limited, a Cyprus Holding Company, and other related companies which are collectively referred to herein as Hemen, the shares of which are held in trusts established by Mr. John Fredriksen for the benefit of his immediate family. Mr. Fredriksen disclaims beneficial ownership of the 119,097,583 shares, or 24.2%23.6%, of the common stock of Seadrill, except to the extent of his voting and dispositive interest in such shares of common stock. Mr. Fredriksen has no pecuniary interest in the shares held by Hemen. In addition to the holdings of shares above, as of March 31, 2016, Hemen is party to Total Return Swap agreements relating to 3,900,000 of Seadrill’s common shares.
(2)Oppenheimer Funds, Inc. has shared voting power and shared dispositive power as to 6,802,915 common units, which represents 9.0% of the common units outstanding and 7.4% of the common and subordinated units outstanding. Oppenheimer SteelPath MLP Alpha Fund has shared voting power and shared dispositive power as to 4,147,646 common units, which represents 5.5% of the common units outstanding and 4.5% of the common and subordinated units outstanding. This information is based solely on the Schedule 13G/A filed by Oppenheimer Funds, Inc. and Oppenheimer SteelPath MLP Alpha Fund on February 4, 2016. 
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)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 Company's board of directorsBoard 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, the Company haswe have entered into agreements and has consummated transactions with certain related parties. The CompanyWe may enter into related party transactions from time to time in the future. In connection with the Company'sour IPO, the Companywe established a conflicts committee, comprised entirely of independent directors, which must approve all proposed material related party transactions.

Additional disclosure of related party transactions for the years ended December 31, 2015, 2014,2017, 2016, and 20132015 are presented in Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out 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, Technicaltechnical and Administrative Services Agreementsadministrative services agreements
v.Operating Agreementsagreements 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 an omnibus agreementthe 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.Omnibus Agreement.

NoncompetitionNon-competition
Under the omnibus agreement,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,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"Five-Year Drilling Rigs”Rigs" and to all other drilling rigs, together with any related contracts, as “Non-Five-Year"Non-Five-Year Drilling Rigs.”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.

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 agreementOmnibus Agreement the Company is not restricted from acquiring, operating or contracting for Non-Five-Year Drilling Rigs.

Upon a change of control of us or the Seadrill Member, the noncompetition provisions of the omnibus agreementOmnibus Agreement will terminate immediately. Upon a change of control of Seadrill, the noncompetition provisions of the omnibus agreementOmnibus 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,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,Omnibus Agreement, Seadrill agreed (and will cause theirits subsidiaries to agree) to grant a similar right of first offer to us for any Five-Year Drilling Rigs they might own. These rights of first offer do not apply to a (a) sale, transfer or other disposition of drilling rigs between any affiliated subsidiaries, or pursuant to the terms of any current or future contract or other agreement with a contractual counterparty or (b) merger with or into, or sale of substantially all of the assets to, an unaffiliated third-party.

Prior to engaging in any negotiation regarding any drilling rig’s disposition with respect to a Five-Year Drilling Rig with a non-affiliated third-party or any Non-Five-Year Drilling Rig, the Company or Seadrill, as the case may be, will deliver a written notice to the other relevant party setting forth the material terms and conditions of the proposed transaction. During the 30 day period after the delivery of such notice, the Company and Seadrill will negotiate in good faith to reach an agreement on the transaction. If the Company does not reach an agreement within such 30 day period, the Company or Seadrill, as the case may be, will be able within the next 180 calendar days to sell, transfer, dispose or re-contract the drilling rig to a third party (or to agree in writing to undertake such transaction with a third party) on terms generally no less favorable to us or Seadrill, as the case may be, than those offered pursuant to the written notice.

Upon a change of control of us or the Seadrill Member, the right of first offer provisions of the omnibus agreementOmnibus Agreement will terminate immediately. Upon a change of control of Seadrill, the right of first offer provisions applicable to Seadrill under the omnibus agreementOmnibus 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,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 agreementOmnibus 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 daysday 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 agreementOmnibus 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 agreementOmnibus Agreement relating to the right of first offer with respect to the equity interests in OPCO will terminate at the later of (a) the date on which all of the outstanding subordinated units have converted into common units and (b) the date of the change of control of Seadrill.

Indemnification
Under the omnibus agreement,Omnibus Agreement, Seadrill has agreed to indemnify us until October 24, 2017 against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to us to the extent arising prior to the time they were contributed or sold to us. Liabilities resulting from a change in law after October 24, 2012 are excluded from the environmental indemnity. There is an aggregate cap of $10 million on the amount of indemnity coverage provided by Seadrill for environmental and toxic tort liabilities. No claim may be made unless the aggregate dollar amount of all claims exceeds $500,000, in which case Seadrill is liable for claims only to the extent such aggregate amount exceeds $500,000.

Seadrill has also agreed to indemnify us for liabilities related to:
certain defects in title to Seadrill’s assets contributed or sold to OPCO and any failure to obtain, prior to the time they were contributed, certain consents and permits necessary to conduct, own and operate such assets, which liabilities arise on or before October 24, 2015 (or, in the case of the T-15 or the T-16, within three years after its purchase of the T-15 or the T-16); and
���
tax liabilities attributable to the operation of the assets contributed or sold to OPCO prior to the time they were contributed or sold.

Amendments
The omnibus agreementOmnibus Agreement may not be amended without the prior approval of the conflicts committee of the Company's board of directorsBoard if the proposed amendment will, in the reasonable discretion of its board of directors,the Board, adversely affect holders of itsthe Company's common units.


ii. Acquisitions
The Company has made the following acquisitions sincefor the IPO:period from January 1, 2015 through December 31, 2017:

T-15Polaris Acquisition
On May 17, 2013, Seadrill Partners Operating LLC acquired Seadrill T-15 Ltd., or Seadrill T-15, the entity that owns the T-15, and Seadrill International Limited, the entity that is party to the T-15 and T-16 drilling contracts, from Seadrill for a total purchase price of $210.0 million, less $100.5 million of debt assumed relating to the proportion of Seadrill's existing $440 million credit facility. Working capital adjustments reduced the purchase price by $34.9 million, which was settled in cash during the year.

In connection with the T-15 acquisition, Seadrill T-15 entered into a related party loan agreement with Seadrill in the amount of approximately $100.5 million, corresponding to the aggregate principal amount outstanding under the $440 Million Rig Financing Agreement allocable to the T-15. Pursuant to the related party loan agreement, Seadrill T-15 can make payments of principal and interest directly to the lenders under the $440 Million Rig Financing Agreement on Seadrill's behalf or to Seadrill, corresponding to payments of principal and interest due under the $440 Million Rig Financing Agreement that are allocable to the T-15. Seadrill has the option to make the payments of principal and interest directly to the lenders themselves, and specify an alternate method of compensation from Seadrill T-15. The $440 Million Rig Financing Agreement is a $440 million senior secured term loan with a syndicate of banks. The T-15 and the T-16 are pledged to secure Seadrill’s obligations under $440 Million Rig Financing Agreement. The $440 Million Rig Financing Agreement bears interest at a rate of LIBOR plus 3.25% and will mature in December 2017.

T-16 Acquisition
On October 18, 2013, Seadrill Partners Operating LLC acquired from Seadrill a 100% ownership interest in the entity that owns the tender rig T-16 for a total purchase price of $200.0 million, less $93.1 million of debt assumed relating to the proportion of the existing $440 million credit facility, relating to the T-16. Working capital adjustments reduced the purchase price by $39.0 million, which was recognized within related party receivables at December 31, 2013.
In connection with the T-16 acquisition, Seadrill T-16 entered into a related party loan agreement with Seadrill in the amount of approximately $93.1 million, corresponding to the aggregate principal amount allocable to the T-16 outstanding under the $440 Million Rig Financing Agreement. Pursuant to the related party loan agreement, Seadrill T-16 can make payments of principal and interest directly to the lenders under the $440 Million Rig Financing Agreement on Seadrill's behalf or to Seadrill, corresponding to payments of principal and interest due under the $440 Million Rig Financing Agreement that are allocable to the T-16.

West Leo and West Sirius Acquisitions
On December 13, 2013, Seadrill Operating LP acquired all of the ownership interests in each of the entities that own, operate and manage the semi-submersible drilling rig, West Leo and Seadrill Capricorn Holdings LLC acquired all of the ownership interests in each of the entities that own and operate the semi-submersible drilling rig, West Sirius. The Leo Acquisition and the Sirius Acquisition were accomplished through a series of purchases and contributions. The implied purchase prices of the Leo Acquisition and the Sirius Acquisition were $1.250 billion and $1.035 billion, respectively, in each case, including working capital. The Company's portion of the purchase price after debt financing at the OPCO level for the Leo Acquisition was $229.4 million. The Company's portion of the purchase price after debt financing at the OPCO level for the Sirius Acquisition was $298.4 million. The Company funded $70 million of the $298.4 million purchase price by issuing a zero coupon discount note to Seadrill which was repaid in full in March 2014. In addition, Seadrill Capricorn Holdings LLC financed $229.9 million of the purchase price of the Sirius Acquisition by issuing a zero coupon discount note to Seadrill which was repaid in full in February 2014. As a result of these transactions, the Company acquired a (i) 30% indirect interest in the Leo Business and (ii) 51% indirect interest in the Sirius Business.

In connection with the acquisitions, Seadrill Capricorn Holdings LLC and Seadrill Leo Ltd each entered into related party loan agreements with Seadrill in the amount of approximately $220.1 million and $485.5 million, respectively, corresponding to the aggregate principal amount outstanding under Seadrill's rig financing facilities allocable to the West Sirius and the West Leo, respectively. These loans were repaid in full in February 2014.

West Auriga Acquisition
On March 24, 2014, Seadrill Capricorn Holdings LLC completed the acquisition from Seadrill all of the ownership interests in each of Seadrill Auriga Hungary Kft., a Hungarian company which owns the drillship, the West Auriga, and Seadrill Gulf Operations Auriga LLC, a Delaware limited liability company which operates the West Auriga. The Auriga Acquisition was accomplished through a series of purchases and contributions. As a result of these transactions, the Company acquired a 51% indirect interest in the ownership and operations of the West Auriga, pursuant to a Contribution, Purchase and Sale Agreement, dated as of March 11, 2014, by and among the Company, Seadrill, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc.

The implied purchase price of the Auriga Acquisition was $1.24 billion. The Company's portion of the purchase price for the Auriga Acquisition, after debt financing at the OPCO level, was $355.4 million. In addition, Seadrill Capricorn Holdings LLC financed $100.0 million of the purchase price by issuing a zero coupon limited recourse discount note to Seadrill. At the time of the acquisition, Seadrill Auriga Hungary Kft. was a borrower under the $1.45 billion credit facility used to finance the West Auriga. As of the closing date of the Auriga Acquisition, Seadrill Auriga

Hungary Kft owed $443.1 million in principal under this facility. The liabilities relating to the Company under the facility were subsequently extinguished when the facility was repaid in June 2014.

Purchase of Additional Limited Partner Interest in Seadrill Operating LP
On July 21, 2014, the Company purchased a 28% limited partner interest in Seadrill Operating LP from Seadrill for cash consideration of $372.8 million.

West Vela Acquisition
On November 4, 2014, the Company’s 51% owned subsidiary, Seadrill Capricorn Holdings LLC, completed the purchase of 100% of the ownership interests in each of Seadrill Vela Hungary Kft, a Hungarian company which owns the drillship, the West Vela, and Seadrill Gulf Operations Vela LLC, a Delaware limited liability company which operates the West Vela, pursuant to a Contribution, Purchase and Sale Agreement, dated as of November 4, 2014, by and among Seadrill, the Company, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc. The Vela Acquisition was accomplished through a series of purchases and contributions. As a result of these transactions, the Company acquired a 51% indirect interest in the ownership and operations of the West Auriga. The initial purchase price was $900.0 million. Seadrill Vela Hungary Kft. is a borrower under the $1.45 billion credit facility (the “Vela Facility”) used to finance the West Vela, and under which its obligations are secured by the West Vela. As of the closing date of the Vela Acquisition, Seadrill Vela Hungary Kft owed $433.1 million in principal under the Vela Facility. Seadrill Vela Hungary Kft’s liability to repay debt under the Vela Facility that relates to another rig owned by Seadrill and financed under the Vela Facility remains. However, Seadrill has agreed to indemnify us, Seadrill Capricorn Holdings LLC and Seadrill Vela Hungary Kft. against any liability we may incur under the Vela Facility in respect of such debt.

As part of the acquisition agreement, Seadrill Capricorn Holdings LLC also has an obligation to pay $44,000 per day for the West Vela's current contract with BP which expires in November 2020. In addition Seadrill Capricorn Holdings LLC will pay contingent consideration of up to $40,000 per day for the remainder of the BP contract, depending on the actual amount of contract revenue received from BP per day. The purchase price was subsequently adjusted by a working capital adjustment of $6.0 million.

West Polaris Acquisition
On June 19, 2015, Seadrill Operating LP completed the purchase of 100% of the ownership interests in Seadrill Polaris, the entity that owns and operates the drillship the West Polaris. The initial consideration for the Polaris Acquisition was comprised of $204.0 million of cash and $336.0 million of debt outstanding under the existing credit facility financing the West Polaris.

In addition, Seadrill Operating issued a note (the “Seller's Credit”) of $50.0 million to Seadrill, payment of which is contingent on the future re-contracted dayrate for the West Polaris. The Seller's Credit is due in 2021 and bears an interest rate of 6.5% per annum. During the three-year period following the completion of the current drilling contract with ExxonMobil, the Seller's Credit may be reduced if the average contracted dayrate (net of commissions) for the period, adjusted for utilization, under any replacement contract is below $450 thousand per day until the Seller's Credit's maturity in 2021. Should the average dayrate of the replacement contract be above $450 thousand per day, the entire Seller's Credit must be paid to Seadrill upon maturity of the Seller's Credit in 2021. In addition, Seadrill Polaris may make further contingent payments to Seadrill based upon the West Polaris's operating dayrate. At the time of acquisition, the West Polaris was contracted with ExxonMobil on a dayrate of $653 thousand per day until March 2018. Under the terms of the acquisition agreement, Seadrill Polaris has agreed to pay Seadrill (a) any dayrate it receives in excess of $450 thousand per day, adjusted for daily utilization, through the remaining term, without extension, of the ExxonMobil contract (the “Initial Earn-Out”) and (b) after the expiration of the term of the existing contract until March 2025, 50% of any day rate above $450 thousand per day, adjusted for daily utilization, tax and agency commission (the “Subsequent Earn-Out”).
Refer to Note 3 - “Business acquisitions”"Business acquisitions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report for more information on each acquisition.

the Polaris Acquisition.
iii. Management and Administrative ServiceServices Agreements
In connection with the IPO, subsidiaries of Seadrill Partners, entered into a management and administrative services agreement with Seadrill Management, a wholly owned subsidiary of the Company,Seadrill, pursuant to which Seadrill Management provides Seadrill Partners certain management and administrative services. In April 2016, the agreement was amended and extended for an indefinite term. It can be terminated by providing 90 days written notice. In September 2017, the agreement was updated to clarify the compensation charges for these services. The services provided by Seadrill Management are charged at cost plus a management fee, equalweighted according to 5%the type and stacking status of Seadrill Management’sthe rig. During the year ended December 31, 2017 the management fee has ranged from 4.85% to 8% of costs and expenses incurred in connection with providing these services. The agreement has an initial term for 5 years and can be terminated by providing 90 days written notice. Effective as of April 1, 2013, this agreement was novated from Seadrill Management AS to Seadrill Management Ltd.]
DuringUnder the years ended December 31, 2015, 2014 and 2013, the Company also paid a management fee to Seadrill UK Ltd. equal to 5% of its costs and expenses pursuant to an additional management and administrative services agreement, the Company is obligated to reimburse Seadrill Management for its reasonable costs and expenses incurred in connection with the provision of executive officer and other administrative services by Graham Robjohns as Chief Executive Officer of the Company. This agreement was terminated concurrently with the end of Mr. Robjohns’ service as an officer of the Company.

to us. Please refer to Item 6- "Directors, Senior Management and Employees B- Compensation" for further details.
iv. Advisory, Technical and Administrative Services Agreements
Each of the Company’s operating subsidiaries have entered into certain advisory, technical and administrative services agreements with subsidiaries of Seadrill, pursuant to which such subsidiaries provide advisory, technical and administrative services. Each quarter, the Company’s

The services provided by Seadrill's subsidiaries will reimburse such Seadrill subsidiaries for their reasonable costs and expenses incurred in connection with the provision of these services. In addition, the Company’s subsidiaries will pay to such Seadrill subsidiaries aare charged at cost plus service fee equal to approximately 5% of their costs and expenses incurred in connection with providing services to the Company’s subsidiaries for the quarter.these services. Amounts payable under the advisory, technical and administrative services agreements must be paid within 30 days after such Seadrill subsidiary submits to the applicable subsidiary an invoice for such fees, costs and expenses, together with any supporting detail that may be reasonably required. Such services include:
Operations Services: assistance and support for the development of technical standards, supervision of third-party contractors, development of maintenance practices and strategies, development of operating policies, improvement of efficiency, minimizing environmental and safety incidents, periodic auditing of operations and purchasing and logistics;
Technical Supervision Services: assistance and advice on maintaining vessel classification and compliance with local regulatory requirements, compliance with contractual technical requirements for the drilling units, ensuring that technical operations are professional and satisfactory in every respect;
Accidents-Contingency Plans: assistance in handling all accidents in the course of operations, and development of a crisis management procedure, and other advice and assistance in connection with crisis response, including crisis communications assistance; and
General Administrative Services: any general administrative services as needed.

Under the advisory, technical and administrative services agreements, the Company’s operating subsidiaries have agreed to indemnify certain affiliates of Seadrill and their officers, employees, agents and sub-contractors against all actions which may be brought against them under the advisory, technical and administrative services agreements; provided, however that such indemnity excludes losses which may be caused by or due to the fraud, gross negligence or willful misconduct of Seadrill Management or its officers, employees, agents and sub-contractors. Except for losses that are caused by or due to the fraud of Seadrill Management or its officers, employees, agents and sub-contractors, in no event shall such affiliates of Seadrill’s liability to us exceed ten times the annual services fee.

v. Operating Agreements for Seadrill Operating LP and Seadrill Capricorn Holdings LLC
The Company's wholly-owned subsidiary, Seadrill Operating GP LLC, and Seadrill have entered into an agreement of limited partnership of Seadrill Operating LP. This agreement governs the ownership and management of Seadrill Operating LP, designates Seadrill Operating GP LLC as the general partner of Seadrill Operating LP, and provides for quarterly distributions of available cash to its partners, as determined by us as the sole member of the general partner of Seadrill Operating LP. Seadrill owns 42% of the limited partner interests in Seadrill Operating LP and the Company owns 58% of such interests.
The Company owns 51% of the limited liability company interests in Seadrill Capricorn Holdings LLC and controls its operations and activities. Seadrill owns 49% of the limited liability company interests. The limited liability company agreement that governs the ownership and management of Seadrill Capricorn Holdings LLC provides for quarterly distributions of available cash to its members, as determined by its board of directors.
These operating agreements provide that the amount of cash reserves for future maintenance and replacement capital expenditures, working capital and other matters and the amount of quarterly cash distributions to owners will be determined by the Company as the sole member of Seadrill Operating GP LLC and by the board of directors of Seadrill Capricorn Holdings LLC. In addition, itsthe Company's approval as the sole member of Seadrill Operating GP LLC and as the controlling member of Seadrill Capricorn Holdings LLC is required for the following actions relating to Seadrill Operating LP or Seadrill Capricorn Holdings LLC:
effecting any merger or consolidation involving Seadrill Operating LP or Seadrill Capricorn Holdings LLC;
effecting any sale or exchange of all or substantially all of Seadrill Operating LP or Seadrill Capricorn Holdings LLC's assets;

dissolving or liquidating Seadrill Operating LP or Seadrill Capricorn Holdings LLC;
creating or causing to exist any consensual restriction on the ability of Seadrill Operating LP or Seadrill Capricorn Holdings LLC to make distributions, pay any indebtedness, make loans or advances or transfer assets to us or its subsidiaries;
settling or compromising any claim, dispute or litigation directly against, or otherwise relating to indemnification by Seadrill Operating LP or Seadrill Capricorn Holdings LLC of, any of the directors or officers of Seadrill Operating GP LLC or Seadrill Capricorn Holdings LLC; or
issuing additional interests in Seadrill Operating LP or Seadrill Capricorn Holdings LLC.
Approval of the conflicts committee of the Company's board of directorsBoard is required to amend these operating agreements.


vi. Loans and Financing Agreements
Seadrill has provided the Company and its subsidiaries with various loans and financing agreements. Below is information regarding the loans outstanding during the yearyears ended December 31, 20152017 and 2014.2016. For additional disclosure regarding these agreements, please read Note 11 - “Debt”"Debt" and Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

$440 MillionTender Rig Facility (previously referred to as $440 million Rig Financing AgreementAgreement).
Seadrill financed the construction of thecertain drilling units in the Company’s fleet with borrowings under third party credit facilities. In connection with the Company's IPO and certain subsequent acquisitions from Seadrill, Seadrill amended and restated the various third party credit facilities (“Rig Financing Agreements”) to allow for the transfer of the respective drilling units to OPCO and to provide for OPCO and its subsidiaries that, directly or indirectly, own the drilling units to guarantee the obligations under the facilities. In connection therewith, such subsidiaries

entered into intercompany loan agreements with Seadrill corresponding to the aggregate principal amount outstanding under the third party credit facilities allocable to the applicable drilling units.
During the twelve months ended December 31, 2014, certain Rig Financing Agreements were repaid with the proceeds of the Senior Secured Credit Facilities as further discussed above. As of December 31, 2015, the only remaining Rig Financing Agreement with Seadrill related toThe Facility was originally secured by the T-15andT-16 (the “$440 Million Rig Financing Agreement”).
In December 2012, Seadrill entered into a $440 million secured term loan facility with a syndicate of banks in part to fund the acquisition of the T-15 and T-16. This secured term loan is referred to herein as the $440 Million Rig Financing Agreement.  The $440 Million Rig Financing Agreement is secured by the T-15 and T-16 and twoone other rigsrig owned by Seadrill. The T-15 and T-16 Credit Facility bears interest at a rate of LIBOR plus 3.25% and will mature in December 2017. In May 2013, Seadrill entered into an amendment to the $440 Million Rig Financing Agreementagreement to allow for the transfer of the T-15 to Seadrill Partners Operating LLC and to add Seadrill Partners Operating LLC as a guarantor under the $440 Million Rig Financing Agreement.financing agreement.  In October 2013, Seadrill entered into an amendment to the $440 Million Rig Financing Agreementagreement to allow for the transfer of the T-16 to Seadrill Partners Operating LLC. Effective from the respective dates of transfer of the T-15 and the T-16 from Seadrill to Seadrill Partners Operating LLC, the entities that own the T-15 and T-16 entered into intercompany loan agreements with Seadrill in the amount of approximately $100.5 million and $93.1 million, respectively. PursuantThese loans bore interest at a rate of LIBOR plus 3.25% and were due to the intercompany loan agreements, themature in December 2017. The entities which own the T-15 and T-16 make made payments of principal and interest directly to the lenders under the $440 Million Rig Financing Agreement, at Seadrill’s direction and on its behalf.  Such payments correspondcorresponded to payments of principal and interest due under the $440 Million Rig Financing Agreement that are allocable to the T-15 and the T-16. T-16. 
In August 2017, amendments were made to insulate Seadrill Partners from the events of default related to Seadrill's use of Chapter 11 proceedings and addressed near-term refinancing requirements. The total amounts owed underfacility has been split into two separate facilities, the $440 Million Rig Financing Agreement, totaled $139 million“Tender rig facility” and the “West Telesto facility”. Recourse of the Tender rig facility is now only to us and recourse of the West Telesto facility is now only to Seadrill. Since the amendment, the facility is no longer a related party agreement and is classified as "Long term debt" on the Consolidated Balance Sheet. The outstanding balance of this facility as of December 31, 2015 (December 31, 2014: $159 million). Certain subsidiaries of the Company are guarantors under the external facilities in which the T-15 and T-16 are pledged as security. Under the terms of the facilities, the guarantors are jointly and severally liable for other guarantors and the borrower who are party to this facility. Seadrill has provided an indemnification to the Company for any payments or obligations related to these facilities for any losses incurred which do not relate to the T-15 and T-16.

2017 was $83.3 million.
West Vencedor Loan Agreement
The senior secured credit facility relating to the West Vencedor was repaid in full by Seadrill in June 2014, and subsequently the related party agreement between the Company's subsidiary, Seadrill Vencedor Ltd., and Seadrill was amended to carry on this facility on the same terms (the “West"West Vencedor Loan Agreement”Agreement"). The West Vencedor Loan Agreement was scheduled to mature in June 2015, andat which time all outstanding amounts thereunder would behave become due and payable, including a balloon payment of $70 million. On April 14, 2015, the West Vencedor Loan Agreement was amended and the maturity date was extended to June 25, 2018. The West Vencedor Loan Agreement bears interest at LIBOR plus a margin of 2.25%, a guarantee fee of 1.4%2.3% and a balloon payment of $21 million due at maturity in June 2018. The total amount owed to Seadrill under the remaining West Vencedor Loan Agreement as of December 31, 2015,2017, was $58$24.7 million (December 31, 2014: $782016: $41.2 million).

$1,450 MillionWest Vela Facility (previously referred to as the $1,450 million Senior Secured Credit FacilityFacility).
Under the terms of the $1,450 Million Senior Secured CreditWest Vela Facility certain subsidiaries of Seadrill and the Company arewere jointly and severally liable for their own debt and obligations under the facility and the debt and obligations of other borrowers who are alsowere party to such agreement.  These obligations are continuing and extend to amounts payable by any borrower under the facility. Seadrill has provided an indemnity to the Companyus for any payments or obligations related to this facility that are not related to the West Vela. The facility hashad a final maturity in 2025, with a commercial tranche due for renewalmaturing in 2018, and bearsbore interest at a rate equal to LIBOR plus a margin that variesvaried from 1.2% to 3% depending on which of the four loan tranches to which it is applicable.applicable which, in the case of the 3% margin, may be further increased by an additional 0.75% per annum depending on the leverage ratio.
In August 2017, amendments were made to insulate Seadrill Partners from the events of default related to Seadrill's use of Chapter 11 proceedings and addressed near-term refinancing requirements. This facility has been split into two separate facilities, the “West Vela facility” and the “West Tellus facility”. Recourse of the West Vela facility is now only to us and recourse of the West Tellus facility is now only to Seadrill. Since the amendment, the facility is no longer a related party agreement and is classified as "Long term debt" on the Consolidated Balance Sheet. The total amount owed by all partiesoutstanding balance under this facility as of December 31, 2015 is $775.62017 was $255.3 million (December 31, 2014: $856 million).

$109.5 Million Vendor FinancingWest Sirius Loan and Seadrill Loan
In May, 2013, the Company borrowed from Seadrill $109.5 million as vendor financing to fund the acquisition of the T-15. The loan bears interest at a rate of LIBOR plus a margin of 5% and matures in May 2016. The outstanding balance as of December 31, 2015 was $109.5 million (December 31, 2014: $109.5 million).

$143 Million Loan Agreement
Effective as of December 17, 2015, an operating subsidiary of the Company borrowed $143.0 million (the “West Sirius loan”) from Seadrill in order to provide sufficient immediate liquidity to meet the terms of its bareboat charter termination payment in connection with the West Sirius contract termination. Concurrently, Seadrill borrowed $143.0 million (the “Seadrill loan”) from a rig owning subsidiary of the Company in order to restore its liquidity with respect to the West Sirius loan.

Each of the loan parties understood and agreed that the loan agreements acted in parallel with each other.
Each loan bearsbore an interest rate of one-month LIBOR plus 0.56% and maturesmatured in August 2017. Each of the loan parties understand and agree that the loan agreements act in parallel with each other. As of December 31, 2015, $143.02017, the loan had been fully repaid by both parties. At December 31, 2016, $39.4 million was outstanding under each such loan.

$100 Million Sponsor Revolving Credit Facility
On October 24, 2012, in connection with the closing of the Company's IPO, OPCO entered into a $300 million revolving credit facility with Seadrill, as the lender, to be used to fund working capital requirements, acquisitions and other general company purposes. On March 1, 2014, the revolving credit facilitySponsor Revolving Credit Facility was amended to reduce its capacity to $100 million. The sponsor credit facility isSponsor Revolving Credit Facility was for a term of 5 years, maturing on October 24, 2017 and bears

bore interest at a rate of LIBOR plus 5% per annum, with an annual 2% commitment fee on the undrawn balance.
In August 2017, amendments were made to insulate Seadrill Partners from the events of default related to Seadrill's use of Chapter 11 proceedings. As part of this arrangement, the Sponsor Revolving Credit Facility was canceled. The outstanding balance of $125.9 million was repaid in full in March 2014. The outstanding balance as offacility had remained undrawn for the year ended December 31, 2015 was nil (December2017 and December 31, 2014: nil).


2016.
vii. Derivative Interest Rate Swap Agreements
AsThe filing of December 31, 2015, the Company wasSeadrill's Chapter 11 petitions triggered an event of default under each of Seadrill's ISDA agreements. The related party to interest rate swap agreements held with Seadrill for a combined outstanding principal amount of approximately $655.3 million at rates between 1.10% per annum and 1.93% per annum. The swap agreements mature between July 2018 and December 2020. The net loss recognized on the Company’s interest rate swaps for the year ended December 31, 2015, was $10.2 million (year ended December 31, 2014: loss of $41.6 million).were therefore canceled September 12, 2017. Refer to Note 14 - “Risk"Risk management and financial instruments”instruments" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report for further information.

viii. Bareboat Charter Agreements
In connection with the transfer of the West Aquarius operations to Canada, the West Aquarius drilling contract was assigned to Seadrill Canada Ltd., a wholly owned subsidiary of OPCO, necessitating certain changes to the inter-company contractual arrangements relating to the West Aquarius.Between October 2012 and April 2017, Seadrill China Operations Ltd, the owner of the West Aquarius andLimited S.A.R.L, a wholly-owned subsidiary of OPCO, had previously entered into a bareboat charter arrangement withSeadrill Operating LP, provided Seadrill Offshore AS, a wholly-owned subsidiary of Seadrill, providing Seadrill Offshore AS with the right to use the West Aquarius. In October 2012, this under a bareboat charter arrangement was replaced with a new bareboat charter between Seadrill China Operations Ltd andarrangement. During the same period, Seadrill Offshore AS and at the same time, Seadrill Offshore AS entered into a bareboat charter arrangement providingprovided Seadrill Canada Ltd.Ltd, a subsidiary of Seadrill Operating LP, with the right to use the West Aquarius in order to perform its obligations under the drilling contract described above.a further bareboat charter arrangement. The net effect to OPCOthe Company of these bareboat chartertwo arrangements iswas a cost of $25,500 per day, but due tofor the downtime ofperiod that the rig during 2015 the total effectarrangement was income of $2.1 million.in place.

Until December 31, 2016 Seadrill T-15 Ltd. and Seadrill International Ltd. arewere each party to a bareboat charter agreement with Seadrill UK Ltd.,Limited, a wholly owned subsidiary of Seadrill. Under this arrangement, the difference in the charter hire rate between the two charters iswas retained by Seadrill UK Ltd., in the amount of approximately $820 per day.

Similarly, until December 31, 2016 Seadrill T-16 Ltd. and Seadrill International Ltd. arewere each party to a bareboat charter agreement with Seadrill UK Ltd.Limited. Under this arrangement, the difference in the charter hire rate between the two charters iswas retained by Seadrill UK Ltd., in the amount of approximately $770 per day.

All of these agreements were terminated effective December 31, 2016.
For the year ended December 31, 20152017 the net effect to OPCOthe Company of the above bareboat charters was net incomeexpenditure of $1.6 million.$2.8 million (December 31, 2016: $9.5 million).
ix. Equity Distribution
During the year-ended December 31, 2017, one of our subsidiaries settled certain balances related to a shareholder loan provided by Seadrill. On account of the loan's structure these payments have been treated as equity distributions. A total balance of $15.3 million has been distributed to Seadrill, comprised of a $6.1 million cash distribution and a $9.2 million non-cash distribution that was offset against certain trading balances owed to us by Seadrill.

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

C.     Interests of Experts and Counsel
Not applicable.

Item 8.         Financial Information

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

Legal Proceedings
From time to time the Company has been, and expects that in the future it will be, subject to legal proceedings and claims in the ordinary course of business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources. Our best estimate of the outcome of the various disputes has been reflected in these financial statements as of December 31, 2017.
West Leo
We received a notice of force majeure in October 2016 for the West Leo 's contract with Tullow in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience.
We do not accept that the contract has been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract has been discharged by frustration. Accordingly, we amended our claim in the English High Court to reflect this. In the event of termination for convenience, we are entitled to an early termination fee of 60% of the remaining contract backlog, subject to an upward or downward adjustment depending on the work secured for the West Leo over the remainder of the contract term, plus other direct costs incurred as a result of the early termination.
The Companytotal amount that we are seeking to recover is $278 million plus interest. The case is scheduled to be heard on May 8, 2018.
Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit against certain of our subsidiaries for patent infringement. The suit alleges that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity drilling. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and Trademark Office which ultimately stayed the litigation. The IPR board held in March 2017 that the patents were valid. Despite this finding, we do not believe that our rigs infringe the Transocean patents, which have now expired, and we continue to defend ourselves vigorously against this suit. We do not believe that the ultimate liability, if any, resulting from this litigation will have a material effect on our financial position. We have not recognized any related loss contingency in our Consolidated Financial Statements as of December 31, 2017 as we do not believe the loss to be probable. We are also not able to make a reasonable estimate of the possible loss.
We are not aware of any other legal proceedings or claims that the Company believes will have, individually or in the aggregate, a material adverse effect on the Company.
Please also see "Note 15 - Commitments"Commitments and Contingencies"contingencies" to the audited Consolidated and Combined Carve-Out Financial Statements included elsewhere in this annual report.
The Company's Cash Distribution Policy
Rationale for the Company's Cash Distribution Policy
The Company'sOur cash distribution policy reflects a judgment that itsour unitholders will be better served by the Company distributing itsour available cash (after deducting expenses, including estimated maintenance and replacement capital expenditures and reserves) rather than retaining it. The CompanyWe will generally finance any expansion capital expenditures from external financing sources, including borrowings from commercial banks and the issuance of equity and debt securities. The Company'sOur cash distribution policy is consistent with the terms of itsour operating agreement, which requires that the Companywe distribute all of the Company'sour 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. The Company'sOur 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 Company's board of directorsBoard 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 of directors)Board), has authority to establish reserves for the prudent conduct of its business. In addition, the Company's board of directorsBoard controls Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC, and has the authority to establish reserves for the prudent conduct of their respective businesses. The establishment of these reserves could result in a reduction in cash distributions to the Company's unitholders from levels the Company currently anticipates pursuant to the Company's stated cash distribution policy.
The Company's ability to make cash distributions will be limited by restrictions on distributions under its financing agreements. The Company’s financing agreements contain material financial tests and covenants that must be satisfied in order to pay distributions. If the Company is unable to satisfy the restrictions included in any of its financing agreements or is otherwise in default under any of those agreements, it could have a material adverse effect on the Company's ability to make cash distributions to its unitholders, notwithstanding the Company's stated cash distribution policy. These financial tests and covenants are described in this annual report in Item 5 “Operating"Operating and Financial Review and Prospects—Liquidity and Capital Resources—Borrowing Activities.”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 March 31, 2016,2018, Seadrill owns approximately 34.9% of the Company's common units and all of the Company's subordinated units.
Even if the Company's cash distribution policy is not modified or revoked, the amount of distributions the Company pays under the Company's cash distribution policy and the decision to make any distribution is determined by the Company's board of directors,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 members or partners, as applicable.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.
The Company'sOur ability to make distributions to the Company's unitholders depends on the performance of the Company'sour controlled affiliates, including OPCO, and their ability to distribute cash to us. The Company'sOur interests in OPCO represent the Company's only cash-generating assets. The ability of the Company'sour 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 Company's board of directors,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 “Operating and Financial Review and Prospects—Liquidity and Capital Resources” for a discussion of the restrictions contained in the Company's credit facilities and lease arrangements that may restrict the Company's ability to make distributions.
Subordination Period
During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3875 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.
The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after September 30, 2017, that each of the following tests are met:
distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

the “adjusted"adjusted operating surplus”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.
Because the Company did not make payment of the minimum quarterly distribution in 2017, the subordinated units will not convert prior to 2021.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The Seadrill Member currently holds the incentive distribution rights, which may be transferred separately from the Seadrill Member interest, subject to restrictions in the operating agreement. Except for transfers of incentive distribution rights to an affiliate or another entity as part of the Seadrill Member’s merger or consolidation with or into, or sale of substantially all of its assets to such entity, the approval of a majority of the Company's common units (excluding common units held by the Seadrill Member and its affiliates) generally is required for a transfer of the incentive distribution rights to a third party prior to September 30, 2017. Any transfer by the Seadrill Member of the incentive distribution rights would not change the percentage allocations of quarterly distributions with respect to such rights.
The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under “Marginal"Marginal Percentage Interest in Distributions”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"Total Quarterly Distribution Target Amount,”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 Distributionup to $0.4456 100% —%
Second Target Distributionabove $0.4456 up to $0.4844 85% 15%
Third Target Distributionabove $0.4844 up to $0.5813 75% 25%
Thereafterabove $0.5813 50% 50%

Quarterly distributions
The table below sets out the quarterly distributions declared and paid to unitholders since December 31, 2014.
 Amount declared and paid per unit ($) Amount declared and paid ($ in millions)
Period in respect of:Common unitsSubordinated units Common unitsSubordinated unitsIncentive distribution rightsTotal
2014 Q40.56750.5675 42.72
9.39
3.17
55.28
2015 Q10.56750.5675 42.72
9.39
3.17
55.28
2015 Q20.56750.5675 42.72
9.39
3.17
55.28
2015 Q30.56750.5675 42.72
9.39
3.17
55.28
2015 Q4 (1) (2)0.25000.2500 18.82
—
—
18.82

(1) This cash distribution was paid on February 12, 2016 to all unitholders of record as of the close of business on February 5, 2016.
(2) The distribution made, in respect of the fourth quarter of 2015 was below the Minimum Quarterly Distribution as set out above. Arrearages in the payment of the minimum quarterly distribution on the common units must be paid before any distributions of available cash from operating surplus may be made in the future on the subordinated units.
B.     Significant Changes

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

Item 9.         The Offer and Listing

3    A.     Offer and Listing Details
The high and low sales prices of the Company's common units as reported by the New York Stock Exchange, for the years, quarters and months indicated, are as follows:
five most recent fiscal years:
Year EndedHigh LowHigh Low
December 31, 2017$5.33
 $2.61
December 31, 20166.45
 1.70
December 31, 2015$17.33 $2.9217.33
 2.92
December 31, 2014$35.10 $14.5735.10
 14.57
December 31, 2013$33.68 $25.6533.68
 25.65
December 31, 2012 (1)$28.00 $22.90
The following table sets forth the high and low prices of our common units trading on the NYSE for each full financial quarter for the two most recent fiscal years:

Quarter EndedHigh Low
March 31, 2016$4.74 $1.70
December 31, 2015$12.20 $2.92
September 30, 2015$13.36 $7.94
June 30, 2015$16.17 $11.80
March 31, 2015$17.33 $11.50
December 31, 2014$31.35 $14.50
September 30, 2014$36.07 $29.58
June 30, 2014$34.38 $28.57
March 31, 2014$33.20 $28.82
Quarter EndedHigh Low
March 31, 2018$4.08
 $2.70
December 31, 20174.20
 3.21
September 30, 20173.95
 2.61
June 30, 20173.73
 2.70
March 31, 20175.33
 2.85
December 31, 20165.07
 3.00
September 30, 20166.45
 3.00
June 30, 20166.24
 3.02
March 31, 20164.74
 1.70


The following table sets forth the high and low prices for our common units on the NYSE for the six most recent months.
Month EndedHigh Low
April 27, 2016 (2)$5.51 $3.02
March 31, 2016$4.74 $1.70
February 29, 2016$3.22 $1.70
January 31, 2016$3.68 $1.94
December 31, 2015$8.62 $2.92
November 30, 2015$12.20 $8.25
October 31, 2015$11.74 $8.78
Month EndedHigh Low
April 11, 2018 (1)
$2.89
 $2.60
March 31, 20183.42
 2.74
February 28, 20183.60
 2.97
January 31, 20184.08
 3.38
December 31, 20173.80
 3.21
November 30, 20174.20
 3.50
October 31, 20173.94
 3.43
(1) Includes the period from October 19, 2012 through December 31, 2012.
(2) Includes the period from April 1, 2016 through2018 to April 27, 2016.

11, 2018


B.     Plan of distribution
Not applicable.

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

D.    Selling Shareholders
Not applicable.

E.    Dilution
Not applicable.

F.    Expenses of the issue
Not applicable.

Item 10.         Additional Information

A.     Share Capital
Not applicable.

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


C.     Material Contracts
The following is a summary of each material contract, other than material contracts entered into in the ordinary course of business, to which the Company or any of the Company's subsidiaries is a party, for the two years immediately preceding the date of this Annual Report,annual report, each of which is included in the list of exhibits in Item 19:

(1)1.Contribution and Sale Agreement among Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating GP LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, Seadrill Opco Sub LLC, Seadrill Americas Inc., Seadrill Offshore AS, and Seadrill UK Ltd., dated as of October 22, 2012, as amended by Amendment No 1, dated June 30, 2013. This agreement effected the transfer of the ownership interests in OPCO to the Company, and the use of the net proceeds of the IPO.
(2)2.Omnibus Agreement among Seadrill Limited, Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating LP, Seadrill Operating GP LLC, and Seadrill Capricorn, dated as of October 24, 2012. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Omnibus Agreement.”"
(3)3.Amended and Restated Management and Administrative Services Agreement with Seadrill Management Ltd. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreement.Agreements."
(4)Management Services Agreement with Seadrill UK Ltd. See Item 7 “Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements.”
(5)4.Advisory, Technical and Administrative Services Agreement with Seadrill Americas, Inc. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(6)5.Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Vencedor Ltd. dated January 1, 2012. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(7)6.Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Deepwater Drillship Ltd. dated January 1, 2012. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"

(8)7.Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(9)8.Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd., effective as of December 13, 2013, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Sirius LLC. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(10)9.Administrative, Technical and Advisory Agreement, effective as of March 21, 2014, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Auriga LLC. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(11)10.Administrative, Technical and Advisory Agreement, effective as of February 15, 2013, between Seadrill Americas Inc. and Seadrill Gulf Operations Vela LLC. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(12)11.Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Nigeria Operations Limited. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(13)12.Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Offshore Nigeria Limited. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(14)13.Advisory, Technical and Administrative Services Agreement, dated June 19, 2015, between Seadrill Management AME Ltd. and Seadrill Polaris Ltd. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements.”"
(15)14.Amended and Restated Revolving Loan Agreement, dated August 31, 2013 among Seadrill Operating LP, Seadrill Capricorn Holdings LLC, and Seadrill Partners Operating LLC as borrowers, and Seadrill Limited, as lender, as amended by the Second Amendment to Revolving Loan Agreement, dated March 1, 2014. See Note 11 - “Debt”11"Debt" and Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(16)Amended and Restated US$1,200,000,000 Senior Secured Credit Facility Agreement dated October 10, 2012 for Seadrill Limited, as Borrower, the subsidiaries of Seadrill Limited named therein as guarantors, and the banks and financial institutions named therein as lenders. See Note 11 - “Debt” and Note 13 - “Related party transactions” to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(17)15.Loan Agreement dated September 28, 2012 between Seadrill Limited and Seadrill Vencedor Ltd, as amended by Amendment No. 1, dated August 28, 2014, and Amendment No. 2, dated April 14, 2015. See Note 11 - “Debt”"Debt" and Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(18)16.US$440,000,000 Secured Credit Facility Agreement dated December 4, 2012 between Seadrill Limited, as borrower, the subsidiaries of Seadrill Limited named therein as guarantors, and the banks and financial institutions named therein as lenders, as amended by the letter agreement, dated June 18, 2015, and the waiver approval letter, dated April 28, 2016.2016, and the consent request and waiver approval letter dated March 28, 2017. See Note 11 - “Debt”"Debt" and Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

(19)Waiver Approval Letter regarding the US$440,000,000 Secured Credit Facility Agreement, dated April 28, 2016.
(20)17.Loan Agreement, dated May 16, 2013, between Seadrill Limited, Seadrill T-15 Ltd., Seadrill Partners Operating LLC and Seadrill International Limited. This is an intercompany loan agreement with Seadrill pursuant to which Seadrill T-15 Ltd. makes payments of principal and interest to the lenders of the $440 Million Rig Financing Agreement on Seadrill’s behalf. See Note 11 - “Debt”"Debt" and Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(21)18.Intercompany Loan Agreement, dated May 16, 2013, between Seadrill Limited, as lender and Seadrill Partners Operating LLC, as borrower. Pursuant to this agreement, Seadrill Partners Operating borrowed $109.5 million to fund the acquisition of the entities that own and operate the T-15. See Note 11 - “Debt”"Debt" and Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(22)19.Loan Agreement, dated October 11, 2013, by and among Seadrill Limited, Seadrill T-16 Ltd. and Seadrill Partners Operating LLC. Pursuant to this agreement, Seadrill T-16 makes payments of principal and interest directly to the lenders under the $440 Million Rig Financing Agreement on Seadrill's behalf. See Note 11 - “Debt”"Debt" and Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(23)20.Amended and Restated Credit Agreement dated as of June 26, 2014, among Seadrill Operating LP, Seadrill Partners Finco LLC, Seadrill Capricorn Holdings LLC, various lenders and Deutsche Bank AG New York Branch, as Administrative Agent and Collateral Agent. See Note 11 - “Debt”"Debt" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(24)21.Second Amended and Restated $1,450 Millionmillion Senior Secured Credit Facility Agreement, dated as of November 4, 2014, among Seadrill Tellus Ltd. and Seadrill Vela Hungary Kft., as Borrowers, Seadrill Limited, as Parent, the guarantors party thereto, ING Bank N.V., as Agent, the lenders party thereto and the other parties thereto, as amended by the letter agreement, dated May 28, 2015 and the waiver approval letter dated April 28, 2016.2016, and the consent request and waiver approval letter, dated March 29, 2017. See Note 11 - “Debt”"Debt" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(25)Waiver Approval Letter regarding the Second Amended and Restated Agreement, dated April 28, 2016.

(26)22.On Demand and Guarantee and Indemnity, dated November 4, 2014, between Seadrill Partners LLC and ING Bank N.V. Pursuant to this agreement, Seadrill Partners LLC has guaranteed the obligations of Seadrill Vela Hungary Kft. under the $1,450 Millionmillion Senior Secured Credit Facility Agreement, dated as of November 4, 2014, among Seadrill Tellus Ltd. and Seadrill Vela Hungary Kft., as Borrowers, Seadrill Limited, as Parent, the guarantors party thereto, ING Bank N.V., as Agent, the lenders party thereto and the other parties thereto, in an amount up to $497.5 million plus interest and costs.
(27)23.Amendment and Restatement Agreement, dated June 19, 2015, between Seadrill Polaris Ltd. as borrower, Seadrill Limited as parent, Ship Finance International Limited as retiring guarantor and the other companies listed therein as guarantors, the banks and financial institutions listed therein as lenders, DNB Bank ASA and Nordea Bank AB, London Branch as bookrunners, the banks and financial institutions named therein as mandated lead arrangers and DNB Bank ASA, as agent, relating to the US$420,000,000 Term Loan and Revolving Credit Facilities Agreement, originally dated December 28, 2012, as previously amended. See Note 11 - “Debt” to the Consolidated and Combined Carve-Out Financial Statements included in this annual reportamended and as amended by the waiver approval letter dated April 28, 2016.2016, and the consent request and waiver approval letter, dated March 28, 2017. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
(28)Waiver Approval Letter regarding the Amendment and Restatement Agreement, dated April 9, 2016.
(29)24.Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Hungary Kft and Seadrill Limited. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Loans and Financing Agreements-$143 Million Loan Agreement.”"
(30)25.Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Neptune Hungary Kft and Seadrill Gulf Operations Sirius LLC. See Item 7 “Major"Major Unitholders and Related Party Transactions-Related Party Transactions-Loans and Financing Agreements-$143 Million Loan Agreement.”"
(31)26.Bareboat Charter Agreement between Seadrill Offshore AS and Seadrill Canada Ltd. dated October 5, 2012. See Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(32)27.Bareboat Charter Agreements between Seadrill China Operations Ltd. and Seadrill Offshore AS dated October 5, 2012. See Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(33)28.Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-15 Ltd. and Seadrill UK Ltd. See Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(34)29.Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-16 Ltd. and Seadrill UK Ltd. See Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(35)30.Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-15. See Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(36)31.Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-16. See Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(37)Purchase and Sale Agreement, dated May 7, 2013, between Seadrill Limited and Seadrill Partners Operating LLC. Pursuant to this agreement, Seadrill Partners Operating LLC purchased the equity interest in each of the entities that own and operate the T-15. See Note 3 - “Business acquisitions” to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(38)Purchase and Sale Agreement, dated October 11, 2013, by and among Seadrill Limited, Seadrill Partners LLC and Seadrill Partners Operating LLC. Pursuant to this agreement, Seadrill Partners Operating purchased the equity interests in the entity that owns the T-16. See Note 3 - “Business acquisitions” to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(39)
Contribution, Purchase and Sale Agreement, dated December 2, 2013, as amended by Amendment to Contribution, Purchase and Sale Agreement, dated as of December 12, 2013, by and among Seadrill Limited, a Bermuda exempted company Seadrill Partners LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, and Seadrill Americas Inc. Pursuant to this agreement, as amended, Seadrill Operating LP acquired all of the ownership interests in each of the entities that own, operate and manage the semi-submersible drilling rig, West Leo and Seadrill Capricorn Holdings LLC acquired all of the ownership interests in each of the entities that own and operate the semi-submersible drilling rig, West Sirius. See Note 3 - “Business acquisitions” to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(40)32.
Contribution, Purchase and Sale Agreement, dated March 11, 2014. Pursuant to this agreement, Seadrill Capricorn Holdings LLC acquired the entities that own and operate the West Auriga. See Note 3 - “Business acquisitions”"Business acquisitions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(41)Promissory Discount Note, dated March 21, 2014 issued by Seadrill Capricorn Holdings LLC. See Note 3 - “Business acquisitions” to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(42)33.Limited Partner Interest Purchase Agreement, dated as of July 17, 2014, between Seadrill Limited and Seadrill Partners LLC. Pursuant to this agreement, the Company purchased an additional 28% limited partner interest in Seadrill Operating LP. See Note 13 - “Related"Related party transactions”transactions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

(43)34.
Contribution, Purchase and Sale Agreement, dated November 4, 2014, by and among Seadrill Limited, Seadrill Partners LLC, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc. Pursuant to this agreement, Seadrill Capricorn Holdings LLC acquired the entities that own and operate the West Vela. See Note 3 - “Business acquisitions”"Business acquisitions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
(44)35.
Purchase and Sale Agreement, dated as of June 16, 2015, by and among Seadrill Limited, Seadrill Operating LP, Seadrill Polaris Ltd. Pursuant to this agreement, Seadrill Operating LP acquired the entity that owns and operates the West Polaris. See Note 3 - “Business Acquisitions”"Business Acquisitions" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.

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

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

D.     Exchange Controls
The Company isWe 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.
The Company isWe are not aware of any limitations on the right of non-resident or foreign owners to hold or vote the Company's securities imposed by the laws of the Republic of The Marshall Islands or the Company's operating agreement.

E.     Taxation
Material U.S. Federal Income Tax Considerations
The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective unitholders.
This discussion is based upon provisions of the Code, Treasury Regulations, and current administrative rulings and court decisions, all as in effect or existence on the date of this prospectus and all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences of unit ownership to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “our”"we", "our" or “us”"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 advisoradviser 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 advisoradviser 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.

U.S. Federal Income Taxation of U.S. Holders
As used herein, the term “U.S. Holder”"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 nontaxablenon-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."U.S. Individual Holder”Holder") generally will be treated as “qualified"qualified dividend income,”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"PFIC Status and Significant Tax Consequences”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 I.R.S.IRS Form 8937 in connection with its distributions paid in the year ended December 31, 2015.2017. There is no assurance that any dividends paid on the Company's common units will be eligible for these preferential rates in the hands of a U.S. Individual Holder, and any dividends paid on the Company's common units that are not eligible for these preferential rates will be taxed as ordinary income to a U.S. Individual Holder.
Special rules may apply to any amounts received in respect of the Company's common units that are treated as “extraordinary dividends.”"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"net investment income”income" or (ii) the excess of “modified"modified adjusted gross income”income" over $200,000 ($250,000 if married and filing jointly or $125,000 if married and filing separately). “Net"Net investment income”income" generally equals the taxpayer’s gross investment income reduced by deductions that are allocable to such income. Unitholders should consult their tax advisorsadvisers regarding the implications of the additional Medicare tax resulting from their ownership and disposition of the Company's common units.

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 the Company's 2015its 2017 taxable year, and the Company expects that the Companyit will not be treated as a PFIC for the current or any future taxable year. The Company expects that more than 25% of the Company'sits gross income for the Company's 2015its 2017 taxable year arose and for the current and each future year will arise from such drilling contracts or other income that the Company believes should not constitute passive income, and more than 50% of the average value of the Company's assets for each such year will be held for the production of such nonpassivenon-passive income. Assuming the composition of the Company's income and assets is consistent with these expectations, the Company believes that the Companyit should not be a PFIC for the Company's 2015its 2017 taxable year or the Company'sits 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 the Company'sits 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 the Company'sits 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"Qualified Electing Fund,”Fund", which the Company refers to as a “QEF election.”"QEF election". As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market”"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”"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,”"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.

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”"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.”"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 advisoradviser 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"foreign financial assets”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 advisorsadvisers regarding the reporting obligations, if any, that result from their purchase, ownership or disposition of the Company's units.

Non-United States Tax Considerations
Unless the context otherwise requires, references in this section to “we,” “our”"we", "our" or “us”"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 engage incarry 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 businesstransactions 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), or “non-U.K. Holders.” ("non-U.K. Holders").
Unitholders who are, or have been, resident in the United Kingdom are urged to consult their own tax advisorsadvisers regarding the potential U.K. tax consequences to them of an investment in the Company's common units. For this purpose, a company incorporated outside of the U.K. will be treated as resident in the United Kingdom in the event its central management and control is carried out in the United Kingdom.
The discussion that follows is based upon existing U.K. legislation and current H.M. Revenue & Customs practice as of April 28, 2016,12, 2018, both of which may change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences of unit ownership described below.
The Company is not required to withhold U.K. tax when paying distributions to unitholders.
Under U.K. taxation legislation, non-U.K. Holders will not be subject to tax in the United Kingdom on income or profits, including chargeable (capital) gains, in respect of the acquisition, holding, disposition or redemption of the common units, provided that:
such holders do not use or hold and are not deemed or considered to use or hold their common units in the course of carrying on a trade, profession or vocation in the United Kingdom; and
such holders do not have a branch or agency or permanent establishment in the United Kingdom through which such common units are used, held or acquired.
U.K. stamp duty should not be payable in connection with a transfer of units, provided that the instrument of transfer is executed and retained outside the U.K. and no other action is taken in the U.K in relation to the transfer.
No U.K. stamp duty reserve tax will be payable in respect of any agreement to transfer units provided that the units are not registered in a register kept in the U.K. by or on behalf of the Company. The Company currently does not intend that any such register will be maintained in the U.K.
EACH PROSPECTIVE UNITHOLDER IS URGED TO CONSULT HISTHEIR OWN TAX COUNSEL OR OTHER ADVISORADVISER WITH REGARD TO THE LEGAL AND TAX CONSEQUENCES OF UNIT OWNERSHIP UNDER HISTHEIR 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 or the Exchange Act.(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 5YA,5YS, United Kingdom.
 

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 Risks
The Company’s exposurePlease refer to interest rate risk relates mainly to its floating interest rate debt and balances of surplus funds placed with financial institutions. This exposure is managed through the use of interest rate swaps and other derivative arrangements. The Company’s objective is to obtain the most favorable interest rate borrowings available without increasing its foreign currency exposure. 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 the Company with flexibility to meet all requirements for working capital and capital investments. The extent to which the Company utilizes interest rate swaps derivatives to manage its interest rate risk is determined by the net debt exposure and its views on future interest rates.
As of December 31, 2015, the Company was party to interest rate swap agreements with Seadrill for a combined outstanding principal amount of approximately $655.3 million at rates between 1.10% per annum and 1.93% per annum. The swap agreements mature between July 2018 and December 2020. The net loss recognized on the Company's interest rate swaps with Seadrill for the year ended December 31, 2015 was $10.2 million.
As of December 31, 2015, the Company was party to interest rate swap agreements with external counterparties for a combined outstanding principal amount of approximately $2,851.9 million at an average rate of 2.49% per annum. The swap agreements mature in February 2021. The net loss recognized on the Company's interest rate swaps with external counterparties for the year ended December 31, 2015 was $72.7 million.
As of December 31, 2015, the Company's exposure to floating interest rate fluctuations on the Company's outstanding debt (including related party debt agreements) was $391.1 million, compared with $78.6 million as of December 31, 2014. An increase or decrease in short-term interest rates of 100 bps would thus increase or decrease, respectively, the Company's interest expense by approximately $3.9 million on an annual basis as of December 31, 2015, as compared to $0.8 million in 2014.
The fair values of the Company's interest rate swap agreements as of December 31, 2015 and 2014 were as follows:
 December 31, 2015 December 31, 2014
(In millions of US dollars)
Outstanding
principal
 Fair Value 
Outstanding
Principal
 Fair Value
Related party receivables (payables) - interest rate swap agreements$655.3
 $2.2
 $690.1
 $6.0
Other current assets (liabilities) - interest rate swap agreements$2,851.9
 $(84.2) $2,881.7
 $(56.1)
For additional disclosure of the fair value of the derivatives and debt obligations outstanding as of December 31, 2015, please read "Note 15 - Risk managementNote 14 "Risk Management and financial instruments" to the Consolidated and Combined Carve-Out Financial Statements included in this annual report.
Credit Risk
The Company has financial assets which expose the Company to credit risk arising from possible default by a counterparty. The Company considers the counterparties to be creditworthy and does not expect any significant loss to result from non-performance by such counterparties. The Company in the normal course of business does not demand collateral from its counterparties.
Foreign Currency Fluctuation Risks
The Company and all of its subsidiaries use the U.S. Dollar as their functional currency because the majority of their revenues and expenses are denominated in U.S. Dollars. Accordingly, the Company's reporting currency is also U.S. Dollars. The Company does, however, earn revenue and incur expenses in other currencies and there is a risk that currency fluctuations could have an adverse effect on the value of the Company's cash flows.
The Company receives 10% of the West Capella’s revenues in Nigerian Naira. There is a natural hedge of exposure to Nigerian Naira as a portion of the Company's operating costs are denominated in Nigerian Naira. The impact of a 10% appreciation or depreciation in the exchange rate of Nigerian Naira against the US Dollar would not have a material impact on the Company. Due to the operations of the West Aquarius in Canada, a portion of the Company's revenues and expenses are denominated in the Canadian Dollar. The impact of a 10% appreciation or depreciation in the exchange rate of Canadian Dollar against the US Dollar would not have a material impact on the Company.
The Company's 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);”
the impact of fluctuations in exchange rates on the reported amounts of the Company's revenues and expenses which are denominated in foreign currencies; and
foreign subsidiaries whose accounts are not maintained in U.S. Dollars, which when converted into US Dollars can result in exchange adjustments, which are recorded as a component in shareholders’ equity.

The Company does not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.
Retained Risk
Physical Damage Insurance. Seadrill purchases hull and machinery insurance to coverreport for physical damage to its drilling units and charges the Company for the cost related to the Company’s fleet.
The Company retains the risk for the deductibles relating to physical damage insurance on the Company’s fleet. The deductible is currently a maximum of $5 million per occurrence.
The Company has 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. The Company has renewed its policy to insure this windstorm risk for a further period starting May 1, 2016 through April 30, 2017.
Loss of Hire Insurance. With the exception of T-15 and T-16, Seadrill purchases insurance to cover for loss of revenue in the event of extensive downtime caused by physical damage to its drilling units, where such damage is covered under the Seadrill’s physical damage insurance, and charges the Company for the cost related to the Company’s fleet.
The loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, insurance policies according to which the Company is compensated for loss of revenue are limited to 290 days per event and aggregated per year. The daily indemnity is approximately 75% of the contracted dayrate. The Company retains 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 insurance policy. If the repair period for any physical damage exceeds the number of days permitted under the Company’s loss of hire policy, it will be responsible for the costs in such period. The Company does not have loss of hire insurance on the Company's tender rigs with the exception of the semi-tender rig the West Vencedor.
Protection and Indemnity Insurance. Seadrill purchases Protection and Indemnity insurance and Excess liability insurance for personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units to cover claims of up to $250 million per event and in the aggregate for the West Vencedor, T-15 and T-16, up to $400 million per event and in the aggregate for the West Aquarius, West Capella, West Leo and West Polaris, up to $750 million per event and in the aggregate for each of the West Capricorn,West Auriga and West Vela. Effective June 1, 2015, the protection and indemnity insurance for the West Sirius was reduced to $500 million.
OPCO retains the risk for the deductible of up to $0.5 million per occurrence relating to protection and indemnity insurance.
Concentration of Credit Risk
The market for the Company’s services is the offshore oil and gas industry, and the customers consist primarily of major oil and gas companies, independent oil and gas producers and government-owned oil companies. Ongoing credit evaluations of the Company's customers are performed and generally do not require collateral in the Company's business agreements. Reserves for potential credit losses are maintained when necessary.details.

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

A.     Debt securities
Not applicable.

B.     Warrants and rights
Not applicable.

C.     Other securities
Not applicable.

D.     American Depositary shares
Not applicable.

PART II

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

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

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 (e)and Rule 15a-15 of the Exchange Act as of December 31, 2015. 2017.
Based upon that evaluation and taking into account the remediation of the material weakness in the internal control over financial reporting set forth in Management's Annual Report on Internal Controls over Financial Reporting below, the Principal Executive Officer and the Principal Financial Officer concluded that the Company's disclosure controls and procedures arewere effective as of the evaluation date.


b)    Management’s Annual Report on Internal ControlControls 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 (b)and Rules 15d-15 promulgated under the Exchange Act.
Internal controlcontrols over financial reporting is defined in Rule 13a-15(f) orand 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 Company's board of directors,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.
Management conducted the evaluation of the effectiveness of the internal controls over financial reporting using the control criteria framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO, published in its report entitled Internal Control- Integrated Framework (2013).
The Company's management with the participation of the Company's Principal Executive Officer and the Principal Financial Officer assessed the effectiveness of the design and operation of the Company's internal controlscontrol over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2015. Based upon that evaluation, management, including the Principal Executive Officer2017 and Principal Financial Officer, concluded that the Company's internal controls over financial reporting arewere effective as of that date.
Management conducted the evaluation of the effectiveness of internal control over financial reporting using the control criteria framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), published in its report entitled Internal Control- Integrated Framework (2013) and concluded that the material weakness previously reported within the annual report on Form 20-F for the year-ended December 31, 2015.2016 had been remediated.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis.
In our annual report on Form 20-F for the year ended December 31, 2016 we reported that the Company had not maintained effective controls over the accounting for interest rate swaps. Specifically, the design and execution of controls over the application of accounting principles under GAAP were ineffective in relation to the inclusion of counterparty credit risk in fair value measurements related to interest rate swaps, and the completeness of accounting policy guidance in relation to the inclusion of counterparty credit risk in fair value measurements. The effectivenesserrors caused by this control deficiency resulted in a cumulative correction which was not material to the year ended December 31, 2016 or to any of the Company's previously issued Consolidated Financial Statements. The errors did not result in a material misstatement in the Company's prior financial statements and therefore did not require the Company's previously filed reports to be amended.
Because of this material weakness, management concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

2016. As set out below, management completed remediation activities that remediated the material weakness.
c)     Attestation reportReport of the registered public accounting firmRegistered 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, 2015,2017, appearing under Item 18 "Financial Statements", and such report is incorporated herein by reference.

d)    Changes in Internal Control over Financial Reporting
ThereWe have completed the remediation activities described below to remediate the material weakness reported in our annual report on Form 20-F for the year-ended December 31, 2016.
Remediation of material weakness
Management completed remediation activities to address the material weakness described above. These activities, summarized below, were no changesintended to address the above material weakness and to improve the overall control environment. These activities included:
We re-designed the fair value measurement process in respect of derivative financial instruments to include counterparty credit risk;
We performed a review of our accounting policy guidance, including a third party review of all accounting policies; and
We enhanced the Company's internal controls overdocumentation of policies, procedures and responsibilities throughout the financial reporting that occurred duringprocess.
Management believes the successful completion of these activities has remediated the material weakness. The completion of these activities was subject to senior management review, including Audit Committee oversight. During the period covered by this annual report that have materially affected, or are reasonably likelythe remediation activities were in-progress, we performed additional control activities, as required, to materially affect, the Company's internal control overensure that our financial reporting.statements were fairly stated in all material respects.

Item 16A.     Audit Committee Financial Expert
The Company's board of directorsBoard has determined that Kate Blankenship qualifiesand Keith MacDonald qualify as an audit committee financial expertexperts and isare independent under applicable NYSE and SEC standards.


Item 16B.     Code of Ethics
The Company hasWe 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. The Company hasWe have posted a copy of the Company'sour Code of Ethics on the Company'sour website at www.seadrillpartners.com. The CompanyWe will provide any person, free of charge, a copy of the Code of Ethics upon written request to the Company'sour registered office.


Item 16C.     Principal Accountant Fees and Services
The Company'sOur principal accountant for 2015the fiscal years ended December 31, 2017 and 2014 isDecember 31, 2016 was PricewaterhouseCoopers LLP in the United Kingdom.

Fees Incurred by the Company for PricewaterhouseCoopers LLP’s Services
In 2015,The following table sets forth the fees incurredrelated to audit and other services provided by the Company for its principal accountant were as follows:
accountants and their affiliates:
2015 20142017 2016
Audit Fees$912,000
 $1,205,808
$1,062,836
 $904,151
Audit-Related Fees—
 —
—
 —
Tax Fees—
 —
—
 —
All other fees—
 —
—
 —
$912,000
 $1,205,808
$1,062,836
 $904,151
Audit Fees
Audit fees represent professional services rendered for the audit of the Company'sour 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 the Company'sour 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 the Company'sour principal accountant for all periods in 2015.2017.

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

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

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


Item 16G.     Corporate Governance
Overview
Pursuant to an exceptionexemption under the NYSE listing standards for foreign private issuers, the Company is not required to comply with the corporate governance practices followed by U.S. companies under the NYSE listing standards. However, pursuant to Section 303.A.11 of the NYSE Listed Company Manual, the Company is required to state any significant differences between the Company's corporateour governance practices and the practices required by the NYSE for U.S. companies. The Company believes that the Company's established practices in the area of corporate governance are in line with the spirit of the NYSE standards and provide adequate protection to the Company's unitholders. The significant differences between the Company's corporate governance practices and the NYSE standards applicable to listed U.S. companies are set forth below.
Independence of Directors
The NYSE rules do not require a listed company that is a foreign private issuer to have a board of directors that is composed of a majority of independent directors. Under Marshall Islands law, the Company is not required to have a board of directors composed of a majority of directors meeting the independence standards described in NYSE rules. However, the Company's boardBoard has determined that each of Mrs. Blankenship, Mr. Bekker, Mr. Cumming and Mr. MacDonald satisfies the independence standards established by The New York Stock Exchange, orthe NYSE, as applicable to us.
Executive Sessions
The NYSE requires that non-management directors of a listed U.S. company meet regularly in executive sessions without management. The NYSE also requires that all independent directors of a listed U.S. company meet in an executive session at least once a year. As permitted under Marshall Islands law and the Company's limited liability company agreement, the Company's non-management directors do not regularly hold executive sessions without management and the Company does not expect them to do so in the future.

Nominating/Corporate Governance Committee
The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Marshall Islands law and the Company's limited liability company agreement, the Company does not currently have a nominating or corporate governance committee.
Compensation Committee
The NYSE requires that a listed U.S. company have a compensation committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Marshall Islands law and the Company's limited liability company agreement, the Company does not have a compensation committee.
Corporate Governance Guidelines
The NYSE requires listed U.S. companies to adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. The Company is not required to adopt such guidelines under Marshall Islands law and the Company has not adopted such guidelines.
Issuance of Additional Units
The NYSE requires that a listed U.S. company obtain unitholder approval in certain circumstances prior to the issuance of additional units. Consistent with Marshall Islands law and the Company's operating agreement, the Company is authorized to issue an unlimited amount of additional limited liability company interests and options, rights and warrants to buy limited liability company interests for the consideration and on the terms and conditions determined by the Company's board of directorsBoard without the approval of the unitholders.
We make available a statement of significant differences on our website (www.seadrillpartners.com).
The Company believes that the Company's established corporate governance practices satisfy the NYSE listing standards.

Item 16H.     Mine Safety Disclosure
Not applicable.

PART III

Item 17.     Financial Statements
Please refer to Item 18.Not applicable.


Item 18.     Financial Statements
The following financial statements listed below and set forth on pages F-1 through F-49F-36 together with the related report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm, are filed as part of this annual report:
 


Item 19.     Exhibits
The following exhibits are filed as part of this annual report:
Exhibit
Number
Description
1.1
Certificate of Formation of Seadrill Partners LLC (incorporated by reference to Exhibit 3.1 to the registrant’s Registration Statement on Form F-1 (File No. 333-184023), filed on September 21, 2012)
1.2
First Amended and Restated Operating Agreement of Seadrill Partners LLC, dated October 24, 2012, (incorporated by reference to Exhibit 1.2 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
1.2.1
Amendment No. 1 to the First Amended and Restated Operating Agreement of Seadrill Partners LLC, dated February 23, 2014 (incorporated by reference to Exhibit 1.2.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
1.3
Amended and Restated Agreement of Limited Partnership of Seadrill Operating LP dated July 21, 2014 (incorporated by reference to Exhibit 10.2 of the registrant’s Current Report on Form 6-K, for the month of July, filed on July 21, 2014)
1.4
Limited Liability Company Agreement of Seadrill Operating GP LLC, dated September 27, 2012 (incorporated by reference to Exhibit 1.4 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
1.5
Amended & Restated Limited Liability Company Agreement of Seadrill Capricorn Holdings LLC dated October 18, 2012 (incorporated by reference to Exhibit 1.5 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.1.
Contribution and Sale Agreement among Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating GP LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, Seadrill Opco Sub LLC, Seadrill Americas Inc., Seadrill Offshore AS, and Seadrill UK Ltd., dated as of October 22, 2012 (incorporated by reference to Exhibit 4.1 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.1.1
Amendment No. 1 to Contribution and Sale Agreement among Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating GP LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, Seadrill Opco Sub LLC, Seadrill Americas Inc., Seadrill Offshore AS, and Seadrill UK Ltd., dated as of June 30, 2013 (incorporated by reference to the Exhibit 10.1 of the registrant’s Report on Form 6-K for the six month period ended June 30, 2013, filed on September 30, 2013)
4.2
Omnibus Agreement among Seadrill Limited, Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating LP, Seadrill Operating GP LLC, and Seadrill Capricorn, dated as of October 24, 2012 (incorporated by reference to Exhibit 4.2 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.3*4.3
Novation and Amendment Agreement in respect of the Management and Administrative Services Agreement among Seadrill Management AS, Seadrill Management Ltd and Seadrill Partners LLC, dated October 24 2012, as amended April 28, 2016 (incorporated by reference to Exhibit 4.3 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016).
4.4
Advisory, Technical and Administrative Services Agreement with Seadrill Americas, Inc. (incorporated by reference to Exhibit 4.4 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.5
Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Vencedor Ltd. dated January 1, 2012 (incorporated by reference to Exhibit 10.5.1 of Amendment No. 3 to the registrant’s Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.6
Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Deepwater Drillship Ltd. dated January 1, 2012 (incorporated by reference to Exhibit 10.5.2 of Amendment No. 3 to the registrant’s Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.7
Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd., effective as of December 13, 2013, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Sirius LLC (incorporated by reference to the Exhibit 10.4 of the registrant’s Report on Form 6-K, for the month of March 2014, filed on March 11, 2014)
4.8
Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd., effective as of December 13, 2013, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Sirius LLC (incorporated by reference to Exhibit 10.5 of the registrant’s Report on Form 6-K, for the month of March 2014, filed on March 11, 2014)
4.9
Administrative, Technical and Advisory Agreement, effective as of March 21, 2014 between Seadrill Americas Inc. and Seadrill Gulf Operations Auriga LLC. (incorporated by reference to Exhibit 4.7.5 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2013, filed on April 30, 2014).
4.10
Administrative, Technical and Advisory Agreement, effective as of February 15, 2013, between Seadrill Americas Inc. and Seadrill Gulf Operations Vela LLC (incorporated by reference to Exhibit 4.7.6 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015).
4.11
Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Nigeria Operations Limited. (incorporated by reference to the Exhibit 10.1 of the registrant’s Report on Form 6-K for the six month period ended June 30, 2015, filed on October 5, 2015)
4.12
Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Offshore Nigeria Limited. (incorporated by reference to the Exhibit 10.2 of the registrant’s Report on Form 6-K for the six month period ended June 30, 2015, filed on October 5, 2015)
4.13
Advisory, Technical and Administrative Services Agreement, dated June 19, 2015, between Seadrill Management AME Ltd. and Seadrill Polaris Ltd. (incorporated by reference to the Exhibit 10.4 of the registrant’s Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.14
Amended and Restated Revolving Loan Agreement, dated August 31, 2013, among Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC, as borrowers, and Seadrill Limited, as lender (incorporated by reference to the Exhibit 10.1 of the registrant’s Report on Form 6-K for the six month period ended June 30, 2013, filed on September 30, 2013)
4.14.1
Second Amendment to Revolving Loan Agreement, dated March 1, 2014, among Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC, as borrowers, and Seadrill Limited, as lender (incorporated by reference to Exhibit 4.8.3 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2013, filed on April 30, 2014)
4.15Amended and Restated US$1,200,000,000 Senior Secured Credit Facility Agreement dated October10, 2012 for Seadrill Limited, as Borrower, the subsidiaries of Seadrill Limited named therein as guarantors, and the banks and financial institutions named therein as lenders, dated October 10, 2012 (incorporated by reference to Exhibit 10.9 of Amendment No. 3 to the registrant’s Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.16
Loan Agreement dated September 28, 2012 between Seadrill Limited and Seadrill Vencedor Ltd. (incorporated by reference to Exhibit 10.15 of Amendment No. 1 to the registrant’s Registration Statement on Form F-1 (File No. 333-184023), filed on October 5, 2012)

4.15.1
Exhibit
Number
Description
4.16.1Amendment to the Loan Agreement between Seadrill Limited and Seadrill Vencedor Limited dated August 28, 2014 (incorporated by reference to Exhibit 4.42 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)

4.16.2
Exhibit
Number
Description
4.15.2
Amendment to the Loan Agreement between Seadrill Limited and Seadrill Vencedor Limited dated April 14, 2015(incorporated by reference to Exhibit 4.43 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.174.16
US$440,000,000 Secured Credit Facility Agreement dated December 4, 2012 between Seadrill Limited, as borrower, the subsidiaries of Seadrill Limited named therein as guarantors, and the banks and financial institutions named therein as lenders(incorporatedlenders (incorporated by reference to the Exhibit 10.110.2 of the registrant’s Report on Form 6-K for the six months ended June 30, 2013, filed on September 30, 2013)
4.17.1*4.16.1
Letter Agreement regarding the US$440,000,000 Secured Credit Facility Agreement, dated June 18, 2015 (incorporated by reference to Exhibit 4.17.1 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.17.2*4.16.2
Waiver Approval Letter regarding the US$440,000,000 Secured Credit Facility Agreement, dated April 28, 2016 (incorporated by reference to Exhibit 4.17.2 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.184.16.3
Consent Request and Waiver Approval Letter regarding the US$440,000,000 Secured Credit Facility Agreement, dated March 28, 2017
4.17
Loan Agreement, dated May 16, 2013, between Seadrill Limited, Seadrill T-15 Ltd., Seadrill Partners Operating LLC and Seadrill International Limited (incorporated by reference to the Exhibit 10.3 of the registrant’s Report on Form 6-K for the six months ended June 30, 2013, filed on September 30, 2013)
4.194.18Intercompany Loan Agreement, dated May 16, 2013, between Seadrill Limited, as lender and Seadrill Partners Operating LLC, as borrower (incorporated by reference to the Exhibit 10.4 of the registrant’s Report on Form 6-K for the six months ended June 30, 2013, filed on September 30, 2013)
4.20
Loan Agreement, dated October 11, 2013, by and among Seadrill Limited, Seadrill T-16 Ltd. and Seadrill Partners Operating LLC (incorporated by reference to Exhibit 10.6 of the registrant’s Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.214.19
Amended and Restated Credit Agreement dated as of June 26, 2014, among Seadrill Operating LP, Seadrill Partners Finco LLC, Seadrill Capricorn Holdings LLC, various lenders and Deutsche Bank AG New York Branch, as Administrative Agent and Collateral Agent (incorporated by reference to the Exhibit 10.1 of the registrant’s Report on Form 6-K, for the month of June, filed on June 30, 2014)
4.224.20
Second Amended and Restated Agreement dated November 4, 2014, among Seadrill Tellus Ltd. and Seadrill Vela Hungary Kft., as Borrowers, Seadrill Limited, as Parent, the guarantors party thereto, ING Bank N.V., as Agent, the lenders party thereto and the other parties thereto, relating to the US$1,450,000,000 Senior Secured Credit Facility Agreement, originally dated March 20, 2013 (incorporated by reference to Exhibit 4.40 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.22.1*4.20.1
Letter Agreement regarding the Second Amended and Restated Agreement, dated May 28, 2015 (incorporated by reference to Exhibit 4.22.1 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.22.2*4.20.2
Waiver Approval Letter regarding the Second Amended and Restated Agreement, dated April 28, 2016 (incorporated by reference to Exhibit 4.22.2 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.234.20.3
Consent Request and Waiver Approval Letter regarding the Amended and Restated Agreement, dated March 28, 2017
4.21
On Demand and Guarantee and Indemnity, dated November 4, 2014, between Seadrill Partners LLC and ING Bank N.V. (incorporated by reference to Exhibit 4.41 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.244.22
Amendment and Restatement Agreement, dated June 19, 2015, between Seadrill Polaris Ltd. as borrower, Seadrill Limited as parent, Ship Finance International Limited as retiring guarantor and and the other companies listed therein as guarantors, the banks and financial institutions listed therein as lenders, DNB Bank ASA and Nordea Bank AB, London Branch as bookrunners, the banks and financial institutions named therein as mandated lead arrangers and DNB Bank ASA, as agent, relating to the US$420,000,000 Term Loan and Revolving Credit Facilities Agreement, originally dated December 28, 2012, as previously amended (incorporated by reference to the Exhibit 10.5 of the registrant’s Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.24.1*4.22.1
Waiver Approval Letter regarding the Amendment and Restatement Agreement, dated April 28, 2016 (incorporated by reference to Exhibit 4.24.1 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.25*4.22.2
Consent Request and Waiver Approval Letter regarding the Second Amendment and Restatement Agreement, dated March 29, 2017
4.23
Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Hungary Kft and Seadrill Limited (incorporated by reference to Exhibit 4.25 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)

4.26*4.24
Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Neptune Hungary Kft and Seadrill Gulf Operations Sirius LLC (incorporated by reference to Exhibit 4.26 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)

4.274.25
Bareboat Charter Agreement between Seadrill Offshore AS and Seadrill Canada Ltd. dated October 5, 2012 (incorporated by reference to Exhibit 10.16 of Amendment No. 3 to the registrant’s Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.284.26
Bareboat Charter Agreements between Seadrill China Operations Ltd. and Seadrill Offshore AS dated October 5, 2012 (incorporated by reference to Exhibit 10.17 of Amendment No. 3 to the registrant’s Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.294.27
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-15 Ltd. and Seadrill UK Ltd. (incorporated by reference to Exhibit 10.1 of Amendment No. 3 to the registrant’s Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.304.28
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-16 Ltd. and Seadrill UK Ltd. (incorporated by reference to Exhibit 10.2 of the registrant’s Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.314.29
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-15 (incorporated by reference to Exhibit 10.3 of the registrant’s Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.324.30
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-16 (incorporated by reference to Exhibit 10.2 of the registrant’s Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.334.31Purchase and Sale Agreement, dated May 7, 2013, between Seadrill Limited and Seadrill Partners Operating LLC (incorporated by reference to the Exhibit 10.5 of the registrant’s Report on Form 6-K for the six months ended June 30, 2013, filed on September 30, 2013)
4.34Purchase and Sale Agreement, dated October 11, 2013, by and among Seadrill Limited, Seadrill Partners LLC and Seadrill Partners Operating LLC (incorporated by reference to Exhibit 10.5 of the registrant’s Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.35Contribution, Purchase and Sale Agreement, dated December 2, 2013 (incorporated by reference to the Exhibit 10.2 of the registrant’s Report on Form 6-K for the month of December, filed on December 9, 2013)
4.35.1Amendment to Contribution, Purchase and Sale Agreement, dated as of December 12, 2013, by and among Seadrill Limited, a Bermuda exempted company Seadrill Partners LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, and Seadrill Americas Inc. (incorporated by reference to the Exhibit 10.1 of the registrant’s Report on Form 6-K for the month of March, filed on March 11, 2014)
4.36
Contribution, Purchase and Sale Agreement, dated March 11, 2014 (incorporated by reference to the Exhibit 10.2 of the registrant’s Report on Form 6-K, for the month of March, filed on March 17, 2014)
4.374.32Promissory Discount Note, dated March 21, 2014 issued by Seadrill Capricorn Holdings LLC (incorporated by reference to Exhibit 4.37 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2013, filed on April 30, 2014)

Exhibit
Number
Description
4.38Limited Partner Interest Purchase Agreement, dated as of July 17, 2014, between Seadrill Limited and Seadrill Partners LLC (incorporated by reference to Exhibit 10.1 of the registrant’s Report on Form 6-K, for the month of July, filed on July 21, 2014.
4.394.33
Contribution, Purchase and Sale Agreement, dated November 4, 2014, by and among Seadrill Limited, Seadrill Partners LLC, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc. (incorporated by reference to Exhibit 4.39 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.404.34
Purchase and Sale Agreement, dated as of June 16, 2015, by and among Seadrill Limited, Seadrill Operating LP, Seadrill Polaris Ltd. (incorporated by reference to the Exhibit 10.1 of the registrant’s Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)

4.41
Exhibit
Number
Description
4.35
Promissory Note, dated as of June 19, 2015, between Seadrill Operating LP and Seadrill Limited (incorporated by reference to the Exhibit 10.2 of the registrant’s Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.424.36
Guaranty, dated as of June 19, 2015, between Seadrill Partners LLC as the guarantor and Seadrill Limited as the holder (incorporated by reference to the Exhibit 10.3 of the registrant’s Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.37
Fifth Amendment and Restated Agreement, dated 16 August 2017, relating to the USD 420,000,000 Term Loan and Revolving Credit Facilities Agreement of Seadrill Polaris Ltd, as borrower (incorporated by reference to the Exhibit 10.1 of the registrants Report on Form 6-K, filed August 17, 2017).
4.38
Third Amendment and Restated Agreement, dated 16 August 2017, relating to, among other things, the USD 483,333,333.34 Third Amended and Restated Senior Secured Credit Facility Agreement for Seadrill Vela Hungary Kft., as borrower (incorporated by reference to the Exhibit 10.2 of the registrants Report on Form 6-K, filed August 17, 2017).
4.39
China ECA Facility Framework Agreement, dated 16 August 2017, relating to, among other things, a new USD 119,100,000 Secured Credit Facility Agreement of Seadrill T-15 Ltd. and Seadrill T-16 Ltd., each as borrowers (incorporated by reference to the Exhibit 10.3 of the registrants Report on Form 6-K, filed August 17, 2017).

4.40
Consent & Amendment No. 1, dated February 12, 2018, relating to the Term Loan B Credit Agreement (incorporated by reference to the Exhibit 10.1 of the registrants Report on Form 6-K, filed February 13, 2018).
8.1*
List of Subsidiaries of Seadrill Partners LLC
12.1*
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
12.2*
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial and Accounting Officer
13.1*
Certification under Section 906 of the Sarbanes-Oxley Act of 2002 of the Principal Executive Officer
13.2*
Certification under Section 906 of the Sarbanes-Oxley Act of 2002 of the Principal Financial and Accounting Officer
15.1*14.1*Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP
Amended and Restated Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Partners LLC, dated September 11 2017.
14.2*
Management and Administrative Services Agreement between Seadrill Management Ltd and Sebras Rig Holdco Kft, dated September 11 2017.
14.3*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Auriga Hungary Kft, dated September 11 2017.
14.4*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Canada Ltd, dated September 11 2017.
14.5*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill China Operations Ltd S.à .r.l, dated September 11 2017.
14.6*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Deepwater Drillship Ltd, dated September 11 2017.
14.7*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Far East Ltd, dated September 11 2017.
14.8*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Ghana Operations Ltd, dated September 11 2017.
14.9*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Gulf Operations Auriga LLC, dated September 11 2017.
14.10*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Gulf Operations Vela LLC, dated September 11 2017.
14.11*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Hungary Kft, dated September 11 2017.
14.12*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill International Limited, dated September 11 2017.
14.13*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Leo Ltd, dated September 11 2017.
14.14*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Polaris Ltd, dated September 11 2017.
14.15*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill T-15 Ltd, dated September 11 2017.
14.16*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill T-16 Ltd, dated September 11 2017.
14.17*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill US Gulf LLC, dated September 11 2017.
14.18*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Vela Hungary Kft, dated September 11 2017.
14.19*
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Vencedor Ltd, dated September 11 2017.
101. INS**INSXBRL Instance Document
101. SCH**SCHXBRL Taxonomy Extension Schema
101. CAL**CALXBRL Taxonomy Extension Schema Calculation Linkbase
101. DEF**DEFXBRL Taxonomy Extension Schema Definition Linkbase
101. LAB**LABXBRL Taxonomy Extension Schema Label Linkbase
101. PRE**PREXBRL Taxonomy Extension Schema Presentation Linkbase
*     Filed herewith.


Index to Consolidated and Combined Carve-out Financial Statements of Seadrill Partners LLC
 
Report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm
F- 2
Consolidated and Combined Carve-out Statements of Operations for the years ended December 31, 2015, 2014,2017, 2016 and 20132015
F- 34
Consolidated Balance Sheets as of December 31, 20152017 and 20142016
F- 45
Consolidated and Combined Carve-out Statements of Cash Flows for the years ended December 31, 2015, 2014,2017, 2016 and 20132015
F- 56
Consolidated and Combined Carve-out Statements of Changes in Members’ Capital for the years ended December 31, 2015, 2014,2017, 2016, and 20132015
F- 78
Notes to Consolidated and Combined Carve-out Financial Statements
F- 89


Report of Independent Registered Public Accounting Firm

To the Board of Directors and Members of Seadrill Partners LLC

In our opinion,Opinions on the Financial Statements and Internal Control over Financial Reporting

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Seadrill Partners LLC and its subsidiaries atthe Company as of December 31, 20152017 and 2014,2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20152017 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, 2015,2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring OrganizationsCOSO.


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

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


Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under Item 15(b).15. Our responsibility is to express opinions on thesethe Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our integrated 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 Public Company Accounting Oversight Board (United States).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 supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.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

PricewaterhouseCoopers LLP
Uxbridge, United Kingdom
April 28, 201612, 2018

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



SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF OPERATIONS
for the years ended December 31, 2015, 20142017, 2016 and 20132015
(In US$ millions, except per unit data)
 
 Note 2017 2016 2015
Operating revenues       
Contract revenues  $1,007.7
 $1,356.4
 $1,603.6
Reimbursable revenues  17.7
 32.8
 49.9
Other revenues6*103.0
 211.1
 88.1
Total operating revenues  1,128.4
 1,600.3
 1,741.6
        
Other operating income       
Revaluation of contingent consideration  89.9
 —
 —
Gain on sale of assets  0.8
 —
 —
Total other operating income7 90.7
 —
 —
        
Operating expenses       
Vessel and rig operating expenses *(345.4) (373.9) (495.5)
Amortization of favorable contracts9 (74.4) (70.6) (66.9)
Reimbursable expenses  (16.1) (30.2) (45.7)
Depreciation and amortization10 (274.9) (266.3) (237.5)
General and administrative expenses *(44.8) (41.2) (52.3)
Total operating expenses  (755.6) (782.2) (897.9)
        
Operating income  463.5
 818.1
 843.7
        
Financial items       
Interest income  15.7
 11.5
 9.8
Interest expense *(179.1) (180.0) (192.5)
Loss on derivative financial instruments14*(13.9) (18.0) (82.9)
Currency exchange gain  0.9
 0.6
 1.6
Gain on bargain purchase *—
 —
 9.3
Other financial expenses  (11.5) —

—
Total financial items  (187.9) (185.9) (254.7)
        
Income before income taxes  275.6
 632.2
 589.0
Income tax expense5 (40.3) (86.5) (100.6)
Net income  235.3
 545.7
 488.4
Net income attributable to the non-controlling interest  (94.1) (264.7) (231.2)
Net income attributable to Seadrill Partners LLC owners  141.2
 281.0
 257.2
        
Earnings per unit (basic and diluted)       
Common unitholders  $1.88
 $3.20
 $2.45
Subordinated unitholders  $—
 $2.28
 $2.45
  2015 2014 2013
Operating revenues      
Contract revenues $1,603.6
 $1,302.7
 $1,047.1
Reimbursable revenues 49.9
 39.9
 11.4
Other revenues*88.1
 —
 5.8
Total operating revenues 1,741.6
 1,342.6
 1,064.3
       
Operating expenses      
Vessel and rig operating expenses*495.5
 425.0
 375.2
Amortization of favorable contracts 66.9
 14.8
 —
Reimbursable expenses 45.7
 37.9
 10.6
Depreciation and amortization 237.5
 198.7
 141.2
General and administrative expenses*52.3
 51.4
 49.6
Total operating expenses 897.9
 727.8
 576.6
       
Operating income 843.7
 614.8
 487.7
       
Financial items      
Interest income 9.8
 3.7
 4.4
Interest expense*(192.5) (140.9) (92.2)
(Loss)/gain on derivative financial instruments*(82.9) (124.9) 49.9
Currency exchange gain / (loss) 1.6
 (3.3) (1.2)
Gain on bargain purchase*9.3
 —

—
Total financial items (254.7) (265.4) (39.1)
       
Income before income taxes 589.0
 349.4
 448.6
Income taxes (100.6) (34.8) (33.2)
Net income $488.4
 $314.6
 $415.4
Net income attributable to the non-controlling interest (231.2) (176.4) (271.0)
Net income attributable to Seadrill Partners LLC owners $257.2
 $138.2
 $144.4
       
Earnings per unit (basic and diluted)      
Common unitholders $2.45
 $1.75
 $2.15
Subordinated unitholders $2.45
 $1.75
 $1.83
* Includes transactions with related parties. Refer to Note 13 - Related"Related party transactions.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 and Combined Carve-out Financial Statements.

SEADRILL PARTNERS LLC
CONSOLIDATED BALANCE SHEETS
As atof December 31, 20152017 and 20142016
(In US$ millions)
 2015 2014Note2017 2016
ASSETS        
Current assets:        
Cash and cash equivalents $319.0
 $242.7
 $848.6
 $767.6
Accounts receivables, net 278.3
 294.5
8
254.1
 249.0
Amount due from related party 128.1
 62.7
13
24.2
 80.6
Other current assets 166.6
 129.3
9
86.8
 117.0
Total current assets 892.0
 729.2
 1,213.7
 1,214.2
Non-current assets:        
Drilling units 5,547.3
 5,141.1
10
5,170.9
 5,340.9
Goodwill 3.2
 3.2
3
3.2
 3.2
Deferred tax assets 34.2
 18.4
5
9.5
 14.1
Amount due from related party 50.0
 —
Other non-current assets 314.4
 376.2
9
133.5
 208.3
Total non-current assets 5,949.1
 5,538.9
 5,317.1
 5,566.5
Total assets $6,841.1
 $6,268.1
 $6,530.8
 $6,780.7
        
LIABILITIES AND MEMBERS’ CAPITAL        
Current liabilities:        
Current portion of long-term debt $93.8
 $68.9
11
$162.9
 $93.8
Current portion of long-term related party debt 145.8
 40.4
13
24.7
 135.6
Trade accounts payable and accruals 24.1
 7.9
 37.4
 31.9
Current portion of deferred and contingent consideration to related party 60.4
 25.8
13
41.7
 45.6
Related party payable 304.7
 250.0
13
157.0
 189.6
Other current liabilities 217.9
 227.4
12
121.8
 168.9
Total current liabilities 846.7
 620.4
 545.5
 665.4
Non-current liabilities:        
Long-term debt 3,440.4
 3,156.6
11
3,180.2
 3,346.5
Long-term related party debt 160.2
 306.1
13
—
 24.7
Deferred and contingent consideration to related party 185.4
 111.2
13
46.0
 157.6
Deferred tax liability 43.7
 —
5
1.5
 1.5
Long-term related party payable 50.0
 —
Other non-current liabilities 17.3
 29.5
12
55.8
 49.2
Total non-current liabilities 3,897.0
 3,603.4
 3,283.5
 3,579.5
        
Commitments and contingencies (see note 15) 

 

Commitments and contingencies (see Note 15) 

 

Equity        
Members’ Capital: 

 

 

 

Common unitholders (issued 75,278,250 units) 945.5
 913.3
 1,208.9
 1,123.2
Subordinated unitholders (issued 16,543,350 units) 18.8
 11.7
 94.8
 69.4
Seadrill member interest —
 3.2
 —
 —
Total members’ capital 964.3
 928.2
 1,303.7
 1,192.6
Non-controlling interest 1,133.1
 1,116.1
 1,398.1
 1,343.2
Total equity 2,097.4
 2,044.3
 2,701.8
 2,535.8
Total liabilities and equity $6,841.1
 $6,268.1
 $6,530.8
 $6,780.7
See accompanying notes that are an integral part of these Consolidated and Combined Carve-out Financial Statements.

SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CASH FLOWS
for the years ended December 31, 2015, 20142017, 2016 and 20132015
(In US$ millions)
 
 2015 2014 2013 2017 2016 2015
Cash Flows from Operating Activities            
Net income $488.4
 $314.6
 $415.4
 $235.3
 $545.7
 $488.4
Adjustments to reconcile net income to net cash provided by operating activities:            
Depreciation and amortization 237.5
 198.7
 141.2
 274.9
 266.3
 237.5
Amortization of deferred loan charges 20.2
 17.6
 7.1
 12.6
 11.4
 20.2
Amortization of favorable contracts 66.9
 14.8
 —
 74.4
 70.6
 66.9
Gain on disposal of PPE (0.8) —
 —
Gain on bargain purchase (9.3) —
 —
 —
 —
 (9.3)
Unrealized loss / (gain) related to derivative financial instruments 31.8
 99.1
 (60.2)
Unrealized (gain) / loss related to derivative financial instruments (25.8) (32.2) 31.8
Unrealized foreign exchange gain (1.7) —
 —
 (3.5) (9.4) (1.7)
Payment for long term maintenance (49.8) (39.1) (26.5) (54.9) (48.0) (49.8)
Deferred income tax (benefit) / expense 27.9
 (8.6) (9.2)
West Aquarius settlement
 —
 —
 25.0
Gain on revaluation of contingent consideration (89.9) —
 —
Net movement in taxes 4.6
 19.2
 27.9
Accretion of discount on deferred consideration 13.3
 —

—
 13.2
 17.3

13.3
            
Changes in operating assets and liabilities, net of effect of acquisitions            
Trade accounts receivable 49.8
 (46.3) (9.4) (1.6) 38.7
 49.8
Prepaid expenses and accrued income (1.9) —
 —
 (4.0) 8.6
 (1.9)
Trade accounts payable 15.3
 (10.7) 48.6
 5.4
 7.8
 15.3
Related party balances (29.0) 31.4
 56.9
 16.1
 (64.3) (29.0)
Other assets 57.9
 9.9
 2.0
 34.4
 70.0
 57.9
Other liabilities (45.0) 41.7
 (14.0) (4.9) (12.1) (45.0)
Changes in deferred revenue (12.0) (14.4) (12.9) (9.7) (17.0) (12.0)
Other, net (0.5) —
 —
 0.4
 1.2
 (0.5)
Net cash provided by operating activities $859.8
 $608.7
 $564.0
 $476.2
 $873.8
 $859.8
            
Cash Flows from Investing Activities            
Additions to newbuildings and drilling units (18.6) (31.6) (159.3)
Additions to drilling units (66.7) (13.1) (18.6)
Proceeds from sale of assets 16.2
 —
 —
Acquisition of subsidiaries, net of cash acquired (214.7) (1,137.7) —
 —
 —
 (214.7)
Loan granted to related parties (143.0) —
 —
 —
 —
 (143.0)
Purchase of non-controlling interest in Seadrill Operating LP —
 (373.5) —
Net cash used in investing activities $(376.3) $(1,542.8) $(159.3)
Payment received from loans granted to related parties 39.4
 103.6
 —
Insurance refund —
 7.1
 —
Net cash (used in) / provided by investing activities $(11.1) $97.6
 $(376.3)



SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CASH FLOWS
for the years ended December 31, 2015, 20142017, 2016 and 20132015
(In US$ millions)
 
  2015 2014 2013
Cash Flows from Financing Activities      
Net proceeds from long term debt $—
 $2,825.4
 $98.0
Repayments of long term debt (97.6) (472.1) (348.8)
Debt fees paid (0.8) —
 —
Net proceeds from related party debt 143.0
 —
 409.5
Repayments of related party debt (40.3) (1,588.3) 

Proceeds from revolving credit facility 50.0
 —
 169.6
Contingent consideration paid (26.6) —
 —
Repayments of revolving credit facility —
 (125.9) (43.7)
Repayments of related party discount notes —
 (399.9) —
Cash distributions (435.3) (660.2) (140.9)
Proceeds on issuance of equity, net of fees —
 937.8
 464.8
Proceeds on issuance of equity to related parties —
 —
 106.9
Proceeds on issuance of units by Seadrill Capricorn Holdings LLC —
 570.3
 —
Distribution to Seadrill Limited for the acquisition of T-15, T-16, West Leo and West Sirius (1)
 —
 —
 (939.2)
Owner’s funding repaid —
 —
 (112.4)
Net cash provided by/ (used in) financing activities $(407.6) $1,087.1
 $(336.2)
       
Effect of exchange rate changes on cash 0.4
 —
 —
       
Net increase in cash and cash equivalents 76.3
 153.0
 68.5
Cash and cash equivalents at beginning of the year 242.7
 89.7
 21.2
Cash and cash equivalents at the end of year $319.0
 $242.7
 $89.7
       
Supplementary disclosure of cash flow information      
Interest paid net of capitalized interest $228.6
 $128.3
 $92.2
Taxes paid 57.0
 42.6
 35.1
(1) Presented net of capital contributions from Seadrill related to the acquisition of the West Leo and West Sirius. For further information refer to Note 3 - Business Acquisitions.
  2017 2016 2015
Cash Flows from Financing Activities      
Repayments of long term debt (215.0) (105.3) (97.6)
Debt fees paid (3.8) (0.3) (0.8)
Net proceeds from related party debt —
 —
 143.0
Repayments of related party debt (66.0) (249.5) (40.3)
Proceeds from revolving credit facility —
 —
 50.0
Contingent consideration paid (40.0) (59.7) (26.6)
Cash distributions (60.1) (107.3) (435.3)
Net cash (used in) / provided by financing activities $(384.9) $(522.1) $(407.6)
       
Effect of exchange rate changes on cash 0.8
 (0.7) 0.4
       
Net increase in cash and cash equivalents 81.0
 448.6
 76.3
Cash and cash equivalents at beginning of the year 767.6
 319.0
 242.7
Cash and cash equivalents at the end of year $848.6
 $767.6
 $319.0
       
Supplementary disclosure of cash flow information      
Interest and other financial items paid $200.3
 $196.4
 $228.6
Taxes paid 42.9
 49.0
 57.0
See accompanying notes that are an integral part of these Consolidated and Combined Carve-out Financial Statements.

SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CHANGES IN MEMBERS’
CAPITAL
for the years ended December 31, 2015, 20142017, 2016 and 20132015
(In US$ millions)
  Members’ Capital      
  
Common
Units
 
Subordinated
Units
 
Seadrill
Member
 
Total Before
Non-
Controlling
interest
 
Non-
controlling
Interest
 
Total 
Equity
Consolidated and Combined Balance at December 31, 2012 $294.1
 $3.7
 $226.8
 $524.6
 $899.8
 $1,424.4
Movement in invested equity —
 —
 (62.3) (62.3) (50.1) (112.4)
Acquisition of dropdown companies from Seadrill —
 —
 (831.5) (831.5) (962.5) (1,794.0)
Deemed distribution to Seadrill for the acquisition of dropdown companies —
 —
 609.7
 609.7
 696.9
 1,306.6
Allocation of deemed distribution to Seadrill for the acquisition of dropdown companies (609.7) —
 —
 (609.7) (696.9) (1,306.6)
Equity contribution from Seadrill to Seadrill Operating LP —
 —
 —
 —
 511.1
 511.1
Units issued by Seadrill Capricorn Holdings LLC to Seadrill Limited —
 —
 —
 —
 338.8
 338.8
Common units issued to Seadrill for the acquisition of the T-16 106.9
 —
 —
 106.9
 —
 106.9
Common units issued to Seadrill and public - (net of transaction costs of $15.3m) 464.8
 —
 —
 464.8
 —
 464.8
Capital injection due to forgiveness of related party payables 9.9
 6.6
 —
 16.5
 24.0
 40.5
Consolidated and Combined carve-out net income 53.4
 33.7
 57.3
 144.4
 271.0
 415.4
Cash Distributions paid (39.2) (25.2) —
 (64.4) (76.5) (140.9)
Consolidated Balance at December 31, 2013 $280.2
 $18.8
 $—
 $299.0
 $955.6
 $1,254.6
Purchase of non-controlling interest (279.6) —
 —
 (279.6) (93.2) (372.8)
Common units issued to Seadrill and public (net of transaction costs) 937.8
 —
 —
 937.8
 —
 937.8
Contribution from non-controlling interest —
 —
 —
 —
 570.3
 570.3
Net income 102.2
 26.8
 9.2
 138.2
 176.4
 314.6
Cash Distributions (127.3) (33.9) (6.0) (167.2) (493.0) (660.2)
Consolidated Balance at December 31, 2014 $913.3
 $11.7
 $3.2
 $928.2
 $1,116.1
 $2,044.3
Net income $203.0
 $44.7
 $9.5
 $257.2
 $231.2
 $488.4
Cash Distributions $(170.8) $(37.6) $(12.7) $(221.1) $(214.2) $(435.3)
Consolidated balance at December 31, 2015 $945.5
 $18.8
 $—
 $964.3
 $1,133.1
 $2,097.4
  Members’ Capital      
  
Common
Units
 
Subordinated
Units
 
Seadrill
Member
 
Total Before
Non-
Controlling
interest
 
Non-
controlling
Interest
 
Total 
Equity
Consolidated Balance at December 31, 2014 $913.3
 $11.7
 $3.2
 $928.2
 $1,116.1
 $2,044.3
Net income 203.0
 44.7
 9.5
 257.2
 231.2
 488.4
Cash Distributions (170.8) (37.6) (12.7) (221.1) (214.2) (435.3)
Consolidated balance at December 31, 2015 $945.5
 $18.8
 $—
 $964.3
 $1,133.1
 $2,097.4
Net income 230.4
 50.6
 —
 281.0
 264.7
 545.7
Cash Distributions (52.7) —
 —
 (52.7) (54.6) (107.3)
Consolidated balance at December 31, 2016 $1,123.2
 $69.4
 $—
 $1,192.6
 $1,343.2
 $2,535.8
Net income 115.8
 25.4
 —
 141.2
 94.1
 235.3
Cash Distributions (30.1) —
 —
 (30.1) (30.0) (60.1)
Other Distributions —
 —
 —
 —
 (9.2) (9.2)
Consolidated balance at December 31, 2017 $1,208.9
 $94.8
 $—
 $1,303.7
 $1,398.1
 $2,701.8
See accompanying notes that are an integral part of these Consolidated and Combined Carve-out Financial Statements.

SEADRILL PARTNERS LLC
NOTES TO CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS
Note 1-1 - General information
Background
On June 28, 2012, Seadrill Limited (“Seadrill”("Seadrill") formed Seadrill Partners LLC (the “Company”)"Company" or "we) under the laws of the Republic of the Marshall Islands.
On October 24, 2012, the Companywe completed its initial public offering of itsofferings ("IPO") and listed our common units ("IPO"), in which the Company sold 10,062,500 common units representing limited liability company interests in the Company (including 1,312,500 common units issued in connection with the exercise by the underwriters’ of their option to purchase additional common units) to the public at a price of $22.00 per unit, raising gross proceeds of $221.4 million. Net proceeds from the offering were $202.6 million, after deducting underwriting discounts, commissions, and structuring fees and expenses of $18.8 million. As part of this transaction, the Company issued to Seadrill 14,752,525 common units and 16,543,350 subordinated units. The Company’s common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “SDLP”.
In addition, the Company 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.
On October 24, 2012, in connection with the Company's IPO the Companywe acquired in return for the issuance of common and subordinated units to Seadrill and the net proceeds received from the IPO (i) a 30% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through the Company'sour 100% ownership of its general partner, Seadrill Operating GP LLC, and (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Seadrill Operating LP owned: (i) a 100% interest in the entities that own the West Aquarius and the West Vencedor and (ii) an approximate 56% interest in the entity that owns and operates the West Capella. Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn. In addition, in connection with the IPO we issued to Seadrill Member LLC, a wholly owned subsidiary of Seadrill, the Seadrill Member interest, which is a non-economic limited liability company interest in the Company, and all of the Company's incentive distribution rights, which entitle the Seadrill Member to increasing percentages of the cash the Company can distribute in excess of $0.4456 per unit, per quarter.
Subsequent to the IPO (i) our wholly-owned subsidiary Seadrill Partners Operating LLC acquired from Seadrill two entities that own the T-15 and T-16, (ii) Seadrill Capricorn Holdings LLC acquired from Seadrill two entities that own the West Auriga and West Vela, (iii) Seadrill Operating LP acquired from Seadrill the entity that owns the West Polaris, and (iv) we acquired from Seadrill an additional 28% limited partner interest in Seadrill Operating LP.
Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC are collectively referred to as “OPCO”"OPCO". These transactions described above were reflected as a reorganization
Seadrill owns the remaining interests in OPCO. As of entities under common controlDecember 31, 2017 and therefore, the assets and liabilities acquired from2016, Seadrill were recorded at historical cost by the Company.
On May 17, 2013,owned 34.9% of the Company's wholly owned subsidiary,common units and all of its subordinated units (which together represent 46.6% of the outstanding limited liability company interests) as well as Seadrill Partners OperatingMember LLC, acquired from Seadrillwhich owns a 100% ownershipnon-economic interest in the entities that ownCompany and operate the tender rig T-15. To finance the acquisitionall of the T-15, Seadrill Partners Operating LLC, borrowed from Seadrill $109.5 million as vendor financing.
On October 18, 2013, the Company's wholly owned subsidiary, Seadrill Partners Operating LLC, acquired from Seadrill a 100% ownership interest in the entity that owns the tender rig T-16. As consideration for the purchase, the Company issued 3,310,622 common units to Seadrill.
On December 13, 2013, the Company completed the acquisition of the companies that own and operate the ultra-deepwater semi-submersible rigs, the West Sirius and West Leo. The West Sirius was acquired by Seadrill Capricorn Holdings LLC (51% owned by the Company) and the West Leo was acquired by Seadrill Operating LP (at the time 30% owned by the Company). In order to finance the acquisitions, the Company issued 11,200,000 common units to the public and 3,394,916 common units to Seadrill, and a further 1,680,000 units to the underwriters, issued in connection with the exercise of the underwriters’ option to purchase additional common units.
These transactions that occurred prior to the IPO and through December 31, 2013 described above, have been reflected as a reorganization of entities under common control and therefore the assets and liabilities acquired from Seadrill have been recorded at historical cost by the Company. See further discussion below for the impact on the year ending December 31, 2013.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 US GAAP and, therefore, Seadrill Partners and Seadrill are no longer deemed to be entities under common control.
On March 21, 2014, Seadrill Capricorn Holdings LLC completed the acquisition of the companies that own and operate the drillship, the WestAuriga which has been accounted for as a business combination. In order to finance the acquisition, the Company issued 11,960,000 common units to the public and 1,633,987 common units to Seadrill. Refer to "Note 3 - Business acquisitions"for more information.
On June 24, 2014, the Company issued 6,100,000 common units to the public and 3,183,700 common units to Seadrill.
On July 21, 2014, the Company purchased an additional 28% limited partner interest in Seadrill Operating LP, from Seadrill for $372.8 million. As a result of the acquisition, the Company’s limited partner interest in Seadrill Operating LP increased from 30% to 58%.
On September 23, 2014, the Company issued 8,000,000 common units to the public.
On November 4, 2014, Seadrill Capricorn Holdings LLC completed the acquisition of the companies that own and operate the drillship West Vela from Seadrill which has been accounted for as a business combination. Refer to "Note 3 - Business acquisitions" for more information.
On June 19, 2015, Seadrill Operating LP (58% owned by the Company) completed the acquisition of Seadrill Polaris Ltd ("Seadrill Polaris"), the entity that owns and operates the drillship the West Polaris from Seadrill. The purchase was accounted for as a business combination. Refer to "Note 3 - Business"Business acquisitions" for more information.
As of December 31, 2015, Seadrill owned 46.6% of the outstanding limited liability interests of the Company, which included Seadrill's interest in both the common and subordinated units (December 31, 2014: Seadrill owned 46.6%).


Basis of consolidation and presentation
The financial statements are presented in accordance with generally accepted accounting principles in the United States of America (“US GAAP”("GAAP"). The amounts are presented in United States dollar (US dollar) rounded to the nearest hundred thousand, unless otherwise stated.
Going concern
The accounting policies set out belowfinancial statements have been applied consistentlyprepared on a going concern basis and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Therefore, financial information in this report does not reflect the adjustments to all periodsthe carrying values of assets and liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in these consolidatedthe normal course of operations. Such adjustments could be material.
Our financial projections indicate that the cash flows we will generate from our current contract backlog, together with our available cash and combined carve-outother 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 unlessare issued. This includes servicing our debt, maintaining working capital, paying for capital expenditure for drilling unit upgrades and major maintenance, making distributions and meeting other obligations as they fall due.
Whilst we have taken steps to insulate the Company from events of default related to Seadrill's Chapter 11 proceedings, we remain operationally dependent on Seadrill on account of the management, administrative and technical support services provided by Seadrill to Seadrill Partners. In the event Seadrill is unable to provide these services, as a result of its restructuring or otherwise, noted.Seadrill Partners has the right to terminate these agreements and would seek to build these capabilities internally or determine a suitable third party contractor to replace Seadrill. This may have an adverse effect on operations and may negatively impact our cash flows and liquidity.
Until Seadrill emerges from Chapter 11, uncertainty remains and the condition gives rise to substantial doubt over our ability to continue as a going concern. To the extent Seadrill emerges from Chapter 11,we expect this substantial doubt to be mitigated.
Out of period adjustments
The financial statements for the year ended December 31, 2017 include a pre-tax gain of $20.9 million for out of period adjustments relating to 2016. These adjustments relate to the valuation of contingent consideration recognized on acquisition of the West Polaris from Seadrill.
The financial statements for the year ended December 31, 2016 include a pre-tax gain of $24.1 million for out-of-period adjustments relating to 2014 and 2015. These adjustments relate to the valuation of our interest rate swap portfolio.
Refer to Note 14 –"Risk management and financial instruments" for further information.

Management evaluated the impact of these out-of-period adjustments in 2017 and 2016 and concluded that they were not material to the financial statements for the year ended December 31, 2017, December 31, 2016 or to any previously reported quarterly or annual financial statements.
Basis of consolidation
Investments inThe financial statements include the results and financial position of all companies in which the Companywe directly or indirectly holdshold more than 50% of the voting control. We eliminate all intercompany balances and transactions.
We control are consolidated in the financial statements. The Company owns 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'sand its majority owned subsidiaries because of our 100% ownership of its non-economic general partner Seadrill Operating GP LLC. Ownership of the generalGLP LLC and through our 58% limited partner is deemed to provide the Company with a controlling financial interesteconomic interest. We control Seadrill Capricorn Holdings LLC and as such, the Company consolidates Seadrill Operating LP in its financial statements. The Company also owns amajority owned subsidiaries through our 51% limited partner interest in Seadrill Capricorn Holdings LLC.interest.
All inter-company balances and transactions are eliminated. The Company allocated the initial company capital of unitholdersWe separately present within equity on the basis of how distributions would be made in a liquidation situation.

Business combinations between entities under common control
Reorganization of entities under common control is accounted for similar to the pooling of interests method of accounting. Under this method, the carrying amount of net assets recognized in theour consolidated balance sheets of each combining entity are carried forwardthe ownership interests attributable to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. The excess of the proceeds paid, if any, over the historical cost of the combining entity is accounted for as a change in equity. In addition re-organization of entities under common control is accounted for as if the transfer occurred from the date that both the combining entity and combined entity were both under the common control of Seadrill. Therefore, the Company’s financial statements prior to the date theparties with noncontrolling interests in the combining entity were actually acquired are retroactively adjustedour consolidated subsidiaries, and we separately present net income attributable to include the resultssuch parties in our consolidated statements of the combined entities during the periods it was under common control of Seadrill.
The acquisitions of the entities that own and operate the T-15, T-16,West Leo and West Sirius in 2013 from Seadrill were accounted for under this method. The companies acquired from Seadrill relating to the T-15, T-16, West Leo and West Sirius are referred to as the "dropdown companies" throughout these financial statements.
As of January 2, 2014, the date of the Company's first annual general meeting, Seadrill ceased to control the Company as defined by US GAAP and therefore Seadrill Partners and Seadrill are no longer be deemed to be entities under common control.

operations.
Business combinations
The Company appliesWe apply the acquisition method of accounting for business combinations. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred. See "Note 3 - –"Business acquisitions" for further discussion on business acquisitions.

Note 2 -2- Accounting policies
The accounting policies set out below have been applied consistently to all periods in these consolidated financial statements, unless otherwise noted.
Use of estimates
Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Contract revenue
A substantial majority of the Company’sour revenues are derived from dayrate based drilling contracts (which may include lump sum fees for mobilization and demobilization) and other service contracts. BothWe recognize dayrate base and lump sum fee revenues are recognized ratably over the contract period when services are rendered. Under some contracts, the Company iswe are entitled to additional payments for meeting or exceeding certain performance targets. Such additional payments are recognized when any uncertainties regarding achievements of such targets are resolved or upon completion of the drilling program.
In connection with drilling contracts, the CompanyWe may receive lump sum fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to commencement of drilling services. These up-front fees are recognized as revenue over the originalexpected contract term, excluding any extension option periods.term. We may also receive fees for making capital upgrades during the contract. We recognize revenue for such fees over the expected remaining contract term.
In some cases, the Companywe may receive lump sum non-contingent fees or dayrate based fees from customers for demobilization upon completion of a drilling contract. Non-contingentWe recognize non-contingent demobilization fees are recognized as revenue over the originalexpected contract term, excluding any extension

option periods not exercised by the Company's customers. Contingentterm. We recognize revenue for contingent demobilization fees are recognized as earned upon completion of the drilling contract.
Fees received from customers under drilling contracts for capital upgrades are deferred and recognized over the remaining contract term, excluding any extension option periods not exercised.
In certainsome countries, in which the Company operates, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government or taxing authority may assess taxes on the Company'sour revenues. The CompanySuch taxes may include sales taxes, use taxes, value-added taxes, gross receipts taxes and excise taxes. We generally recordsrecord tax-assessed revenue transactions on a net basis in the consolidated and combined carve-out statement of income.

basis.
Reimbursable revenue and expenses
Reimbursements received for the purchases of supplies, personnel services and other services provided on behalf of and at the request of the Company'sour customers in accordance with a contract or agreement are recorded as revenue. The related costs are recorded as reimbursable expenses in the same period.

Other revenues
Other revenues include amounts recognized as early termination fees under the offshore 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 revenues earned within the Company's Nigerian service company relatingfees charged to certain services, including the provision ofSeadrill for onshore support and offshore personnel. During the year ended December 31, 2015, other revenues include Seadrill's drilling rigs West Jupiter and West Saturn and to services provided to Seadrill’s West Polaris drilling rig that was operating in Nigeria for the year ended December 31, 2013.

Mobilization and demobilization expenses
MobilizationWe incur costs incurred as part ofto prepare a drilling unit for a new customer contract are capitalized and recognized asto move the rig to the contract location. We recognize the expense for such mobilization costs over the expected contract term, excluding any extension periods not exercised by the Company's customers. Theterm.
We incur costs of relocating drilling units that are not under contract are expensed as incurred.
Demobilization costs are costs related to the transfer of a vessel or drilling unit to a safe harbor or different geographic area andat the end of a contract. We expense such demobilization costs as incurred. We also expense any costs incurred to relocate drilling units that are expensed as incurred.

not under contract.
Vessel and rig operating expenses
Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, and include the remuneration of offshore crews and related costs, rig supplies, insurance costs, expenses for repairs and maintenance as well asand costs related tofor onshore personnel in various locations where the Company operates the rigs and are expensedsupport personnel. We expense such costs as incurred.

Repairs, maintenance and periodic surveys
Costs related to periodic overhauls of drilling units are capitalized under drilling units 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. AmortizationWe include amortization costs for periodic overhauls are included in depreciation and amortization expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.

Foreign currencies
The Company and all of its subsidiaries use the U.S. dollarsdollar as their functional currencycurrencies because the majoritymost of their revenues and expenses are denominated in U.S. dollars. Accordingly, the Company’sour reporting currency is also U.S. dollars.
Transactions in foreign currencies during a period are translated into U.S. dollars at the rates of exchange in effect at the date of the transaction. Foreign currency assets and liabilities are translated using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the consolidated statements of operations.

Gain on Bargain Purchase
When the fair value of the identifiable assets and liabilities acquired in a business combination is in excess of the sum of the fair value of consideration and the fair value of any retained non- controlling interest, the Company recognizes in earnings a gain on bargain purchase. Before recognizing any gain on bargain purchase, the Company reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed.

Earnings Per Unit ("EPU")
The Company computes earnings per unitWe compute EPU using the two-class method set out in US GAAP. AnyWe first allocate undistributed earnings for the period are allocated to the various unitholdersholders 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 Company's Operating Agreement across the common and subordinated members and incentive distribution right holders. Where distributions relating to the period are in excess of earnings, the deficit is also allocated according to thesame cash distribution model.
TheWe calculate the EPU for each category of units by taking the sum of the distributed amounts anddistributions to those units plus the allocation of thethose units undistributed earnings or deficit to each class of unitholders is dividedfor the period and dividing this total by the weighted average number of units outstanding duringfor the period. Diluted earnings per unit, if applicable, reflects the potential dilution that could

occur ifWe don't have any potentially dilutive instruments were exercised, resulting in the issuance of additional units that would then share in the Company's net earnings.

and therefore don't present a diluted EPU.
Current and non-current classification
Assets and liabilities (excluding deferred taxes) are classified as current assets and liabilities respectively, if their maturity is within one year of the balance sheet date. Otherwise, they are classified as non-current assets and liabilities.

Cash and cash equivalents
Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.

Receivables
Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. The Company establishesWe 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, the Company considerswe consider the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. Receivable amounts determined as being unrecoverable are written off.

Drilling units
Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of the Company’sour semi-submersibles, drillships and tender rigs, when new, is 30 years. Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset’s value for its remaining useful life are capitalized and depreciated over the remaining life of the asset.
Drilling units that are acquired in business combinations are recognized at fair value on date of acquisition.
Cost of property and equipment sold or retired, with the related accumulated depreciation and write-downs are removed from the consolidated balance sheet, and resulting gains or losses are included in the consolidated statement of operations.

Impairment of long-lived assets
We review the carrying value of our long-lived assets for impairment whenever certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and fair value.
Favorable drilling contracts - intangible assets
Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition less accumulated amortization. The amortization is recognized in the statement of operations under "amortization of favorable contracts". The amounts of these assets are amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.

Impairment of long-lived assets
The carrying value of long-lived assets that are held and used by the Company are reviewed for impairment whenever certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and fair value.

Derivative Financial Instruments and Hedging Activities
The Company’s interest-rate swap agreements are recordedWe record derivative financial instruments at fair value, and are recorded within related party receivables/payables on the balance sheet when the counter party to the agreements is Seadrill, and within other current assets/liabilities when the counter party to the agreements is an external party. Changes in the fair valuevalue. None of interest-rate swap agreements, whichour derivative financial instruments have not been designated as hedging instruments,instruments. Therefore, changes in their fair value are recorded as ataken to the consolidated statement of operations in each period.
We classify the gain or loss on derivative financial instruments as a separate line item within financial items in the consolidated statement of operations.

We classify the asset or liability for derivative financial instruments as an other current asset or liability in our consolidated balance sheet. We offset assets and liabilities for derivatives that are subject to legally enforceable master netting agreements.
Income taxes
Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. The Company does not conduct business or operate in the Republic of the Marshall Islands, and is not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom the Company is subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate.
Significant judgment is involved in determining the provision for income taxes. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. The Company recognizes tax liabilities based on its assessment of whether its tax positions are more likely than not sustainable, based on the technical merits and considerations of the relevant taxing authority’sauthorities widely understood administrative practices and precedent.
Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is

recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, to simplify the presentation of deferred income taxes in a classified statement of financial position. The update requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position as opposed to the current requirement to separate these into current and non-current amounts. As permitted by ASU 2015-17, the Company early-adopted this standard effective December 31, 2015 and applied it retrospectively to all periods presented. As a result, the Company has presented all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. The adoption of this guidance did not have a material impact on Company's consolidated financial statements and related disclosures.
Deferred charges
Loan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, and amortized over the term of the related loan and the amortization is included in interest expense.

Loss contingencies
Provisions
A provision is recognizedWe recognize a loss contingency in the consolidated balance sheet when the Company haswhere we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.

Related parties
Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence.

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 Company’s consolidated and combined carve-out 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.
Pre-acquisition earnings presented which relates to entities acquired from Seadrill as part of common control transactions have been allocated to the Seadrill member interest. The Seadrill Member interest, and its rights to the incentive distribution rights, is owned by the predecessor owner of acquired entities, Seadrill.

Recently Adopted Accounting Standards
In September 2015,We adopted the Financial Accounting Standards Board (FASB) issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. The amendments in this update require that an acquirer recognize adjustments to provisional amounts that are identifiedfollowing accounting standard updates ("ASUs") during the measurement period in the reporting period in which the adjustment amounts are determined. The guidance further requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date and present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance will be effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and early adoption is permitted. The Company has chosen to early adopt this standard in 2015. Please refer to "Note 3 - Business acquisitions".
The Company has adopted ASU 2015-03, Interest - Imputation of Interest, (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs as of June 30, 2015, which requires the debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. This ASU is effective for the first interim period beginning after December 15, 2015 and early adoption is permitted. The Company has chosen to early adopt this ASU in the second quarter of 2015. As a result, the consolidated balance sheet as ofyear ended December 31, 2014 has been retrospectively adjusted to reflect this change in accounting principle. $7.6 million2017, none of debt issuance costs have been reclassified from other current assets to a direct deduction from current portion of long-term debt and $70.8 million of debt issuance costs have been reclassified from other non-current assets to a direct deduction from long-term debt. As of December 31, 2015, $11.5 million of debt issuance costs have been presented as a direct deduction from the current portion of long-term debt and $46.6 million of debt issuance costs have been presented as a direct deduction from long-term debt. Refer also to Note 11 - Debt.
In April 2015, the FASB issued ASU 2015-06, Earnings Per Share (Topic 260) which includes the final version of Proposed ASU EITF -14A - Earnings Per Share - Effects on Historical Earnings per Unit of Master Limited Partnership Drop Down Transactions. The amendments in this update specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported earnings per unit of the limited partners would not change as a result of a drop down transaction. This ASU is effective for the first interim period beginning after December 15, 2015 and early adoption is permitted. The Company has chosen to early adopt this ASU in the first quarter of 2015. However, the adoption of this standard by the Company does not have a materialhad any impact on itsour consolidated financial statements and related disclosures.disclosures:

ASU 2016-05 - Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (a consensus of the Emerging Issues Task Force)

ASU 2016-06 - Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments (a consensus of the Emerging Issues Task Force)
In November 2015,ASU 2016-07 - Investments—Equity Method and Joint Ventures (Topic 323): Simplifying the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, to simplify the presentation of deferred income taxes in a classified statement of financial position. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position as opposedTransition to the current requirementEquity Method of Accounting
ASU 2016-09 - Compensation—Stock Compensation (Topic 718): Improvements to separate these into currentEmployee Share-Based Payment Accounting
ASU 2016-17 - Consolidation (Topic 810): Interests Held through Related Parties that are under Common Control
ASU 2016-19 - Technical Corrections and non-current amounts. As permitted by ASU 2015-17,Improvements
Recently Issued Accounting Standards
The FASB have issued the Company early-adopted this standard as at December 31, 2015 and applied it retrospectively to all periods presented. As a result the Company has presented all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. The adoption of this guidance didfollowing ASUs that we have not have a material impact on Company'syet adopted but which could affect our consolidated financial statements and related disclosures.disclosures in future periods.

ASU 2014-09 - Revenue from Contracts with Customers (also 2016-8, 2016-10, 2016-11, 2016-12, 2016-20, 2017-13, 2017-14)
Recently Issued Accounting StandardsASU 2016-01 - Financial Instruments — Recognition and Measurement of Financial Assets and Financial Liabilities

ASU 2016-02 - Leases
ASU 2016-13 - Financial Instruments — Measurement of Credit Losses on Financial Instruments
ASU 2016-15 - Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments
ASU 2016-16 - Income taxes — Intra-Entity Transfers of Assets other than Inventory
ASU 2016-18 - Statement of Cash Flows — Restricted Cash
ASU 2017-01 - Business Combinations — Clarifying the Definition of a Business
ASU 2017-04 - Intangibles — Simplifying the Test for Goodwill Impairment
ASU 2017-05 - Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets
ASU 2014-09 - Revenue from contracts with customers
In May 2014, the FASB issued ASU 2014-09,Revenue from Contracts with Customers, which provides new authoritative guidance on the methods of revenue recognition and related disclosure requirements. In April 2015This new standard supersedes all existing revenue recognition requirements, including most industry-specific guidance. We will be required to apply this standard for the FASB proposedyear ended December 31, 2018 and for interim periods within that year.
We have substantially completed our work to deferimplement the effective datenew standard and do not expect our pattern of revenue recognition to materially change as a consequence of adopting the guidance by one year. Based on this proposal, public entities would neednew guidance. We plan to use the modified retrospective method to transition to the new standard. This method requires us to apply the new standard to all outstanding contracts as of January 1, 2018. Under this method we record the cumulative effect of applying the new standard as an adjustment to opening retained earnings.
To apply the standard, we were required to assess the core promise made to our customers under a drilling contract. We have assessed that our core promise is to stand ready to provide drilling services, as directed by our customer, over the operating period of a contract. We have concluded that this promise is provided as a series of distinct services that are substantially the same and have the same pattern of transfer to the customer. Therefore, we follow the so-called series guidance and treat the series of distinct services as a single performance obligation.

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

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which provides new authoritative guidance with regards to management's responsibility to assess an entity's ability to continue as a going concern, and to provide related footnote disclosures in certain circumstances. The ASU will be effective for all entities in the first annual period ending after December 15, 2016 (December 31, 2016 for calendar year-end entities) and early adoption is permitted. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which made targeted amendments to the current consolidation guidance that could affect all industries. The FASB issued this guidance to respond to stakeholders’ concerns about the current accounting for consolidation of certain legal entities. Financial statement users asserted that in certain situations in which consolidation is ultimately required, deconsolidated financial statements are necessary to better analyze the reporting entity’s economic and operational results. Previously, the FASB issued an indefinite deferral for certain entities to partially address those concerns. However, the amendments in this guidance rescind that deferral and address those concerns by making changes to the consolidation guidance. The ASU will be effective for public entities in the first annual period, and for interim periods thereafter, beginning after December 15, 2015 and early adoption is permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

2016-02 - Leases
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update requires an entity to recognize right-of-use assets and lease liabilities on its balance sheet and disclose key information about leasing arrangements. It also offers specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and early adoption is permitted, using a modified retrospective application.

We have started to assess the impact of this standard update on our consolidated financial statements and related disclosures. We have determined that our drilling contracts contain a lease component and therefore adoption of this standard will result in increased disclosure of our leasing arrangements and may affect the way we recognize revenues associated with the lease and revenue components. Based on our work to date, we don't expect our pattern of revenue recognition to change significantly compared to current accounting standards.
We are consulting with other drilling companies to fully determine recognition and disclosure under the new standard. We may change our initial assessment as we complete the implementation process.
ASU 2016-13 - Financial Instruments — Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which revises guidance for the accounting for credit losses on financial instruments within its scope. The new standard introduces an approach, based on expected losses, to estimate credit losses on certain types of financial instruments and modifies the impairment model for available-for-sale debt securities. The guidance will be effective January 1, 2020, with early adoption permitted. The CompanyEntities are required to apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted.
We are in the processearly stage of evaluating the impact of this standard update on itsupdate. 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.disclosures when we adopt it.

ASU 2016-15 - Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments
In MarchAugust 2016, the FASB issued ASU 2016-07,No. 2016-15, Investments-Equity MethodStatement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting. The update eliminates the requirement that an investor retrospectively apply equity method accounting when an investment that it had accounted for by another method initially qualifies for useCash Payments based on a consensus of the equity method.Emerging Issues Task Force (EITF), to address the classification of certain cash receipts and cash payments on the statement of cash flows. The new guidance willalso clarifies how the predominance principle should be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal yearsapplied when cash receipts and early adoption is permitted. The Company does not expect the adoptioncash payments have aspects of this standard to have a material impact on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). The update clarifies principal vs agent accountingmore than one class of the new revenue standard.cash flows. The guidance will be effective for annual and interim periods beginning after December 15, 2017, and shall be applied, atwith early adoption permitted. Entities are generally required to apply the Company’s option, retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Early adoption is not permitted until periods beginning after December 15, 2016. The Company isguidance retrospectively.
We are in the process of evaluating the impact of this standard update on itsupon our consolidated financial statements and related disclosures.

ASU 2016-16 - Income taxes — Intra-Entity Transfers of Assets other than Inventory
In MarchOctober 2016, the FASB issued ASU 2016-09,2016-16, Compensation-Stock CompensationIncome Taxes (Topic 718)740): ImprovementsIncome Taxes Intra-Entity Transfers of Assets other than Inventory, which requires companies to Employee Share-Based Payment Accounting.recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the consolidated statement of operations as income tax expense (or benefit) in the period of sale or transfer occurs. The update simplifiesexception to recognizing the accountingincome tax effects of intercompany sales or transfers of assets remains in place for share based paymentintercompany inventory sales and transfers, i.e. companies will still be required to defer the income tax effects of intercompany inventory transactions. The standard will be effective for annual periods beginning after December 15, 2017, with early adoption permitted. Entities are required to apply the guidance on a modified retrospective basis, with the cumulative effect adjustment to retained earnings at the beginning of the period of adoption.
We have not historically incurred any substantial tax liabilities as a result of making intra-entity transfers of assets. Our balance sheet does not include assets or liabilities recorded for the deferral of income tax expenses or benefits on intra-entity transfers. Therefore, we do not currently expect this guidance to affect our consolidated financial statements and related disclosures when we adopt it.
ASU 2016-18 - Statement of Cash Flows — Restricted Cash
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, to address classification of activity related to restricted cash and restricted cash equivalents in the cash flows. The standard eliminates the presentation of transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents and restricted cash equivalents are presented in more than one line item on the balance sheet, a reconciliation of the totals in the cash flows to the related captions in the balance sheet are required, either on the face of the cash flow or in the notes to the financial statements. Additional disclosures are required for the nature of the restricted cash and restricted cash equivalents. The standard will be effective for fiscal years beginning after December 15, 2016, including2017, and interim periods within those fiscal years and early adoption is permitted. The Company doesyears.
We do not currently have any substantial restricted cash balances. Therefore, we do not currently expect the adoption of this standardguidance to have a material impact on itsaffect our consolidated financial statements and related disclosures.disclosures when we adopt it.

ASU 2017-01 - Business Combinations — Clarifying the Definition of a Business
In April 2016,January 2017, the FASB issued ASU 2016-10,2017-01, Business Combinations Revenue from Contracts(Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business to assist entities with Customers (Topic 606): Identifying Performance Obligations and Licensing. The update provide more clarification about identifying performance obligations and licensing.evaluating whether transactions should be accounted for as acquisitions (or disposals) or assets or businesses. The guidance will be effective for annual and interim periods beginning after December 15, 2017, and shall be applied, at2017. Entities apply the Company’s option, retrospectively to each period presentedguidance prospectively. We will apply this standard when we next undertake a business acquisition or as a cumulative-effect adjustment as of the date of adoption. Early adoption is not permitted until periods beginning after Decemberdisposal.

15, 2016.ASU 2017-04 - Intangibles — Simplifying the Test for Goodwill Impairment
In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the new guidance, entities will continue to perform Step 1 of the goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. The Company is inentity will now recognize an impairment charge for the processamount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of evaluating the impact ofgoodwill allocated to that reporting unit.
We do not currently have any substantial goodwill balances. Therefore, we do not currently expect this standard update on itsguidance to significantly affect our consolidated financial statements and related disclosures.disclosures when we adopt it.
ASU 2017-05 - Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets
In February 2017, the FASB issued 2017-05, Other Income — Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The standard update clarifies that a model consistent with ASC 606 and ASC 810 should be applied to sales of non-financial assets to non-customers. Under this guidance an entity would recognize a gain or loss in full when it transfers control of the asset. The effective date of the guidance will be effective for annual and interim periods beginning after December 15, 2017.
The new guidance is consistent with our current practice and therefore we do not expect this guidance to affect our consolidated financial statements and related disclosures when we adopt it.
Other accounting standard updates issued by the FASB
As of March 31, 2018, the FASB has issued several further updates not included above. We do not currently expect any of these updates to affect our consolidated financial statements and related disclosures either on transition or in future periods.

Note 3 - Business acquisitions

For the year-ended December 31, 20152017

There were no business acquisitions undertaken in the year ended December 31, 2017.
For the year-ended December 31, 2016
There were no business acquisitions undertaken in the year ended December 31, 2016
For the year-ended December 31, 2015
West Polaris Acquisition
On June 19, 2015, the Company’sour 58% owned subsidiary, Seadrill Operating LP, (“Seadrill Operating”), completed the purchase (the “Polaris Acquisition”"Polaris Acquisition") of 100% of the ownership interests in Seadrill Polaris Ltd. (“("Seadrill Polaris”Polaris") the entity that owns and operates the drillship the West Polaris (the “Polaris Business”"Polaris Business") from Seadrill. Seadrill Operating LP is 42% owned by Seadrill. The acquisition is in line with the Company’s strategy to increase quarterly cash distributions through accretive acquisitions of modern offshore drilling units with long-term contracts attached.

The initial consideration for the Polaris Acquisition was comprised of $204.0 million of cash and $336.0$336.0 million of debt outstanding under the existing facility financing the West Polaris.

In addition, Seadrill Operating LP issued a note (the “Seller's Credit”"Seller's Credit") of $50.0 million to Seadrill, payment of which is contingent on the future re-contracted dayrate for the West Polaris. The Seller's Credit is due in 2021 and bears an interest rate of 6.5% per annum. During the three-year period following the completion of the current drilling contract with ExxonMobil, the Seller's Credit may be reduced if the average contracted dayrate (net of commissions) for the period, adjusted for utilization, under any replacement contract is below $450 thousand$450,000 per day until the Seller's Credit's maturity in 2021. Should the average dayrate of the replacement contract be above $450 thousand$450,000 per day, the entire Seller's Credit must be paid to Seadrill upon maturity of the Seller's Credit in 2021.
In addition, Seadrill Polaris may be required to make further contingent payments to Seadrill based upon the West Polaris's operating dayrate.dayrate until March 2025. At the time of acquisition, the West Polaris was contracted with ExxonMobil on a dayrate of $653 thousand$653,000 per day until March 2018. Under the terms of the acquisition agreement, Seadrill Polaris has agreed to pay Seadrill (a) any dayrate it receivesreceived in excess of $450 thousand$450,000 per day, adjusted for daily utilization, through the remaining term, without extension, of the ExxonMobil contract (the “Initial Earn-Out”"Initial Earn-Out") and (b) after the expiration of the term of the existing contract until March 2025, 50% of any day ratedayrate above $450 thousand$450,000 per day, adjusted for daily utilization, tax and agency commission (the “Subsequent Earn-Out”"Subsequent Earn-Out").

In connection with the completion of the Polaris Acquisition, Seadrill Polaris as borrower, entered into an amendment and restatement of the $420.0 million term loan facility secured by the West Polaris (the “West"West Polaris Facility”Facility"). Please refer further to "Note 11 – Debt""Debt".

The fair value of the total consideration paid was $374.6 million, was comprised of cash of $204.0 million, the Seller's Credit, which had a fair value of $44.6 million as of the acquisition date, contingent consideration with a fair value of $95.3 million as of the acquisition date, and a working capital adjustment which increased consideration by $30.7 million.

The following table summarizes the consideration paid, and the amounts of the assets and liabilities recognized at the acquisition date.
(In US$ millions)June 19, 2015
Consideration
Cash204.0
Contingent consideration95.3
Seller's Credit44.6
Plus: Working capital adjustment30.7
Fair value of total consideration transferred374.6
Recognized amounts of identifiable assets acquired and liabilities assumed at estimated fair value
Cash20.0
Current assets52.1
Intangible asset - favorable drilling contract124.3
Drilling unit575.3
Long term interest bearing debt(336.0)
Current liabilities(20.2)
Non-current liabilities(1.3)
Total identifiable net assets at acquisition414.2
Measurement period adjustment(30.3)
Gain on bargain purchase(9.3)
Total374.6

(In US$ millions)June 19, 2015
Consideration 
Cash$204.0
Contingent consideration95.3
Seller's Credit44.6
Plus: Working capital adjustment30.7
Fair value of total consideration transferred$374.6
  
Recognized amounts of identifiable assets acquired and liabilities assumed at estimated fair value 
Cash$20.0
Current assets52.1
Intangible asset - favorable drilling contract124.3
Drilling unit575.3
Long term interest bearing debt(336.0)
Current liabilities(20.2)
Non-current liabilities(1.3)
Total identifiable net assets at acquisition$414.2
  
Measurement period adjustment$(30.3)
Gain on bargain purchase(9.3)
Total$374.6
The West Polaris drilling unit has been valued at fair value separately fromWe estimated the related drilling contract. The estimated fair value of the West Polaris drilling unit was derived using an income approach with market participant based assumptions, including the Company's expectations aroundestimates of future dayrates, drilling unit utilization, operating costs, capital and long term maintenance expenditures and applicable tax rates. The cash flows arewere estimated over the remaining useful economic life of the drilling unit. At the acquisition date, the cash flows were discounted using an estimated market participant weighted average cost of capital of 8.5%. At the acquisition date, theThe estimated fair value of the West Polarisdrilling unit recognized was $575.3 million.million at the acquisition date.

The fair value of the West Polarisdrilling contract has been assessed separately. The contract was valueddetermined using an “excess earnings”"excess earnings" technique where the terms of the contract arewere assessed relative to current market conditions. The value of the contract related intangible was determined by means of calculating the incremental cash flows arising over the life of the contract compared with a contract with terms at prevailing market rates. At the acquisition date, the fair value of the favorable contract was recognized as an intangible asset totaling $124.3 million. This intangible asset will bewas amortized over the remaining contract period until March 2018.

term.
The fair value of trade receivables was $31.9 million at the acquisition date, which was also the gross contractual amount. All amounts have since been collected.

At the time of acquisition, the fair value of contingent consideration consisted of the fair value of the Initial Earn-Out of $61.8 million, the fair value of the Subsequent Earn-Out of $33.5 million and the fair value of the Seller's Credit of $44.6 million. The fair value as of the acquisition date was determined using future estimated contract revenues based upon estimates of re-contracted dayrate, average utilization, less any expected commissions and taxes. The contingent consideration has been discounted to present value using a weighted average cost of capitaldiscount rate of 8.5%.

At the time of acquisition, the Initial Earn-Out had a maximum possible outcome (based on undiscounted cash flows) of $67.6 million, assuming the West Polarisachieved 100% utilization for the remainder of the ExxonMobil contract and the contracted dayrate was not re-negotiated. The lowest possible outcome of the Initial Earn-Out is nil, assuming the utilization for the West Polaris is 0% and or the contracted dayrate is re-negotiated to less than $450 thousand per day. It is not possible to calculate a range of possible outcomes for the Subsequent Earn-Out as it is impossible to determine a maximum possible re-contract dayrate and as such the maximum amount of the payment is unlimited. The lowest possible outcome for the subsequent earn-out is nil, assuming the utilization for the West Polaris is 0%, and or the re-contracted dayrate is less than $450 thousand per day. The range of undiscounted outcomes for the Seller's Credit varies from nil to $50.0 million.
Acquisition related transaction costs consisted of various advisory, legal, accounting, valuation and other professional fees of $0.7 million, which were expensed as incurred and are presented in the statementStatement of operationsOperations within general and administrative expenses.

Measurement period adjustment
At the acquisition date, the Companywe initially recognized a gain on bargain purchase from the Polaris Acquisition of $39.6 million, which was the excess of the total identifiable net assets acquired over the consideration transferred. In February 2016, customer ongoing negotiations were concluded and the customer contract for the West Polaris was adjusted to $490 thousand$490,000 per day. This provided further information regarding the value of the favorable contract intangible asset and the Initial Earn-Out. The information iswas further evidence of a condition that existed at the time of the acquisition and therefore should bewas accounted for as a measurement period adjustment. The favorable contract intangible asset and the Initial Earn-out liability were reduced by $47.9 million and $17.6 million, respectively. As a result, we reduced the company has recognized a $30.3 million reduction in the Gaingain on Bargain Purchase since the acquisition date and a $9.3 million Net Gain on Bargain Purchasebargain purchase for the year ended December 31, 2015.
Polaris Acquisition by $30.3 million. The final gain on the bargain purchase has been recordedwas therefore $9.3 million. This was classified in thea separate line “Gainitem "Gain on bargain purchase”purchase" in the Consolidated Statement of Operations. The gain was attributed to the Company's belief that Seadrill may obtain additional value through the transaction, over and above the consideration transferred.  This may include, but is not limited to, the potential future realization of value through Seadrill's investments in Seadrill Partners. These investments include direct ownership interests, common and subordinated units and incentive distribution rights. As a result of these investments Seadrill has a continuing interest in the growth and success of Seadrill Partners.
In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. The amendments in this update require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The guidance further requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date and present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance will be effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and early adoption is permitted. The Company has early adopted this standard and has recognized the measurement period adjustment with regard to the Polaris Acquisition in the current year.
After the measurement period adjustment, and as at December 31, 2015, the Initial Earn-Out has a maximum possible outcome (based on undiscounted cash flows) of$17.5 million, assuming the West Polarisachieves 100% utilization for the remainder of the ExxonMobil contract and the contracted dayrate is not re-negotiated. The lowest possible outcome of the Initial Earn-Out is nil, assuming the utilization for theWest Polaris is 0% and or the contracted dayrate is re-negotiated to less than $450 thousand per day.

Pro-forma information
In the consolidated statement of operations, $131.6 million of revenue and $7.8 million of net income have been included from the acquisition date of the Polaris Business until December 31, 2015.

The pro forma revenue and pro forma net income of the combined entity for the year ended December 31, 2015 and December 31, 2014, had the acquisition date been January 1, 2014 are as follows:
 Year ended December 31,
(In US$ millions)2015 2014
 Seadrill Partners LLC as reported Supplemental pro forma combined entity Seadrill Partners LLC as reported Supplemental pro forma combined entity
Total Revenue$1,741.6
 $1,851.3
 $1,342.6
 $1,564.1
Net Income488.4
 535.7
 314.6
 388.9
Net income attributable to Seadrill Partners LLC members257.2
 284.6
 138.2
 181.3


For the year-ended December 31, 2014

West Auriga Acquisition
On March 21, 2014, the Company’s 51% owned subsidiary, Seadrill Capricorn Holdings LLC, completed the purchase of 100% of the ownership interests in the entities that own and operate the West Auriga (the “Auriga business”)from Seadrill. The acquisition is in line with the Company’s strategy to increase quarterly cash distributions through accretive acquisitions of modern offshore drilling units with long-term contracts attached.
The purchase price was $1,240.0 million, less debt of $443.1 million that was outstanding under the existing facility related to West Auriga. The total consideration of $797.0 million comprised of cash of $696.9 million, and a zero coupon limited recourse discount note issued by Seadrill Capricorn Holdings LLC to Seadrill in an initial amount of $100.0 million. This note was repaid in June 2014 with the proceeds of the Amended Senior Secured Credit Facilities. Upon maturity of such note, Seadrill Capricorn Holdings LLC was due to repay $103.7 million to Seadrill. The purchase price was subsequently adjusted by a working capital adjustment of $330.4 million. The working capital adjustment predominately arose as a result of related party payable balances which remained in the acquired entities. These payable balances related to funding provided by Seadrill to the acquired entities for the construction, equipping and mobilization of the West Auriga.

In conjunction with this acquisition, the Company issued 11,960,000 common units to the public and 1,633,987 common units to Seadrill, at a price of $30.60 per unit, raising total net proceeds after fees of $401.3 million. Issuance costs of $14.7 million were charged against Members’ Capital.
The Company funded its 51% share of the cash purchase price with proceeds from the equity issuance described above. The remaining 49% was funded through the issuance of new units by Seadrill Capricorn Holdings LLC to Seadrill for $341.5 million.
Following the deconsolidation of the Company from Seadrill on January 2, 2014, this transaction is deemed to constitute a business combination rather than a transaction between entities under common control. The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized at the acquisition date.
(In US$ millions)March 21, 2014
Consideration
Cash696.9
Discount note issued100.0
Working capital adjustment(330.4)
Fair value of total consideration transferred466.5
Recognized amounts of identifiable assets acquired and liabilities assumed at estimated fair value
Cash24.4
Current assets44.4
Intangible asset - favorable drilling contract76.2
Drilling unit1,065.7
Non current assets76.6
Long term interest bearing debt(443.1)
Current liabilities(380.6)
Total identifiable net assets463.6
Goodwill2.9
Total466.5

The Company recognized goodwill from the acquisition of $2.9 million, which is the excess of consideration transferred over the net assets acquired. The value of the goodwill is attributed to the assembled workforce. None of the goodwill recognized is expected to be deductible for income tax purposes.
The drilling unit has been valued at fair value separately from the related drilling contract. The estimated fair value of the drilling unit was derived using an income approach with market participant based assumptions. The fair value of the drilling contract has been also been assessed separately. The contract was valued using an 'excess earnings' technique where the terms of the contract are assessed relative to current market conditions. The value of the contract related intangible was determined by means of calculating the incremental or decremental cash flows arising over the life of the contract compared with a contract with terms at prevailing market rates.

The fair value of trade receivables was $28.3 million at the acquisition date, which was also the gross contractual amount. All amounts are expected to be collected. The fair value of the mobilization fee receivable included in other current and non-current assets was $92.4 million at the acquisition date, which equaled the book value. All amounts are expected to be collected over the duration of the drilling contract.
Acquisition related transaction costs consisted of various advisory, legal, accounting, valuation and other professional fees of $0.2 million, which were expensed as incurred and are presented in the statement of operations within general and administrative expenses.
In the consolidated statement of operations, revenue of $164.5 million and net income of $46.1 million have been included since the acquisition date of the Auriga Business until December 31, 2014.

The pro forma revenue and pro forma net income of the combined entity for the year ended December 31, 2014 and 2013, had the acquisition date been January 1, 2013 are as follows:
 Year ended December 31,
(In US$ millions)2014 2013
 Seadrill Partners LLC as reported Supplemental pro forma combined entity Seadrill Partners LLC as reported Supplemental pro forma combined entity
Revenues1,342.6
 1,390.7
 1,064.3
 1,096.1
Net Income314.6
 331.0
 415.4
 412.5

Acquisition of additional limited partner interest in Seadrill Operating LP

On July 21, 2014, the Company completed the purchase of an additional 28% limited partner interest in Seadrill Operating LP from Seadrill for a total of $372.8 million. As a result of this acquisition, the Company’s limited partner interest in Seadrill Operating LP increased from 30% to 58%. Seadrill Operating LP was already a controlled subsidiary of the Company and therefore this has been accounted for as an equity transaction. Non-controlling interests of $93.2 million were derecognized with the residual $279.6 million recognized against members' capital.

West Vela Acquisition
On November 4, 2014, the Company’s 51% owned subsidiary, Seadrill Capricorn Holdings LLC, completed the purchase of 100% of the ownership interests in the entities that own and operate the West Vela (the “Vela business”)from Seadrill. The acquisition is in line with the Company’s strategy to increase quarterly cash distributions through accretive acquisitions of modern offshore drilling units with long-term contracts attached.
The initial purchase price was $900.0 million, less debt of $433.1 million that was outstanding under the existing facility related to West Vela. As part of the agreement Seadrill Capricorn Holdings LLC also has an obligation to pay deferred consideration of $44,000 per day for the remainder of the West Vela's current contract with BP which runs to November 2020. In addition Seadrill Capricorn Holdings will pay contingent consideration of up to $40,000 per day for the remainder of the BP contract, depending on the actual amount of contract revenue received from BP per day. The total consideration thus included deferred consideration payable to Seadrill of $73.7 million and contingent consideration of $65.7 million. The purchase price was subsequently reduced by a working capital adjustment of $6.0 million.
The Company funded its 51% share of the cash purchase price with proceeds from the equity issuance in September 2014 where the Company issued 8,000,000 common units to the public at a price of $30.68 per unit, raising total proceeds after fees of $245.4 million. Issuance costs of $10.9 million were charged against Members’ Capital. The remaining 49% was funded through the issuance of new units by Seadrill Capricorn Holdings LLC to Seadrill for $228.8 million.

Following the deconsolidation of the Company from Seadrill on January 2, 2014, this transaction is deemed to constitute a business combination rather than a transaction between entities under common control. The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized at the acquisition date.

(In US$ millions)November 4, 2014
Consideration
Cash467.0
Mobilization payable73.7
Contingent consideration65.7
Less: Working capital adjustment(6.0)
Fair value of total consideration transferred600.4
Recognized amounts of identifiable assets acquired and liabilities assumed at estimated fair value
Cash1.9
Current assets61.4
Intangible asset - favorable drilling contract204.7
Drilling unit755.8
Non current assets61.8
Long term interest bearing debt(433.1)
Current liabilities(52.3)
Total identifiable net assets600.2
Goodwill0.2
Total600.4


The Company recognized goodwill from the acquisition of $0.2 million, which is the excess of consideration transferred over the net assets acquired. The value of the goodwill is attributed to the assembled workforce. None of the goodwill recognized is expected to be deductible for income tax purposes.
The drilling unit has been valued at fair value separately from the related drilling contract. The estimated fair value of the drilling unit was derived using an income approach with market participant based assumptions. The fair value of the drilling contract has been also been assessed separately. The contract was valued using an 'excess earnings' technique where the terms of the contract are assessed relative to current market conditions. The value of the contract related intangible was determined by means of calculating the incremental or decremental cash flows arising over the life of the contract compared with a contract with terms at prevailing market rates.

The fair value of trade receivables was $44.1 million at the acquisition date, which was also the gross contractual amount. All amounts are expected to be collected. The fair value of the mobilization fee receivable included in other current and non-current assets was $94.2 million, at the acquisition date which equaled the book value. All amounts are expected to be collected over the duration of the drilling contract.
Acquisition related transaction costs consisted of various advisory, legal, accounting, valuation and other professional fees of $0.2 million, which were expensed as incurred and are presented in the statement of operations within general and administrative expenses.
In the consolidated statement of operations, revenue of $32.9 million and net income of $5.7 million have been included since the acquisition date of the Vela Business until December 31, 2014.
The pro forma revenue and pro forma net income of the combined entity for the twelve months ended December 31, 2014 and December 31, 2013, had the acquisition date been January 1, 2013 are as follows:
 Year ended December 31,
(In US$ millions)2014 2013
 Seadrill Partners LLC as reported Supplemental pro forma combined entity Seadrill Partners LLC as reported Supplemental pro forma combined entity
Revenues1,342.6
 1,532.4
 1,064.3
 1,083.4
Net Income314.6
 407.6
 415.4
 403.8

For the year-ended December 31, 2013

T-15 Acquisition
On May 17, 2013, the Company's wholly owned subsidiary, Seadrill Partners Operating LLC, acquired a 100% interest in the companies that own and operate the tender rig T-15 from Seadrill for a total purchase price of $210.0 million, less $100.5 million of debt assumed relating to the proportion of Seadrill's existing $440 million credit facility, relating to the T-15. Working capital adjustments reduced the purchase price by $34.9 million, which was settled in cash during the year. The acquisition has been accounted for as a transaction between entities under common control. The net assets acquired are recorded at the historic book value of Seadrill. The excess of the purchase price over the book value of net assets acquired of $79.4 million has been recorded as a reduction of equity. The acquisition was funded by a vendor financing loan from Seadrill of $109.5 million.

T-16 Acquisition
On October 18, 2013, Seadrill Partners Operating LLC, acquired from Seadrill a 100% ownership interest in the entity that owns the tender rig T-16 for a total purchase price of $200.0 million, less $93.1 million of debt assumed relating to the proportion of Seadrill's existing $440 million credit facility, relating to the T-16. Working capital adjustments reduced the purchase price by $39.0 million, which was recognized within related party receivables at December 31, 2013. The acquisition has been accounted for as a transaction between entities under common control. The net assets acquired are recorded at the historic book value of Seadrill. The excess of the purchase price over the book value of net assets acquired of $67.6 million has been recorded as a reduction of equity. As consideration for the purchase, the Company issued 3,310,622 common units to Seadrill in a private placement transaction at a price of $32.29 per unit, which was valued at $106.9 million.

West Sirius and West Leo Acquisition
On December 13, 2013, the acquisition of the companies that own and operate the West Sirius (the "Sirius Business") and West Leo (the "Leo Business") was completed. The Sirius Business was acquired by Seadrill Capricorn Holdings LLC (51% owned by the Company) and the Leo Businesswasacquired by Seadrill Operating LP (30% owned by the Company).
The total purchase price of the Sirius Business was $1,035.0 million, less debt assumed of $220.2 million, relating to the proportion of Seadrill's existing $1,500 million credit facility relating to the West Sirius. Working capital adjustments increased the purchase price by $106.7 million. 51% (which corresponds to the Company's ownership share of Seadrill Capricorn Holdings LLC) of this was recognized within related party payables at December 31, 2013. The remaining amount was recognized as an increase in the equity contribution from Seadrill described below. The acquisition has been accounted for as a transaction between entities under common control. The net assets acquired are recorded at the historic book value of Seadrill. The excess of the purchase price over the book value of net assets acquired of $546.9 million has been recorded as a reduction of equity. The Company funded its share of the purchase price through the equity issue described below, the issuance of a $229.9 million discount note by Seadrill Capricorn Holdings LLC, the issuance of a $70.0 million discount note by the Company, with the remaining 49% (which corresponds to Seadrill's share of Seadrill Capricorn Holdings LLC) being funded by an issuance of common units by Seadrill Capricorn Holdings LLC to Seadrill, totalling $338.8 million.
The total purchase price of the Leo Business was $1,250.0 million, less debt assumed of $485.0 million, relating to the proportion of Seadrill's existing $1,121 million credit facility relating to the West Leo. Working capital adjustments reduced the purchase price by $35.0 million. 30% (which corresponds to the Company's ownership share of Seadrill Operating LP) of this was recognized within related party payables at December 31, 2013. The remaining amount was recognized as a reduction in the equity contribution from Seadrill described below. The acquisition has been accounted for as a transaction between entities under common control. The net assets acquired are recorded at the historic book value of Seadrill. The excess of the purchase price over the book value of net assets acquired of $612.7 million has been recorded as a reduction of equity. The Company funded its share of the purchase price through the equity issue described below, with the remaining 70% (which corresponds to Seadrill's share of Seadrill Operating LP) being funded by an equity contribution to Seadrill Operating LP, by Seadrill totaling $511.1 million.
In order to fund the cash portion of the purchase price of these acquisitions, Seadrill Partners issued 12,880,000 common units to the public (including 1,680,000 common units issued to underwriters’ option to purchase additional common units) and 3,394,916 common units to Seadrill, at a price of $29.50 per unit on December 9, 2013 amounting to total gross proceeds of $480.1 million. Issuance fees were $15.3 million.



The following table summarizes the above acquisitions during the year ended December 31, 2013:
(In US$ millions) T-15 T-16 West Sirius West Leo Total
           
Total purchase price 210.0
 200.0
 1,035.0
 1,250.0
 2,695.0
Debt assumed (100.5) (93.1) (220.2) (485.0) (898.8)
Purchase price less debt 109.5
 106.9
 814.8
 765.0
 1,796.2
Working capital adjustments (34.9) (39.0) 106.7
 (35.0) (2.2)
Adjusted purchase price 74.6
 67.9
 921.5
 730.0
 1,794.0
Carrying value of net assets / (liabilities) acquired (4.8) 0.3
 374.6
 117.3
 487.4
Excess of sales price over net assets acquired 79.4
 67.6
 546.9
 612.7
 1,306.6

Refer to Note 1 - General Information - Business combinations between entities under common control - for further information on how these transactions have had an effect on the Company's consolidated and combined carve out financial statements.

Note 4 – Segment information
Operating segment
OPCO’sWe regard our fleet which is regarded as one single global segment, and is reviewed by theoperating segment. The Chief Operating Decision Maker, which is the Company's boardBoard of directors,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 the Company’sour revenues by customer for the years ended December 31, 2015, 20142017, 2016 and 20132015 is as follows:
 
 2015 2014 2013
BP44.8% 41.5% 35.0%
ExxonMobil *
32.1% 26.4% 14.5%
Tullow13.5% 17.4% 18.8%
Chevron8.5% 14.7% 12.1%
Total—% —% 19.6%
Other1.1% —% —%
Total100.0% 100.0% 100.0%

* The ExxonMobil drilling contract for the West Aquarius was assigned to Hibernia Management and Development Co. Ltd during 2015, 2014 and part of 2013 and to Statoil Canada Ltd. during part of 2013.
 2017 2016 2015
BP56.8% 42.0% 44.8%
ExxonMobil22.2% 22.0% 29.5%
Chevron7.9% 5.4% 8.5%
Hibernia6.4% 15.1% 2.6%
Tullow—% 13.0% 13.5%
Other6.7% 2.5% 1.1%
Total100.0% 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, 2015, 20142017, 2016 and 20132015 and fixed assets as of December 31, 20152017 and 20142016 by geographic area:
Revenues

(In US$ millions)2015 2014 20132017 2016 2015
United States$781.1
 $556.6
 $370.4
$638.0
 $672.2
 $781.1
Nigeria250.1
 228.5
 213.3
Ghana234.7
 233.5
 198.6
Canada190.9
 126.1
 153.5
Angola179.4
 92.3
 87.9
152.5
 175.9
 179.4
Thailand99.8
 105.6
 40.6
89.2
 86.3
 99.8
Canada87.1
 241.5
 190.9
Equatorial Guinea48.1
 —
 —
Nigeria39.5
 185.2
 250.1
Indonesia37.3
 —
 —
Ghana—
 208.1
 234.7
Other5.6
 —
 —
36.7
 31.1
 5.6
Total$1,741.6
 $1,342.6
 $1,064.3
$1,128.4
 $1,600.3
 $1,741.6

Fixed Assets—Drilling Units (1)
 
(In US$ millions)2015 20142017 2016
United States$2,927.4
 $3,024.3
$2,729.6
 $2,815.5
Spain1,075.9
 496.2
Canada460.9
 488.0
Thailand234.6
 241.0
Gabon507.4
 —
Indonesia162.5
 —
Ghana591.5
 608.4
—
 575.0
Angola571.3
 182.5
—
 554.0
Canada519.2
 539.3
Nigeria508.0
 525.4
Thailand251.5
 261.2
Myanmar178.4
 —
Singapore—
 171.2
Total$5,547.3
 $5,141.1
$5,170.9
 $5,340.9
(1)The fixed assets referred to in the table above include the eleven drilling units at December 31, 20152017 and ten drilling units at December 31, 2014.2016. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

Note 5 – Taxation
Income taxes consist of the following:
Year Ended December 31,Year Ended December 31,
(In US$ millions)2015 2014 20132017 2016 2015
Current tax expense:          
United Kingdom—
 —
 —
$(4.5) $(1.6) $—
Foreign72.6
 43.5
 42.4
40.4
 110.2
 72.6
Total current tax expense72.6
 43.5
 42.4
35.9
 108.6
 72.6
Deferred tax (benefit) expense:          
United Kingdom—
 —
 —
—
 —
 —
Foreign28.0
 (8.7) (9.2)4.4
 (22.1) 28.0
Total income tax expense100.6
 34.8
 33.2
$40.3
 $86.5
 $100.6
Seadrill Partners LLC is tax resident in the United Kingdom. The Company's controlled affiliates operate and earn income in several countries and are subject to the laws of taxation within those countries. Currently some of the Company's controlled affiliates formed in the Marshall Islands along with all those incorporated in the United Kingdom (none of whom presently own or operate rigs) are resident in the United Kingdom and are subject to U.K. tax. Subject to changes in the jurisdictions in which the Company's drilling units operate and/or are owned, differences in levels of income and changes in tax laws, the Company's effective income tax rate may vary substantially from one reporting period to another. The Company's effective income tax rate for each of the years ended on December 31, 2015, 20142017, 2016 and 20132015 differs from the U.K. statutory income tax rate as follows:
2015 2014 20132017 2016 2015
U.K. statutory income tax rate20.3 % 21.3 % 23.3 %19.3 % 20.0 % 20.3 %
Non-U.K. taxes(3.2)% (11.3)% (15.8)%(4.7)% (6.3)% (3.2)%
Effective income tax rate17.1 % 10.0 % 7.5 %14.6 % 13.7 % 17.1 %
Deferred Income Taxes
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

The net deferred tax assets consist of the following:
(In US$ millions)2015 20142017 2016
Provisions19.7
 1.5
$0.5
 $7.6
Net operating losses carry forward10.7
 14.8
33.3
 23.3
Property, plant and equipment—
 3.0
Other3.8
 —
5.0
 6.4
Gross deferred tax assets34.2
 19.3
38.8
 37.3
Valuation allowance related to NOL—
 (0.9)(28.9) (22.6)
Net deferred tax asset34.2
 18.4
Deferred tax asset, net of valuation allowance$9.9
 $14.7
The net deferred tax liabilities consist of the following:
(In US$ millions)2015 2014
Property, plant and equipment42.6
 —
Other1.1
 —
Gross deferred tax liabilities43.7
 —
Net deferred tax (liability) / asset(9.5) 18.4

The deferred tax liability recognized during the year ended December 31, 2015 is due to a change in tax legislation in Nigeria which required a retrospective adjustment in 2015. The Nigerian tax regime has changed from a deemed profit percentage of revenue to an actual profit regime using 30% of net income impacting both the current and deferred income tax. As such a deferred tax liability arises on the difference between book value and the assumed tax write-down value of the West Capella, the Company's drilling unit operating in Nigeria. The deferred tax liability is expected to reverse in approximately 2020.

The Company did not have any deferred tax liabilities at December 31, 2014 and 2013.
The net deferred taxes are classified as follows:
(In US$ millions)2015 2014
Long-term deferred tax asset34.2
 18.4
Long-term deferred tax liability(43.7) —
Net deferred tax (liability) / asset(9.5) 18.4
(In US$ millions)2017 2016
Property, plant and equipment$0.4
 $0.6
Unremitted earnings of subsidiaries1.5
 1.5
Gross deferred tax liabilities1.9
 2.1
    
Net deferred tax asset / (liability)8.0
 12.6
As of December 31, 2015,2017, deferred tax assets related to net operating loss ("NOL") carryforwards was $10.7were $33.3 million, which can be used to offset future taxable income. NOL carry forwards,carryforwards which were generated in various jurisdictions, include $33.3 million which will expire, if not utilized, in 2033 and 2034.expire. A valuation allowance of nil$28.9 million exists on the NOL carryforwards results where we dothe Company does not expect to generate future taxable income.

In November 2015,At December 31, 2017, we recalculated our deferred tax assets and liabilities to reflect the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,reduction in the U.S. corporate income tax rate from 35 percent to simplify the presentation of deferred income taxes21 percent. This has resulted in a classified statement of financial position. The update requires that$3 million increase in income tax expense for the year ended December 31, 2017 and a corresponding $3 million decrease in net deferred tax liabilities and assets be classified as non-current in a classified statement of financial position as opposed to the current requirement to separate these into current and non-current amounts. As permitted by ASU 2015-17, the Company early-adopted this standard effective December 31, 2015 and applied it retrospectively to all periods presented. As a result the Company has presented all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. The adoption of this guidance did not have a material impact on Company's consolidated financial statements and related disclosures.

2017.  
Uncertain tax positions

As of December 31, 2015,2017, the Company had uncertain tax positions, exclusive of $9.0interest, of $43.7 million which is(December 31, 2016: $40.0 million) included in other current liabilities"Other non-current liabilities" on ourthe consolidated balance sheet.sheets and is exclusive of interest. The changes to ourthe Company's liabilities related to uncertain tax positions including interest and penalties that we recognize as a component of income tax expense, were as follows:
(In US$ millions)2015 2014 2013
Balance beginning of period—
 —
 —
Increases as a result of positions taken in prior periods—
 —
 —
Increases as a result of positions taken during the current period9.0
 —
 —
Decreases as a result of positions taken in prior periods—
 —
 —
Decreases as a result of positions taken in the current period—
 —
 —
Balance end of period9.0
 —
 —
(In US$ millions)2017 2016
Balance beginning of year$40.0
 $9.0
Increases as a result of positions taken in prior years—
 42.0
Increases as a result of positions taken during the current year3.7
 31.9
Decreases as a result of positions taken in prior years—
 (34.2)
Decreases as a result of positions taken in the current year—
 (8.7)
Uncertain tax position$43.7
 $40.0

Accrued interest and penalties totaling $8.0 million as of December 31, 2017 (December 31, 2016: $1.8 million) was included in "Other non-current liabilities" on the consolidated balance sheets. The associated expense of $6.2 million was recognized in "Income tax expense" in the consolidated statements of operations during the year ended December 31, 2017 (December 31, 2016: $1.8 million and December 31, 2015: nil).
As of December 31, 2015,2017, if recognized, $9.0$51.7 million of ourthe Company's unrecognized tax benefits, including interest and penalties, would have a favorable impact on ourits effective tax rate.
Tax examinations
The Company is subject to taxation in various jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:
JurisdictionEarliest Open Year
United States2014
Angola2015
Nigeria2012
Ghana2013


Note 6 – Other revenues
Related party otherOther revenues comprise the following items:
 
Year Ended December 31,Year Ended December 31,
(In US$ millions)2015 2014 20132017 2016 2015
Termination payments revenue74.7
 —
 —
$95.9
 $198.8
 $74.7
Related party other revenues13.4
 —
 5.8
7.1
 12.3
 13.4
Total88.1
 —
 5.8
$103.0
 $211.1
 $88.1
Termination payments earned during the yearyears ended December 31, 2017, December 31, 2016 and December 31, 2015 include the termination fees afterfor the West Sirius drilling contract wasand West Capella, which were canceled before the completion date, with an effective dateend of April 1, 2015.the contract term.
The Company's Nigerian service company earned relatedRelated party other revenues relatingprimarily relate to certain services, including the provision of onshore support services and offshore personnel which the Company provided to Seadrill's West Saturn and the West Jupiter drilling rigs that were operating in Nigeria during the yearyears ended December 31, 20152017, December 31, 2016 and Seadrill’sDecember 31, 2015. Please refer to West PolarisNote 13 drilling rig that– "Related party transactions" for further detail on related party other revenues.

Note 7 – Other operating income
Other operating income comprises the following items: 
 Year Ended December 31,
(In US$ millions)2017 2016 2015
Revaluation of contingent consideration$89.9
 $—
 $—
Gain on sale of assets0.8
 —
 —
Total$90.7
 $—
 $—
There was operating in Nigeria duringgain on revaluation of contingent consideration of $89.9 million for the year ended December 31, 2013.2017 (December 31, 2016 and December 31, 2015: nil).
This gain resulted from a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the West Polaris in 2015. We use estimates of long-term dayrates and re-contracting factors to determine the fair value of these liabilities. These estimates have decreased during the year as new market information has become available, resulting in a decrease in the fair value of the liabilities. For further information please see Note 13 "Related party transactions".

Note 78 – Accounts receivable
Accounts receivable are presented net of allowances for doubtful accounts. There were nocustomer disputes and bad debts.
We have recorded provisions related to allowances for doubtful accountsdisputes with customers totaling $247.5 million as atof December 31, 2015. There was a provision of $5.9 million related2017 (December 31, 2016: $242.3 million). The offsetting entry for these provisions is to allowancereduce revenue. These provisions primarily relate to disputed amounts billed to Tullow on the West Leo, for doubtful accounts as at December 31, 2014. There were nowhich litigation proceedings are ongoing. Please refer to Note 15 – "Commitments and contingencies" for further details on this dispute.
We do not hold any provisions related to allowances for doubtful accounts as at December 31, 2013.
The Companybad debts. We did not recognize any bad debt expense in 2015, 20142017, 2016 or 2013, but has instead reduced contract revenues2015.

Note 9 – Other assets
Other assets include the following:
(In US$ millions)December 31,
2017		 December 31,
2016
Reimbursable amounts due from customers$3.6
 $5.9
Mobilization revenue receivables73.8
 108.5
Intangible asset- Favorable contracts to be amortized130.6
 205.0
Prepaid expenses8.5
 4.5
Other3.8
 1.4
Total other assets$220.3
 $325.3
Other assets are presented in our Consolidated Balance Sheet as follows:
(In US$ millions)December 31,
2017		 December 31,
2016
Other current assets86.8
 117.0
Other non-current assets133.5
 208.3
Total other assets$220.3
 $325.3
Mobilization revenue receivables
Under our contracts for any disputed amounts. There were no contract reductions in 2015, however there were reductions of $6.5 million in 2014 and $22.1 million in 2013. The reduction in 2014 was the result of a write-off of re-chargeables of $0.6 million relating to the West Leo as well as $5.9 million disputed with Hibernia relating to the West Aquarius. The reduction in 2013 was the result of amounts disputed with Hibernia in relation to the West Aquarius.

Note 8 – Other current assets
Other current assets include:
(In US$ millions)December 31,
2015		 December 31,
2014
Reimbursable amounts due from customers23.5
 18.5
Mobilization revenue receivable - short-term42.0
 42.0
Favorable contracts to be amortized - short-term70.5
 40.5
Insurance receivable12.1
 14.9
Prepaid expenses13.1
 11.2
Other5.4
 2.2
Total other current assets166.6
 129.3

The Mobilization revenue receivable - short-term portion relates to the mobilization revenue receivable from the West VelaCapricorn, West Aurigaand West Capricorn. Favorable contracts to be amortized - short-term portion relates to the favorable contracts acquired with the West Polaris, West Vela 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 from Seadrill.and


West Vela will be collected by October 2020 and November 2020 respectively.
Favorable contracts
Favorable drilling contracts are recorded as intangible assets at fair value on the date of acquisition less accumulated amortization. The amounts recognized represent the net present value of the existing contracts at the time of acquisition compared to the current market rates at the time of acquisition, discounted at the weighted average cost of capital. The estimated favorable contract values have been recognized and amortized on a straight line basis over the terms of the contracts, ranging from two to five years.
Favorable contracts to be amortized relate to the favorable contracts acquired with the West Vela, West Auriga and the West Polaris from Seadrill. As at December 31, 2017 the balance related to the contract acquired with the West Polaris was fully amortized. The gross carrying amounts and accumulated amortization included in 'Other current assets' and 'Other non-current assets' in the Consolidated Balance Sheets were as follows:

 December 31, 2015 December 31, 2014
 Gross carrying amount Accumulated amortization Net carrying amount Gross carrying amount Accumulated amortization Net carrying amount
Favorable contracts - intangible assets           
Balance at beginning of period280.9
 (14.8) 266.1
 —
 —
 —
Additions *76.4
 —
 76.4
 280.9
 —
 280.9
Amortization of favorable contracts—
 (66.9) (66.9) —
 (14.8) (14.8)
Balance at end of period357.3
 (81.7) 275.6
 280.9
 (14.8) 266.1
*Additions to favorable contracts during the year are net of measurement period adjustments.


 December 31, 2017 December 31, 2016
(In US$ millions)Gross carrying amount Accumulated amortization Net carrying amount Gross carrying amount Accumulated amortization Net carrying amount
Intangible assets- Favorable contracts           
Balance at beginning of period$357.3
 $(152.3) $205.0
 $357.3
 $(81.7) $275.6
Amortization of favorable contracts—
 (74.4) (74.4) —
 (70.6) (70.6)
Balance at end of period$357.3
 $(226.7) $130.6
 $357.3
 $(152.3) $205.0
The amortization is recognized in the statement of operations under "amortization of favorable contracts". The table below shows the amounts relating to favorable and unfavorable contracts that is expected to be amortized over the next five years:
 Year ended December 31
(In US$ millions)2016
 2017
 2018
 2019
 2020
 Total
Amortization of favorable contracts70.5
 70.5
 50.6
 45.6
 38.4
 275.6




Note 9 – Drilling units
(In US$ millions)December 31,
2015		 December 31,
2014
Cost6,434.2
 5,790.5
Accumulated depreciation(886.9) (649.4)
Net book value5,547.3
 5,141.1
 Year ended December 31
(In US$ millions)2018
 2019
 2020
 2021
 2022
 Total
Amortization of favorable contracts$45.2
 $45.1
 $40.3
 $—
 $—
 $130.6

Note 10 – Drilling units
The below table shows the gross value and net book value of our drilling units at December 31, 2017 and December 31, 2016.
(In US$ millions)December 31,
2017		 December 31,
2016
Cost$6,599.0
 $6,494.1
Accumulated depreciation(1,428.1) (1,153.2)
Net book value$5,170.9
 $5,340.9
Depreciation and amortization expense related to the drilling units was $237.5$274.9 million, $198.7$266.3 million and $141.2$237.5 million for the years ended December 31, 2015, 20142017, 2016 and 20132015 respectively.

Note 10 – Other non-current assets
(In US$ millions)December 31,
2015		 December 31,
2014
Mobilization revenue receivable - long-term portion109.2
 150.6
Favorable contract – long-term portion205.2
 225.6
Total other non-current assets314.4
 376.2

The Mobilization revenue receivable - long-term portion consistsEach of the West Vela, West Auriga and West Capricorn. The favorable contracts to be amortized - long-term portion consists of the favorable contracts acquired with the West Polaris, West Vela and West Auriga from Seadrill.our drilling units has been pledged as collateral under our debt agreements. Please also refer toread Note 811- Other non-current assets. – "Debt" for further details.

Note 11 – Debt

As of December 31, 20152017 and December 31, 2014, the Company2016, we had the following debt amounts outstanding:
 (In US$ millions)
December 31, 2015
 December 31, 2014
External debt agreements   
Amended Senior Secured Credit Facilities2,894.7
 2,881.0
$1,450 Senior Secured Credit Facility382.6
 422.9
   $420 West Polaris Facility315.0
 —
Sub-total external debt3,592.3
 3,303.9
Less current portion long term external debt(105.3) (76.5)
Long-term external debt3,487.0
 3,227.4
    
Related party debt agreements   
 Rig Financing and Loan Agreements   
   West Vencedor Loan Agreement (previously $1,200 facility)
57.5
 78.2
  $440 Rig Financing Agreement139.0
 158.8
Sub-total Rig Financing Agreements196.5
 237.0
    
 Other related party debt   
$109.5 T-15 vendor financing facility109.5
 109.5
Total related party debt306.0
 346.5
Less current portion of related party debt(145.8) (40.4)
Long-term related party debt and related party loan notes160.2
 306.1
    
Total external and related party debt3,898.3
 3,650.4
 (In US$ millions)
December 31, 2017
 December 31, 2016
External debt agreements   
Term Loan B$2,836.9
 $2,865.7
West Vela Facility255.3
 342.4
West Polaris Facility205.6
 279.0
Tender Rig Facility

83.3
 —
Sub-total external debt3,381.1
 3,487.1
    
Related party debt agreements   
   West Vencedor Facility24.7
 41.2
   Tender Rig Facility—
 119.1
Sub-total related party debt24.7
 160.3
    
Total external and related party debt$3,405.8
 $3,647.4

The outstanding debt as of December 31, 2015 is repayable as follows: 
(In US$ millions)As at December 31,
2016251.1
2017240.8
2018598.8
201929.0
202029.0
2021 and thereafter2,749.6
Total external and related party debt3,898.3

As discussed in "Note 2 - Accounting policies",Term Loan B (previously the Company has adopted ASU 2015-03, Interest - Imputation of Interest, (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs as of June 30, 2015. As a result, the consolidated balance sheet as of December 31, 2014 has been restated to reflect this change in accounting principle. Details of the debt issuance costs netted against the current and long-term debt for each of the period presented are shown below.

  Outstanding debt as of December 31, 2015
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $105.3
$(11.5)$93.8
Long-term external debt 3,487.0
(46.6)3,440.4
Total external debt $3,592.3
$(58.1)$3,534.2

  Outstanding debt as of December 31, 2014
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $76.5
$(7.6)$68.9
Long-term external debt 3,227.4
(70.8)3,156.6
Total external debt $3,303.9
$(78.4)$3,225.5

Amended"Amended Senior Secured Credit FacilitiesFacilities")
On February 21, 2014, Seadrill Operating LP, Seadrill Capricorn Holdings LLCOur Term Loan B facilities ("TLB") consists of a term loan and Seadrill Partners Finco LLC, which are subsidiaries of the Company (the “Borrowers”), entered into Senior Secured Credit Facilities (the “Senior Secured Credit Facilities”). The Senior Secured Credit Facilities consist of (i) a linked $100.0 million revolving credit facility (the “revolving facility”) available for borrowing from time to time by any Borrower, and (ii) afacility. We initially borrowed $1.8 billion under the term loan (the “term loan”) which was borrowed by Seadrill Operating LP in full on February 21, 2014 and then a further $1.1 billion on June 26, 2014. The proceeds from this transaction were usedThis loan is subject to (a) refinance debt relateda 1% per year ($29.0 million) amortization payment with the balance of the loan then being repayable in February 2021. We had $2,786.9 million outstanding on the term loan at December 31, 2017. We have drawn $50 million under the $100 million revolving credit facility linked to the rig facilities forTLB. The remaining $50 million was available and undrawn at December 31, 2017. The revolving credit facility matures in February 2019 and does not amortize.
During the West Capella, West Aquarius, West Sirius and West Leo , (b) repay in part unsecured loans from Seadrill, (c) add cashyear to the balance sheet in supportDecember 31, 2017, we paid interest of general company purposes and (d) pay all fees and expenses associated therewith.
On June 26, 2014, the Senior Secured Credit Facilities were amended ("Amended Senior Secured Credit Facilities") for the borrowing by Seadrill Operating LP of $1.1 billion of additional term loans in addition toLIBOR + 3.0% on the term loans already outstanding under the Senior Secured Credit Facilities as noted above. The proceeds from the additional $1.1 billion of term loans were used to (a) refinance debt secured by West Auriga of $443 millionloan and West Capricorn of $426.3 million, (b) repay in part certain unsecured loans from Seadrill, (c) add cash to the Company's balance sheet for general company purposes and (d) pay all fees and expenses associated with the Amended Senior Secured Credit Facilities. In June 2015, $50.0 million was drawn fromLIBOR + 2.25% on the revolving credit facilityfacility. LIBOR is subject to partially finance the acquisitiona 1% floor. We also pay a commitment fee of 0.5% on any unused portion of the entity that ownsrevolving credit facility. As set out below, we have agreed to a 3.0% increase in margin on the West Polaris.term loan as part of an amendment to the TLB agreed in February 2018.
The Amended Senior Secured Credit Facilities are guaranteed on a senior secured basis by the Borrowers and the Borrowers’ subsidiaries that own or charterWe have pledged the West Capella, West Aquarius, West Sirius, West Leo, West Capricorn and West Auriga.as collateral vessels under the TLB. The Amended Senior Secured Credit Facilities also are secured by mortgages on the six drilling units, security interests on the earnings, earnings accounts, and insurances owned by the subsidiary guarantors relating to the six drilling units, and pledges of the equity interests of each subsidiary guarantor. As at December 31, 2015, the total net book value of thethese drilling units at December 31, 2017 was $3.7 billion. We have also pledged substantially all the assets of our subsidiaries, which own or charter the collateral vessels as security was $3.8 billion.
Loans underwell as our investments in those companies. As set out below, we have agreed to add the Amended Senior Secured Credit Facilities will bear interest, atWest Vencedor to the Company's option, at a rate per annum equalTLB collateral vessels as part of an amendment to either the LIBOR Rate (subject to a 1% floor) for interest periods of one, two, three or six months plus the applicable margin or the Base Rate plus the applicable margin. The Base Rate is the highest of (a) the prime rate of interest announced from time to time by the agent bank as its prime lending rate, (b) 0.50% per annum above the Federal Funds rate as in effect from time to time, (c) the Eurodollar Rate for 1-month LIBOR as in effect from time to time plus 1.0% per annum, and (d) for term loans only, 2.0% per annum. The applicable margin is 2.00% for term loans

bearing interest at the Base Rate and 3.00% for term loans bearing interest at the Eurodollar Rate. The applicable margin is 1.25% for revolving loans bearing interest at the Base Rate and 2.25% for revolving loans bearing interest at the Eurodollar Rate. In addition, the Company will incur a commitment fee based on the unused portion of the revolving facility of 0.5% per annum.
The term loan maturesTLB agreed in February 2021. Amortization payments in the amount of 0.25% of the original term loan amount are required to2018.
We may be paid on the last day of each calendar quarter. The revolving facility matures in February 2019 and does not amortize. The Company is required to make mandatory prepayments of the term loans usingloan if we generate proceeds from asset sales that are not otherwise utilized for permitted purposes andor loss events. As set out below, we have also agreed to make offers to purchase term loans using proceeds of loss events that are not otherwise utilized for permitted purposes.
The Company has entered into interest rate swap transactions to fix 100% of the variable elementa partial prepayment of the term loan facility atif there is a weighted average fixed ratesuccessful outcome from our ongoing litigation with Tullow for the West Leo contract in Ghana. Please see Note 15 – "Commitments and contingencies" for further details on this litigation.

The TLB includes certain covenants and other provisions that can cause amounts borrowed to become immediately due and payable. This included a covenant over the ratio of 2.49% per annum. A variable rate option included inTLB debt to the swap provides thatEBITDA of the counterparty shall payTLB collateral vessels. Based on our results for the greater of 1.00% or 3 Month LIBOR. Thus, where the variable rate is less than 1%, the variable rate payment shall be equal to 1%.
During the year endedyear-ended December 31, 2015,2017 this ratio would have been above the Company drew down $50.0 millionlevel 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 $100.0 million revolving credit facilityTLB in February 2018. Under this amendment our lenders agreed to financewaive the leverage covenant until maturity. In return the TLB lenders receive a portion of the Polaris Acquisition. Refer to Note 3 – Business acquisitions for more information.
As of December 31, 2015, the outstanding balance of3% increase in margin on the term loan was $2,894.7 million and $50.0 milliona prepayment contingent on the successful outcome of our ongoing litigation with Tullow on the West Leo. We will also be required to repay the West Vencedor facility and make the West Vencedor a collateral vessel under the TLB. The amendment also adds certain other restrictions on our ability to transfer cash outside of the $100 million revolvingTLB collateral group.
Full details of covenants, terms of default and restrictions may be found in the TLB loan agreements and subsequent amendments which have all been filed as exhibits to this 20-F report. Please refer to Item 19- "Exhibits".
West Vela facility remains undrawn.

$(previously the "$1,450 million Senior Secured Credit FacilityFacility")
In March 20, 2013 Seadrill entered into a $1,450 million senior secured credit facility with a syndicate of banks and export credit agencies, relating to theThe West AurigaVela, 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 and one other drilling unit owned by Seadrill. Upon closing of the West Auriga acquisition in March 2014, the entity which owns the West Auriga owed $443 million under the facility. This amount was repaid in June 2014 with proceeds from the Amended Senior Secured Credit Facilities discussed above. Upon closing of the West Vela acquisitionSeadrill in November 2014,2014. The loan is subject to amortization payments of $40.3 million per year. We made a prepayment of $46.7 million in August 2017 and agreed to further prepayments of $11.8 million in February 2018 and $11.9 million in August 2018. The residual $120.9 million is repayable in October 2020. We had $255.3 million outstanding on this loan at December 31, 2017.
We pay interest on the entity that ownsterm loan at LIBOR plus a margin of between 3.35% and 4%, inclusive of guarantee fees, depending on the tranche.
We have pledged the West Vela owed $433 million under the facility. The facility hasas a final maturity in 2025, with a commercial tranche due for renewal in 2018, and bears interest at a rate equal to LIBOR plus a margin in the range that varies from 1.2% to 3% depending on which of the four loan tranches to which it is applicable. As discussed in the section entitled “Restrictive Covenants and Events of Default” below, the 3% margin, which is applicable to two of the four loan tranches, may be further increased depending on the leverage ratio, by up to 7.5% per annum. The $307.4 portion of the loans that benefits from the guarantee provided by the Norwegian export credit agency also is subject to a guarantee fee of 1.5% plus, as discussed in the section entitled “Restrictive Covenants and Events of Default” below, up to an additional 7.5% per annum depending on the leverage ratio. If the balloon payment of $86 million on the commercial tranche does not get refinanced to the satisfaction of the remaining lenders after five years, the remaining tranches also become due after five years. Under the terms of the $1,450 million secured credit facility agreement, certain subsidiaries of Seadrill and the entity that owns the West Vela are jointly and severally liable for their own debt and obligations under the facility and the debt and obligations of other borrowers who are also party to such agreement.  These obligations are continuing and extend to amounts payable by any borrower under the facility. The total amount owed by all partiescollateral vessel under this facility as of December 31, 2015 is $775.6 million.facility. The Company has not recognized any amounts that are related to amounts owed under the facility by other borrowers.  Seadrill has provided an indemnity to the Company for any payments or obligations related to this facility that are not related to the West Vela. As at December 31, 2015, the total net book value of the West Vela was $679.5 million at December 31, 2017. We have also pledged as security was $734.8 million. The outstanding balance relating tosubstantially all the assets of our subsidiaries which own and operate the West Vela, as of December 31, 2015 was $382.6 million.well as our investments in those companies.

The West Vela facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable. Full details of covenants, terms of default and restrictions may be found in the West Vela facility agreements and subsequent amendments which have all been filed as exhibits to this 20-F report.
$420West Polaris facility (previously the $420 million West Polaris FacilityFacility)
On June 19, 2015, in connection with the completionThe West Polaris facility consists of the Polaris Acquisition, Seadrill Polaris Ltd. as borrower, entered into an amendment and restatement of the $420.0 milliona term loan facility (the “West Polaris Facility”). The West Polaris Facility is comprised of a $320.0 million term loan facility and a $100.0 millionlinked revolving credit facility. The 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 Facility matures on January 31, from Seadrill in June 2015. The loan is subject to amortization payments of $36 million per year. We made a prepayment of $37.4 million in August 2017 and agreed to further prepayments of $9.4 million in February 2018 and bearsAugust 2018. The residual $93.8 million is repayable in July 2020. We had $205.6 million outstanding on this facility at December 31, 2017.
We pay interest on the term loan and revolving credit facility at a rate of LIBOR plus 2.25%a margin of 3.25%. Commitment fees are payable quarterly in arrearsWe also pay a commitment fee of 1.3% on theany unused portion of the revolving credit facility at the rate of 0.9% per annum. The term loan of the West Polaris Facility is payable on a monthly basis in equal installments of $3.0 million and a final lump sum payment of $143.0 million upon maturity. Upon closing of the Polaris Acquisition, Seadrill Polaris owed $336.0 million under the West Polaris Facility. Refer to Note 3 - Business Acquisitions. The outstanding balance under the West Polaris Facility as of December 31, 2015 was $315.0 million.

facility.
Seadrill and the Company are guarantors of the West Polaris Facility. Security for the West Polaris Facility consists of a first priority perfected pledge by Seadrill Operating of all of its equity interests in Seadrill Polaris, a first priority ship mortgage by Seadrill Polaris overWe have pledged the West Polaris, and first priority perfected security interests granted by Seadrill Polaris in its earnings, earnings accounts and insurances. as a collateral vessel under this facility. The net book value of the West Polarispledged as security as was $523.4 million at December 31, 2015 is $571.3 million.2017. We have also pledged substantially all the assets of our subsidiaries which own and operate the West Polaris, as well as our investments in those companies.

The West Polaris facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable. Full details of covenants, terms of default and restrictions may be found in the West Polaris facility agreements and subsequent amendments which have all been filed as exhibits to this 20-F report.
$440Tender rig facility (previously the $440 million Rig Financing Loan AgreementsAgreement)

Seadrill financed the constructionThe Tender Rig facility consists of the drilling units in the Company’s fleet with borrowingstwo term loans. We initially borrowed $100.5 million and $93.1 million under third party credit facilities. In connection with the Company's IPO and certain subsequent acquisitionsintercompany loans from Seadrill Seadrill amended and restated the various third party credit facilities, or Rig Financing Agreements, to allow for the transfer of the respective drilling units to OPCO and to provide for OPCO and its subsidiaries that, directly or indirectly, own the drilling units to guarantee the obligations under the facilities. In connection therewith, such subsidiaries entered into intercompany loan agreements with Seadrill corresponding to the aggregate principal amount outstanding under the third party credit facilities allocable to the applicable drilling units. During the twelve months ended December 31, 2014, certain Rig Financing Agreements

were repaid with the proceeds of the Senior Secured Credit Facilities.   As of December 31, 2015 and 2014, the only remaining Rig Financing Agreement related towhen we acquired the T-15 and T-16 (the” $440 million Rig Financing Agreement”).
In December 2012,in May 2013 and October 2013 respectively. These intercompany loans were back to back with an external debt facility Seadrill entered into a $440 million secured term loan facility with a syndicate of banks in parthad used to fundfinance the acquisitionconstruction of the T-15 and T-16. In August 2017, we amended the terms of these loans so that we held the facility directly with the external lender.
We are required to make amortization payments of $19.8 million per year against this facility. We made a prepayment of $15.8 million in August 2017 when we amended the facility and agreed to further prepayments of $3.8 million in February 2018 and $3.7 million in August 2018. The $440residual $31.2 million Rig Financing Agreement is secured byrepayable in June 2020. We had $83.3 million outstanding on this loan at December 31, 2017.
We pay interest on these loans at LIBOR plus a margin of 4.25%.
We have pledged the T-15 and T-16 and one other rig owned by Seadrill. In May 2013, Seadrill entered into an amendment to the $440 million Rig Financing Agreement to allow for the transferas collateral vessels under this facility. The net book value of the T-15 to Seadrill Partners Operating LLC and to add Seadrill Partners Operating LLC as a guarantor underT-16 was $234.6 million at December 31, 2017. We have also pledged substantially all the $440 million Rig Financing Agreement.  In October 2013, Seadrill entered into an amendment to the $440 million Rig Financing Agreement to allow for the transferassets of the T-16 to Seadrill Partners Operating LLC. Effective from the respective dates of transfer of the T-15our subsidiaries which own and the T-16 from Seadrill to Seadrill Partners Operating LLC, the entities that ownoperate the T-15 and T-16 entered into intercompany loan agreements with Seadrill, as well as our investments in those companies.
The Tender Rig facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable. Full details of covenants, terms of default and restrictions may be found in the amount of approximately $100.5 million and 93.1 million, respectively. Pursuant to the intercompany loan agreements, the entities which own the T-15 and T-16 make payments of principal and interest directly to the lenders under the $440 millionTender Rig Financing Agreement, at Seadrill’s direction and on its behalf.  Such payments correspond to payments of principal and interest due under the $440 million Rig Financing Agreement that are allocable to the T-15 and the T-16.  The $440 million Rig Financing Agreement matures in December 2017.
During the twelve months ended December 31, 2014, certain Rig Financing Agreements were repaid by the Company in conjunction with the drawdown of the Senior Secured Credit Facilities as further discussed above. As at December 31, 2015 and 2014, the $440 million Rig Financing Agreements with Seadrill related to the T-15, and T-16 (the “Rig Financing Agreement”).
Under the terms of the external secured credit facility agreements for the T-15and T-16, certain subsidiaries of Seadrill and the Company are jointly and severally liable for their own debt and obligations under the relevant facility and the debt and obligations of other borrowers who are also partysubsequent amendments which have all been filed as exhibits to the $440 million Rig Financing Agreements. These obligations are continuing and extend to amounts payable by any borrower under the relevant agreement. The total amount owed the $440 million Rig Financing Agreement as at December 31, 2015 is $224.3 million ($258.4 million as of December 31, 2014); the Company retains a related party balance as of December 31, 2015 of $139.0 million payable to Seadrill ($158.8 million as of December 31, 2014). The Company has not recognized any amounts that are related to amounts owed by Seadrill subsidiaries. Additionally the Company has received an indemnity from Seadrill for any payments or obligations related to these facilities that are not related to the T-15 and T-16. As at December 31, 2015 the total net book value of the T-15 and T-16 pledged as security was $251.5 million.this 20-F report.

West Vencedor Loan Agreement
The senior secured credit facility relating to the West Vencedor was repaid in full by Seadrill in June 2014, and subsequently the related party agreement between the Company's subsidiary, Seadrill Vencedor Ltd., and Seadrill was amended to carry on this facility on the same terms, referred to as the West Vencedor Loan Agreement. The West Vencedor Loan Agreement facility consists of a term loan due to Seadrill. The outstanding balance of the loan at December 31, 2017 was scheduled$24.7 million. The remaining amounts borrowed on the facility are to maturebe repaid in June 2015 and all outstanding amounts thereunder would be due and payable, including2018. We pay interest on the facility at LIBOR plus a balloon paymentmargin of $69.9 million. On April 14, 20152.3%.
We have pledged the Loan Agreement was amended and the maturity date was extended to June 25, 2018. The West VencedorLoan Agreement bears as a margincollateral vessel under this facility. As set out above, we agreed to repay this facility and make the West Vencedor a collateral vessel under the TLB as part of 2.25%, a guarantee feeas part of 1.4% and a balloon payment of $20.6 million due at maturityan amendment to the TLB agreed in JuneFebruary 2018. As at December 31, 2015 the totalThe net book value of the West Vencedor pledged as security was $178.4 million. $162.5 million at December 31, 2017.
Debt repayments by year
The outstanding balance under the West Vencedor Loan Agreement due to Seadrill was $57.5 milliondebt as of December 31, 2015 ($78.2 million2017 is repayable as follows: 
(In US$ millions)As of December 31, 2017
2018$199.8
2019175.1
2020331.1
20212,699.8
2022—
2023 and thereafter—
Total external and related party debt$3,405.8
Presentation in Consolidated Balance Sheet
We present external debt net of December 31, 2014).

$109.5 million Vendor Financing Loan Agreement
In May 2013, a subsidiary ofdebt issuance costs. The below tables show how the Company, Seadrill Partners Operating LLC, borrowed from Seadrill $109.5 million as vendor financing to fund the acquisition of the T-15. The facility bears interest of LIBOR plus a margin of 5.0% and is due in May 2016.

Sponsor Revolving Credit Facility
In October 2012, in connection with the closing of the Company's IPO, the Company entered into a $300 million revolving credit facility with Seadrill. The facility is for a term of 5 years and bears interest at a rate of LIBOR plus 5.0% per annum, with an annual 2% commitment fee on the undrawn balance. On March 1, 2014, the revolving credit facility was reduced to $100 million. There were no amounts owed under the facility as of December 31, 2015 and (nil as of December 31, 2014).


Restrictive Covenants
The Company's facilities and related party loan agreements include financial and non-financial covenants applicable to the Company and Seadrill. Financing agreements entered into during the year ended December 31, 2015 and December 31, 2014above balances are discussed further below. The Company and Seadrill were in compliance with the related covenants as of December 31, 2015.
In addition to the collateral provided to lenderspresented in the form of pledged assets, the Company's and Seadrill’s credit facility agreements generally contain financial covenants, the primary covenants being as follows:Consolidated Balance Sheet:
  Outstanding debt as of December 31, 2017
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $175.1
$(12.2)$162.9
Long-term external debt 3,206.0
(25.8)3,180.2
Total external debt $3,381.1
$(38.0)$3,343.1
Current portion of long term related party debt $24.7
$—
$24.7
Total interest bearing debt $3,405.8
$(38.0)$3,367.8
  Outstanding debt as of December 31, 2016
(In $ millions) Principal outstanding
Debt Issuance Costs
Total Debt
Current portion of long-term external debt $105.3
$(11.5)$93.8
Long-term external debt 3,381.8
(35.3)3,346.5
Total external debt $3,487.1
$(46.8)$3,440.3
Current portion of long term related party debt $135.6
$—
$135.6
Long term related party debt $24.7
$—
$24.7
Total interest bearing debt $3,647.4
$(46.8)$3,600.6

The Amended Senior Secured Credit Facilities
Our subsidiaries that are borrowers or guarantors of the Amended Senior Secured Credit Facilities are subject to certain financial and restrictive covenants contained in our Amended Senior Secured Credit Facilities including the following:
Limitations on the incurrence of indebtedness and issuance of preferred equity;
Limitations on the incurrence of liens;
Limitations on dividends and other restricted payments;
Limitations on investments;
Limitations on mergers, consolidation and sales of all or substantially all assets;
Limitations on asset sales;
Limitations on transactions with affiliates;
Limitation on business activities to businesses similar to those now being conducted; and
Requirement to maintain a senior secured net leverage ratio of no more than 5.5 to 1.0 (5.0 to 1.0 for the fiscal quarter ending March 31, 2015 and thereafter).

In addition, the Amended Senior Secured Credit Facilities contain other customary terms, including the following events of default (subject to customary grace periods), upon the occurrence of which, the loans may be declared (or in some cases automatically become) immediately due and payable:
Failure of any borrow of the term loan to pay principal, interest or other amounts owing with respect to the loans under the Amended Senior Secured Credit Facilities;
Breach in any material respect of any representation or warranty contained in Amended Senior Secured Credit Facilities documentation;
Breach of any covenant contained in Amended Senior Secured Credit Facilities documentation;
The occurrence of a payment default under, or acceleration of, any indebtedness aggregating $25 million or more other than the term loan;
Failure by our subsidiaries that are borrowers or guarantors of our Amended Senior Secured Credit Facilities to pay or stay any judgment in excess of $25 million;
Repudiation by our subsidiaries that are borrowers or guarantors of our Amended Senior Secured Credit Facilities of any guarantee or collateral documents related to the Amended Senior Secured Credit Facilities;
Any guarantee related to the Amended Senior Secured Credit Facilities is found to be unenforceable or invalid or is not otherwise effective;
Any of our subsidiaries that are borrowers or guarantors of our Amended Senior Secured Credit Facilities file for bankruptcy or become the subject of an involuntary bankruptcy case or other similar proceeding;
The equity interests of any of the company, Seadrill Operating LP or Seadrill Capricorn Holdings LLC is pledged to anyone other than the collateral agent for the term loan; and
The occurrence of a change of control.

As of December 31, 2015, the Company was in compliance with all covenants under the Amended Senior Secured Credit Facilities.

$440 million Rig Financing Agreements
The $440 million Rig Financing Agreements contain various customary covenants that may limit, among other things, the ability of the borrower to:
sell the applicable drilling unit;
incur additional indebtedness or guarantee other indebtedness;
make investments or acquisitions;
pay dividends or make any other distributions if an event of default occurs; or
enter into inter-company charter arrangements for the drilling units not contemplated by the applicable Rig Facility.

The $440 million Rig Financing Agreements also contains financial covenants requiring Seadrill to:
Aggregated minimum liquidity requirement for Seadrill's consolidated group: to maintain cash and cash equivalents of at least $150 million within the group.
Interest coverage ratio: to maintain an EBITDA to interest expense ratio of at least 2.5:1.
Current ratio: to maintain current assets to current liabilities ratio of at least 1:1. Current assets are defined as book value less minimum liquidity, but including up to 20.0% of shares in listed companies owned 20.0% or more. Current liabilities are defined as book value less the current portion of long term debt.
Equity to asset ratio: to maintain total equity to total assets ratio of at least 30.0%. Both equity and total assets are adjusted for the difference between book and market values of drilling units.
Leverage ratio: to maintain a ratio of net debt to EBITDA no greater than 4.5:1, up to the effective date of the amended covenants discussed further below. Net debt is calculated as all interest bearing debt less cash and cash equivalents excluding minimum liquidity requirements.

In May 2015, Seadrill Limited executed an amendment to the covenants contained in the $1,450 million facility and the $440 million Rig Financing Agreement. Under the amended terms, the permitted leverage ratio has been amended to the following:

6.0:1, from and including the financial quarter starting on July 1, 2015 and including the financial quarter ending on September 30, 2016;
5.5:1, from and including the financial quarter starting on October 1, 2016 and including the financial quarter ending December 31, 2016;
4.5:1, from and including the financial quarter starting on January 1, 2017 until the final maturity date.

In connection with the amendment, effective from July 1, 2015, an additional margin may be payable on the above mentioned facilities as follows:
.125 percent per annum if the leverage ratio is 4.50:1 up to and including 4.99:1;
.25 percent per annum if the leverage ratio is 5.00:1 up to and including 5.49:1;
.75 percent per annum if the leverage ratio is 5.50:1 up to and including 6.00:1

For the purposes of the above tests, EBITDA is defined as the earnings before interest, taxes, depreciation and amortization on a consolidated basis and (ii) the cash distributions from investments, each for the previous period of twelve months as such term is defined in accordance with accounting principles consistently applied. However, in the event that Seadrill or a member of the group acquires rigs or rig owning entities with historical EBITDA available for the rigs' previous ownership, such EBITDA shall be included for covenant purposes in the relevant loan agreement, and if necessary, be annualized to represent a twelve (12) month historical EBITDA. In the event that Seadrill or a member of the group acquires rigs or rig owning companies without historical EBITDA available, Seadrill is entitled to base a twelve month historical EBITDA calculation on future projected EBITDA only subject to any such new rig having (i) a firm charter contract in place at the time of delivery of the rig, with a minimum duration of twelve months, and (ii) a firm charter contract in place at the time of such EBITDA calculation, provided Seadrill provides the agent bank with a detailed calculation of future projected EBITDA. Further, EBITDA shall include any realized gains and/or losses in respect of the disposal of rigs or the disposal of shares in rig owning companies.
Cash distributions from investments are defined as cash received by Seadrill, by way of dividends, in respect of its ownership interests in companies which Seadrill does not control but over which it exerts significant influence.

In addition to financial covenants, our credit facility agreements generally contain covenants which are customary in secured financing in this industry, including operational covenants in relation to the relevant rigs, information undertakings and covenants in relation to corporate existence and conduct of our business.
The $440 million Rig Financing Agreements also identify various events that may trigger mandatory reduction, prepayment, and cancellation of the facility including, among others, the following:
total loss or sale of a drilling unit securing a Rig Financing Agreements;
cancellation or termination of any existing charter contract or satisfactory drilling contract; and
a change of control.

The $440 million Rig Financing Agreements contain customary events of default, such as failure to repay principal and interest, and other events of defaults, such as:
failure to comply with the financial or insurance covenants;
cross-default to other indebtedness held by both Seadrill and its subsidiaries and by the Company;
failure by Seadrill or by the Company to remain listed on a stock exchange;
the occurrence of a material adverse change;

revocation, termination, or modification of any authorization, license, consent, permission, or approval as necessary to conduct operations as contemplated by the applicable Rig Financing Agreement ; and
the destruction, abandonment, seizure, appropriation or forfeiture of property of the guarantors or Seadrill and its subsidiaries, or the limitation by seizure, expropriation, nationalization, intervention, restriction or other action by or on behalf of any governmental, regulatory or other authority, of the authority or ability of Seadrill or any subsidiary thereof to conduct its business, which has or reasonably may be expected to have a material adverse effect.

Our $440 million Rig Financing Agreement is secured by:
guarantees from rig owning subsidiaries (guarantors),
a first priority share pledge over all the shares issued by each of the guarantors,
a first priority perfected mortgage in all collateral rigs and any deed of covenant thereto, subject to contractual agreed "quiet enjoyment" undertakings with the end-user of the collateral rigs to be entered into if this is required by the relevant end-user pursuant to the relevant contract,
a first priority security interest over each of the rig owners' with respect to all earnings and proceeds of insurance, and
a first priority security interest in the earnings accounts.

Our $440 million Rig Financing Agreements also contain, as applicable, loan-to-value clauses, which could require the Company, at its option, to post additional collateral or prepay a portion of the outstanding borrowings should the value of the drilling units securing borrowings under each of such agreements decrease below required levels. The market value of the rigs must be at least 135% of the loan outstanding.

If an event of default exists under any of the $440 million Rig Financing Agreements, the lenders have the ability to accelerate the maturity of the applicable $440 million Rig Financing Agreements and exercise other rights and remedies. In addition, if Seadrill were to default under one of its other financing agreements, it could cause an event of default under each of the Rig Financing Agreements. Further, because the Company's drilling units are pledged as security for Seadrill’s obligations under the Rig Financing Agreements , lenders thereunder could foreclose on the company’s drilling units in the event of a default thereunder. Seadrill’s failure to comply with covenants and other provisions in its existing or future financing agreements could result in cross-defaults under the Company’s existing financing agreements, which would have a material adverse effect on us.

As of December 31, 2015, the Company was in compliance with the covenants under the $440 million Rig Financing Agreement and Seadrill was in compliance with the covenants with the back-to-back credit facilities related to each of the rigs covered by the $440 million Rig Financing Agreement.

$1,450 million Senior Secured Credit Facility
The above facility contains materially the same covenants as those set out for the Rig Financing Agreements above. In addition to the financial covenants relating to Seadrill Limited, each of the borrowers are required to ensure that the combined Debt Service Cover ratio shall not be less than 1.15:1.
In addition, the combined market values of the West Vela and West Tellus must have a minimum market value of at least 125% of the outstanding loans at any time, rising to 140% from March 31, 2016. If it does not, the Company must prepay a portion of the outstanding borrowings or provide additional collateral to correct the shortfall.
If Seadrill were to default under the facility, or to default under one of its other financing agreements, it could cause an event of default under the facility. Further, because the West Vela is pledged as security under the facility, lenders thereunder could foreclose on the West Vela in the event of a default thereunder. Seadrill’s failure to comply with covenants and other provisions in its existing or future financing agreements could result in cross-defaults under the Company’s existing financing agreements.
Seadrill and the Company were in compliance with the covenants under the facility as of December 31, 2015.

$420 million West Polaris Facility
The West Polaris Facility contains materially the same covenants as the $440 million Rig Financing Agreement described above. If Seadrill were to breach its financial covenants, or to default under one of its other financing agreements, it could cause an event of default under the facility. Further, because the West Polaris is pledged as security under the facility, lenders thereunder could foreclose on the West Polaris in the event of a default thereunder. Seadrill’s failure to comply with covenants and other provisions in its existing or future financing agreements could result in cross-defaults under the Company’s existing financing agreements. In addition, the West Polaris must have a minimum market value of at least 125% of the outstanding loans at any time. If it does not, Seadrill Polaris must prepay a portion of the outstanding borrowings or provide additional collateral to correct the shortfall.
Seadrill and the Company were in compliance with the covenants under the facility as of December 31, 2015.


April 2016 Amendments to Senior Secured Credit Facilities
On April 28, 2016, Seadrill executed amendment and waiver agreements in respect of all of its senior secured credit facilities. The key terms and conditions of these agreements that affect the Company's $1,450 million Senior Secured Credit Facility, $440 million Rig Financing Agreement and the West Polaris Facility are as follows:

Key amendments and waivers:
◦
Equity ratio: Seadrill is required to maintain a total equity to total assets ratio of at least 30.0%. Prior to the amendment, both total equity and total assets were adjusted for the difference between book and market values of drilling units, as determined by independent broker valuations. The amendment removes the need for the market value adjustment from the calculation of the equity ratio until June 30, 2017.
Leverage ratio: Seadrill is required to maintain a ratio of net debt to EBITDA. Prior to the amendment the leverage ratio had to be no greater than 6.0:1, falling to 5.5:1 from October 1, 2016, and falling again to 4.5:1 from January 1, 2017. The amendment retains the ratio at 6.0:1 until December 31, 2016, and then increases to 6.5:1 between January 1, 2017 and June 30, 2017.
Minimum-value-clauses: Seadrill’s secured bank credit facilities contain loan-to-value clauses, or minimum-value-clauses (“MVC”), which could require Seadrill to post additional collateral or prepay a portion of the outstanding borrowings should the value of the drilling units securing borrowings under each of such agreements decrease below required levels. Subject to compliance with the terms of the amendment, this covenant has been suspended until June 30, 2017.
Minimum Liquidity: Seadrill has previously been required to maintain a minimum of $150 million of liquidity. This has been reset to $250 million until June 30, 2017.

Additional undertakings:
◦
Further process: Seadrill has agreed to consultation, information provision and certain processes in respect of further discussions with its lenders under its senior secured credit facilities, including agreements in respect of progress milestones towards the agreement of, and implementation plan in respect of, a comprehensive financing package.
◦
Restrictive undertakings: Seadrill has agreed to additional near-term restrictive undertakings applicable during this process, applicable to Seadrill and its subsidiaries, including (without limitation) limitations in respect of:
▪incurrence and maintenance of certain indebtedness
▪dividends, share capital repurchases and total return swaps;
▪investments in, extensions of credit to or the provision of financial support for non-wholly owned subsidiaries;
▪investments in, extensions of credit to or the provision of financial support for joint ventures or associated entities;
▪acquisitions;
▪dispositions;
▪prepayment, repayment or repurchase of any debt obligations;
▪granting security; and
▪payments in respect of newbuild drilling units,
in each case, subject to limited exceptions.

Other changes and provisions:
◦
Undrawn availability: Seadrill has agreed it will not borrow any undrawn commitments under its senior secured credit facilities unless the coordinating committee of lenders has been provided 15 days notice of such borrowing.
◦
Fees: Seadrill has agreed to pay certain fees to its lenders in consideration of these extensions and amendments.

Revolving credit facility
The revolving credit facility contains covenants that require us to, among other things:
notify Seadrill of the occurrence of any default or event of default; and
provide Seadrill with information in respect of its business and financial status as Seadrill may reasonably require, including, but not limited to, copies of the Company's unaudited quarterly financial statements and its audited annual financial statements.

Events of default under the revolving credit facility include, among others, the following:
failure to pay any sum payable under the revolving credit facility when due;
breach of certain covenants and obligations of the revolving credit facility;
a material inaccuracy of any representation or warranty;
default under other indebtedness in excess of $25.0 million;
bankruptcy or insolvency events; and

commencement of proceedings seeking issuance of a warrant of attachment, execution, distraint or similar process against all or any substantial part of the Company’s assets that results in an entry of an order for any such relief that is not vacated, discharged, stayed or bonded pending appeal within sixty days of the entry thereof.

As of December 31, 2015, the Company was in compliance with all covenants under the revolving credit facility.

Note 12 – Other current liabilities
Other current liabilities are comprised of the following:
 
(In US$ millions)December 31, 2015
 December 31, 2014
December 31, 2017
 December 31, 2016
Uncertain tax position$51.7
 $41.9
Taxes payable28.4
 12.1
36.5
 47.7
Accrued expenses35.4
 29.3
Unrealized loss on derivative financial instruments29.0
 55.2
Deferred mobilization/demobilization revenues9.4
 19.6
Employee and business withheld taxes, social security and vacation payment15.4
 19.5
8.7
 12.3
VAT payable4.0
 6.1
6.5
 10.9
Deferred mobilization/demobilization revenues short-term18.0
 15.9
Unrealized loss on derivatives84.2
 56.1
Accrued expenses and other current liabilities67.9
 117.7
Total other current liabilities217.9
 227.4
Other liabilities0.4
 1.2
Total other liabilities$177.6
 $218.1

Other liabilities are classified in our Consolidated Balance sheet as follows:
(In US$ millions)December 31,
2017		 December 31,
2016
Other current liabilities121.8
 168.9
Other non-current liabilities55.8
 49.2
Total other liabilities$177.6
 $218.1

Note 13 – Related party transactions
The Company has entered into certain agreementsbelow table provides a summary of revenues and expenses for transactions with affiliates of Seadrill to provide certain management and administrative services, as well as technical and commercial management services. Seadrill has also provided financing arrangements as described within this note below. The total amounts charged to the Company for the years ended December 31, 2015, 20142017, 2016 and 2013 were $161.8 million, $158.1 million and $122.5 million respectively.

Net expenses (income) with Seadrill: 2015.
(In US$ millions) 2015 2014 2013
Management and administrative fees (a) and (b) 75.3
 58.6
 47.1
Rig operating costs (c) 29.3
 22.4
 16.5
Insurance premiums (d) 20.2
 21.8
 21.8
Interest expense (e) 13.7
 87.7
 87.7
Commitment fee (f) 2.0
 2.2
 4.5
Derivative (gains) / losses (o) 10.2
 41.6
 (49.9)
Bareboat charters (h) (1.6) (25.8) (4.9)
Other revenues - operating expenses recharged to Seadrill (i) (13.4) —
 (5.8)
Operating expenses related to operations recharged to Seadrill (i) 12.8
 —
 5.5
Accretion of discount on deferred consideration (j) 13.3
 —
 —
Total 161.8
 158.1
 122.5
(In US$ millions) Year ended December 31,
  2017 2016 2015
Related party operating expenses      
Management and technical support fees (a) and (b) $74.5
 $62.8
 $75.3
Rig operating costs (c) 22.9
 24.9
 29.3
Insurance premiums (d) 10.5
 16.0
 20.2
Bareboat charters (e) 2.8
 9.5
 (1.6)
Related party inventory purchases (f) 1.0
 2.0
 —
  111.7
 115.2
 123.2
Related party financing expenses      
Related party interest expense (g) 4.7
 10.1
 13.7
Losses on related party derivatives (h) 1.3
 4.1
 10.2
Related party commitment fee (i) 1.3
 2.0
 2.0
  7.3
 16.2
 25.9
Less: related party revenues      
Operation support fees (j) (4.9) (10.9) (13.4)
Related party inventory sales (f) (2.2) (1.4) —
  (7.1) (12.3) (13.4)
       
Total $111.9
 $119.1
 $135.7
(a) Management and administrative services agreement – Seadrill provides us with services covering functions including general management, information systems, accounting & finance, human resources, legal and commercial. We are charged for these services on a cost plus mark-up basis. During the year ended December 31, 2017, the mark-up we were charged for these services ranged from 4.85% to 8%. The agreement has an indefinite term but we can terminate it for convenience by providing 90 days written notice.


(b) Operations and technical supervision agreements – Seadrill provides us with operations support and technical supervision services. The functions covered by these services include logistics, supply chain, warehousing, technical services and QHSE. We also have access to a pool of shared capital equipment maintained by Seadrill. We are charged for these services on a cost plus mark-up basis. During the year ended December 31, 2017, the mark-up we were charged for these services was approximately 5%.
Receivables (payables) with Seadrill:
(In US$ millions) December 31, 2015
 December 31, 2014
Trading balances due from Seadrill and subsidiaries (k) 175.9
 56.7
Trading balances due to Seadrill and subsidiaries (k) (354.7) (250.0)
Revolving credit facility with Seadrill (f) —
 —
$440 Million Rig Financing Agreement with Seadrill (T-15 and T-16) (g) (139.0) (158.8)
West Vencedor Loan Agreement with Seadrill (West Vencedor) (g) (57.5) (78.2)
Vendor financing loan agreement with Seadrill (l) (109.5) (109.5)
Discount notes with Seadrill (m) —
 —
Deferred and contingent consideration to related party - short term portion (j) (60.4) (25.8)
Deferred and contingent consideration to related party - long term portion (j) (185.4) (111.2)
Derivatives with Seadrill - interest rate swaps (n) 2.2
 6.0
(a)
Management and administrative services agreements – In connection with the IPO, OPCO entered into a management and administrative services agreement with(c) Rig operating costs – Seadrill provided onshore support and crew for the West Polaris during its operations in Angola, which ended in July 2017. We were charged for these services on a cost plus mark-up basis. The mark-up we were charged was approximately 5%. During the year ended December 31, 2016 we also received similar services from Seadrill Management a wholly owned subsidiary of Seadrill, pursuant to which Seadrill Management provides the Company certain management and administrative services. The services provided by Seadrill Management are charged at cost plus management fee equal to 5% of Seadrill Management’s costs and expenses incurred in connection with providing these services. The agreement has an initial term for 5 years and can be terminated by providing 90 days written notice.

(b)
Technical and administrative service agreement – In connection with the IPO, OPCO entered into certain advisory, technical and/or administrative services agreements with subsidiaries of Seadrill. The services provided by Seadrill’s subsidiaries are charged at cost plus service fee equal to approximately 5% of Seadrill’s costs and expenses incurred in connection with providing these services.

(c)
Rig operating costs – relates to rig operating costs recharged by Seadrill in relation to costs incurred on behalf of the West Polaris and the West Vencedor operating in Angola. These costs are recharged by Seadrill at a markup of 5%.

(d)
Insurance premiums – the Company’s drilling units are insured by a Seadrill company and the insurance premiums incurred are recharged to the Company.

(e)
Interest expense – consists of interest expense incurred on the $440 Million Rig Financing Agreement, West Vencedor Loan Agreement, discount notes and the $109.5 million T-15 Vendor Financing Loan. Prior to entering these agreements, these costs were allocated to the Company from Seadrill based on the Company’s debt as a percentage of Seadrill’s overall debt. Upon entering these agreements, the costs and expenses have been incurred by the Company.

(f)
$100 million revolving credit facility – In October 2012 the Company entered into a $300 million revolving credit facility with Seadrill. The facility is for a term of five years and bears interest at a rate of LIBOR plus 5% per annum, with an annual 2% commitment fee on the undrawn balance. On March 1, 2014, the revolving credit facility was amended to reduce the maximum borrowing limit from $300 million to $100 million. During 2015 the Company drew down nothing from the revolving credit facility and repaid nothing. As at December 31, 2015 and 2014, the outstanding balance was nil and nil, respectively.

(g)
Rig Financing Agreements and Loan Agreements – See Note 11 - Debt for details of the $440 Million Rig Financing Agreement and West Vencedor Loan Agreement. Under the agreements each rig owning subsidiary makes payments of principal and interest directly to the lenders under each Rig Financing Agreement, at Seadrill’s direction and on its behalf, corresponding to payments of principal and interest due under each Rig Financing Agreement that are allocable to each rig.
The West Vencedor Loan Agreement relates to the financing of the West Vencedor, which was previously classified as a Rig Financing Agreement until June 2014 when Seadrill repaid the underlying senior secured loan, and the related party loan agreement between the Company and Seadrill was amended to carry on this facility on the same terms. Please refer to Note 11 - Debt for further information..

(h)
Bareboat charters – In connection with the transfer of the West Aquarius operations to Canada, the West Aquarius drilling contract was assigned to Seadrill Canada Ltd.,(d) Insurance premiums – Our drilling units are insured by a wholly owned subsidiary of OPCO, necessitating certain changes to the related party contractual arrangements relating to the West Aquarius. Seadrill China Operations Ltd, the owner of the West Aquarius and a wholly-owned subsidiary

of OPCO, had previously entered into a bareboat charter arrangement with Seadrill Offshore AS, a wholly-owned subsidiary of Seadrill. We are recharged for insurance premiums that are arranged by Seadrill providingfor our rigs.
(e) Bareboat charters – Seadrill Offshore AS with the right to useacted as an intra-charterer for the West Aquarius. In October 2012, this bareboat charter arrangement was replaced during its contract with Hibernia in Canada, which ended in April 2017. Seadrill also previously acted as an intra-charterer for the T-15 and T-16 until December 2016. Seadrill earned a new bareboat charter between Seadrill China Operations Ltd and Seadrill Offshore AS, and at the same time, Seadrill Offshore AS entered into a bareboat charter arrangement providing Seadrill Canada Ltd. with the right to usemargin of $25,500 per day under the West Aquariusin order to perform its obligations arrangement and $1,590 per day under the drilling contract described above. The net effect to OPCO of these bareboat charter arrangements is a cost of $25,500 per day, but due to the downtime of the rig during 2015 the total effectT-15 and T-16 arrangement. This margin was income of $2.1 million.adjusted for utilization.
Seadrill T-15We incurred expenses for these arrangements of $2.8 million and Seadrill International are each party to a bareboat charter agreement with Seadrill UK Ltd., a wholly owned subsidiary of Seadrill. Under this arrangement, the difference$9.5 million in the charter hire rate betweenyears ended December 31, 2017 and 2016, respectively. We experienced high downtime on the two charters is retained by Seadrill UK Ltd.,West Aquarius in the amount of approximately $820 per day. Seadrill T-16 Ltd. and Seadrill International Ltd. are each party to a bareboat charter agreement with Seadrill UK Ltd. Under this arrangement, the difference in the charter hire rate between the two charters is retained by Seadrill UK Ltd., in the amount of approximately $770 per day. The net effect of the T-15 and T-16 bareboat charter agreements was an expense of $0.5 million.
For the year ended December 31, 2015 the net effect to OPCO of the above bareboat charters waswhich resulted in us earning net income of $1.6 million (2014: net incomeunder these arrangements that year.
(f) Related party inventory sales and purchases - Revenue and expenses from the sale and purchase of $25.8 million, 2013: net incomeinventories and spare parts from Seadrill.
(g) Related party interest expense – Interest charged by Seadrill on the Tender Rig facility, West Vencedor loan agreement and West Vela deferred consideration liability. Please read Note 11 – "Debt" for a description of $4.9 million).

(i)
Other revenues and expenses - The Company incurs certain operating costs on behalf of Seadrill drilling units and recharges them at a markup of 5%. During the year ended December 31, 2015 the Company earned $13.4 million in other revenues within our Nigerian service company from Seadrill for certain services, including the provision of onshore and offshore personnel, which the Company provided to Seadrill’s West Jupiter and West Saturn drilling rigs. Operating expenses relating to these related party revenues were $12.8 million in the year ended December 31, 2015.
During the year ended December 31, 2014loan facilities and note (n) below for a description of the Company earned no other revenues within the Company's Nigerian service company and related expenses were nil.deferred consideration balance.
During(h) Loss on related party derivatives - Losses on related party interest rate swaps previously held to mitigate interest rate exposures on the year ended December 31, 2013,West Vela facility, West Polaris facility and Tender Rig facility. See Note 14 – "Risk management and financial instruments" for a description of these interest rate swaps. These swaps were canceled in September 2017 when Seadrill filed for Chapter 11.
(i) Related party commitment fee - Seadrill previously provided us with a revolving credit facility of $100 million. We were charged an interest rate of LIBOR of 5% for any amounts drawn under the company earnedfacility and a commitment fee of 2% for any unused portion. The facility was canceled in August 2017 as part of the insulation transaction.
(j) Other revenues of $5.8 million, relating to certain- We provided onshore support services including the provision of onshore and offshore personnel whichfor two of Seadrill's drilling units, the Company provided to Seadrill’s West PolarisJupiter drillingand West Saturn, whilst the rigs operated in Nigeria. We charged Seadrill on a cost plus mark-up basis for these services. The mark-up charged was approximately 5%. This arrangement ended during 2017.
The below table provides a summary of amounts due to or from Seadrill at December 31, 2017 and December 31, 2016.
(In US$ millions) December 31, 2017
 December 31, 2016
Trading balances due from Seadrill and subsidiaries (k) $24.2
 $80.6
Trading balances due to Seadrill and subsidiaries (k) (157.0) (192.0)
Tender Rig Facility Seadrill (T-15 and T-16) (l) —
 (119.1)
West Vencedor Loan Agreement with Seadrill (l) (24.7) (41.2)
Derivatives with Seadrill - interest rate swaps (m) —
 2.4
Deferred and contingent consideration to related party - short term portion (n) (41.7) (45.6)
Deferred and contingent consideration to related party - long term portion (n) (46.0) (157.6)
Total (245.2) (472.5)
(k) Trading balances – Receivables and payables with Seadrill are comprised primarily of invoices for management fees, operation support fees, rig that was operating costs, insurance premiums, bareboat charters. We also include accrued interest on financing balances within this category. In addition, certain receivables and payables arise when we pay an invoice on behalf of Seadrill or vice versa.
Related party invoices are generally settled quarterly in Nigeria during that period. Related operating expenses relatedarrears. Trading balances with Seadrill are unsecured, interest free, and are intended to these operationsbe settled in the year ended December 31, 2013ordinary course of business.
(l) Tender Rig Facility and West Vencedor Loan Agreement – Please read Note 11 "Debt" for details of these loan facilities.
(m) Derivatives with Seadrill - Interest rate swaps - The interest rate swaps held with Seadrill were $5.5 million.canceled on September 12, 2017 when Seadrill entered Chapter 11.Refer to Note 14 "Risk management and financial instruments" for further information.

(j)
Deferred consideration to related party - On the acquisition of the West Polaris in 2015 the Company recognized a seller's credit balance payable of $44.6 million, a long term deferred consideration balance of $63.7 million and a short-term deferred consideration balance of$31.6 million.
On(n) Deferred consideration to related party - We have deferred and contingent consideration liabilities to Seadrill from the acquisition of the West Vela in 2014and West Polaris.

On the Company recognized a long term deferred consideration balanceWest Vela we are required to pay to Seadrill $42k per day over the life of $61.7 millionthe contract with BP which runs until November 2020 for mobilization of the rig and a long term contingent consideration balancefurther $40k per day, adjusted for utilization, over the remaining contract term.
On the West Polaris we agreed to pay Seadrill 100% of $49.5 million. The short-term portiondayrate earned above $450k per day for the remainder of the deferred consideration balancecontract with ExxonMobil and 50% of the short-term contingent consideration balance was $25.8 million.
Asdayrate 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 December 31, 20156.5% per year is accreted to the short-term portion of these balances relating tonote. 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 West Vela are $30.7 million and $29.7 million respectively. As of December 31, 2015amount that would have been earned if the long-term portion of the balances relating to the West Polaris and West Vela are $90.1 millionand $95.3 million respectively. As at December 31, 2014, the short term portions were $12.0 million and $13.8 million which relate to the West Vela.average dayrate earned had been $450k per day.
DuringIn the year ended December 31, 2015,2017, we recorded a gain of $89.9 million due to a reduction in the Company recognized an unwindfair value of these liabilities. Please read Note 7 - "Other operating income" for further detail.
The below table sets out the fair value of the discount of the contingent liabilities of $13.3 million.at December 31, 2017 and December 31, 2016.

(k)
Trading balances – Receivables and payables with Seadrill and its subsidiaries are comprised primarily of unpaid management fees, advisory and administrative services, as well as, accrued interest. In addition, certain receivables and payables arise when the Company pays an invoice on behalf of a related party and vice versa. Receivables and payables are generally settled quarterly in arrears. Trading balances to Seadrill and its subsidiaries are unsecured, generally bear interest at a rate equal to LIBOR plus approximately 4% per annum, and are intended to be settled in the ordinary course of business.

(l)
$109.5 million Vendor financing loan - On May 17, 2013, Seadrill Operating LP borrowed from Seadrill $109.5 million as vendor financing to fund the acquisition of the T-15. The loan bears interest at a rate of LIBOR plus a margin of 5% and matures in May 2016.


(m)Discount loan notes:
$229.9 million discount note - On December 13, 2013, as part of the acquisition of the West Sirius, Seadrill Capricorn Holdings issued a zero coupon discount note from Seadrill for $229.9 million. The note was repayable in June 2015 and upon maturity, the Company was due to pay $238.5 million to Seadrill. This note was repaid in full in February 2014 with proceeds from the Senior Secured Credit Facilities.
(In US$ millions) December 31, 2017
 December 31, 2016
West Vela    
Mobilization due to Seadrill 44.2
 56.1
Seadrill share of dayrate from BP contract 38.6
 49.0
  82.8
 105.1
West Polaris    
Seadrill share of dayrate from ExxonMobil contract ("Earnout 1") 4.2
 9.2
Seadrill share of dayrate from subsequent contracts ("Earnout 2") 0.7
 38.1
Seller's credit —
 50.8
  4.9
 98.1
     
Total 87.7
 203.2
$70.0 million discount note - On December 13, 2013,These liabilities are presented in our Consolidated Balance Sheet as part of the acquisition of the West Sirius, the Company issued a zero coupon discount note from Seadrill for $70.0 million. The note was repayable in June 2015 and upon maturity, the Company was due to pay $72.6 million to Seadrill.This note was repaid in full in February 2014 with proceeds from the Senior Secured Credit Facilities.follows:
$100.0 million discount note - On March 21, 2014, as part of the acquisition of the West Auriga, Seadrill Capricorn Holdings issued a zero coupon discount note to Seadrill in an initial amount of $100.0 million. The note was repayable in September 2015 and upon maturity, the Company was due to pay $103.7 million to Seadrill. This note was repaid in June 2014 with proceeds from the Senior Secured Credit Facilities.
(In US$ millions) December 31, 2017
 December 31, 2016
Current portion of deferred and contingent consideration to related party 41.7
 45.6
Non-current portion of deferred and contingent consideration to related party 46.0
 157.6
Total 87.7
 203.2

(o)
Derivatives with Seadrill - Interest rate swaps - As of December 31, 2015, the Company was party to interest rate swap agreements with Seadrill for a combined outstanding principal amount of approximately $655.3 million at rates between 1.10% per annum and 1.93% per annum. The swap agreements mature between July 2018 and December 2020. The net loss recognized on the Company’s interest rate swaps for the year ended December 31, 2015, was $10.2 million (year ended December 31, 2014: loss of $41.6 million). Refer to Note 14 for further information.

Other agreements and transactions with Seadrill

Equity Distribution
During the year-ended December 31, 2017, one of our subsidiaries settled certain balances related to a shareholder loan provided by Seadrill. On account of the loan's structure these payments have been treated as equity distributions.
A total balance of $15.3 million has been distributed to Seadrill, comprised of a $6.1 million cash distribution and a $9.2 million non-cash distribution that was offset against certain trading balances owed to us by Seadrill.
These transactions have been presented in the Consolidated Statement of Changes in Members Capital in the year ended December 31, 2017.
$143 million Loan Agreement
Effective as of December 17, 2015, anone of our operating subsidiary of the Companysubsidiaries borrowed $143.0 million from Seadrill (the “West"West Sirius loan”) from Seadrill in order to provide sufficient immediate liquidity to meet the terms of itsa bareboat charter termination payment in connection withfor the West Sirius contract termination. Concurrently, Seadrill borrowed $143.0 million (the “Seadrill"Seadrill loan”) from aone of our rig owning subsidiary of the Company in ordersubsidiaries to restore its liquidity with respect to the West Sirius loan.

Each loan bears an interest rate of one-month LIBOR plus 0.56% and matures in August 2017.liquidity. Each of the loan parties understandunderstood and agreeagreed that the loan agreements actacted in parallel with each other.
Each loan had an interest rate of LIBOR plus 0.56% and matured in August 2017. As ofat December 31, 2015, $143.0 million was2017, the loans had been fully repaid (December 31, 2016: outstanding under each such loan.

balance $39.4 million)
These transactions have beenwere classified within current and long-term portions of "Amount due from related party", "Related party payable" and "Long-term related"Related party payable".

Amendment to Contribution and Sale Agreement
On June 30, 2013, the Company and certain of its subsidiaries entered into an agreement with Seadrill and certain of its subsidiaries to amend the Contribution and Sale Agreement that was entered into with Seadrill at the time of the IPO . This amendment was made in order to convert certain related party payables to equity. Pursuant to that amendment, as of June 30, 2013, the Company's accounts and those of Seadrill were adjusted to reflect a net capital contribution in the amount of $20.0 million by Seadrill to Seadrill Operating LP and a net capital contribution in the amount of $20.5 million by Seadrill to Seadrill Capricorn Holdings LLC. No additional units were issued to Seadrill in connection with either of these contributions.

T-15 Acquisition
On May 17, 2013, pursuant to a Purchase and Sale Agreement, dated May 7, 2013, between Seadrill Limited and Seadrill Partners Operating LLC, Seadrill Partners Operating LLC acquired from Seadrill a 100% ownership interest in the entities that own and operate the tender rig T-15. This transaction was deemed to be a reorganization of entities under common control. As a result, the Company’s financial statements have been retroactively adjusted in accordance with US GAAP as if Seadrill Partners had acquired the entities that own and operate the T-15 for the entire period that the entities have been under the common control of Seadrill Limited. Refer to Note 3 for more information.

T-16 Acquisition
On October 18, 2013, pursuant to a Purchase and Sale Agreement, dated October 11, 2013, by and among Seadrill Limited, Seadrill Partners LLC and Seadrill Partners Operating LLC, acquired from Seadrill a 100% ownership interest in the entity that owns the tender rig T-16. This transaction was deemed to be a reorganization of entities under common control. As a result, the Company’s financial statements have been retroactively adjusted in accordance with US GAAP as if Seadrill Partners had acquired the entity that owns the T-16 for the entire period that the entities have been under the common control of Seadrill Limited. As consideration for the purchase, the Company issued 3,310,622 common units to Seadrill in a private placement transaction. Refer to Note 3 for more information.


West Leo and West Sirius Acquisition
On December 13, 2013, the Company completed the acquisition of the companies that own and operate the West Sirius and West Leo. The West Sirius was acquired by Seadrill Capricorn Holdings LLC (51% owned by the Company) and the West Leo was acquired by Seadrill Operating LP (30% owned by the Company). These transactions were deemed to be a reorganization of entities under common control. As a result, the Company’s financial statements have been retroactively adjusted in accordance with US GAAP as if Seadrill Partners had acquired the entities that own and operated the West Sirius and West Leo for the entire period that the entities have been under the common control of Seadrill. In order to finance the acquisitions, the Company issued 11,200,000 common units to the public and 3,394,916 common units to Seadrill, and a further 1,680,000 units to the underwriters, issued in connection with the exercise of the underwriters’ option to purchase additional common units. Refer to Note 3 for more information.

West Auriga Acquisition
In March 2014, pursuant to a Contribution, Purchase and Sale Agreement, dated as of March 11, 2014, by and among the Company, Seadrill, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc., Seadrill Capricorn Holdings LLC acquired the entities that own and operate the drillship West Auriga from Seadrill, which has been accounted for as a business combination. Seadrill has agreed to indemnify the Company, Seadrill Capricorn Holdings LLC and Seadrill Auriga Hungary Kft. against any liability they may incur under the credit facility financing the West Auriga in respect of debt that is related to other rigs owned by Seadrill that are financed under the same credit facility as the West Auriga. In order to fund the Company’s portion of the purchase price of the West Auriga acquisition, on March 17, 2014, the Company issued an aggregate of (i) 11,960,000 common units to the public at a price of $30.60 per unit and (ii) 1,633,987 common units to Seadrill at a price of $30.60 per unit, pursuant to a Unit Purchase Agreement, dated March 12, 2014, between the Company and Seadrill. Refer to Note 3 for more information. Refer to Note 3 for more information.

Purchase of additional limited partner interest in Seadrill Operating LP
On July 21, 2014, the Company completed the purchase of an additional 28% limited partner interest in Seadrill Operating LP, an existing controlled subsidiary of the Company, from Seadrill for $372.8 million. As a result of this acquisition, the Company’s ownership interest in Seadrill Operating LP increased from 30% to 58%.

West Vela Acquisition
On November 4, 2014, pursuant to a Contribution, Purchase and Sale Agreement, dated as of November 4, 2014, by and among Seadrill, the Company, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc., Seadrill Capricorn Holdings LLC acquired the entities that own and operate the drillship West Vela from Seadrill which has been accounted for as a business combination. Seadrill has agreed to indemnify the Company, Seadrill Capricorn Holdings LLC and Seadrill Vela Hungary Kft. against any liability they may incur under the credit facility financing the West Vela in respect of debt that is related to other rigs owned by Seadrill that are financed under the same credit facility as the West Vela. Refer to Note 3 for more information.

West Polaris Acquisition
On June 19, 2015, a subsidiary of the Company (Seadrill Operating) acquired Seadrill Polaris, the entity that owns and operates the drillship the West Polaris from Seadrill, which has been accounted for as a business combination. Refer to Note 3 for more information. Seadrill continues to act as a guarantor under the $420 million West Polaris Facility, pursuant to which Seadrill Polaris is a borrower.Consolidated Balance Sheet.

Spare parts agreement with Seadrill
During the year ended December 31, 2015, a subsidiary of Seadrillwe entered into an agreement with the CompanySeadrill to store spare parts of the Company's West Sirius rig while it is stacked. Seadrill is responsible at its own cost for the moving and storing of the spare parts during the stacking period. Seadrill may use the 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 as required by the Company at its own cost.cost when the West Sirius returns to operations.

Other indemnificationsIndemnifications and guarantees
Performance guarantees
Seadrill Limited provides performance guarantees in connection with the Company’sour drilling contracts in favor of our customers, of the Company, amounting to a total of $370.0$165.4 million as atof December 31, 20152017 (December 31, 2014: $370.02016: $184.5 million).

Customs guarantees
Seadrill Limited provides customs guarantees in connection with the Company’s operations, primarily in Nigeria,Thailand, in favor of banks amounting to a total of $85.8$0.6 million as at December 31, 20152017 (December 31, 2014: $92.4 million)2016: nil).

Tax indemnifications
Under our omnibus agreement with Seadrill at the Omnibus Agreementtime of the IPO (the "Omnibus Agreement") and Salepurchase and Purchasesale agreements relating to acquisitions from Seadrill subsequent to the IPO, Seadrill has agreed to indemnify the Company against any tax liabilities arising from the operation of the assets contributed or sold to the Company prior to the time they were contributed or sold.

Loan Guarantees
Seadrill was previously a guarantor under the West Polaris Facility and West Vela Facility. In August 2017, we completed amendments to these facilities which released Seadrill as a guarantor. Please refer to Note 11- "Debt" for further discussion.
T-15 and T-16 Acquisitions
In connection with the T-15 and T-16 acquisitions, Seadrill agreed to indemnify Seadrill T-15 Ltd, Seadrill T-16 Ltd, Seadrill International Ltd and Seadrill Partners Operating LLC against any liability incurred by them pursuant to their guarantees and share pledges under the Tender Rig Agreement. Seadrill was entitled to set off any such claims for indemnification against any claim it may have against Seadrill T-15 Ltd, Seadrill T-16 Ltd, Seadrill International Ltd and Seadrill Partners Operating LLC, including for claims under the related party loan agreements for the T-15 and T-16. As at August 17, 2017, indemnifications of this nature from Seadrill have been canceled in connection with the new Tender Rig Facility.
Environmental and other indemnifications
Under the Omnibus Agreement, and Salesale and Purchasepurchase agreements relating to acquisitions from Seadrill subsequent to the IPO, Seadrill has agreed to indemnify the Company for a period of five years against certain environmental and toxic tort liabilities with respect to the assets that Seadrill contributed or sold to the Company to the extent arising prior to the time they were contributed or sold. However, claims are subject to a deductible of $0.5 million and an aggregate cap of $10 million.

In addition, pursuant to the Omnibus Agreement, Seadrill agreed to indemnify the Company for any defects in title to the assets contributed or sold to the Company and any failure to obtain, prior to October 14, 2012, certain consents and permits necessary to conduct the Company’s business, which liabilities arise within three years after the closing of the IPO onThis indemnification expired October 24, 2012.

2017.

Note 14 – Risk management and financial instruments
The Company isWe are exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. The CompanyWe 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
The Company’sOur exposure to interest rate risk relates mainly to itsour floating interest rate debt and balances of surplus funds placed with financial institutions. This exposure is managed through the use of interest rate swaps and other derivative arrangements. The Company’sswaps. Our objective is to obtain the most favorable interest rate borrowings available without increasing its foreign currency exposure.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, whilstwhile providing the Companyus with flexibility to meet all requirements for working capital and capital investments. The extent to which the Company utilizeswe utilize interest rate swaps derivatives to manage itsour interest rate risk is determined by theour net debt exposure and itsour views on future interest rates.
Interest rate swap agreements
AtAs of December 31, 2015, the Company2017, we had interest rate swap agreements with Seadrillswaps for ana combined outstanding principal amount of $655.3$2,793.9 million, (December 31, 2014: $690.12016: $2,822.9 million) swapping floating rate for an average fixed rate of 1.23%2.49% per annum. The combined total fair value of the interest rate swaps outstanding as atof December 31, 20152017 amounted to a gross and net assetliability of $2.2$29.0 million, (December 31, 2014:2016: a gross liability of $70.2 million and a net assetliability of $6.0$55.2 million). ThisThe 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 classifiedas allowed under International Swaps and Derivatives Association, Inc. ("ISDA") Master Agreements. We classify the liability within related party receivables in the Company's balance sheetother current liabilities. We have not designated any interest swaps as of December 31, 2015 (December 31, 2014: within related party receivables). These agreements do not qualify for hedge accounting,hedges and accordingly any changes in the fair values of the swap agreements are included in the consolidated statement of operations under (Loss)/gain"loss on derivative financial instruments. instruments".
The total realized and unrealized loss recognized for 2015 was $10.2 million (2014: lossunder "loss on derivative financial instruments" in the consolidated statement of $41.6 million, 2013 gain of $49.9 million).
At December 31, 2015, the Company hadoperations relating to interest rate swap agreements with external parties for a combined outstanding principal2017 was $12.5 million (2016: $13.9 million, 2015: $72.7 million). Included

in the $13.9 million net loss for the year ended December 31, 2016 was an out of $2,851.9period gain of $21.8 million (December 31, 2014: $2,881.7 million) swapping floating rate for an average fixed rate of 2.49% per annum. The combined total fair valuerecognized in respect of the interest rate outstanding as at December 31, 2015 amounted to a gross and net liability of $84.2 million (December 31, 2014: $56.1 million). This is classified within other current liabilities in the Company's balance sheet as of December 31, 2015. These agreements do not qualify for hedge accounting, 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 net loss recognized for 2015 was $72.7 million (2014: $83.3 million, 2013: nil ).own creditworthiness.

The Company’sOur interest rate swap agreements as atof December 31, 2015,2017, were as follows:
Outstanding principal as at December 31, 2015 Receive ratePay rateExpiry of contract
(In US$ millions)    
416.3
(1), (2)3 month LIBOR1.10%July 2, 2018
100.0
(2)3 month LIBOR1.36%October 29, 2019
70.4
(1), (2)3 month LIBOR1.11%June 19, 2020
68.6
(1), (2)3 month LIBOR1.93%December 21, 2020
2,851.9
(1)3 month LIBOR 2.45% to 2.52%February 21, 2021

Maturity dateOutstanding principal as of December 31, 2017Receive ratePay rate 
 (In US$ millions)   
February 21, 20212,793.9
3 month LIBOR 2.45% to 2.52%(1) (2)
Total outstanding principal$2,793.9
   
(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.
(2) Related partyThe Company has a LIBOR floor of 1% whereby the Company receives 1% when LIBOR is below 1%.
As of December 31, 2017, $611.9 million of our debt was exposed to interest rate swap agreements.

fluctuations, compared to $204.2 million as of December 31, 2016. An increase or decrease in short-term interest rates of 100 bps would thus increase or decrease, respectively, our interest expense by approximately $6.1 million on an annual basis as of December 31, 2017, as compared to $2.0 million in 2016.
The counterparties to the abovecredit exposure of interest rate swap agreements are Seadrill and various banks. The Company believesis 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 be creditworthy.derivative financial instrument contracts, which give us the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes us.

The related party interest rate swaps held by Seadrill were canceled on September 12, 2017 as a result of Seadrill entering a Chapter 11 restructuring. The total fair value of the related party interest rate swaps, with Seadrill as counterparty, was therefore nil at December 31, 2017 (December 31, 2016: a net asset of $2.4 million and gross asset of $2.6 million). The fair value of the related party interest rate swaps is classified within amounts due to related party in the Consolidated Balance Sheets.
The total realized and unrealized loss recognized under "loss on derivative financial instruments" in the Consolidated Statement of Operations relating to interest rate swap agreements with Seadrill for the year ended December 31, 2017 was $1.3 million (2016: $4.1 million, 2015: $10.2 million). Included in the $4.1 million net loss for the year ended December 31, 2016 is an out of period loss of $0.4 million recognized in respect of the Company's' own creditworthiness.
Foreign currency risk
The Company and all of its subsidiariesWe use the U.S.US Dollar as theirthe functional currency of all our subsidiaries because the majority of theirour revenues and expenses are denominated in U.S.US Dollars. Accordingly, the Company'sTherefore, we also use US Dollars as our reporting currency is U.S. Dollars. The Company does,currency. We do, however, earn revenue and incur expenses in Canadian Dollars due to the operations of the West Aquarius in Canada and Nigerian Naira andas 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:
Concentrationthe measurement of creditmonetary 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
The Company hasWe have financial assets which expose the Companyus to credit risk arising from possible default by a counterparty. The Company considers theOur 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 doesdo not expect any significant loss due to resultcredit risk. We don't demand collateral from non-performance by such counterparties. The Companyour counterparties in the normal course of business doesbusiness.
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 demandrequire collateral from its counterparties.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.

Fair Values
The carrying value and estimated fair value of the Company’s financial assets and liabilities as of December 31, 2015 and December 31, 2014 are as follows:
 December 31, 2015 December 31, 2014
(In US$ millions)Fair Value Carrying Value Fair Value Carrying Value
Cash and cash equivalents319.0
 319.0
 242.7
 242.7
Current portion of long-term debt88.0
 105.3
 68.3
 76.5
Current portion of long-term debt to related party145.8
 145.8
 40.4
 40.4
Long-term debt1,763.5
 3,487.0
 2,574.8
 3,227.4
Long-term portion of debt to related party160.2
 160.2
 306.1
 306.1
Related party deferred and contingent consideration245.8
 245.8
 137.0
 137.0
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 fair value of the $100 million revolving credit facility with Seadrill is considered to be equal to the carrying value, as the facility bears an interest of LIBOR plus a margin of 5.0%, with a commitment fee of 40% of the margin, which is concluded to be market rate. This is therefore categorized at level 2 on the fair value measurement hierarchy.

The fair value of the current and long-term portion of floating rate debt (consisting of external debt, rig financing agreements with Seadrill and vendor financing agreements with Seadrill) are estimated to be equal to the carrying value since they bear variable interest rates, which are reset on a quarterly basis, except for the T-15 and T-16 Rig Facilities which are reset on a semi-annual basis. This debt is not freely tradable and cannot be purchased by the Company at prices other than the outstanding balance plus accrued interest. This is categorized at level 2 on the fair value measurement hierarchy.


The fair value of the related party deferred and contingent consideration relating to the purchase of the West Vela and West Polaris is estimated to be equal to the carrying value since the liabilities have been calculated using the estimated future cash outflows discounted back to the present value. These liabilities are considered to be market rate. This is categorized at level 2 on the fair value measurement hierarchy.

Financial instruments that are measured at fair value on a recurring basis:
  
Fair value measurements
at reporting date using
 Total fair value as at December 31, 2015
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions) (Level 1)(Level 2)(Level 3)
Current assets:    
Derivative instruments - Interest rate swap contracts (related party)2.2
—
2.2
—
Total assets2.2
—
2.2
—
     
Current liabilities:    
Derivative instruments - Interest rate swap contracts(84.2)—
(84.2)—
Total liabilities(84.2)—
(84.2)—
  
Fair value measurements
at reporting date using
 Total fair value as at December 31, 2014
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions) (Level 1)(Level 2)(Level 3)
Current assets:    
Derivative instruments - Interest rate swap contracts (related party)6.0
—
6.0
—
Total assets6.0
—
6.0
—
     
Current liabilities:    
Derivative instruments - Interest rate swap contracts (related party)(56.1)—
(56.1)—
Total liabilities(56.1)—
(56.1)—

US 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, US GAAP establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within levels one and two of the hierarchy) and the reporting entity’s own assumptions about market participant assumptions (unobservable inputs classified within level three of the hierarchy).
Level one input utilizes unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Level two inputs are inputs other than quoted prices included in level one that are observable for the asset or liability, either directly or indirectly. Level two inputs may include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability, other than quoted prices, such as interest rates, foreign exchange rates and yield curves that are observable at commonly quoted intervals. Level three inputs are unobservable inputs for the asset or liability, which are typically based on an entity’s own assumptions, as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability.
Fair value of financial assets and liabilities recorded at cost
The carrying value and estimated fair value of our financial assets and liabilities as of December 31, 2017 and December 31, 2016 are as follows:
 December 31, 2017 December 31, 2016
(In US$ millions)Fair Value Carrying Value Fair Value Carrying Value
Cash and cash equivalents$848.6
 $848.6
 $767.6
 $767.6
Term Loan B2,249.8
 2,802.3
 1,925.2
 2,865.7
Other external debt facilities514.7
 540.8
 581.8
 621.4
Long-term debt to related party23.8
 24.7
 153.3
 160.3
The carrying value of cash and cash equivalents, which are highly liquid, is a reasonable estimate of fair value and categorized at level 1 on the fair value measurement hierarchy.
The loans under the Term Loan B are freely tradable and their fair value has been set equal to the price at which they were traded on December 31, 2017 and December 31, 2016. This has been categorized at level 1 on the fair value measurement hierarchy.
Loans under other external debt facilities being the West Vela facility (previously the $1,450 million Senior Secured Credit Facility), West Polaris facility, Tender Rig facility (previously the $440 million Rig Financing Agreement) and the West Vencedor facility are not freely tradable. For the years ended December 31, 2017 and December 31, 2016 the fair value of the current and long term portion of these debt facilities was derived using the Discounted Cash Flow (DCF) model. A cost of debt of 8.36% (December 31, 2016 8.34%) was used to estimate the present value of the future cash flows. This is categorized at level 2 on the fair value measurement hierarchy.
Assets and liabilities recorded at cost on a recurring basis
Other financial instruments that are measured at fair value on a recurring basis:
  
Fair value measurements
at reporting date using
 Total fair value as of December 31, 2017
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions) (Level 1)(Level 2)(Level 3)
Current liabilities:    
Derivative instruments - Interest rate swap contracts(29.0)—
(29.0)—
Related party deferred and contingent consideration(87.7)—
(87.7)—
Total liabilities$(116.7)—
(116.7)—

  
Fair value measurements
at reporting date using
 Total fair value as of December 31, 2016
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions) (Level 1)(Level 2)(Level 3)
Current assets:    
Derivative instruments - Interest rate swap contracts (related party)$2.4
—
2.4
—
Total assets2.4
—
2.4
—
     
Current liabilities:    
Derivative instruments - Interest rate swap contracts (related party)(55.2)—
(55.2)—
Related party deferred and contingent consideration
(203.2)—
(203.2)—
Total liabilities$(258.4)—
(258.4)—
The fair values of interest rate swapsswap 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, 20152017 and December 31, 2014.2016. The calculation of the credit risk in the swap values is subject to a number of assumptions including an assumed Credit Default Swap rate based on the Company's traded debt, plus a curve profile and recovery rate.

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

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

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

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

Retained risk
a) Physical Damage Insurance
Seadrill has purchased hull and machinery insurance to cover for physical damage to its drilling units and those of the Company and charges the CompanyCompany. We are charged for the associated cost for its respectiveof insuring our drilling units. The Company retainsWe retain the risk for the deductibles relating to physical damage insurance on the Company’sour fleet. The deductible is currently a maximum of $5 million per occurrence.
The Company has 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. The Company has renewed its policy to insure this windstorm risk for a further period starting May 1, 2016 through April 30, 2017.

b) Loss of Hire Insurance
With the exception of T-15 and T-16, Seadrill purchases insurance to cover for loss of revenue for their operational rigs in the event of extensive downtime caused by physical damage to its drilling units and those of the Company, where such damage is covered under the Seadrill’s physical damage insurance, and charges the Companyus for the cost related to the Company’sour fleet.
The loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, insurance policies according to which OPCO iswe are compensated for loss of revenue are limited to 290 days per event and aggregated per year. The daily indemnity is approximatelywill vary from 75% to 100% of the contracted dayrate. OPCO retains

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 Company’s loss of hire policy, itwe will be responsible for the costs in such period. The Company doesWe do not havepurchase loss of hire insurance on the Company's tender rigs with the exception of the semi-tender rig the West Vencedor.T-15 and T-16.

c) Protection and Indemnity Insurance
Seadrill purchases Protectionprotection and Indemnityindemnity insurance and Excessexcess liability insurance for personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units to cover claims of up to $250 million per event and in the aggregate for the West Vencedor, T-15 and T-16, up to $400$300 million per event and in the aggregate for the West Aquarius, West Capella, West Leo and West Aquarius. $400 million per event and in the aggregate for the West Capellaand West Polaris, up to $750$500 million per event and in the aggregate for the West Sirius; and up to $0.5 million per event and in the aggregate for each of theWest Capricorn, West Auriga and West Vela.
Effective June 1, 2015,In the protectionevent of no drilling activities, the excess liability insurance is suspended and indemnity insurance fortherefore the limit is reduced from $500 million to $350 million per events and in the aggregate with the exception of the West Sirius Capricornwas, West Auriga and West Vela which is reduced from $750 million to $500 million.$500.0 million per event and in aggregate.
OPCO retainsWe retain the risk for the deductible of up to $0.5 million per occurrence relating to protection and indemnity insurance.

d) Windstorm Insurance
ConcentrationWe have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Risk
There isMexico (West Sirius, West Capricorn, West Vela and West Auriga) with a concentrationCombined Single Limit of credit$100 million in the annual aggregate, which includes loss of hire. We intend to renew this policy to insure this windstorm risk with respect to cash and cash equivalents as most of the amounts are deposited with Nordea Bank Finland Plc, Danske Bank A/S and Citibank. The Company considers these risks to be remote.
In the years ended December 31, 2015, 2014, and 2013 the Company's contract revenues were attributable to the following customers:
 2015 2014 2013
BP44.8% 41.5% 35.0%
ExxonMobil *
32.1% 26.4% 14.5%
Tullow13.5% 17.4% 18.8%
Chevron8.5% 14.7% 12.1%
Total—% —% 19.6%
Other1.1% —% —%
Total100.0% 100.0% 100.0%
* During 2015 and 2014 the ExxonMobil drilling contract was assigned to Hibernia Management and Development Co. Ltd and Statoil Canada Ltd in 2013.for a further period starting May 1, 2018 through April 30, 2019.

Note 15 – Commitments and contingencies
Legal Proceedings
From time to time we arethe Company is a party, as plaintiff or defendant, to lawsuits in various jurisdictions in the ordinary course of business or in connection with ourits acquisition or disposal activities. We believe that the resolution of such claims will not have a material impact individually or in the aggregate on our operations or financial condition. Our best estimate of the outcome of the various disputes has been reflected in ourthese financial statements as of December 31, 2015.2017.

West Leo
Pledged AssetsWe received notification of a force majeure occurrence on October 1, 2016 in respect of the West Leo which was operating for Tullow Ghana Limited ("Tullow") in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience. We do not accept that the contract has been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract has been discharged by frustration.  Accordingly, we amended our claim in the English High Court to reflect this. In the event of termination for convenience, we are entitled to an early termination fee of 60% of the remaining contract backlog, subject to an upward or downward adjustment depending on the work secured for the West Leo over the remainder of the contract term, plus other direct costs incurred as a result of the early termination. The total amount we are seeking to recover is $278.0 million plus interest.
Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit against certain of our subsidiaries for patent infringement. The book valuesuit alleges that two of assets pledged under mortgageour drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity drilling. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and overdraft facilitiesTrademark Office which ultimately stayed the litigation. The IPR board held in March 2017 that the patents were valid. Despite this finding, we do not believe that our rigs infringe the Transocean patents, which have now expired, and we continue to defend ourselves vigorously against this suit. We do not believe that the ultimate liability, if any, resulting from this litigation will have a material effect on our financial position. We have not previously recognized any related loss contingency in our Consolidated Financial Statements as of December 31, 2017 as we do not believe the loss to be probable. We are also not able to make a reasonable estimate of the possible loss.
Other claims or legal proceedings
We are not aware of any other legal proceedings or claims that we expect to have, individually or in the aggregate, a material adverse effect on the Company.
Commitments
We had no material lease commitments or unconditional purchase obligations at December 31, 20152017 and 2014 was $5,367.7 million, and $4,953.4 million, respectively.2016.

Purchase Commitments
At December 31, 2015 and 2014 the Company had no contractual purchase commitments.

Note 16 – Earnings per unit and cash distributions

Year ended December 31,Year ended December 31,
(in US $ millions, except per unit data)2015 2014 20132017 2016 2015
Net income attributable to:          
Common unitholders$184.1
 $109.2
 $56.4
$141.2
 $240.7
 $184.1
Subordinated unitholders40.5
 29.0
 30.2
—
 37.8
 40.5
Seadrill member interest (1)
32.6
 —
 57.8
—
 2.5
 32.6
Net income attributable to Seadrill Partners LLC owners$257.2
 $138.2
 $144.4
$141.2
 $281.0
 $257.2
          
Weighted average units outstanding (basic and diluted) (in thousands):          
Common unitholders75,278
 62,374
 26,266
75,278
 75,278
 75,278
Subordinated unitholders16,543
 16,543
 16,543
16,543
 16,543
 16,543
          
Earnings per unit (basic and diluted):          
Common unitholders$2.45
 $1.75
 $2.15
$1.88
 $3.20
 $2.45
Subordinated unitholders$2.45
 $1.75
 $1.83
$—
 $2.28
 $2.45
          
Cash distributions declared and paid in the period per unit (2)
$1.7025
 $1.6025
 $1.2325
Cash distributions declared and paid in the period per unit (1) (2)
$0.4000
 $0.7000
 $1.7025
          
Subsequent event: Cash distributions declared and paid relating to the period per unit (3) :
$0.2500
 $0.5675
 $0.4450
Subsequent event: Cash distributions declared and paid relating to the period per unit (2) (3):
$0.1000
 $0.1000
 $0.2500
(1)Pre-acquisition net income from entities acquired from Seadrill in common control transactions during 2013 (See Note 3), has been allocated to the Seadrill member interest. The Seadrill member interest, and its rights to the incentive distribution rights, is owned by the predecessor owner of acquired entities, Seadrill Limited. Included within the amount allocated to the Seadrill member interest in 2013 is $0.5 million allocated to the incentive distribution rights.
(2)Refers to the cash distributions relating to the period declared and paid during the year.
(3)
(1) Refers to the cash distributions declared and paid during the year.
(2) Distributions were declared and paid only with respect to the common units in 2017.
(3) Refers to the cash distribution relating to the period, declared and paid subsequent to the year-end.

Earnings per unit is calculated using the two-class method where undistributed earnings are allocated to the various member interests. The net income attributable to the common and subordinated unitholders and the holders of the incentive distribution rights is calculated as if all net income was distributed according to the terms of the distribution guidelines set forth in the First Amended and Restated Operating Agreement of the Company (the “Operating Agreement”), regardless of whether those earnings could be distributed. The Operating Agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of the quarter after establishment of cash reserves determined by the Company’s board of directors to provide for the proper conduct of the Company’s business including reserves for maintenance and replacement capital expenditure and anticipated credit needs. Therefore, the earnings per unit is not indicative of potential cash distributions that may be made based on historic or

future earnings. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on non-designated derivative instruments and foreign currency translation gains (losses).
Under the Operating Agreement, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3875 per unit per quarter, plus any arrearages in the payment of minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.
Distributions of available cash from operating surplus are to be made in the following manner for any quarter during the subordination period:
First, to the common unitholders, pro-rata, until the Company distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
Second, to the common unitholders, pro-rata, until the Company distributes for each outstanding common an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters during the subordination period; and
Third, to the subordinated units, pro-rata, the Company distributes for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter;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;distribution.
then, the Company will distribute any additional available cash from operating surplus for that quarter among the unitholders and the holders of the incentive distributions rights in the following manner:
first, 100.0% to all unitholders, until each unitholder receives a total of $0.4456 per unit for that quarter (the “first target distribution”);
second, 85% to all unitholders, pro rata, and 15.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.4844 per unit for that quarter (the “second target distribution”);
third, 75.0% to all unitholders, pro rata, and 25.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.5813 per unit for that quarter (the “third target distribution”); and
thereafter, 50.0% to all unitholders, and 50.0% to the holders of the incentive distribution rights, pro rata.
The percentage interests set forth above assumes that the Company does not issue additional classes of equity securities.
The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after September 30, 2017, that each of the following tests are met:
distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
the “adjusted operating surplus” (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted weighted average basis during those periods; and
there are no outstanding arrearages in payment of the minimum quarterly distribution on the common units.

In addition, at any time on or after September 30, 2017, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units and subject to approval by the conflicts committee, the holder or holders of a majority of the subordinated units will have the option to convert each subordinated unit into a number of common units at a ratio that may be less than one-to-one on a basis equal to the percentage of available cash from operating surplus paid out over the previous four-quarter period in relation to the total amount of distributions required to pay the minimum quarterly distribution in full over the previous four quarters.
The distributionCommencing with the distributions made in February 2016, in respect of the fourth quarter of 2015, isno distributions have been made to the holders of the subordinated units and distributions to the common units have been below the Minimum Quarterly Distribution as set out above.minimum quarterly distribution. Arrearages in the payment of the minimum quarterly distribution on the common units must be settled before any distributions of available cash from operating surplus may be made in the future on the subordinated units.


The following distributions were paid to the incentive distribution rights holders for the years ending December 31, 20152017, 20142016 and 20132015.
Year ended December 31,Year ended December 31,
(in US $ millions)2015 2014 20132017 2016 2015
Distributions paid to incentive distribution rights holders9.5
 9.2
 —
—
 —
 9.5

Note 17 - Supplementary cash flow information

The table below summarizes the non-cash investing and financing activities relating to the periods presented:

(In US$ millions)2015 2014 2013
Purchase of West Auriga, issuance of loan note to related party (1)
—
 100.0
 —
Purchase of West Vela, deferred consideration payable to related party (2)
—
 73.7
 —
Purchase of West Vela, contingent consideration payable to related party (2)
—
 65.7
 —
Purchase of the West Polaris, deferred consideration payable to related party (3)(4)
65.0
 —
 —
Purchase of the West Polaris, seller's credit payable to related party (3)
44.6
 —
 —
Capital injection due to forgiveness of related party payables—
 —
 40.5
(In US$ millions)2017 2016 2015
Purchase of the West Polaris, deferred consideration payable to related party (1)(2)
—
 —
 65.0
Purchase of the West Polaris, seller's credit payable to related party (1) (2)
—
 —
 44.6
Other distributions (3)9.2
 —
 —
(1) The purchase of the West Polaris was financed in part by a seller's credit and deferred consideration: refer to Note 3 "Business acquisitions".
(2) The contingent consideration payable to Seadrill was reduced by a measurement period adjustment in the year ended December 31, 2017 and December 31, 2015. Refer to Note 14 "Risk management and financial instruments" and Note 3 "Business acquisitions".
(3) Non cash distribution, refer to Note 13 – "Related party transactions" for further information.

1.
The purchase of the West Auriga was financed by the issuance of a discount loan note: refer to Note 3- Business acquisitions
2.
The purchase of the West Vela was financed partly by deferred and contingent consideration: refer to Note 3- Business acquisitions
3.
The purchase of the West Polaris was financed party by a seller's credit and deferred consideration: refer to Note 3- Business acquisitions.
4.
The contingent consideration payable to Seadrill was reduced by a measurement period adjustment in the year ended December 31, 2015. Refer to Note 3- Business acquisitions.

Note 18 – Subsequent Events

events
Distribution declared

On January 26, 2016, the CompanyFebruary 22, 2018, we declared a distribution for the fourth quarter of 20152017 of $0.2500$0.1000 per common unit, which was paid on FebruaryMarch 12, 2016 to unitholders of record on February 5, 2016.2018.

On April 25, 2016, the Company declared a distribution for the first quarter of 2016 of $0.2500 per unit. This cash distribution will be paid on or about May 13, 2016 to all unitholders of record as of the close of business on May 6, 2016.

AmendmentAmendments to the West Polaris drilling contract    TLB credit agreement
OnIn February 8, 2016, the drilling contract for the West Polaris was amended whereby its dayrate was reduced to $490,000 per day from $653,000 per day, effective January 1, 2016. This will not have a net cash impact on the Company. Under the terms of the acquisition agreement associated with the acquisition of the Polaris business, Seadrill Polaris agreed to pay Seadrill any dayrate it receives in excess of $450 thousand per day, adjusted for daily utilization, through the remaining term, without extension, of the ExxonMobil contract.

Amendment to Credit Facilities
On April 28, 2016 the Company executed2018, we completed an amendment to the covenants contained interms of our Term Loan B ("TLB"). In connection with the $1,450 million Senior Secured Credit Facility,amendment, the Company has agreed to certain amendments, including but not limited to, increasing the applicable margin by 3%, a par prepayment contingent on the successful outcome of certain ongoing litigation, adding the West Polaris FacilityVencedor as collateral and certain amendments relating to cash movements outside the $440 million Rig Financing Agreement . The amendment, among other things, amends the requirements and definitions of the equity ratio, leverage ratio, minimum-value-clauses, and minimum liquidity requirements, as described in TLB collateral group. Please read Note 11 – Debt. "Debt" for further details.




SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.
 
  
SEADRILL PARTNERS LLC
(Registrant)
    
Date: April 28, 201612, 2018   
    
  By:/s/ Mark Morris
  Name:Mark Morris
  Title:
Chief Executive Officer of Seadrill Partners LLC
(Principal Executive Officer of Seadrill Partners LLC)