20-F
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 20-F

[_] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE
SECURITIES EXCHANGE ACT OF 1934

OR

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

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: 001-34667

SEADRILL LIMITED
(Exact name of Registrant as specified in its charter)
(Address of principal executive offices)
Bermuda
(Jurisdiction of incorporation or organization)
Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda
(Address of principal executive offices)
Georgina Sousa
Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda
Tel: +1 (441) 295-9500, Fax: +1 (441) 295-3494
(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:
 
Common stock, $2.00 par value
 
New York Stock Exchange
 
 
 
 
 
 
 
Title of class
 
Name of exchange on which registered
 

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:



As of December 31, 2015, there were 492,759,940 shares, par value $2.00 per share, of the Registrant’s common stock outstanding.
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[X] Yes
[_] No
 
 
If this report is an annual report 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
[X] No
 
 
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.
[X] Yes
[_] 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 during the preceding 12 months
[X] Yes
[_] No

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  [X]
Accelerated filer  [_]
Non-accelerated filer   [_]
(Do not check if a smaller reporting company)
Smaller reporting company  [_]
Indicate by check mark which basis of accounting the Registrant has used to prepare the financial statements included in this filing:
 
[X]  U.S. GAAP
 
[_]  International Financial Reporting Standards as issued by the International Accounting Standards Board
 
[_]  Other
 
If ”Other” has been checked in response to the previous question, indicate by check mark which
financial statement item the Registrant has elected to follow.
 
[_]  Item 17
 
[_]  Item 18

If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
[_]  Yes
[X]  No


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

We desire to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, or the PSLRA, and are including this cautionary statement in connection therewith. The PSLRA provides safe harbor protections for forward-looking statements in order to encourage companies to provide prospective information about their business.

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 document 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:

•
factors related to the offshore drilling market, including changes in oil and gas prices and the state of the global economy on market outlook for our various geographical operating sectors and classes of rigs;
•
supply and demand for drilling units and competitive pressure on utilization rates and dayrates;
•
customer contracts, including contract backlog, contract commencements, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations;
•
the repudiation, nullification, modification or renegotiation of contracts;
•
delays in payments by, or disputes with, our customers under our drilling contracts;
•
fluctuations in the market value of our drilling units and the amount of debt we can incur under certain covenants in our debt financing agreements;
•
the liquidity and adequacy of cash flow for our obligations;
•
our ability to successfully employ our drilling units;
•
our ability to procure or have access to financing;
•
our expected debt levels;
•
our ability to comply with certain covenants in our debt financing agreements;
•
credit risks of our key customers;
•
political and other uncertainties, including political unrest, risks of terrorist acts, war and civil disturbances, public health threats, piracy, corruption, significant governmental influence over many aspects of local economies, or the seizure, nationalization or expropriation of property or equipment;
•
the concentration of our revenues in certain jurisdictions;
•
limitations on insurance coverage, such as war risk coverage, in certain areas;
•
any inability to repatriate income or capital;
•
the operation and maintenance of our drilling units, including complications associated with repairing and replacing equipment in remote locations and maintenance costs incurred while idle;
•
newbuildings, upgrades, shipyard and other capital projects, including the completion, delivery and commencement of operation dates;
•
import-export quotas;
•
wage and price controls and the imposition of trade barriers;
•
the recruitment and retention of personnel;
•
regulatory or financial requirements to comply with foreign bureaucratic actions, including potential limitations on drilling activity, changing taxation policies and other forms of government regulation and economic conditions that are beyond our control;
•
the level of expected capital expenditures, our expected financing of such capital expenditures, and the timing and cost of completion of capital projects;
•
fluctuations in interest rates or exchange rates and currency devaluations relating to foreign or U.S. monetary policy;




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•
tax matters, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Bermuda, Brazil, Norway, the United Kingdom and the United States;
•
legal and regulatory matters, including the results and effects of legal proceedings, and the outcome and effects of internal and governmental investigations;
•
hazards inherent in the drilling industry and marine operations causing 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 the suspension of operations;
•
customs and environmental matters; and
•
other important factors described from time to time in the reports filed or furnished by us with the Securities and Exchange Commission, or the Commission, and the New York Stock Exchange, or the NYSE.

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.


Table of Contents

TABLE OF CONTENTS
 
 
Page
PART 1
 
 
ITEM 1.
ITEM 2.
ITEM 3
ITEM 4.
ITEM 4A
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 8
ITEM 9.
ITEM 10.
ITEM 11.
ITEM 12.
 
 
 
PART II
 
 
ITEM 13.
ITEM 14.
ITEM 15
ITEM 16.
ITEM 16A.
ITEM 16B.
ITEM 16C.
ITEM 16D.
ITEM 16E.
ITEM 16F.
ITEM 16G.
ITEM 16H.
 
 
 
PART III
 
 
ITEM 17.
ITEM 18.
ITEM 19.

Table of Contents

PART 1.
 
ITEM 1.
IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
 
Not applicable.
 
ITEM 2.
OFFER STATISTICS AND EXPECTED TIMETABLE
 
Not applicable.
 
ITEM 3.
KEY INFORMATION

Throughout this Annual Report, unless the context otherwise requires, references to “Seadrill Limited,” “Seadrill,” the “Company,” “we,” “us,” “Group,” “our” and words of similar import refer to Seadrill Limited, its subsidiaries and its other consolidated entities.

References in this Annual Report to “Cosco,” “Samsung,” “DSME,” “Dalian,” “Jurong,” and “HSHI” refer to the shipyards Cosco (Qidong) Offshore Co. Limited, Samsung Heavy Industries, Daewoo Shipbuilding & Marine Engineering, Dalian Shipbuilding Industry Offshore Co., Ltd.,Jurong Shipyard Pte Ltd., and Hyundai Sambo Heavy Industries Co Ltd. respectively.

Unless otherwise indicated, all references to “US$” and “$” in this Annual Report are to, and amounts are presented in, U.S. dollars. All references to “€” are to euros, all references to “£” or “GBP” are to pounds sterling, all references to “NOK” are to Norwegian kroner and all references to “SEK” are to Swedish kroner.

A.
SELECTED FINANCIAL DATA
 
The selected statement of operations and other financial data of the Company with respect to the fiscal years ended December 31, 2015, 2014 and 2013 and the selected balance sheet data of the Company as of December 31, 2015 and 2014 have been derived from the Company’s consolidated financial statements (the “Consolidated Financial Statements”) included in Item 18 of this Annual Report, which have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).
 
The selected statement of operations and other financial data for the fiscal years ended December 31, 2012 and 2011 and the selected balance sheet data as of December 31, 2013, 2012 and 2011 have been derived from the Consolidated Financial Statements of the Company which are not included herein.
 
The following table should be read in conjunction with “Item 5. Operating and Financial Review and Prospects” and the Company’s Consolidated Financial Statements and Notes thereto, which are included herein. The Company’s financial statements are maintained in U.S. dollars. We refer you to the Notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are presented.

The Company deconsolidated its investments in Seadrill Partners LLP, or Seadrill Partners, on January 2, 2014, and deconsolidated its investments in SeaMex Limited, or SeaMex, on March 10, 2015. Please see “Item 4. Information on the Company—A. History and Development of the Company” for further information.
 
 
Year ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
(In millions of U.S. dollars except common share and per share data)
 
 
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Total operating revenues
4,335

 
4,997

 
5,282

 
4,478

 
4,192

Net operating income
1,019

 
2,279

 
2,098

 
1,791

 
1,774

Net (loss)/income
(750
)
 
4,087

 
2,786

 
1,205

 
1,482

(Loss)/earnings per share, basic
(1.49
)
 
8.32

 
5.66

 
2.37

 
3.05

(Loss)/earnings per share, diluted
(1.49
)
 
8.30

 
5.47

 
2.34

 
2.96

Dividends paid
—

 
1,415

 
1,287

 
1,925

 
1,440

Dividends paid per share
—

 
2.98

 
2.74

 
4.31

 
3.14

Dividends declared per share *
—

 
2.00

 
3.72

 
3.51

 
3.06


 * Includes the fourth quarter dividends for 2013, 2011 and 2010 that were declared subsequent to the year end in the first quarter of the following year.
 


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Year ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
(In millions of U.S. dollars except
common share and per share data)
 
 
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
1,044

 
831

 
744

 
318

 
483

Drilling units
14,930

 
15,145

 
17,193

 
12,894

 
11,223

Newbuildings
1,479

 
2,030

 
3,419

 
1,882

 
2,531

Investment in associated companies
2,590

 
2,898

 
140

 
509

 
721

Goodwill
—

 
604

 
1,200

 
1,320

 
1,320

Total assets (1) , (2)
23,470

 
26,297

 
26,048

 
19,321

 
18,052

Long-term debt (including current portion) (2)
10,543

 
12,475

 
13,314

 
10,663

 
9,902

Common share capital
985

 
985

 
938

 
938

 
935

Total equity
9,975

 
10,390

 
8,202

 
6,024

 
6,302

Common shares outstanding (in millions)
492.8

 
492.8

 
469.0

 
469.2

 
467.8

Weighted average common shares outstanding (in millions)
492.8

 
478.0

 
469.0

 
468.5

 
458.6

Other Financial Data:
 
 
 
 
 

 
 

 
 

Net cash provided by operating activities
1,788

 
1,574

 
1,695

 
1,590

 
1,669

Net cash (used in)/provided by investing activities
(190
)
 
66

 
(2,964
)
 
(1,360
)
 
(2,486
)
Net cash (used in)/provided by financing activities
(1,370
)
 
(1,521
)
 
1,695

 
(395
)
 
538

Capital expenditures (3)
(1,041
)
 
(3,168
)
 
(4,463
)
 
(1,690
)
 
(2,543
)
 
(1)
Historically, the Company presented balances due to/from Ship Finance International Limited (“Ship Finance”) (NYSE: “SFL”) on a gross basis. Beginning on June 30, 2015, the Company has elected to present this on a net basis due to the fact that the right of offset is established in the related long-term loan agreements with Ship Finance, and the balances are intended to be settled on a net basis, providing a more appropriate description of the Company’s related party net debt position. Accordingly the Company has represented from amounts due from related parties (current assets) to offset against long-term debt due to related parties (non-current liabilities). The total amounts represented were $28 million as of December 31, 2015, $64 million as of December 31, 2014, $100 million as of December 31, 2013, $213 million as of December 31, 2012, and $161 million as of December 31, 2011.

(2)
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 previous year’s selected financial data has been represented to reflect the adoption of this ASU. The total amounts represented were $118 million as of December 31, 2015, $145 million as of December 31, 2014, $152 million as of December 31, 2013, $98 million as of December 31, 2012, and $91 million as of December 31, 2011. Please see “Note 2—Accounting policies” of the Notes to our Consolidated Financial Statements included herein.

(3)
Capital expenditures include expenditure on our drilling units and newbuildings, as well as payments for long-term maintenance.


B.
CAPITALIZATION AND INDEBTEDNESS
 
Not applicable.
 
C.
REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

D.
RISK FACTORS

Our assets are primarily engaged in offshore contract drilling for the oil and gas industry in benign and harsh environments worldwide, including ultra-deepwater environments. The following risks relate principally to the industry in which we operate and our business in general. Other risks relate principally to the market and ownership of our securities. The occurrence of any of the events described in this section could materially and negatively affect our business, financial condition, operating results, cash available for the payment of dividends or the trading price of our common shares. Unless otherwise indicated, all information concerning our business and our assets is as of December 31, 2015. 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.
 

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Risks Relating to Our Company

Our business in the offshore drilling sector depends on the level of activity in the offshore oil and gas industry, which is significantly affected by, among other things, volatile oil and gas prices, and may be materially and adversely affected by a decline in the offshore oil and gas industry.

The offshore contract drilling industry is cyclical and volatile. Our business in the offshore drilling sector 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 our customers’ drilling programs. Oil and gas prices and market expectations of potential changes in these prices also significantly affect the level of activity and demand for drilling units.

Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including, but not limited to, the following:
•
worldwide production and demand for oil and gas and geographical dislocations in supply and demand;
•
the cost of exploring for, developing, producing and delivering oil and gas;
•
expectations regarding future energy prices and production;
•
advances in exploration, development and production technology;
•
the ability of the Organization of Petroleum Exporting Countries (“OPEC”), to set and maintain levels and pricing;
•
the level of production in non-OPEC countries;
•
international sanctions on oil-producing countries, or the lifting of such sanctions;
•
government regulations, including restrictions on offshore transportation of oil and natural gas;
•
local and international political, economic and weather conditions;
•
domestic and foreign tax policies;
•
the development and exploitation of alternative fuels and unconventional hydrocarbon production, including shale;
•
worldwide economic and financial problems and the corresponding decline in the demand for oil and gas and, consequently, our services;
•
the policies of various governments regarding exploration and development of their oil and gas reserves, accidents, severe weather, natural disasters and other similar incidents relating to the oil and gas industry; and
•
the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, eastern Europe or other geographic areas or further acts of terrorism in the United States, Europe or elsewhere.

In addition to oil and gas prices, the offshore drilling industry is influenced by additional factors, including:
• the availability of competing offshore drilling units;
• the availability of debt financing on reasonable terms;
• the level of costs for associated offshore oilfield and construction services;
• oil and gas transportation costs;
• the level of rig operating costs, including crew and maintenance;
• the discovery of new oil and gas reserves;
• the political and military environment of oil and gas reserve jurisdictions; and
• regulatory restrictions on offshore drilling.

Any of these factors could reduce demand for our services and adversely affect our business and results of operations.

The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.

The oil and gas drilling industry is cyclical, and the industry is currently in a downcycle. The price of Brent crude has fallen from $115 per barrel in June 2014 to a low of $30 per barrel in January 2016. As of March 31, 2016, the price of Brent crude was approximately $39.60 per barrel. The significant decrease in oil and natural gas prices is expected to continue to reduce many of our customers’ demand for our services in 2016 due to 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 put significant pressure on dayrates and utilization. The decline and the perceived risk of a further decline 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.

Declines in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, have affected and could continue to negatively affect our business in the offshore drilling sector. Sustained periods of low oil prices have resulted in reduced

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exploration and drilling 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. As a result of the low commodity prices, the majority of exploration and production companies have announced 2016 capital expenditure budgets with significant reductions in capital spending from prior years. These changes in commodity prices can have a dramatic effect on rig demand, and periods of low demand can cause excess rig supply and intensify the competition in the industry that often results in drilling units, particularly older and less technologically advanced drilling units, being idle for long periods of time. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. In response to the recent decrease in the prices of oil and gas, a number of our oil and gas company customers have recently announced decreases in budgeted expenditures for offshore drilling. Any future decrease in exploration, development or production expenditures by oil and gas companies could reduce our revenues and materially harm our business and results of operations.

We may not be able to set profitable utilization and dayrates or delay entry of newbuild drilling units into our active fleet.

During the 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 subsequent decline in utilization and dayrates when the new drilling units entered the market. A relatively large number of the drilling units currently under construction have not been contracted for future work, and a number of units in the existing worldwide fleet are currently off-contract.

The over-supply of drilling units will be exacerbated by the entry of newbuild rigs into the market. We estimate that approximately 46 high-specification rigs are scheduled for delivery and entry into the global fleet between early 2016 and late 2018, many of which are without firm drilling contracts. The supply of available uncontracted units has intensified price competition as scheduled delivery dates occur and contracts terminate without renewal, reducing dayrates as the active fleet grows.

We currently have 13 rigs under construction comprised of four drillships, one semi-submersible rig and eight jack-up rigs. Of the rigs under construction, none have drilling contracts that commence upon delivery. We have reached agreements with Cosco, Samsung, DSME and Dalian to delay taking delivery of all the drilling units in our newbuilding program. In addition, North Atlantic Drilling Ltd. (“NADL”), our consolidated subsidiary, has agreed with Jurong to, among other things, delay taking delivery of the West Rigel until June 2016, at which point, if NADL has not secured acceptable employment for the rig, it will be sold into a joint asset holding company with Jurong. There is no assurance that we will be able to further delay the delivery of our newbuildings that do not have associated drilling contracts.

If we are unable to secure contracts for our drilling units, including for when newbuildings are delivered to us and upon the expiration of our existing contracts, we may continue to idle or stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. As of March 31, 2016, we had twelve units either “warm stacked,” which means the rig is kept operational and ready for redeployment, and maintains most of its crew, or “cold stacked,” which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is reassigned to an active rig or dismissed. Please see “—Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues.” 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.The supply of available uncontracted units is intensifying price competition as scheduled delivery and re-delivery dates occur and additional contracts terminate without renewal, which will continue to reduce dayrates as the active fleet grows. Rig owners are bidding for available work extremely competitively with a focus on utilization over returns, which has driven rates down to or below cash breakeven levels. 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, increasing the supply of available drilling units in regions with relatively fewer reductions in activity. To maintain the continued employment of our units, we may also accept contracts at lower dayrates or on less favorable terms due to market conditions. In addition, customers have requested and may in the future request the renegotiation of existing contracts to lower dayrates. In an over-supplied market, we may have limited bargaining power to renegotiate on more favorable terms. Lower utilization and dayrates have affected and will adversely affect our revenues and profitability.

Our customers may seek to cancel or renegotiate their contracts at rates that are not profitable for us.

In the current environment our customers may seek to cancel or renegotiate our contracts using various techniques, including threatening breaches of contract and applying commercial pressure, resulting in lower dayrates or the cancellation of contracts with or without any applicable early termination payments. For example, on March 30, 2015, Sevan Drilling Limited (“Sevan”) and Brasiliero S.A. (“Petrobras”) agreed to terminate early the drilling contracts for the Sevan Driller and to reduce the contracted dayrate relating to the drilling contract for the Sevan Brasil, and on March 23, 2016, we extended the contract for the West Tellus with Petrobras by 18 months in exchange for a dayrate reduction on the current contract. In addition, on February 8, 2016, we secured a new drilling contract in Angola for the West Eclipse, which is expected to commence in the second quarter of 2016. The contract is for a firm period of two years and adds backlog of approximately $285 million inclusive of mobilization. As part of this agreement, the backlog for the West Polaris has been decreased by approximately $95 million, which reduces the contingent consideration that we receive from Seadrill Partners, following the sale of the West Polaris to Seadrill Partners in June 2015.

The possible termination or loss of contracts, prolonged periods of low dayrates 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

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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. Please see “—We may be unable to comply with covenants in our credit facilities or any future financial obligations that impose operating and financial restrictions on us, which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed” and “—Failure to comply with covenants and other provisions in our existing or future debt agreements could result in cross-defaults under our existing debt agreements, which would have a material adverse effect on us.”

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.

We may not be able to renew or obtain new and favorable contracts for drilling units with expiring or terminated contracts, which could adversely affect our revenues and profitability.
 
As of March 31, 2016, we had 12 contracts that expire in 2016, eight contracts that expire in 2017, six contracts that expire in 2018, and three contracts that expire in 2019. Our ability to renew existing contracts or obtain new contracts will depend on the prevailing market conditions, which may vary among different geographic regions, different types of drilling units, and specific customers. Likewise, our customers may reduce their activity levels or seek to terminate or renegotiate drilling contracts with us. If we are not able to obtain new contracts in direct continuation, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contracts terms, our revenues and profitability could be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract which risk we may be unable to push down to other contractors, are unable or unwilling at competitive prices to insure against and which therefore have to be managed by applying other controls.

The offshore drilling markets in which we compete experience fluctuations in the demand for drilling services, as measured by the level of exploration and development expenditures and supply of capable drilling equipment. Upon the expiration or termination of their current contracts, we may not be able to obtain contracts for our drilling units and there may be a gap in employment of the rigs between current contracts and subsequent contracts. In particular, if, as is presently the case, oil and natural gas prices are low, or it is expected that such prices will decrease in the future, at a time when we are seeking to arrange contracts for our drilling units, we may not be able to obtain drilling contracts at attractive dayrates or at all.

If the dayrates that we receive for the re-employment of our current drilling units are less favorable, we will recognize less revenue from their operations. Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts for our drilling units at sufficiently high dayrates. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. If oil and gas prices remain low and/or if companies do not continue to maintain or increase exploration, development and production expenditures, we may have difficulty securing drilling contracts, or we may be forced to enter into contracts at unattractive dayrates, which would have a material adverse effect on our financial position, results of operations and cash flows.

Our contract backlog for our fleet of drilling units may not be realized.
 
As of March 31, 2016, our contract backlog was approximately $4.8 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. For example, we cancelled the construction contract for the West Mira due to the shipyard’s inability to deliver the unit within the timeframe required under the contract, resulting in the termination of the drilling contract with Husky Oil Operations Limited (“Husky”) with an estimated contract backlog of approximately $1 billion. Additionally, on March 30, 2015, Sevan Drilling and Petrobras agreed to terminate early the drilling contract for the Sevan Driller contract and to reduce the contracted dayrate relating to the drilling contract for the Sevan Brasil, which decreased the contract backlog by approximately $127 million. Subsequent to the effective cancellation of the Sevan Driller contract the unit was awarded a contract by Shell do Brasil (“Shell”) in Brazil for 60 days. Further, on March 23, 2016, we extended the contract for the West Tellus with Petrobras by 18 months in exchange for a dayrate reduction on the current contract, resulting in an increase in contract backlog of $32 million. Our inability, or the inability of our customers to perform, under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

The market value of our current drilling units and those we acquire in the future may decrease, which could cause us to incur losses if we decide to sell them following a decline in their market values.

During 2015, the estimated fair value of our drilling units, based upon various broker valuations, has decreased by approximately 20%. 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 contract drilling industry, including competition from other offshore contract drilling companies;
•
the types, sizes and ages of drilling units;
•
the supply and demand for drilling units;

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•
the costs of newbuildings;
•
the prevailing level of drilling services contract dayrates;
•
governmental or other regulations; and
•
technological advances.

Additionally, if we sell one or more of our drilling units at a time when drilling unit prices have fallen and before we have recorded an impairment adjustment to our Consolidated Financial Statements, the sale price may be less than the drilling unit’s carrying value in our Consolidated Financial Statements, resulting in a loss and a reduction in earnings. Furthermore, 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. Please also see “—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 market value of our drilling units may fall, which may impact our ability to incur additional indebtedness. Please see “—We may not have sufficient liquidity to service our debt or flexibility to obtain additional financing and pursue other business opportunities” below. If the market value of our drilling units falls, we may also be required to, among other things, make prepayments on certain of our secured credit facilities, which may adversely impact our liquidity. Please see “—We may be unable to comply with covenants in our credit facilities or any future financial obligations that impose operating and financial restrictions on us, which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.”

A reduction in the market value of our drilling units or investments in other companies within our industry could lead to the recognition of further impairment charges on, among other things, our drilling units if future cash flow estimates, based on information available to management at the time, indicates 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 our results of operations. Please see “—The decreasing value of our drilling units could result in impairment charges or impact our ability to incur debt under our debt financing agreements.”

The decreasing value of our drilling units could result in impairment charges or impact our ability to incur debt under our debt financing agreements.

During the year ended December 31, 2015 we recognized a charge of $563 million relating to the impairment of goodwill allocated to our floater segment, in addition to other impairment charges related to certain investments due to declining dayrates and future market expectations for dayrates in the sector. These have been trending lower as a result of the recent continued decline in the price of oil, which has impacted the spending plans of our customers. In the future, we may be required to record additional impairment charges to our investments or other assets. Such impairment charges could have a material adverse effect on our financial performance or results of operations. In addition, such impairment charges could adversely impact our ability to comply with the restrictions and covenants in our debt agreements, including meeting financial ratios and tests in those agreements. For example, under our secured bank credit facilities, we may be required to comply with loan-to-value or minimum-value-clauses, which could require us 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. If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness or in current or future debt financing agreements, a default could occur under the terms of those agreements.

We may not have sufficient liquidity to service our debt or flexibility to obtain additional financing and pursue other business opportunities.
 
As of December 31, 2015, we had $11.1 billion in principal amount of interest-bearing debt (including related party debt of $0.4 billion), representing approximately 663% of our total market capitalization, of which $8.3 billion was secured by, among other things, liens on our drilling units. Our current indebtedness and future indebtedness that we may incur could affect our future operations, since a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes. Covenants contained in our debt agreements require us to meet certain financial tests and non-financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business or economic conditions, may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns, and compete with others in our industry for strategic opportunities, and may limit our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes.

Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our newbuilding projects, will be dependent upon our future performance, which will be subject to prevailing economic conditions, industry cycles and financial, business, regulatory and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all our debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent that we are unable to repay our indebtedness as it becomes due or at maturity, we may need to refinance our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments. Please see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources.”


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We may be unable to comply with covenants in our credit facilities or any future financial obligations that impose operating and financial restrictions on us, which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.

Our debt agreements impose operating and financial restrictions on us, which may prohibit or otherwise limit our ability to, among other things:
•enter into other financing arrangements;
•incur additional indebtedness;
•create or permit liens on our assets;
•sell our drilling units or the shares of our subsidiaries;
•make investments;
•change the general nature of our business;
•pay dividends to our shareholders;
•change the management and/or ownership of the drilling units;
•make capital expenditures; and
•compete effectively to the extent our competitors are subject to less onerous restrictions.

Therefore, we may need to seek consent from our lenders in order to engage in some corporate actions. Our lenders’ interests may be different from ours and we may not be able to obtain our lenders’ consent when needed. This may limit our ability to finance our future operations or capital requirements, make acquisitions or pursue business opportunities.

In addition, certain of our debt agreements require us to maintain specified financial ratios and to satisfy financial covenants, including ratios and covenants that pertain to, among other things, our total equity, our total indebtedness and the market value of our drilling units. We may seek and obtain waivers or amendments from our lenders with respect to these financial covenants contained in our debt agreements. For example, in May 2015, we agreed with our lenders to amend the leverage ratio covenant under our senior secured credit facilities until January 1, 2017, and as a result, so long as the amended ratio is in effect, we are restricted from, among other things, paying dividends and repurchasing our own shares. Further, under certain of these loan agreements, our indebtedness thereunder may be subject to an additional interest margin. In addition, in April 2016, we agreed with our lenders, among other things, to amend the equity ratio, leverage ratio, minimum value clauses, and minimum liquidity under our secured credit facilities until June 30, 2017.

If we are unable to comply with any of the restrictions and covenants in our debt agreements, or in current or future debt financing agreements, and we are unable to obtain a waiver or amendment from our lender for such noncompliance, a default could occur under the terms of those 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. Our drilling units serve as security for our commercial bank indebtedness. If our lenders were to foreclose their liens on our drilling units in the event of a default, this may impair our ability to continue our operations. As of December 31, 2015, we had $8.3 billion of interest-bearing debt secured by, among other things, liens on our drilling units. In addition, all 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. We also consolidate certain subsidiaries of Ship Finance into our financial statements as variable interest entities (“VIEs”). To the extent that the VIEs may default under their indebtedness and their debt becomes classified as current in their financial statements, we would in turn make such indebtedness current in our Consolidated Financial Statements. The characterization of the indebtedness in our financial statements as current may adversely impact our compliance with the covenants contained in our existing and future debt agreements. In addition, Seadrill Partners has joint obligations with us under certain of our existing debt agreements. Furthermore, we are guarantor under Seadrill Partners’ $420 million senior secured credit facility relating to the West Polaris. In the event Seadrill Partners defaults under its indebtedness, such default could trigger the cross-default provisions in our other debt agreements. If any of these events occur, we cannot guarantee that our assets will be sufficient to repay in full all of our outstanding indebtedness, and we may be unable to find alternative financing. Even if we could obtain alternative financing, that financing might not be on terms that are favorable or acceptable to us.

Moreover, in connection with any further waivers of or amendments to our credit facilities that we may obtain, our lenders may impose additional operating and financial restrictions on us or modify the terms of our existing credit facilities. These restrictions may further restrict our ability to, among other things, pay dividends, repurchase our common shares, make capital expenditures or incur additional indebtedness, including through the issuance of guarantees. Please see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources.”

Failure to comply with covenants and other provisions in our existing or future debt agreements could result in cross-defaults under our existing debt agreements, which would have a material adverse effect on us.

Our existing debt agreements contain cross-default provisions that may be triggered if we default under the terms of our existing or future financing agreements. In the event of a default by us under one of our debt agreements, the lenders under our existing debt agreements could determine that we are in default under our other financing agreements. In addition, certain subsidiaries of Seadrill Partners have joint obligations with our subsidiaries under some of our existing debt agreements, and certain subsidiaries of Seadrill Partners have provided guarantees and collateral in relation to certain of our debt agreements in which they have a financial interest. Furthermore, we are guarantor under Seadrill Partners’ $420 million senior secured credit facility relating to the West Polaris. In the event that the subsidiaries of Seadrill Partners default

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under their indebtedness, such default could trigger the cross-default provisions in our existing debt agreements or future debt agreements. Such cross-defaults 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 our drilling units, even if we were to subsequently cure such default. In the event of such acceleration and foreclosure, we might not have sufficient funds or other assets to satisfy all of our obligations, which would have a material adverse effect on our business, results of operations and financial condition for so long as such default is continuing.

Certain of our affiliated companies may be unable to service their debt requirements and comply with the provisions contained in their loan agreements, which would have a material adverse effect on us.

The failure of certain of our affiliated companies, including our majority-owned subsidiaries, NADL, Asia Offshore Drilling (“AOD”) and Sevan, certain subsidiaries of Ship Finance that we consolidate in our financial statements as VIEs and Seadrill Partners and certain subsidiaries of Seadrill Partners, which are borrowers under our $440 million secured credit facility, to service their debt requirements and to comply with the provisions contained in their debt agreements may lead to an event of default under such agreements, which would have a material adverse effect on us.

If a default occurs under the debt agreements of our affiliated companies, the lenders could accelerate the outstanding borrowings and declare all amounts outstanding due and payable. In this case, if such entities are unable to obtain a waiver or an amendment to the applicable provisions of the debt agreements, or do not have enough cash on hand to repay the outstanding borrowings, the lenders may, among other things, foreclose their liens on the drilling units and other assets securing the loans, if applicable, or seek repayment of the loan from such entities.  In addition, with respect to NADL’s debt, which we have guaranteed, and in the case of our $440 million secured credit facility under which we are jointly and severally liable together with Seadrill Partners and certain of their subsidiaries, such lenders may seek repayment from us for which we may not have sufficient funds.  Furthermore, to the extent such debt becomes classified as “current” in the financial statements of our affiliated companies, we may be required under applicable accounting standards to mark such indebtedness as “current” in our consolidated financial statements.  The characterization of the indebtedness in our financial statements as “current” may, among other things, adversely impact our compliance with the covenants contained in our existing and future debt agreements.

In addition, our debt agreements contain cross-default provisions that may be triggered if the entities described above default under the terms of their debt agreements.  In the event of a default by such entities under any of its debt agreements, the lenders under our debt agreements could determine that we are in default under our debt agreements. Such cross-defaults could result in the acceleration of the maturity of the debt under our agreements and our lenders may foreclose upon any collateral securing that debt, including our drilling units and other assets, even if such default was subsequently cured. In the event of such acceleration and foreclosure, we will not have sufficient funds or other assets to satisfy all of our obligations.

The occurrence of any of the events described above would have a material adverse effect on our business, results of operations and financial condition, would significantly reduce our ability or make us unable to pay dividends to our shareholders for so long as such default is continuing, and may impair our ability to continue as a going concern.

We may not be able to raise equity or debt financing sufficient to pay the cost of all of our newbuilding drilling units, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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.

Borrowings under our current credit facilities, which are subject to certain conditions, and available cash on hand are not sufficient to pay the remaining installments related to our contracted commitments of all of our newbuilding drilling units, which as of March 31, 2016 was $4.0 billion. If we are not able to borrow additional funds, raise other capital or utilize available cash on hand, we may not be able to acquire these drilling units, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. If for any reason we fail to make a payment when due under our newbuilding contracts, which may result in a default under our newbuilding contracts, or otherwise fail to take delivery of our newbuild units, we would be prevented from realizing potential revenues from these projects, we could also lose all or a portion of our yard payments that were paid by us, which as of March 31, 2016 amounted to $0.8 billion, and we could be liable for penalties and damages under such contracts. Following such potential defaults we would also be exposed under cross-default provisions in our loan financing agreements.

Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Please also see “—We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us” and “—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.”


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We rely on a small number of customers.

Our contract drilling business is subject to the risks associated with having a limited number of customers for our services. As of December 31, 2015, our five largest customers accounted for approximately 70% of our future contracted revenues, or contract backlog. Our results of operations could be materially adversely affected if any of our major customers fail to compensate us for our services, terminate our contracts with or without cause, fail to renew our existing contracts or refuse to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates.

We are exposed to the credit risks of our key customers and certain other third parties, and nonpayment by these customers and other parties could adversely affect our financial position, results of operations and cash flows.

We are subject to risks of loss resulting from nonpayment or nonperformance 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 nonpayment or nonperformance by these entities, other key customers or certain other third parties could adversely affect our financial position, results of operations and cash flows.

Our international operations in the offshore drilling sector involve additional risks, which could adversely affect our business.

We operate in various regions throughout the world. As a result of our international operations, we may be exposed to political and other uncertainties, including risks of:
•
terrorist acts, armed hostilities, war and civil disturbances;
•
acts of piracy, which have historically affected ocean-going vessels;
•
significant governmental influence over many aspects of local economies;
•
the seizure, nationalization or expropriation of property or equipment;
•
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;
•
regulatory or financial requirements to comply with foreign bureaucratic actions;
•
changing taxation policies, including confiscatory taxation;
•
other forms of government regulation and economic conditions that are beyond our control; and
•
governmental corruption.

In addition, international contract drilling operations are subject to various laws and regulations of the countries in which we operate, including laws and regulations relating to:
•
the equipping and operation of drilling units;
•
the repatriation of foreign earnings and exchange controls;
•
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 our ability to compete. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, the denial of export privileges, injunctions or seizures of assets.


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The Brazilian government has exercised, and continues to exercise, significant influence over the Brazilian economy. This involvement, as well as Brazilian political and economic conditions and uncertainties, could adversely affect our Brazilian operations, our financial results and the market for our common shares.

In the years ended December 31, 2015, 2014 and 2013, 19%, 20% and 16%, respectively, of our revenues were derived from our Brazilian operation, particularly from our contract with Petrobras Brasileiro S.A., a national oil company customer, or Petrobras. The Brazilian government frequently intervenes in the Brazilian economy and occasionally makes significant changes in policy and regulations. The Brazilian government’s actions to control inflation and other policies and regulations have often involved, among other measures, increases in interest rates, changes in tax policies, price controls, currency devaluations, capital controls and limits on imports. Our business, financial condition and results of operations may be adversely affected by changes in policy or regulations at the federal, state or municipal levels involving or affecting factors such as interest rates, monetary policy, currency fluctuations, inflation, the liquidity of domestic capital and lending markets, tax policies, changes in labor laws, the regulatory environment of our industry, exchange rates and exchange controls, and restrictions on remittances abroad, such as those that were briefly imposed in 1989 and early 1990; and other political, social and economic developments in or affecting Brazil.

In addition, current political conditions in Brazil may affect the confidence of investors and the public in general as well as the development of the economy. Uncertainty with regard to matters such as the presidential administration’s future policies and appointments to influential governmental positions and ongoing investigations into allegations of corruption in state-controlled enterprises may also affect the confidence of investors and the general public.

Currently, Brazilian markets are experiencing heightened volatility due to the uncertainties derived from the ongoing Lava Jato investigation, being conducted by the Office of the Brazilian Federal Prosecutor, and its impact on the Brazilian economy and political environment. Certain of these companies are also facing investigations by the Brazilian Securities Commission (Comissão de Valores Mobiliários) (“CVM”) and the Commission. Members of the Brazilian federal government and of the legislative branch, as well as senior officers of large state-owned companies, have faced allegations of political corruption, since they have allegedly accepted bribes by means of kickbacks on contracts granted by the government to several infrastructure, oil and gas, and construction companies. The profits of these kickbacks allegedly financed the political campaigns of political parties of the current federal government coalition that were unaccounted for or not publicly disclosed and served to personally enrich the recipients of the bribery scheme. The potential outcome of these investigations is uncertain, but they have already an adverse impact on the image and reputation of the implicated companies, and on the general market perception of the Brazilian economy. We cannot predict whether such allegations will lead to further political and economic instability or whether new allegations against government officials will arise in the future. In addition, we cannot predict the outcome of any such allegations or their effect on the Brazilian economy.

In the year ended December 31, 2015, Petrobras was our largest customer, accounting for approximately 19% of our revenues. On June 29, 2015, Sevan Drilling disclosed that it had initiated an internal investigation into activities with an agent under certain drilling contracts with Petrobras in Brazil, which were entered prior to the separation from the Sevan Marine Group. Please see “Item 8. Financial Information—Legal Proceedings—Other matters.” In addition, on March 30, 2016, Sevan Drilling and Petrobras terminated early the Sevan Driller contract and reduced the contract dayrate on the drilling contract for the Sevan Brasil. Subsequent to the effective cancellation of the Sevan Driller contract the unit was awarded a contract by Shell in Brazil for 60 days. The combined impact of the cancellation, reduction and new award is a decrease in contract backlog of approximately $127 million.

We cannot assure you that these and other developments in Brazil’s political conditions, economy and government policies will not, directly or indirectly, adversely affect our business and results of operations.
 
Newbuilding projects and surveys are subject to risks that could cause delays or cost overruns.
 
As of March 31, 2016, we had an outstanding newbuilding order book with various yards for an additional 13 drilling units with corresponding contractual yard and other payment commitments totaling $4.0 billion. These construction projects are subject to risks of delay or cost overruns inherent in any large construction project from numerous factors, including shortages of equipment, materials or skilled labor, unscheduled delays in the delivery of ordered materials and equipment or shipyard construction, the failure of equipment to meet quality and/or performance standards, financial or operating difficulties experienced by equipment vendors or the shipyard, unanticipated actual or purported change orders, the inability to obtain required permits or approvals, unanticipated cost increases between order and delivery, design or engineering changes, and work stoppages and other labor disputes, adverse weather conditions or any other events of force majeure, terrorist acts, war, piracy or civil unrest. Significant cost overruns or delays could adversely affect our financial position, results of operations and cash flows. Additionally, failure to complete a project on time may result in the delay of revenue from that rig. For example, on September 14, 2015, we cancelled the construction contract for the West Mira due to the shipyard’s inability to deliver the unit within the timeframe required under the contract, which thereby caused Husky to terminate the five-year drilling contract for the unit with us. In respect of the cancelled construction contract, the shipyard is seeking damages for wrongful termination of the contract, which we reject, and we are counter-claiming damages including for the installment prepaid by us. If we lose, our damages will include the difference in value between the contract price for the rig and the market value of the rig. New drilling rigs may also experience start-up difficulties following delivery or other unexpected operational problems that could result in uncompensated downtime, which also could adversely affect our financial position, results of operations and cash flows or the cancellation or termination of drilling contracts.


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Failure to secure a drilling contract prior to delivery of our newbuilding drilling rigs could adversely affect our results of operations.
 
We have entered into agreements with various shipbuilding yards in Singapore, South Korea and China for the construction of 13 new drilling units consisting of drillships, semi-submersible rigs and jack-up rigs. We have not yet secured any drilling contracts on these newbuilding drilling units. Historically, the industry has at times experienced periods of overcapacity, during which many rigs were idle for a period of time. Our failure to secure a drilling contract for any newbuild drilling units prior to their delivery could adversely affect our cash flows and results of operations. In addition, in the event we are unable to secure a contract for any newbuild drilling units prior to their delivery we may not be able to obtain financing for such drilling units, or we may not be able to obtain financing in the amounts or on the terms that we have obtained financing for other drilling units in the past. We have reached agreements with the shipyards Cosco, Samsung, DSME and Dalian to delay our taking delivery of all the drilling units in our newbuild program, and NADL, our consolidated subsidiary, agreed with Jurong to , among other things, delay taking delivery of the West Rigel until June 2016. There is no assurance that we will be able to further delay taking delivery of our newbuilding drilling rigs that do not have associated drilling contracts. To the extent we delay taking delivery of, or fail to take delivery of, our newbuilding drilling rigs, we would be prevented from realising potential revenues from these units, which would adversely affect our financial position, results of operations and cash flows.
 
Some of our offshore drilling contracts may be terminated early due to certain events.

Some of our customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. The general principle is that such early termination fee shall compensate us for lost revenues less operating expenses for the remaining contract period; however, in some cases, such payments may not fully compensate us for the loss of the drilling contract. Under certain circumstances our contracts may permit customers to terminate contracts early without the payment of any termination fees, as a result of nonperformance, periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events beyond our control. In addition, national oil company customers may have special termination rights by law. During periods of challenging market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of nonperformance. Our customers’ ability to perform their obligations under their drilling contracts with us may also be negatively impacted by the prevailing uncertainty surrounding the development of the world economy and the credit markets. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, the events could adversely affect our consolidated statement of financial position, results of operations or cash flows.

The provisions of the majority of our offshore rig contracts that are term contracts at fixed dayrates may not permit us fully to recoup our costs in the event of a rise in our expenses.
 
The average remaining contract length as of March 31, 2016, was 1.5 years for our floaters and one year for our jack-up rigs. The majority of these contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from term contracts, most of our long-term contracts include escalation provisions. These provisions allow us to adjust the dayrates based on stipulated cost increases, including wages, insurance and maintenance costs. However, actual cost increases may result from events or conditions that do not cause correlative changes to the applicable indices. Furthermore, certain indices are updated semiannually, and therefore may be outdated at the time of adjustment. The adjustments are typically performed on a semi-annual or annual basis. For these reasons, the timing and amount awarded as a result of such adjustments may differ from our actual cost increases, which could adversely affect our financial performance. Some of our long-term contracts contain rate adjustment provisions based on market dayrate fluctuations rather than cost increases. In such contracts, the dayrate could be adjusted lower during a period when costs of operation rise, which could adversely affect our financial performance. Shorter-term contracts normally do not contain escalation provisions. In addition, our contracts typically contain provisions for either fixed or dayrate compensation during mobilization. These rates may not fully cover our costs of mobilization, and mobilization may be delayed, increasing our costs, without additional compensation from the customer, for reasons beyond our control.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues.

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 and affect the entire offshore drilling industry. During periods after which a rig becomes idle, we 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, our operating expenses during a warm stacking will not be substantially different from those we would incur if the rig remained active. We may also decide to “cold stack” the rig, which the 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. However, 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 our drilling 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 units and demand for contract drilling services, which in turn, affect dayrates, and the economic utilization and performance of our fleet of drilling units. However, our operating costs are generally related to the number of units in operation and the cost level in each country or region where the units are located. In addition, equipment maintenance costs fluctuate depending upon the type of activity that the unit is performing and the age and condition of the equipment. In connection with new assignments, we might incur expenses relating to preparation for operations under a new contract. Expenses may vary based on the scope and length of such required preparations and the duration of the contractual period over which such expenditures are amortized. 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

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prepare drilling units for stacking and maintenance in the stacking period. Should units be idle for a longer period, we will seek to redeploy crew members, who are not required to maintain the drilling unit, to active rigs, to the extent possible. However, there can be no assurance that we will be successful in reducing our costs in such cases.

Competition within the offshore drilling industry may adversely affect our results of operations and financial condition.

The offshore drilling industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, the condition and integrity of equipment, 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. 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. Changes in oil and gas 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 drilling units. We have idled and stacked rigs, and may in the future idle or stack additional rigs or enter into lower dayrate drilling contracts in response to market conditions. We 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 industry downturns, which could have a material adverse effect on our results of operations and financial condition.

An economic downturn could have a material adverse effect on our revenue, profitability and financial position.

We depend on our customers’ willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and the demand for energy, including oil and gas. The world economy is currently facing a number of challenges. Concerns persist regarding the debt burden of certain 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. This includes uncertainty surrounding the sovereign debt and credit crises in certain European countries. 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. In addition, 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.

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 results of operations and cash flows beyond what might be offset by the simultaneous impact of possibly higher oil and gas prices.

Failure to obtain or retain highly skilled personnel could adversely affect our operations.

We require highly skilled personnel to operate and provide technical services and support for our business. Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased. The number of rigs in operation may grow in the future as new units are delivered, which could increase the future demand for offshore drilling crews. Notwithstanding the general downturn in the drilling industry, in some regions, such as Brazil and 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. Future 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 for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for qualified personnel, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents.


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Our labor costs and the operating restrictions that apply to us could increase as a result of 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 Brazil, Mexico, Nigeria, Norway and the United Kingdom. In addition, some of our contracted labor works under collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and are restricted in our 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.

An inability to obtain visas and work permits for our employees on a timely basis could hurt our operations and have an adverse effect on our business.

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. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, it could adversely affect our consolidated statement of financial position, results of operations or cash flows.

We have, and may continue, to suffer losses through our investments in other companies in the offshore drilling and oilfield services industry, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We currently hold investments in several other companies in our industry that own/operate offshore drilling rigs with similar characteristics to our fleet of rigs or deliver various other oilfield services. These investments include equity interests in Archer Limited (“Archer”), until recently SapuraKencana Petroleum Berhad, or SapuraKencana and Seabras Sapura Participacoes SA and Seabras Sapura Holding GmbH (together “Seabras Sapura”), among others. In addition, following the deconsolidation of Seadrill Partners on January 2, 2014, and SeaMex Limited, or SeaMex, in March 2015, our interest in Seadrill Partners, Seadrill Operating LP, Seadrill Capricorn Holdings LLC and SeaMex are all treated as investments in associates. The market value of our equity interest in these companies has been, and may continue to be, volatile and has fluctuated, and may continue to fluctuate, in response to changes in oil and gas prices and activity levels in the offshore oil and gas industry. If we sell our equity interest in an investment at a time when the value of such investment has fallen, we may incur a loss on the sale or an impairment loss being recognized, ultimately leading to a reduction in earnings.

In addition, as part of Archer’s broader refinancing package, Seadrill has also agreed to provide additional capital to Archer, in an aggregate amount of up to $75 million in the event that Archer does not have sufficient funds to meet its commitments under its debt facilities by April 30, 2016. As of the balance sheet date, we have not recognized a liability as no obligation existed; however, it is likely that we will be required to do so after April 30, 2016.

During the year ended December 31, 2015 we recorded a loss on impairment of our investments in Seadrill Partners and SapuraKencana totaling $1,274 million. Please see “Note 8—Impairment loss on marketable securities and investments in associated companies” to our Consolidated Financial Statements included herein for further discussion.

Interest rate fluctuations could affect our earnings and cash flow.

In order to finance our growth we have incurred significant amounts of debt. With the exception of some of our bonds, 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. As of December 31, 2015, our total floating rate debt amounted to $8.6 billion, of which we had entered into interest rate swap agreements to fix the interest rate for a principal amount of $7.3 billion. 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, any increase in market interest rates would increase our interest rate exposure and debt service obligations, which would exacerbate the risks associated with our leveraged capital structure.

Fluctuations in exchange rates and the non-convertibility of currencies could result in losses to us.

As a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. dollars. Accordingly, we may experience currency exchange losses if we have not fully hedged our exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. We may also be unable to collect revenues because of a shortage of convertible currency available in the country of operation, controls over currency exchange or controls over the repatriation of income or capital.


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We use the U.S. dollar as our functional currency because the majority of our revenues and expenses are denominated in U.S. dollars. Accordingly, our reporting currency is also U.S. dollars. We do, however, earn revenues and incur expenses in other currencies, such as Norwegian kroner, U.K. pounds sterling and Brazilian reais, and there is a risk that currency fluctuations could have an adverse effect on our statements of operations and cash flows.

If one of our drilling units fails to maintain its class certification or fails any required survey, that drilling unit would be unable to operate, thereby reducing our 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. Our drilling units are certified as being “in class” by the American Bureau of Shipping, or ABS, Det Norske Veritas and Germanisher Lloyd, or DNV GL, and the relevant national authorities in the countries in which our drilling units operate. If any drilling unit does not maintain its class and/or fails any periodical survey or special survey, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable. Any such inability to carry on operations or be employed could have a material adverse impact on our financial condition and results of operations.

We cannot guarantee that the use of our drilling units will not infringe the intellectual property rights of others.

The majority of the intellectual property rights relating to our drilling units and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over an infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services or replacement parts, or could be required to cease using some equipment. In addition, our competitors may assert claims for infringement of intellectual property rights related to certain equipment on our drilling units and we may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of technology disputes involving our suppliers or competitors could adversely affect our financial results and operations. We have provisions in some of our supply contracts to provide indemnity from the supplier against intellectual property lawsuits. However, we cannot make any assurances that these suppliers will be willing or financially able 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.

A change in the tax laws of any country in which we operate could result in a higher tax expense or a higher effective tax rate on our worldwide earnings.

We conduct our operations through various subsidiaries in countries throughout the world. Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, regulations and treaties in and between the countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, regulations or treaties, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, which is beyond our control, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings.

U.S. tax authorities may treat us as a “passive foreign investment company” for U.S. federal income tax purposes, which may have adverse tax consequences for U.S. shareholders.
 
A foreign corporation will be treated as a “passive foreign investment company” (“PFIC”), for U.S. federal income tax purposes if either (1) at least 75% of its gross income for any taxable year consists of certain types of “passive income” or (2) at least 50% of the average value of the corporation’s assets produce or are held for the production of those types of “passive income.” For purposes of these tests, “passive income” includes dividends, interest and gains from the sale or exchange of investment property, and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute “passive income.” U.S. shareholders 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 shares in the PFIC.

Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we intend to take the position that we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. Our position is based on valuations and projections regarding our assets and income. While we believe these valuations and projections to be accurate, such valuations and projections may not continue to be accurate. Moreover, as we have not sought a ruling from the Internal Revenue Service, or IRS, on this matter, the IRS or a court could disagree with our position. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the nature of our operations may change in the future, and if so, we may not be able to avoid PFIC status in the future.
 
If the United States Internal Revenue Service (the “IRS”) were to find that we are or have been a PFIC for any taxable year, our U.S. shareholders may face adverse U.S. federal income tax consequences.  Under the PFIC rules, unless those shareholders make an election available under the United States Internal Revenue Code of 1986, as amended (the “Code”) (which election could itself have adverse consequences for such shareholders, as discussed below under “Item 10. Additional Information—E. Taxation”), such shareholders would be liable to pay U.S. federal

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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 shares, as if the excess distribution or gain had been recognized ratably over the shareholder’s holding period of the common shares. In the event that our shareholders face adverse U.S. federal income tax consequences as a result of investing in shares of our common stock, this could adversely affect our ability to raise additional capital through the equity markets. See “Item 10. Additional Information—E. Taxation” for a more comprehensive discussion of the U.S. federal income tax consequences to U.S. shareholders if we are treated as a PFIC.
 
Investors are encouraged to consult their own tax advisers concerning the overall tax consequences of the ownership of the common shares arising in an investor’s particular situation under U.S. federal, state, local or foreign law.

We depend on directors who are associated with affiliated companies, which may create conflicts of interest.

Our principal shareholder is Hemen Holding Limited, or Hemen. All of our directors also serve as directors of other companies affiliated with Hemen. Our directors owe fiduciary duties to both us and other related parties, and may have conflicts of interest in matters involving or affecting us and our customers. In addition, they may have conflicts of interest when faced with decisions that could have different implications for other related parties than they do for us. We cannot assure you that any of these conflicts of interest will be resolved in our favor.

We may be restricted from competing with Seadrill Partners under the Omnibus Agreement with Seadrill Partners.

We have entered into an omnibus agreement with Seadrill Partners (the “Omnibus Agreement”) in connection with its initial public offering, which may restrict our ability to, among other things, acquire, own, operate or contract for certain drilling units operating under drilling contracts of five or more years, unless we offer to sell such drilling units to Seadrill Partners. These restrictions could harm our business and adversely affect our financial position and results of operations and ability to implement our growth strategy. For additional information, please see “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions—Seadrill Partners—Omnibus Agreement with Seadrill Partners.”

We may not pay dividends in the future.

Under our bye-laws, any dividends declared will be in the sole discretion of our Board of Directors, or the Board, and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities. Under Bermuda law, we may not declare or pay a dividend, or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) we are, or would after the payment be, unable to pay our liabilities as they become due or (b) the realizable value of our assets would thereby be less than our liabilities. In addition, since we are a holding company with no material assets other than the shares of our subsidiaries through which we conduct our operations, our ability to pay dividends will depend on our subsidiaries distributing to us their earnings and cash flow. We suspended the payment of dividends in November 2014, and we cannot predict when, or if, dividends will be paid in the future. In connection with the amendments to our secured loan agreements in May 2015 to increase the leverage ratio contained in our senior secured credit facilities, we are restricted from paying dividends so long as the amended ratio is in effect, until January 1, 2017. In addition, in April 2016, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from making dividend distributions during the amendment period until June 30, 2017.

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. 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 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 example, we are currently a defendant in a class action lawsuit alleging that we made certain materially false and misleading statements in our public disclosure. One of our subsidiaries is also currently a party in an arbitration proceeding regarding its cancellation of the construction contract for the West Mira. Although we are vigorously defending these claims, we cannot predict the outcome of these cases, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized within our Consolidated Financial Statements. For additional information on these, and other, litigation matters that we are currently involved in, please see “Item 8. Financial Information—A. Consolidated Statements and Other Financial Information—Legal Proceedings.”

Risks Relating to Our Industry

Our business and operations involve numerous operating hazards, and our insurance and indemnities from our customers may not be adequate to cover potential losses from our operations.

Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch-throughs, craterings, fires, explosions and pollution. Contract drilling and well servicing require the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution

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or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. We customarily provide contract indemnity to our customers for claims that could be asserted by us relating to damage to or loss of our equipment, including rigs and claims that could be asserted by us or our employees relating to personal injury or loss of life.

Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurances that these customers will be willing or financially able to indemnify us against all these risks. In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 case related to the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the Gulf of Mexico in April 2010, or the Deepwater Horizon Incident (to which we were not a party), the U.S. District Court for the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the U.S. Clean Water Act under a drilling contract governed by U.S. maritime law as a matter of public policy. Further, pollution and environmental risks generally are not totally insurable.

If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect our consolidated statement of financial position, results of operations or cash flows. The amount of our insurance may also be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes 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. In addition, we could decide to retain more risk through self-insurance in the future. This self-insurance results in a higher risk of losses, which could be material, which are not covered by third-party insurance contracts. Specifically, we have at times in the past elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico due to the substantial costs associated with such coverage. Beginning April 1, 2014 we have insured a limited part of this windstorm risk in a combined single limit annual aggregate policy. We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a combined single limit of $100 million in the annual aggregate, which includes loss of hire. We have renewed our policy to insure a limited part of this windstorm risk for a further period starting May 1, 2016 through April 30, 2017. If we elect to self-insure such risks again in the future and such windstorms cause significant damage to any rig and equipment we have in the U.S. Gulf of Mexico, it could have a material adverse effect on our financial position, results of operations or cash flows. Moreover, no assurance can be made that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, or that we will be able to obtain insurance against certain risks.

Governmental laws and regulations, including environmental laws and regulations, may add to our costs, expose us to liability or limit our drilling activity.

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. The offshore drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and, 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. Our ability to compete in international contract drilling markets may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. Offshore drilling in certain areas, including arctic areas, has been curtailed and, in certain cases, prohibited because of concerns over protecting of the environment. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

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 to the offshore drilling industry, in particular, our business or prospects could be materially adversely affected. The operation of our drilling units will require 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. 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.


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As an operator of mobile drilling units, we may be liable for damages and costs incurred in connection with spills of oil and other chemicals and substances related to our operations, and we may also be subject to significant fines in connection with spills. For example, an oil spill could result in significant liability, including fines, penalties, criminal liability and remediation costs for natural resource damages under other international laws, as well as third-party damages, to the extent that the contractual indemnification provisions in our drilling contracts are not sufficient, or if our customers are unwilling or unable to contractually indemnify us from these risks. Additionally, we may not be able to obtain such indemnities in our future contracts and our customers may not have the financial capability to fulfill their contractual obligations to us. Also, these indemnities may be held to be unenforceable in certain jurisdictions, as a result of public policy or for other reasons. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence. These laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for acts that were in compliance with all applicable laws at the time when such acts were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations or cash flows.

We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to numerous international, national, state and local laws and regulations, treaties and conventions in force in international waters and the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. These requirements include, but are not limited to the United Nation’s International Maritime Organization (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 IMO 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 IMO International Convention on Load Lines in 1966, as from time to time amended, the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004 (the “BWM Convention”), the U.S. Oil Pollution Act of 1990 (the “OPA”), requirements of the U.S. Coast Guard (the “USCG”), the U.S. Environmental Protection Agency (the “EPA”), the U.S. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the U.S. Maritime Transportation Security Act of 2002, the U.S. Outer Continental Shelf Lands Act, certain regulations of the European Union, and Brazil’s National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Federal Law (9966/2000) relating to pollution in Brazilian waters. 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.


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If we are able to obtain from our customers some degree of contractual indemnification against pollution and environmental damages in our contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases, and we may not be able to obtain such indemnification agreements in the future. In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. 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.

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

Climate change and the regulation of greenhouse gases could have a negative impact on our business.

Due to concern over the risk of climate change, a number of countries and the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions. The 2015 United Nations Climate Change Conference in Paris did not result in an agreement that directly limits greenhouse gas emissions from ships. As of January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted by the IMO’s Maritime Environment Protection Committee (the “MEPC”) in July 2011, relating to greenhouse gas emissions. The European Union has indicated that it intends to propose an expansion of the existing EU Emissions Trading Scheme to include emissions of greenhouse gases from marine vessels.

Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining our assets, and might also require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. Any passage of climate control legislation or other regulatory initiatives by the IMO, the European Union, the United States or other countries in which we operate, or any treaty adopted at the international level to succeed the Kyoto Protocol, which restricts emissions of greenhouse gases, could require us to make significant financial expenditures which we cannot predict with certainty at this time.

Additionally, adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also adversely affect demand for our services. For example, increased regulation of greenhouse gases or other concerns relating to climate change may reduce the demand for oil and gas in the future or create greater incentives for the use of alternative energy sources. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business, including capital expenditures to upgrade our drilling rigs, which we cannot predict with certainty at this time.

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.

In the near-term aftermath of the Deepwater Horizon Incident, in which we were not involved, which led to the Macondo well blowout, 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 N-06, 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 (the “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 U.S Bureau of Safety and Environmental Enforcement (the “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 have complied 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 Mobile Offshore Drilling UNits, or 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, such as the American Petroleum Institute Standard 53 relating to the installation and testing of well control equipment. Likewise, in August 2015, the U.S Bureau of Ocean Energy Management (the “BOEM”) issued a Notice to Lessees (NTL 2015-NO4), regarding things such as the general financial assurance required before drilling. In December 2015, the BSEE announced a new pilot inspection program for offshore facilities. These new and proposed guidelines and standards for safety, environmental and financial assurance and any other new guidelines or standards the U.S. government or

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industry may issue or any other steps the U.S. government or industry may take, could disrupt or delay operations, increase the cost of operations, increase out-of-service time or reduce the area of operations for drilling rigs in U.S. and non-U.S. offshore areas.

We continue to evaluate these new measures to ensure that our rigs and equipment are in full compliance, where applicable. As new standards and procedures are being integrated into the existing framework of offshore regulatory programs, we anticipate that there may be increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as re-completions, workovers and abandonment activities.

Additional requirements could be forthcoming based on further recommendations by regulatory agencies investigating the Macondo incident. For example, in April 2015 it was announced that new regulations are expected to be imposed in the United States regarding offshore oil and gas drilling. We are not able to predict the likelihood, nature or extent of additional rulemaking or when the interim rules, or any future rules, could become final. The current and future regulatory environment in the U.S. Gulf of Mexico could impact the demand for drilling units in the U.S. Gulf of Mexico in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the U.S. Gulf of Mexico. It is possible that short-term potential migration of rigs from the U.S. Gulf of Mexico could adversely impact dayrate 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 our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration and development activity in the U.S. Gulf of Mexico and, therefore, reduce demand for our services. In addition, insurance costs across the industry are expected to increase 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. We cannot predict if the U.S. government will issue new drilling permits in a timely manner, nor can we predict the potential impact of new regulations that may be forthcoming as the investigation into the Macondo well incident continues. Nor can we predict if implementation of additional regulations might subject us to increased costs of operating and/or a reduction in the area of operation in the U.S. Gulf of Mexico. As such, our cash flow and financial position could be adversely affected if our three ultra-deepwater semi-submersible drilling rigs and three ultra-deepwater drillships operating in the U.S. Gulf of Mexico were subject to the risks mentioned above.

If our drilling units are located in countries that are subject to economic sanctions or other operating restrictions imposed by the United States. or other governments, our reputation and the market for our common shares could be adversely affected.

In 2010, the United States enacted the Comprehensive Iran Sanctions Accountability and Divestment Act, or CISADA, which expanded the scope of the former Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to non-U.S. companies such as ours, and introduced limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. On August 10, 2012, the U.S. signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the Iran Threat Reduction Act, which places further restrictions on the ability of non-U.S. companies to do business or trade with Iran and Syria. Perhaps the most significant provision in the Iran Threat Reduction Act is that prohibitions in the existing Iran sanctions applicable to U.S. persons will now apply to any foreign entity owned or controlled by a U.S. person. These new sanctions were codified within the Iranian Transactions Regulations on or about December 26, 2012. The other major provision in the Iran Threat Reduction Act is that issuers of securities must disclose to the Commission in their annual and quarterly reports filed 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 Commission will publish the disclosure on its website. The President of the United States 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, we are not aware of any violative activity, conducted by us or by any affiliate, which is likely to trigger a Commission disclosure requirement.

Sanctions affecting non-U.S. companies like us were expanded yet again under the 2013 National Defense Authorization Act, with the passage of the Iran Freedom and Counter-Proliferation Act, and we believe that these sanctions will continue to become more restrictive for the foreseeable future. In addition to the sanctions against Iran, subject to certain exceptions, U.S. law continues to restrict U.S. owned or controlled entities from doing business with Cuba and various U.S. sanctions have certain other extraterritorial effects that need to be considered by non-U.S. companies. Moreover, any U.S. persons who serve as officers, directors or employees of our subsidiaries would be fully subject to U.S. sanctions. It should also be noted that other governments are more frequently implementing sanctions regimes.

From time to time, we may enter into drilling contracts with countries or government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism where entering into such contracts would not violate U.S. law, or may enter into drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S government and/or identified by the U.S. government as state sponsors of terrorism. However, this could negatively affect our ability to obtain investors. In some cases, U.S. investors would be prohibited from investing in an arrangement in which the proceeds could directly or indirectly be transferred to or may benefit a sanctioned entity. Moreover, even in cases where the investment would not violate U.S. law, potential investors could view such drilling contracts negatively, which could adversely affect our reputation and the market for our shares. With the exception of certain drilling contracts between our majority-owned subsidiary NADL and Rosneft Oil Company, or Rosneft, for activity in Russian Arctic and deepwater areas, we do not currently have any drilling contracts or plans to initiate any drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism.

On November 24, 2013, the P5+1 (the United States, United Kingdom, Germany, France, Russia and China) entered into an interim agreement with Iran entitled the “Joint Plan of Action,” or the JPOA. Under the JPOA it was agreed that, in exchange for Iran taking certain voluntary

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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 indicated that they would begin implementing the temporary relief measures provided for under the JPOA. These measures include, among other things, the suspension of certain sanctions on the Iranian petrochemicals, precious metals and automotive industries from January 20, 2014 to July 20, 2014.

The JPOA was subsequently extended twice. On July 14, 2015, the P5+1 and the E.U. 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, which is intended 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 does not involve U.S. persons. On January 16, 2016 (“Implementation Day”), the United States joined the E.U. 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.

Certain of our customers or other 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. In addition, such sanctions may prevent us from closing the previously announced transactions between our subsidiary NADL and Rosneft, or performing some or all of our obligations under any potential drilling contracts with Rosneft, which could impact our future revenue, contract backlog and results of operations.

As stated above, we believe that we are in compliance with all applicable sanctions and embargo laws and regulations, and intend to maintain such compliance. However, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in our shares. Additionally, some investors may decide to divest their interest, or not to invest, in our shares simply because we may do business with companies that do business in sanctioned countries. Moreover, our drilling contracts may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, or our drilling rigs, and those violations could in turn negatively affect our reputation. Investor perception of the value of our shares may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.

Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.

The shipment of goods, services and technology across international borders subjects our offshore drilling segment to extensive trade laws and regulations. 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. 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 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.

Our ability to operate our 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 drilling units unaffiliated to us in the Gulf of Mexico. The Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) formerly the Minerals Management Service of the U.S. Department of the Interior, effective October 1, 2011, reorganized into two new organizations: the BOEM and the 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. The BSEE subsequently issued additional guidelines requiring MODUs to be outfitted with global positioning systems (“GPS”) and to provide the BSEE with real-time GPS location data for MODUs effective March 19, 2013. These guidelines effectively impose new requirements on the offshore oil and natural gas industry in an attempt to increase the likelihood of the survival of offshore drilling units during a hurricane. The

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guidelines also provide for enhanced information and data requirements from oil and natural gas companies that operate properties in the U.S. Gulf of Mexico region of the outer continental shelf. The BOEM and the 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 our ultra-deepwater drilling units, thereby reducing their marketability. Implementation of new guidelines or regulations that may apply to ultra-deepwater drilling units may subject us to increased costs and limit the operational capabilities of our drilling units, although such risks should rest with our customers, to the extent possible.

We currently do not have any jack-up rigs or moored drilling units operating in the U.S. Gulf of Mexico. However, we do have one ultra-deepwater semi-submersible drilling rig and one ultra-deepwater drillship operating in the U.S. Gulf of Mexico, both of which are self-propelled and equipped with thrusters and other machinery, that enable the rigs to move between drilling locations and remain in position while drilling without the need for anchors.

Violations of the U.S. Foreign Corrupt Practices Act of 1977 or the Bribery Act 2010 of the United Kingdom could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

We currently operate, and historically have operated, our drilling units in a number of countries throughout the world, including some with developing economies. 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. For instance, our controlled subsidiary Sevan has previously disclosed that its predecessor entity, Sevan Drilling ASA, has been accused of breaches of Norwegian law in respect of payments made in connection with the performance during 2012 to 2015 of drilling contracts originally awarded by Petrobras to subsidiaries of Sevan Marine ASA in the period between 2005 and 2008. Furthermore, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

In order to effectively compete in some foreign jurisdictions, we utilize local agents and/or establish entities with local operators or strategic partners. All of these activities may involve interaction by our agents with government officials. Even though some of our agents and partners may not themselves be subject to the FCPA, the U.K. Bribery Act or other anti-bribery laws to which we may be subject, if our agents or partners make improper payments to government officials or other persons in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violations of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on our business and results of operation.

The consolidation of suppliers may increase the cost of obtaining supplies, or restrict our ability to obtain needed supplies, which may have a material adverse effect on our results of operations and financial condition.

We rely on certain third parties to provide supplies and services necessary for our offshore drilling operations, including, but not limited to, drilling equipment suppliers, catering and machinery suppliers. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing key supplies. With respect to certain items, such as blow-out preventors (“BOPs”), we are dependent on the original equipment manufacturer for repair and replacement of the item or its spare parts. Such consolidation, combined with a high volume of drilling units under construction, may result in a shortage of supplies and services, thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time. These cost increases or delays could have a material adverse effect on our results of operations and result in rig downtime, and delays in the repair and maintenance of our drilling rigs.

Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.

Acts of terrorism, piracy, and political and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. Our drilling operations could also be targeted by acts of sabotage carried out by environmental activist groups. In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower dayrates. Insurance premiums could also increase and coverage may be unavailable in the future. Increased insurance costs or increased costs of compliance with applicable regulations may have a material adverse effect on our results of operations.

A cyber-attack could materially disrupt our business.

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.


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We may not be able to keep pace with the continual and rapid technological developments that characterize the market for our services, and our failure to do so may result in our loss of market share.

The market for our services is characterized by continual and rapid technological developments that have resulted in, and will likely continue to result in, substantial improvements in equipment functions and performance. As a result, our future success and profitability will be dependent in part upon our ability to keep pace with technological developments. If we are not successful in acquiring new equipment or upgrading our existing equipment in a timely and cost-effective manner in response to technological developments or changes in standards in our industry, we could lose business and profits. The cost of upgrading our equipment may increase as our fleet ages, which could adversely affect our financial performance. In addition, current competitors or new market entrants may develop new technologies, services or standards that could render some of our services or equipment obsolete, which could have a material adverse effect on our operations.

Public health threats could have an adverse effect on our operations and financial results.

Public health threats, such as ebola, influenza, SARS, the Zika virus, and other highly communicable diseases or viruses, outbreaks of which have from time to time occurred in various parts of the world in which we operate, could adversely impact our operations, and the operations of our customers. In addition, public health threats in any area, including areas where we do not operate, could disrupt international transportation. Our crews generally work on a rotation basis, with a substantial portion relying on international air transport for rotation. Any such disruptions could impact the cost of rotating our crews, and possibly impact our ability to maintain a full crew on all rigs at a given time. Any of these public health threats and related consequences could adversely affect our financial results.


Risks Relating to Our Common Shares
 
The market price of our common shares has recently declined significantly.  If the average closing price of our common shares declines to less than $1.00 over 30 consecutive trading days, our common shares could be delisted from the NYSE or trading could be suspended.

Our common shares are currently listed on the NYSE. In order for our common shares 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 share during a consecutive 30 trading-day period. A renewed or continued decline in the closing price of our common shares 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 shares. 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 shares, we would expect decreases in institutional and other investor demand, analyst coverage, market making-activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such common shares. A suspension or delisting would likely decrease the attractiveness of our common shares to investors and cause the trading volume of our common shares to decline, which could result in a further decline in the market price of our common shares.

Because we are a foreign corporation, you may not have the same rights that a shareholder in a U.S. corporation may have.
 
We are a Bermuda exempted company limited by shares. Our memorandum of association and bye-laws and the Companies Act, 1981 of Bermuda (the “Companies Act”) govern our affairs. The Companies Act does not clearly establish your rights and the fiduciary responsibilities of our directors as do statutes and judicial precedent in some U.S. jurisdictions. Therefore, it may be more difficult to protect your interests as a shareholder in relation to the actions of management, directors or controlling shareholders, than it would be for shareholders of U.S. corporations to do the same. There is a statutory remedy under Section 111 of the Companies Act which provides that a shareholder may seek redress in the courts as long as such shareholder can establish that our affairs are being conducted, or have been conducted, in a manner oppressive or prejudicial to the interests of some part of the shareholders, including such shareholder.
 
We are incorporated in Bermuda and it may not be possible for our investors to enforce U.S. judgments against us.

We are incorporated in Bermuda and substantially all of our assets are located outside the United States. In addition, all but one of our directors and all but one of our executive officers are non-residents of the United States, and all or a substantial portion of the assets of these nonresidents are located outside the U.S. As a result, it may be difficult or impossible for U.S. investors to serve process in the United States upon us or our directors and executive officers, or to enforce a judgment against us for civil liabilities in U.S. courts.

In addition, you should not assume that courts in the countries in which we are incorporated or where our assets are located would enforce judgments of U.S. courts obtained in actions against us based upon the civil liability provisions of applicable U.S. federal and state securities laws or would enforce, in original actions, liabilities against us based on those laws.

We are subject to certain anti-takeover provisions in our constitutional documents.
 
Several provisions of our bye-laws may have anti-takeover effects. These provisions are intended to avoid costly takeover battles, lessen our vulnerability to a hostile change of control and enhance the ability of our Board to maximize shareholder value in connection with any unsolicited offer to acquire us. However, these anti-takeover provisions could also discourage, delay or prevent the merger, amalgamation or acquisition of

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our company by means of a tender offer, a proxy contest or otherwise, that a shareholder may consider to be in its best interests. For more detailed information, please see “Item 10. Additional Information.”

The market price of our common shares has fluctuated widely and may fluctuate widely in the future

The market price of our common shares 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 financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. Further, there may be no continuing active or liquid public market for our common shares. If an active trading market for our common shares does not continue, the price of our common shares may be more volatile and it may be more difficult and time consuming to complete a transaction in the common shares, which could have an adverse effect on the realized price of the common shares. In addition, an adverse development in the market price for our common shares could negatively affect our ability to issue new equity to fund our activities.


ITEM 4.
INFORMATION ON THE COMPANY
 
A.
HISTORY AND DEVELOPMENT OF THE COMPANY
 
The Company
Seadrill Limited was incorporated in Bermuda under the Companies Act on May 10, 2005 as an exempted company limited by shares.  Our shares of common stock have been listed under the symbol “SDRL” on the Oslo Stock Exchange (the “OSE”) since November 2005 and on the NYSE since April 2010. Our principal executive offices are located at Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda and our telephone number is +1 (441) 295-6935.

We are an offshore drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of drillships, semi-submersible rigs and jack-up rigs for operations in shallow-, mid-, deep-, and ultra deepwater areas, and in benign and harsh environments. We contract our drilling units primarily on a dayrate basis to drill wells for our customers, who are oil super-majors and major integrated oil and gas companies, state-owned national oil companies, and independent oil and gas companies. A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. We also provide management services to certain unconsolidated companies in which we hold investments.

Through a number of acquisitions of companies, secondhand units and contracts for newbuildings, we have developed into one of the world’s largest international offshore drilling contractors, employing approximately 6,995 skilled employees. At March 31, 2016, we had a fleet of 38 offshore drilling units consisting of 12 semi-submersible rigs, seven drillships and 19 jack-up rigs in operation, and contracts for the construction of 13 offshore drilling units. Of the total fleet, 12 are currently idle. Please see “Item 4. Information on the Company—D. Property, Plant and Equipment,” for further information on our fleet of drilling units and newbuildings.

Our Majority-Owned Subsidiaries
NADL is a Bermuda company formed in 2011 that focuses entirely on harsh environment offshore drilling operations. In January 2014, NADL completed its initial public offering (“IPO”) in the United States of 13,513,514 common shares at $9.25 per share. As of March 31, 2016, we owned approximately 70.4% of NADL’s outstanding common shares, which are listed for trading on the NYSE and the Norwegian Over-the-Counter Exchange (the “Norwegian OTC”) under the symbol “NADL.” For the year ended December 31, 2015, NADL contributed $748 million (or 17%) to our revenues, and $98 million (or 10%) to our operating income. The outstanding debt of NADL as of December 31, 2015 amounted to $2,128 million (or 20%), of which $1,715 million is guaranteed by Seadrill.

Sevan Drilling, a controlled subsidiary, is a Bermuda company that focuses on owning and operating drilling units and specializes in the ultra-deepwater segment. As of March 31, 2016, we owned 50.1% of the outstanding shares in Sevan Drilling. Sevan Drilling’s common shares trade on the OSE under the symbol “SEVDR.” For the year ended December 31, 2015, Sevan Drilling contributed $478 million (or 11%), and $217 million (or 21%) to our revenue and operating income, respectively. The outstanding debt of Sevan Drilling as of December 31, 2015 amounted to $1,085 million (or 10%), all of which is guaranteed by Seadrill.

AOD, a controlled subsidiary, is a company incorporated in Bermuda that owns and operates three high-specification jack-up drilling rigs. As of March 31, 2016, we owned 66.2% of the outstanding shares in AOD. For the year ended December 31, 2015, AOD contributed $214 million (or 5%) and $105 million (or 10%) to our revenue and operating income, respectively. The outstanding debt of AOD as of December 31, 2015 amounted to $273 million (or 3%), all of which is guaranteed by Seadrill.

Investments in Other Companies
In addition to owning and operating our offshore drilling units through our subsidiaries, we also, from time to time, make investments in other offshore drilling and oil services companies. We currently have the following significant equity investments, among others, in other companies in our industry:

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•
Seadrill Partners, an associated company, is a Marshall Islands limited liability company formed in 2012 that focuses on owning and operating offshore drilling rigs under long-term contracts with major oil companies. In October 2012, Seadrill Partners completed its IPO in the United States of 8,750,000 common units at $22.00 per unit. Seadrill Partners was a consolidated subsidiary of Seadrill, but as of January 2, 2014, we deconsolidated Seadrill Partners from our financial statements. As of December 31, 2015, we own 46.6% of the outstanding limited liability interests of Seadrill Partners, which includes outstanding common and subordinated units. Seadrill Partners’ common units trade on the NYSE under the symbol “SDLP.” We also own significant non-controlling interests in various subsidiaries of Seadrill Partners. Furthermore, we are a guarantor under certain of Seadrill Partners’ credit facilities, and we also have joint and several liability under certain of Seadrill Partners’ credit facilities. Please see Note 23 of our Consolidated Financial Statements included herein for more information.
•
Archer is a global oilfield service company that specializes in drilling and well services. We currently own 39.9% of the outstanding common shares of Archer and provide various financial and performance guarantees on behalf of Archer. The total outstanding guarantees to Archer as of December 31, 2015 was $326 million. In addition, we have agreed to inject additional capital to Archer, in an aggregate amount of up to $75 million in the event that Archer will not have sufficient funds to repay and cancel commitments under its facilities by April 30, 2016.
•
Seabras Sapura is a group of related companies that construct, own and operate pipe-laying service vessels in Brazil. We have a 50% ownership stake in each of these companies. We have provided Seabras Sapura with various loans to finance working capital and financial guarantees. The total amount of loans outstanding as of December 31, 2015 was $46 million, and the total amount guaranteed as of December 31, 2015 was $498 million. In addition, we provide bank guarantees in relation to certain credit facilities to cover six months of debt service costs and three months of operating expenses under retention accounts. The total amount guaranteed as of December 31, 2015 was $52 million.
•
SeaMex, a joint venture, that owns and operates five jack-up drilling units located in Mexico under contract with Petróleos Mexicano, or Pemex. We and an investment fund controlled by Fintech Advisory Inc., or Fintech, have a 50% ownership stake in SeaMex, respectively. SeaMex was deconsolidated from our financial statements on March 10, 2015. We have provided a $250 million seller’s credit to SeaMex divided into two facilities: (a) a term loan facility for an amount up to $230 million and (b) a revolving loan facility of up to $20 million, and made available a subordinated unsecured credit facility of $20 million, which is to be provided by both Seadrill and Fintech at a ratio of 50.0% each. As of December 31, 2015 the facility remained undrawn. We have also provided loan facilities for a $30 million bank guarantee to the lenders of SeaMex’s external bank facility, $51 million under a joint and several guarantee for potential prepayment deficits that SeaMex might face under its loan agreements, and performance guarantees for the SeaMex drilling units, up to a total of $30 million as of December 31, 2015.
•
Ship Finance is a related party of the Company through which we have entered into sale and leaseback agreements for three drilling units: the West Taurus, West Hercules and West Linus. As of December 31, 2015, through our VIEs we had gross loans outstanding to Ship Finance amounting to $415 million and net loans of $387 million.

Please see the Notes to our Consolidated Financial Statements included herein for further information on our investments.

Management of the Company
Overall responsibility for the management of Seadrill Limited and its subsidiaries rests with the Board. The Board has organized the provision of management services through Seadrill Management Ltd., or Seadrill Management, one of our subsidiaries incorporated in the United Kingdom. The Board has defined the scope and terms of the services to be provided by Seadrill Management, authorizing it to run day-to-day operations. The Board must be consulted on all matters of material importance and/or of an unusual nature and, for such matters, will provide specific authorization to personnel in Seadrill Management to act on its behalf.

Seadrill Management also has service and other management agreements with Seadrill Partners and SeaMex (our associated companies) and SapuraKencana, pursuant to which Seadrill Management provides management and operational services relating to various drilling units owned by these companies.

Recent Developments

Significant Developments for the Period from January 1, 2013 Through and Including December 31, 2015

Capital expenditures
We had total capital expenditures on our drilling units and newbuildings of approximately $1.0 billion, $3.2 billion and $4.5 billion in the years ended 2015, 2014 and 2013, respectively. This includes maintenance expenditures of $0.1 billion, $0.3 billion and $0.2 billion in the years ended 2015, 2014 and 2013, respectively. Our capital expenditures related primarily to our newbuild drilling unit program, capital additions and equipment to our existing drilling units and payments for long-term maintenance of our fleet. We financed this capital expenditure through cash generated from operations, secured and unsecured debt arrangements, and the sale of partial ownership interests in certain subsidiaries and investments. Please see “Item 4. Information on the Company—D. Property, Plant and Equipment” and “Item 5. Operating and Financial Review and Prospects” for further information on our fleet.


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Sale of investments
On April 27, 2016 the Company sold all of its investment in shares of SapuraKencana resulting in net cash proceeds of approximately $195 million.

Disposals
In 2013, we sold the entities that own and operate ten tender rigs to SapuraKencana for an enterprise value of $2.9 billion. The sale included the following tender rigs: T-4, T-7, T-11, T-12, West Alliance, West Berani, West Jaya, West Menang, West Pelaut, West Setia, and the newbuild rigs T-17, T-18, and West Esperanza. In addition, our 49% ownership in Varia Perdana and Tioman Drilling was sold as part of this transaction, which included the following rigs: T-3, T-6, T-9, T-10, and the Teknik Berkat. We also sold the entities that own and operate the tender rigs T-15 and T-16 and semi-submersible rigs West Leo and West Sirius to subsidiaries of Seadrill Partners. As of December 31, 2013, Seadrill Partners was a consolidated subsidiary and therefore no gain or loss was recorded on our sale.

In 2014, we sold the entities that own and operate the West Auriga to Seadrill Capricorn Holdings LLC, which is owned 49% by the Company and 51% by Seadrill Partners, for $1.24 billion, of which Seadrill Partners’ 51% share was $632 million, along with the entities that own and operate the West Vela for $900 million, of which Seadrill Partners’ 51% share was $459 million. We also sold an additional 28% interest in Seadrill Operating LP, a limited partnership controlled by Seadrill Partners, for $373 million to Seadrill Partners, which reduced our ownership interest in Seadrill Operating LP to 42%. In addition, during the twelve months ended December 31, 2014, we sold a portion of our investment in SapuraKencana and received proceeds of $297 million, net of transaction costs. As a result of the sale, a gain of $131 million was recognized, which is included in the consolidated statement of operations in “Gain on realization of marketable securities.” As a result of this transaction, our ownership interest in SapuraKencana’s outstanding common shares decreased to 8.18%.

In 2015, we sold the entities that own and operate the West Polaris to Seadrill Operating LP, a consolidated subsidiary of Seadrill Partners and an entity in which we own a 42% limited partner interest. Please see “Note 11–Disposals of businesses and deconsolidation of subsidiaries” to our Consolidated Financial Statements included herein, for more information.

Deconsolidations
We deconsolidated Seadrill Partners on January 2, 2014. As a result of the deconsolidation, we derecognized the assets and liabilities of Seadrill Partners and recognized our ownership interests in Seadrill Partners and its subsidiaries,at fair value. Please see “Note 11–Disposals of businesses and deconsolidation of subsidiaries” to our Consolidated Financial Statements included herein for further discussion on deconsolidation of Seadrill Partners.

On March 10, 2015, Fintech subscribed for a 50% ownership interest in SeaMex, which was previously 100% owned by us. As a result of the transaction we deconsolidated certain entities as of March 10, 2015 and recognized our remaining 50% investment in the joint venture at fair value. Please refer to “Note 11 - Disposals of businesses and deconsolidation of subsidiaries” to our Consolidated Financial Statements included herein, for more information.

Newbuilding Deferrals and Cancellations
In August 2015, Samsung agreed to postpone the delivery of the West Dorado and the West Draco until the end of the first quarter of 2017, and Dalian agreed to defer one jack-up rig until the end of December 2015, five jack-up rigs to 2016 and two jack-up rigs to 2017.

On September 14, 2015, we cancelled the construction contract for the West Mira due to HSHI inability to deliver the unit within the timeframe required under the contract, which thereby caused Husky to terminate the five-year drilling contract for the unit with us. Please see “Item 3. Key Information—D. Risk Factors—Risks Relating to Our Company—We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.”

On October 30, 2015, we mutually agreed with Cosco to exercise the first six-month option to extend the deferral agreement for the delivery of the Sevan Developer. In addition, on April 15, 2016, we exercised our second six-month deferral option, until October 15, 2016. Sevan Drilling and Cosco have two remaining six-month deferral options available.

On January 15, 2016, we entered into an agreement with DSME to defer the delivery of two ultra-deepwater drillships, the West Aquila and West Libra, until the second quarter 2018 and the first quarter of 2019, respectively.

On April 18, 2016, we entered into agreements with Dalian to further defer the deliveries of all eight jack-up rigs under construction, which were previously due to be delivered in 2016 and 2017. Following this latest deferral agreement, one unit is scheduled to be delivered to us at the end of 2016, four units in 2017, and three units in 2018.



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On December 3, 2015, NADL entered into an agreement with Jurong, effective until June 2016, regarding the delivery of the West Rigel. During the period until June 2016, NADL will continue to market the unit for an acceptable drilling contract and the unit will remain at the Jurong yard in Singapore. Jurong and NADL can also consider other commercial opportunities for the unit during this period. In the event no employment is secured and no alternative transaction is completed before the period concludes, NADL and Jurong have agreed to form a joint asset holding company for joint ownership of the unit to be owned 23% by NADL and 77% by Jurong.  NADL will continue to market the unit for the joint asset holding company .

Acquisitions
In December 2013, we acquired the high specification jack-up newbuild in process, Prospector 3, from Prospector Offshore Drilling Rig Construction S.à.r.l., an unrelated party, for a total purchase price of $235 million. The rig was subsequently renamed West Titania.

In July 2013, we obtained control of 50.1% of the total outstanding shares of Sevan Drilling, which resulted in Sevan Drilling becoming a consolidated subsidiary from July 2, 2013 and triggered the requirement to make a mandatory offer in accordance with the OSE rules for the remaining outstanding shares in Sevan, bringing our total interest in Sevan to 50.11%.

In March 2013, we signed a shareholder resolution with Mermaid Maritime Plc that aligned the percentage of our voting rights with our majority ownership of AOD. Based on this change, we obtained control of the board of directors of AOD and consolidated its results and financial position from March 25, 2013. We currently own 66.23% of the outstanding common shares of AOD.

For the year ended December 31, 2013 we also entered into agreements with yards to construct eight high-specification jack-up rigs and four ultra-deepwater drillships with a total estimated project price for all rigs of $4.2 billion including project management, drilling and handling tools, spares, operations preparation and capitalized interest.

In December 2014, we exercised a purchase option for the West Polaris, an ultra-deepwater drillship, from Ship Finance. The West Polaris was acquired from us by Ship Finance in 2008 and subsequently bareboat chartered back to us with purchase options commencing in 2012. The purchase option price was $456 million and total consideration payable to Ship Finance was $111 million after debt, which settled in January 2015.

Rosneft Framework Agreement
On May 26, 2014, we entered into an investment and co-operation agreement (the “Investment and Co-Operation Agreement”) with NADL and Rosneft to pursue onshore and offshore growth opportunities in the Russian market. In connection with the Investment and Co-Operation Agreement, we entered into a framework agreement (the “Framework Agreement”) with NADL and Rosneft, pursuant to which, among other things, Rosneft agreed to sell, and NADL agreed to purchase, 100% of the capital of Rosneft’s Russian land drilling subsidiary, RN Burenie LLC, together with its subsidiaries, in exchange for such number of newly issued common shares of NADL, based on an agreed share price of $9.25 per share, as payment of the agreed purchase price, subject to certain cash adjustments. The Framework Agreement provided for an original closing date of no earlier than November 10, 2014, which was first extended until May 31, 2015 and further extended until May 31, 2017.

The parties have agreed to use their reasonable endeavors to renegotiate, by no later than May 31, 2017, the terms of the transactions contemplated in the Framework Agreement, the characteristics of the transactions contemplated in the Framework Agreement and the terms of the related offshore drilling contracts. During this time, NADL is permitted to market its offshore drilling rigs subject to existing drilling contracts with Rosneft, enter into binding contracts with third parties in respect of those rigs, delay the mobilization of those rigs under the Rosneft contracts in order to comply with the terms of any contracts with third parties, delay the construction or delivery of any of those rigs, and extend the construction period or shipyard stay of any of those rigs.

In June 2015, the parties agreed to cancel any restrictions of business included in the terms of the Framework Agreement and replaced such restrictions with a requirement for us, subject to applicable law, to inform Rosneft of any material developments affecting NADL. We can provide no assurance that we will be able to reach an agreement with Rosneft by May 31, 2017. Even if an agreement is reached, the terms of such agreement may differ materially from the terms contemplated in the original Framework Agreement.

Other significant developments
On December 9, 2013, Seadrill Partners closed a public offering of 12,880,000 common units representing liability company interests at a price of $29.50 per common unit (including the underwriters’ allotment), and we purchased 3,394,916 common units directly from Seadrill Partners at a price of $29.50 per unit. On March 17, 2014, Seadrill Partners issued 10,400,000 common units in a public offering, and we subscribed directly for 1,633,987 common units. On June 18, 2014, Seadrill Partners issued 6,100,000 common units to the public and 3,183,700 to us. On September 29, 2014, Seadrill Partners issued a further 8,000,000 common units to the public. As a result of these transactions, our equity ownership interest in Seadrill Partners increased to 46.6%, including both common and subordinated units.


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B.
BUSINESS OVERVIEW
 
Our Company

We are an offshore drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of drillships, semi-submersible rigs and jack-up rigs for operations in shallow-, mid-, deep- and ultra deepwater areas, and in benign and harsh environments. We contract our drilling units primarily on a dayrate basis for periods between one and seven years to drill wells for our customers, typically oil super-majors and major integrated oil and gas companies, state-owned national oil companies and independent oil and gas companies.

Through a number of acquisitions of other companies and contracts for newbuildings, we have developed into one of the world’s largest international offshore drilling contractors, employing approximately 6,995 skilled employees. As of December 31, 2015, we owned and operated a fleet of 38 offshore drilling units, which consisted of 7 drillships, 12 semi-submersible rigs and 19 jack-up rigs. In addition, we also have 13 rigs currently under construction (“newbuilds” or “newbuildings”), consisting of 4 drillships, 1 semi-submersible rigs and 8 jack-up rigs. While we are one of the largest offshore drilling companies, we also have one of the youngest rig fleets in our industry, with an average fleet age of approximately six years.

Shares of our common stock have traded on the Oslo Stock Exchange (“OSE”), since November 22, 2005, under the symbol “SDRL” and our common stock commenced trading on the NYSE on April 15, 2010, also under the symbol “SDRL.” As of March 31, 2016 our nonaffiliated public float represented 75.8% of total shares outstanding, and our principal shareholder, Hemen Holding Ltd. (“Hemen”), held 24.2%. Hemen is indirectly held in Trusts established by Mr. John Fredriksen, our President and Chairman, for the benefit of his immediate family.

Our Fleet

We believe that we have one of the most modern fleets in the offshore drilling industry with the majority of our rigs, which are set forth in the fleet table in “–D. Property, Plants and Equipment.” We believe a modern fleet allows us to enjoy improved utilization rates and the daily rates obtainable for our drilling units.

Drillships
 
Our 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 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.

Semi-submersible drilling rigs
 
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.
 
Jack-Up Rigs
 
Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor. A jack-up rig is towed to the drill site with its hull riding in the sea as a vessel and 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 until it rests on the water, the legs are raised and the rig can be relocated to another drill site. Jack-ups are generally suitable for water depths of 450 feet or less and operate with crews of 40 to 60 people.
 
Our Competitive Strengths

We believe that our competitive strengths include:

One of the largest offshore drilling contractors

Since our inception in 2005, we have developed into one of the world’s largest international offshore drilling contractors. As of December 31, 2015, we owned and operated a fleet of 38 offshore drilling units, which consisted of 7 drillships, 12 semi-submersible rigs and 19 jack-up rigs. In addition, we also have 13 rigs currently under construction (“newbuilds” or “newbuildings”), consisting of 4 drillships, 1 semi-submersible rigs and 8 jack-up rigs.


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In addition we hold investments in several other companies in our industry that own and/or operate offshore drilling units with similar characteristics to our own fleet of drilling units or deliver various oil services.

Technologically advanced and young fleet

Our drilling units are among the most technologically advanced in the world. The majority of our rigs were built after 2007, which is among the lowest average fleet age in the industry. Although current offshore drilling demand in weak, the demand that does exist if for new and modern units that offer superior technical capabilities, operational flexibility and reliability. We believe, based on our proven track record of operating these types of units and diverse fleet composition, we will be better placed to capture new drilling contracts than some of our competitors with older, less advanced rig fleets.

Offshore industry fundamentals

We believe offshore production will be required to meet global demand, even with lower demand levels now evident in the market. This production will require drilling rigs both for infill and maintenance drilling, and to complete new projects that have already been committed. We also believe this is true in shallow and deepwater drilling areas.

Strong and diverse customer relationships

We have strong relationships with our customers that we believe are based on our operational performance, operational track record and quality of our fleet. Our customers are oil and gas exploration and production companies, including oil super-majors, major integrated oil companies, state-owned national oil companies and independent oil and gas producers. As of March 31, 2016, our four largest customers in terms of revenue were certain subsidiaries of Petròleo Brasileiro S.A. (“Petrobras”), Total S.A. Group (“Total”), Exxon Mobil Corp (“ExxonMobil”) and Statoil ASA (“Statoil”).

Commitment to safety and the environment

We believe that the combination of our quality drilling units and experienced and skilled employees allows us to provide our customers with safe and effective operations, to establish, develop and maintain a position as a preferred provider of offshore drilling services for our customers and to facilitate the procurement of term contracts and premium daily rates.

Our Business Strategy
 
Our immediate objective during the current industry downturn is to complete a refinancing plan in order to provide a bridge to the industry recovery and realize the value of our high specification, modern fleet. To this end, our strategies 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.

Continue cost-cutting measures and deliver steady, stable cash flow

We intend to continue to implement our cost savings program 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. Total onshore and offshore headcount reduced from 9,450 to 6,995 during the year. In 2016, we have identified a further $260 million of cost savings relative to levels achieved in 2015 as we continue to focus on headcount reductions, insurance savings, supplier discounts, travel costs and compensation adjustments.

Strengthen our balance sheet

On April 28, 2016 we entered into agreements with our banking group to amend the financial covenants on all of our secured credit facilities. In addition to the covenant waiver we have also deferred the maturities of three facilities maturing prior to May 2017, significantly improving our liquidity profile over the next 15 months.

This agreement is the first stage is one component of a broader effort to refinance our indebtedness, and provides a more stable platform from which to work with all parts of our capital structure to achieve a more comprehensive refinancing solution that we aim to communicate later in the year. The second stage of the effort is expected to address medium- to long-term liquidity requirements and create an investable platform for new capital.


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In addition, we expect to take additional steps to further delay newbuild deliveries until the dayrates justify taking delivery. We do not expect to take delivery of any units in 2016 and currently have $4.0 billion of newbuild yard installments due in 2017, 2018 and 2019 that we will be working with shipyards to defer.

Our longer term strategy is to:
•
Grow through newbuildings and strategic acquisitions.
•
Pursue long-term contracts and maintain stable cash flow.
•
Provide excellent customer service and continue to prioritize safety as a key element of the company's operations.
•
maintain a modern and reliable fleet.


Please see “Item 5. Operating and Financial Review—B. Liquidity and Capital Resources” for further information.


Market Overview
 
We provide operations in oil and gas exploration and development in regions throughout the world and our customers include integrated 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 encountering a significant reduction in demand.

The global fleet of drilling units
 
The global fleet of offshore drilling units consists of drillships, semi-submersible rigs, jack-up rigs and tender rigs. As of March 31, 2016, the existing worldwide drilling rig fleet totaled 879 units including 121 drillships, 185 semi-submersible rigs, 536 jack-up rigs and 37 tender rigs. In addition, at such date there were 46 drillships, 122 jack-up rigs, 23 semi-submersible rigs and 8 tender rigs under construction.

The water depth capacities for various drilling rig types depend on rig specifications, capabilities and equipment outfitting. Jack-up rigs normally work in water depths up to 450ft while semi-submersible rigs and drillships can work in water depths up to 12,000ft and tender rigs work in water depths up to 410ft for tender barges and up to 6,000ft for semi-tenders. All offshore rigs are capable of working 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 153 units.

Semi-submersible rigs and drillships

The worldwide fleet of semi-submersible rigs and drillships currently totals 306 units. Of the total delivered fleet, 165 units are capable of ultra-deepwater operations above 7500 feet, 51 are classed for deepwater operations up to 7,500 feet and the remainder for operations up to 4500 feet. Overall, the average global fleet is 17 years old. The average age of ultra-deepwater units is 7 years, 27 years for units classed for deepwater operations up to 7,500 feet and 31 years for units classed for operations up to 4,500 feet.

Included in the global floater fleet are units classed for operations in harsh environments. The global harsh environment floater fleet is comprised of 78 units and is 20 years old on average.

Oil companies continue to prefer newer and more capable equipment, demonstrated by the utilization rates of different asset classes. Ultra-deepwater units are currently experiencing 65% capacity utilization versus 41% for deepwater and 46% for mid-water floaters. Utilization for harsh environment floaters is currently 54%. 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, we expect accelerated stacking and scrapping activity is expected to continue. We believe a total of 49 floaters have been been scrapped since the end of 2013, equivalent to 14% of the total fleet, and currently there are 55 cold stacked units that are 15 years old or older, which are prime scrapping candidates. In the next 18 months 37 units that are 15 years old or older and will be coming off contract with no follow on work identified which represents additional scrapping candidates. A key rational for scrapping is the 15 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.

The current newbuilding orderbook stands at approximately 69 units, comprised of 46 drillships and 23 semi-submersibles. 26 new rigs are scheduled for delivery in 2016, 18 in 2017 and 25 in 2018 and beyond. Due to the subdued level of contracting activity it is likely that a significant number of newbuild orders will be delayed or cancelled pending an improved market.


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Jack-up rigs
 
The worldwide fleet of jack-up rigs currently totals 536 units. Of the total delivered fleet, 223 units are termed as high specification or capable of operations in 350-450 feet of water and 313 units are termed as standard jack-ups and can work at water depths up to 350 feet. Overall, the global jack-up fleet is 22 years old on average. The average age of high specification units is 11 years and 31 years for standard units.

Included in the global jack-up fleet are units classed for operations in harsh environments. The global harsh environment jack-up fleet is comprised of 75 units and is 14 years old on average.

Oil companies continue to prefer newer and more capable equipment, demonstrated by the utilization rates of different asset classes. High specification jack-ups are currently experiencing 67% capacity utilization versus 58% for standard units. Harsh environment jack-ups are currently operating at 72% capacity utilization.

A total of 25 jack-ups have been been scrapped since the end of 2013, equivalent to 4% of the total fleet, and currently there are 59 cold stacked units that are 30 years old or older, which are prime scrapping candidates. In the next 18 months 75 units that are 30 years old or older will be coming off contact with no follow on work identified which represent additional scrapping candidates, however scrapping activity in the jack-up segment is subdued relative to the floater segment due to the lower cost of stacking and classing these units.

The current newbuilding orderbook stands at approximately 122 units. 83 are scheduled for delivery in 2016, 28 in 2017 and 11 in 2018 and beyond. Due to the subdued level of contracting activity it is likely that a significant number of newbuild orders will be delayed or cancelled until an improved market justifies taking delivery.

The above overview of the various offshore drilling sectors is based on historical market developments and current market conditions. Future markets conditions and developments cannot be predicted and may materially differ from our current expectations.
 
Reporting Segments
 
We report our business in the following reportable segments:

•
Floaters: We offer services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contract results reported in this segment relate to semi-submersible rigs and drillships.

•
Jack-ups: We offer services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contract results reported in this segment relate to jack-up rigs.

In prior periods, we reported a Tender Rigs segment, which related to services encompassing drilling, completion and maintenance of offshore production wells in Southeast Asia, West Africa and the Americas. In these periods, we had drilling contracts related to self-erecting tender rigs and semi-submersible tender rigs. Following the sale of the majority of the tender rig business to SapuraKencana, which closed on April 30, 2013, and after the deconsolidation of Seadrill Partners as of January 2, 2014, we no longer have any drilling contracts in the Tender rig segment.

Information regarding our revenues, segment operating profit or loss and total assets attributable to each operating segment for the last three fiscal years is presented in Note 3 to our Consolidated Financial Statements included in this Annual Report. Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operations for the last three fiscal years is also presented in Note 3 to our Consolidated Financial Statements included in this Annual Report.

Seasonality
 
In general, seasonal factors do not have a significant direct effect on our business. However, we have operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operational utilization of the rigs and our ability to relocate rigs between drilling locations, and as such, limit contract opportunities in the short term. Such adverse weather could include the hurricane season for our operations in the Gulf of Mexico, the winter season in offshore Norway and Canada, and the monsoon season in Southeast Asia.

Customers
 
Our customers are oil and gas exploration and production companies, including major integrated oil companies, independent oil and gas producers and government-owned oil and gas companies. In the year ended December 31, 2015 our largest customers were:
•
Petroleo Brasileiro S.A., or Petrobras, which accounted for approximately 19% of our revenues;
•
Total S.A. Group, or Total, which accounted for approximately 16% of our revenues;
•
Exxon Mobil Corp, or Exxon, which accounted for approximately 14% of our revenues; and
•
Statoil ASA, or Statoil, which accounted for approximately 12% of our revenues.


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Our contract backlog, at March 31, 2016 totaled approximately $4.8 billion. Of the total contract backlog, $3.7 billion is attributable to our semi-submersible rigs and drillships and $1.1 billion attributable to our jack-up units. We expect approximately $2.9 billion of our contract backlog to be realized in the remainder of 2016. Contract backlog for our drilling fleet is calculated as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Contract backlog excludes revenues for mobilization and demobilization, contract preparation, and customer reimbursables.  The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the backlog projections due to various 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 light of the current environment, we are 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 fee is typically payable to Seadrill, in accordance with the terms of the drilling agreement. While we are confident that our contract terms are enforceable, we may be willing to engage in discussions to modify such contracts if there is a commercial agreement that is beneficial to both parties.

Examples of such negotiations, at our request or counterparties, include:
•
On February 8, 2016, we secured a new drilling contract in Angola for the West Eclipse, which is expected to commence in the second quarter of 2016. The contract is for a firm period of 2 years and adds backlog of approximately $285 million inclusive of mobilization. As part of this agreement, the backlog for the West Polaris has been decreased by approximately $95 million, which reduces the contingent consideration that we receive from Seadrill Partners, following the sale of the West Polaris to Seadrill Partners in June 2015.

•
On March 23, 2016, we extended the contract for the West Tellus with Petrobras by 18 months, commencing in April 2018 to the end of October 2019. The total backlog for the contract extension is approximately $164 million. As part of the agreement to extend the West Tellus, we agreed to a dayrate reduction on the current contract effective from February 26, 2016, resulting in a $132 million reduction in our backlog. The resulting net effect of this agreement is an increase in contract backlog of $32 million.

•
On March 30, 2016, Sevan Drilling and Petrobras terminated early the Sevan Driller contract and reduced the contract dayrate on the drilling contract for the Sevan Brasil. Subsequent to the effective cancellation of the Sevan Driller contract the unit was awarded a contract by Shell in Brazil for 60 days. The combined impact of the cancellation, reduction and new award is a decrease in contract backlog of approximately $127 million.


The following table shows the percentage of rig days committed by year as of March 31, 2016. The percentage of rig days committed is calculated as the ratio of total days committed under contracts to total available days in the period. This excludes our newbuilding units under construction.
 
Year ending December 31,
% of rig-days committed
2016

 
2017

 
2018

Floaters
65
%
 
42
%
 
21
%
Jack-up rigs
56
%
 
25
%
 
10
%

Competition

The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to small locally-owned companies.

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 our customers’ drilling programs. Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by our customers for drilling services. Variations in market conditions during cycles impact us in different ways, depending primarily on the length of drilling contracts in different regions. For example, contracts in shallow waters for jack-up rig activities are shorter term, so a deterioration or improvement in market conditions for such units tends to quickly impact revenues and cash flows from those operations. On the other hand, contracts in deepwater for semi-submersible rigs and drillships tend to be longer term, so a change in market conditions tends to have a more delayed impact. Accordingly, 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. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability and sustainability, rig location, condition of equipment, operating integrity, safety performance record, crew experience, reputation, industry standing and client relations.

Furthermore, competition for offshore drilling rigs 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 upgrades of the unit and its equipment to specific regional requirements. In particular, for rigs to operate in harsh environments, such as offshore Norway and Canada, as opposed to

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benign environments, such as the Gulf of Mexico, West Africa, Brazil, the Mediterranean and Southeast Asia, more demanding weather conditions would require more costly investment in the outfitting and maintenance of the drilling units.

We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future.

For further information on current market conditions and global offshore drilling fleet, please see “Item 5D - Trend Information.”

Risk of Loss and Insurance

Our operations are subject to hazards inherent in the drilling of oil and gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, or seriously damage or destroy the equipment involved. Offshore drilling contractors such as us are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our marine insurance package policy provides insurance coverage for physical damage to our rigs, loss of hire for some of our rigs and third party liability.

Our insurance claims are subject to a deductible, or non-recoverable, amount. We currently maintain a deductible per occurrence of up to $5 million related to physical damage to our rigs. However, a total loss of, or a constructive total loss of, a drilling unit is recoverable without being subject to a deductible. For general and marine third-party liabilities, we generally maintain a deductible of up to $500,000 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, for some of our rigs we purchase insurance to cover loss due to the drilling unit being wholly or partially deprived of income as a consequence of damage to the unit. The loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, our insurance policies are limited to 290 days. If the repair period for any physical damage exceeds the number of days permitted under our loss of hire policy, we will be responsible for the costs in such period. We do not have loss of hire insurance on our benign environment jack-up rigs.

We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the 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 a limited part of this windstorm risk for a further period starting May 1, 2016 through April 30, 2017.

Environmental and Other Regulations in the Offshore Drilling Industry

Our operations are subject to numerous laws and regulations in the form of international treaties and maritime regimes, flag state requirements, national environmental laws and regulations, navigation and operating permits requirements, local content requirements, and other national, state and local laws and regulations in force in the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. See “Item 3. Key Information – D. Risk Factors – Governmental laws and regulations, including environmental laws and regulations, may add to our costs or limit our drilling activity.”

Flag State Requirements

All of our drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered.

The flag state requirements are international maritime requirements and in some cases further interpolated by the flag state itself. These requirements include, but are not limited to, MARPOL, the CLC, ILO, the Bunker Convention, SOLAS, the ISM Code, MODU Code and the BWM Convention.  These various conventions regulate air emissions and other discharges to the environment from our drilling units worldwide, and we may incur costs to comply with these regimes and continue to comply to 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. 

The requirements are recognized minimum standard agreed to be able to work worldwide, some flag states are working outside these international convention and for those flag states a drilling unit or ship will not be able to work world wide

Class Societies

These include engineering, safety and other requirements related to the Maritime industry. In addition, each of our drilling units must be “classed” by a classification society. The classification society certifies that the drilling rig is “in-class,” signifying that such drilling rig has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the flag state and the international conventions of which that country is a member. Maintenance of class certification requires expenditure of substantial sums, and can require taking a drilling unit out of service from time to time for repairs or modifications to meet class requirements.  Our drilling units must generally undergo a class survey once every five years.

For some of the international required certification the Class society will act on flag state behalf, such as the MODU code certificate.

Environmental Laws and Regulations

These laws and regulations include the U.S. Oil Pollution Act of 1990, (OPA), the Comprehensive Environmental Response, Compensation and Liability Act, (CERCLA), the U.S. Clean Water Act (CWA), the U.S. Clean Air Act (CAA), the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, or the “MTSA, European Union regulations, and Brazil’s National Environmental Policy

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Law (6938/81), Environmental Crimes Law (9605/98) and Federal Law (9966/2000) relating to pollution in Brazilian waters. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection.

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.  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 add new requirements and amend 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 contain a number of other requirements including third-party verification and certifications, real-time monitoring of deepwater and certain other activities, and sets criteria for safe drilling margins. 

In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. Implementation of new environmental laws or regulations that may apply to ultra deepwater drilling units may subject us to increased costs or limit the operational capabilities of our drilling units and could materially and adversely affect our operations and financial condition. See “Item 3 Key Information – D. Risk Factors – We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.”

Safety Requirements

Our operations are subject to special safety regulations relating to drilling and to the oil and gas industry in many of the countries where we operate. The United States undertook substantial revision of the safety regulations applicable to our industry following the Deepwater Horizon Incident, in which we were not involved, that led to the Macondo well blow out situation, in 2010. Other countries are also undertaking a review of their safety regulations related to our industry. These safety regulations may impact our operations and financial results. For instance, the revisions to the regulations in the United States have resulted in new requirements, such as specific requirements for maintenance and certification of BOP’s, which may cause us to incur cost and may result in additional downtime for our drilling units in the U.S. Gulf of Mexico. Please see “Item 3 Key Information – D. Risk Factors – The aftermath of the moratorium on offshore drilling in the Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout, could negatively impact us.”

Navigation and Operating Permit Requirements

Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Some of these laws contain criminal sanctions in addition to civil penalties.

Local Content Requirements

Governments in some countries have become increasingly active in local content requirements on the ownership of drilling companies, local content requirements for equipment utilized in our operations, and other aspects of the oil and gas industries in their countries. These regulations include requirements for participation of local investors in our local operating subsidiaries in countries such as Angola and Nigeria, and local content requirements in relation to drilling unit construction contracts in which we are participating in Brazil. Although these requirements have not had material impact on our operations in the past, they could have a material impact on our earnings, operations and financial condition in the future.

Other Laws and Regulations

In addition to the requirements described above, our international operations in the offshore drilling segment are subject to various other international conventions and laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling units and other equipment.

C.
ORGANIZATIONAL STRUCTURE

Please see “Item 4. Information on the Company – A. History and Development of the Company” for further information on the Seadrill Limited group of companies.

A full list of our significant management, operating and rig-owning subsidiaries is shown in Exhibit 8.1.


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D.
PROPERTY, PLANT AND EQUIPMENT
 
We own a substantially modern fleet of drilling units. The following table sets forth the units that we own or have contracted for delivery as of March 31, 2016:

Unit
Year built
 
Water depth (feet)
 
Drilling depth (feet)
 
Area of location
 
Month of contract expiry
 
 
 
 
 
 
 
 
 
 
Jack-up rigs
 
 
 
 
 
 
 
 
 
West Epsilon (2)
1993
 
400
 
30,000
 
Norway
 
December 2016
West Resolute
2007
 
350
 
30,000
 
Sharjah, U.A.E.
 
available
West Prospero
2007
 
400
 
30,000
 
Malaysia
 
May 2016
West Vigilant
2008
 
350
 
30,000
 
Malaysia
 
available
West Ariel
2008
 
400
 
30,000
 
Republic of Congo
 
February 2018
West Triton
2008
 
375
 
30,000
 
Sharjah, U.A.E.
 
available
West Freedom
2009
 
350
 
30,000
 
Venezuela
 
April 2017
West Cressida
2009
 
375
 
30,000
 
Thailand
 
April 2016
West Mischief
2010
 
350
 
30,000
 
Abu Dhabi
 
November 2017
West Callisto
2010
 
400
 
30,000
 
Saudi Arabia
 
November 2018
West Leda
2010
 
375
 
30,000
 
Vietnam
 
available
West Elara (2)
2011
 
450
 
40,000
 
Norway
 
March 2017
West Castor
2013
 
400
 
30,000
 
Brunei
 
May 2016
West Telesto
2013
 
400
 
30,000
 
Malaysia
 
available
West Tucana
2013
 
400
 
30,000
 
In transit, Angola
 
June 2017
AOD-1 (3)
2013
 
400
 
30,000
 
Saudi Arabia
 
May 2016
AOD-2 (3)
2013
 
400
 
30,000
 
Saudi Arabia
 
July 2016
AOD-3 (3)
2013
 
400
 
30,000
 
Saudi Arabia
 
October 2016
West Linus (2) (5)
2014
 
450
 
40,000
 
Norway
 
May 2019
West Titan (NB)(1)
2016
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Proteus (NB)(1)
2016
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Rhea (NB)(1)
2016
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Tethys (NB)(1)
2016
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Hyperion (NB)(1)
2016
 
400
 
30,000
 
Dalian Shipyard (China)
 

West Umbriel (NB)(1)
2016
 
400
 
30,000
 
Dalian Shipyard (China)
 

West Dione (NB)(1)
2017
 
400
 
30,000
 
Dalian Shipyard (China)
 

West Mimas (NB)(1)
2017
 
400
 
30,000
 
Dalian Shipyard (China)
 

 
 
 
 
 
 
 
 
 
 
Semi-submersible rigs
 
 
 
 
 
 
 
 
 
West Alpha (2)
1986
 
2,000
 
23,000
 
Norway
 
July 2016
West Venture (2)
2000
 
2,600
 
30,000
 
Norway
 
available
West Phoenix (2) (6)
2008
 
10,000
 
30,000
 
United Kingdom
 
September 2016
West Hercules (5)
2008
 
10,000
 
35,000
 
Canada
 
January 2017
West Taurus (5)
2008
 
10,000
 
35,000
 
Spain
 
available
West Eminence
2009
 
10,000
 
30,000
 
Spain
 
available
Sevan Driller (4) (7)
2009
 
10,000
 
40,000
 
Brazil
 
July 2016
West Orion
2010
 
10,000
 
35,000
 
Brazil
 
July 2016
West Pegasus
2011
 
10,000
 
35,000
 
Mexico
 
August 2018
West Eclipse
2011
 
10,000
 
40,000
 
Angola
 
June 2018
Sevan Brasil (4)
2012
 
10,000
 
40,000
 
Brazil
 
July 2018

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Unit
Year built
 
Water depth (feet)
 
Drilling depth (feet)
 
Area of location
 
Month of contract expiry
Sevan Louisiana (4)
2013
 
10,000
 
40,000
 
USA
 
May 2017
Sevan Developer (NB) (1)(4)
2015
 
10,000
 
40,000
 
Cosco Shipyard (China)
 

 
 
 
 
 
 
 
 
 
 
Drillships
 
 
 
 
 
 
 
 
 
West Navigator (2)
2000
 
7,500
 
35,000
 
Norway
 
available
West Gemini
2010
 
10,000
 
35,000
 
Angola
 
October 2017
West Tellus
2013
 
12,000
 
40,000
 
Brazil
 
October 2019
West Neptune
2014
 
12,000
 
40,000
 
USA
 
December 2017
West Jupiter
2014
 
12,000
 
40,000
 
Nigeria
 
December 2019
West Saturn
2014
 
12,000
 
40,000
 
Nigeria
 
December 2016
West Carina
2015
 
12,000
 
40,000
 
Brazil
 
June 2018
West Draco (NB)(1)
2017
 
12,000
 
40,000
 
Samsung Heavy Industries (South Korea)
 

West Dorado (NB)(1)
2017
 
12,000
 
40,000
 
Samsung Heavy Industries (South Korea)
 

West Aquila (NB)(1)
2018
 
12,000
 
40,000
 
DSME Shipyard (South Korea)
 

West Libra (NB)(1)
2019
 
12,000
 
40,000
 
DSME Shipyard (South Korea)
 


(1)
Newbuild under construction or in mobilization to its first drilling assignment.
(2)
Owned by our subsidiary NADL, in which we own 70.4% of the outstanding shares.
(3)
Owned by AOD, in which we own 66.2% of the outstanding shares.
(4)
Owned by Sevan Drilling, in which we own 50.1% of the outstanding shares.
(5)
Owned 100% by Ship Finance and leased back under bareboat charter agreements. These are consolidated in our financial statements as variable interest entities. Please see Note 35 of our Consolidated Financial Statements included herein for more information. The West Linus is 100% owned by Ship Finance and leased back to NADL.
(6)
The West Phoenix receives a reduced dayrate whilst being warm stacked during the winter period, and subsequently commenced drilling operations in April 2016.
(7)
The Sevan Driller contract with Shell in Brazil is for 60 days.

In addition to the drilling units listed above, as of December 31, 2015, we have buildings, plant and equipment with a net book value of $46 million, including office equipment. Our offices, including Stavanger and Oslo in Norway, Singapore, Houston in the United States, Rio de Janeiro in Brazil, Dubai in the United Arab Emirates, and Aberdeen, Liverpool and London in the United Kingdom are leased and the aggregate office operating costs were $23 million in 2015.

We do not have any material intellectual property rights.

ITEM 4A.
UNRESOLVED STAFF COMMENTS

Not applicable.

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 our Consolidated Financial Statements and accompanying Notes thereto included herein. 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—A. Selected Financial Data,” “Item 3. Key Information—D. Risk Factors” and “Item 4. Information on the Company.” Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and are presented in U.S. dollars unless otherwise indicated.


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Fleet Development
The following table summarizes the development of our fleet of drilling units for the periods presented, based on the dates when the units began operations:
 
 
 
Floaters
 
 
 
 
Unit type
Jack-up
rigs
 
Drillships
 
Semi-
submersible
rigs
 
Tender
rigs
 
Total
units
 
 
 
 
 
 
 
 
 
 
December 31, 2012
16

 
4

 
12

 
11

 
43

additions
5

 
3

 
3

 
2

 
13

(disposals)
(1
)
 
—

 
—

 
(10
)
 
(11
)
December 31, 2013
20

 
7

 
15

 
3

 
45

additions
4

 
3

 
1

 
—

 
8

(disposals)
—

 
(3
)
 
(4
)
 
(3
)
 
(10
)
December 31, 2014
24

 
7

 
12

 
—

 
43

additions
—

 
1

 
—

 
—

 
1

(disposals)
(5
)
 
(1
)
 
—

 
—

 
(6
)
December 31, 2015
19

 
7

 
12

 
—

 
38


Additions of drilling units relate primarily to the completion of our newbuildings.

The disposals in 2015 relate to the deconsolidation of five jack-up rigs relating to SeaMex on March 10, 2015, and the disposal of the West Polaris to Seadrill Partners on June 19, 2015. The disposals in 2014 relate to the deconsolidation of Seadrill Partners on January 2, 2014, and our subsequent disposals of the West Auriga to Seadrill Partners on March 21, 2014, and the West Vela to Seadrill Partners on November 4, 2014. The disposals in 2013 relate to our disposal of the tender rig segment to SapuraKencana on March 30, 2013.

Factors Affecting Our Results of Operations
The principal factors that we believe have affected our results and are expected to affect our future results of operations and financial position include:
•
our ability to successfully employ our drilling units at economically attractive dayrates as long-term contracts expire or are otherwise terminated;
•
the ability to maintain good relationships with our existing customers and to increase the number of customer relationships;
•
the number and availability of our drilling units;
•
fluctuations and the current decline in the price of oil and gas, which influence the demand for offshore drilling services;
•
the effective and efficient technical management of our drilling units;
•
our ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards;
•
economic, regulatory, political and governmental conditions that affect the offshore drilling industry;
•
accidents, natural disasters, adverse weather, equipment failure or other events outside of our control that may result in downtime;
•
mark-to-market changes in interest rate swaps;
•
foreign currency exchange gains and losses;
•
increases in crewing and insurance costs and other operating costs;
•
the level of debt and the related interest expense and amortization of principal;
•
the impairment of goodwill, investments, drilling units and other assets;
•
gains on disposals of assets;
•
interest and other financial items;
•
acquisitions and divestitures of businesses and assets;
•
tax expenses; and
•
the deconsolidation of subsidiaries.

Please see “Item 3. Key Information-Risk Factors” for a discussion of certain risks inherent in the Company’s business.

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Important Financial Terms and Concepts

Revenues
In general, our drilling units are contracted for a period of time to provide offshore drilling services at an agreed dayrate. A unit generally will be stacked if it has no contract in place. Dayrates are volatile and can vary depending on the type of drilling unit and its capabilities, operating expenses, taxes and other factors. An important factor in determining the level of revenue is the technical utilization of the drilling rig. To the extent that our operations are interrupted due to equipment breakdown or operational failures, we do not generally receive dayrate compensation for the period of the interruption. Furthermore, our dayrates may be reduced in instances of interrupted or suspended service due to, among other things, repairs, upgrades, weather, maintenance, force majeure or the requested suspension of services by the client and other operating factors.
 
The terms and conditions of our drilling contracts allow for compensation when factors beyond our control, including weather conditions, influence drilling operations and, in some cases, for compensation when we perform planned maintenance activities. In many of our drilling contracts we are entitled to escalated compensation to cover some of our cost increases as reflected in publicly available cost indices.
 
In addition to contracted dayrates, our customers may pay mobilization and demobilization fees for units before and after their drilling assignments, and may also reimburse us for costs we incur at their request for additional supplies, personnel and other services, not covered by the contracted dayrate.
 
The following table summarizes our average dayrates and economic utilization percentage by rig type for the periods indicated: 
 
Year ended December 31,
 
2015
 
2014
 
2013
 
Average
dayrates
($) (1)
 
Economic utilization
(%) (2)
 
Average
dayrates
($) (1)
 
Economic utilization
(%) (2)
 
Average
dayrates
($) (1)
 
Economic utilization
(%) (2)
Jack-up rigs
197,649

 
97
 
179,327

 
96
 
168,000

 
98
Floaters
440,687

 
91
 
488,771

 
92
 
497,000

 
94
Tender rigs
N/A

 
N/A
 
N/A

 
N/A
 
152,000

 
99

(1)
Average dayrates are the weighted average dayrates for each type of unit, based on the actual days available for each unit of that type, while on contract. Average dayrates for jack-up rigs on contract increased in 2015 due to a number of contracts at lower rates coming to an end and not being replaced.
(2)
Economic utilization is calculated as the total revenue, excluding bonuses, for the period as a proportion of the full operating dayrate multiplied by the number of days in the period.

Gain/Loss on disposal
From time to time we may sell, or otherwise dispose of, drilling units, businesses, and other fixed assets, to external parties or related parties. In addition, assets may be classified as “held for sale” on our balance sheet when, among other things, we are committed to a plan to sell assets, and consider a sale probable within twelve months. We may recognize a gain or loss on disposal depending on whether the fair value of the consideration received is higher or lower than the carrying value of the asset.

Operating Expenses
Our operating expenses consist primarily of vessel and rig operating expenses, reimbursable expenses, the impairment of goodwill and drilling units, depreciation and amortization, and general and administrative expenses.
•
Vessel and rig operating expenses are related to the drilling units we have in operation and include the remuneration of offshore crews, onshore rig supervision staff and expenses for repairs and maintenance, as well as other expenses specifically related to our drilling units.
•
Reimbursable expenses are incurred at the request of our customers, and include supplies, personnel and other services.
•
Loss on impairment of goodwill and drilling units is based on management’s review of these assets for impairment, which is done at least once each year or more often if there are factors indicating that it is more likely than not that the fair value of these assets will be lower than their respective carrying value. Please see “—Critical Accounting Estimates” below for further information.
•
Depreciation and amortization expenses are based on the historical cost of our drilling units and other equipment.
•
General and administrative expenses include the costs of our regional offices in various locations, as well as the remuneration and other compensation of our officers, directors and employees engaged in the management and administration of the Company.

Financial Items and Other Income/Expense

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Our financial items and other income/expense consist primarily of interest income, interest expense, share in results from associated companies, impairment of investments, gain/loss on derivative financial instruments, foreign exchange gain/loss and other non-operating income or expenses.
•
The amount of interest expense recognized depends on the overall level of debt we have incurred and prevailing interest rates under our debt agreements. However, overall interest expense may be reduced as a consequence of the capitalization of interest expense relating to drilling units under construction.
•
Share in results from associated companies recognized relates to our share of earnings or losses in our investments accounted for as equity method investments.
•
Impairment of investments are recorded when a fall in the value of our investments is determined to be other than temporary. Management reviews our investment in marketable securities and associated companies on a quarterly basis and makes its determination on the basis of the longevity and severity of any fall in the respective value of our investments, among other available information.
•
Gains/losses recognized on derivative financial instruments reflect various mark-to-market adjustments to the value of our interest rate and forward currency swap agreements and other derivative financial instruments, and the net settlement amount paid or received on swap agreements.
•
Foreign exchange gains/loss recognized generally relate to transactions and revaluation of balances carried in currencies other than the U.S. dollar.
•
Other non-operating income or expense relates to items that generally do not fall within any other categories listed above.

Income Taxes
Income tax expense reflects current taxes payable and deferred taxes related to our ownership and operation of drilling units and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the calculation of taxes is based on net income or deemed income, the latter generally being a function of gross revenue.

Critical Accounting Estimates
The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience, available information and assumptions that we believe to be reasonable.  Our critical accounting estimates are important factors to our financial condition and results of operations, and require us to make subjective or complex assumptions or estimates about matters that are uncertain.  Our significant accounting policies are discussed in “Note 2–Accounting Policies” to our Consolidated Financial Statements included herein. We believe that the following are the critical accounting estimates used in the preparation of our Consolidated Financial Statements. In addition, there are other items in our Consolidated Financial Statements that require estimation.

Drilling Units
Drilling units and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of our floaters and jack-up rigs, when new, is 30 years.

Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset’s value for its remaining useful life are capitalized and depreciated over the remaining life of the asset. We determine the carrying value of these assets based on policies that incorporate our estimates, assumptions and judgments relative to their respective carrying value, remaining useful lives and residual value. The assumptions and judgments we use in determining the estimated useful life of our drilling units and related equipment 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 could result in materially different net book values of our drilling units and results of operations.

The useful lives of drilling units and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We reevaluate the remaining useful lives of our drilling units and related equipment as and when certain events occur which directly impact our assessment of their remaining useful lives, and include changes in operating condition, functional capability, and market and economic factors.

The carrying values of our long-lived assets, such as our drilling units, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We first assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment is made to the market value or to the discounted future net cash flows. In general, impairment analyses are 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. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels,

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dayrates and costs. The use of different estimates and assumptions could result in significantly different carrying values of our assets and could materially affect our results of operations.

With regard to older drilling units which have relatively short remaining estimate useful lives, the results of impairment tests are particularly sensitive to management’s assumptions. These assumptions include the likelihood of the unit obtaining a contract upon the expiration of any current contract, and the Company’s intention for the drilling unit should no contract be obtained, including warm/cold stacking or scrapping. The use of different assumptions in the future could potentially result in an impairment of drilling units, which could materially affect our results of operations. If market supply and demand conditions in the ultra-deepwater offshore drilling sector do not improve it is likely that the Company will be required to impair certain drilling units.

Goodwill
We allocate the purchase price of acquired businesses to the identifiable tangible and intangible assets and liabilities acquired, with any remaining amount being capitalized as goodwill. Goodwill is tested for impairment at least annually, usually as of December 31, for each reporting segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. We have determined that our reporting units are the same as our operating segments for the purpose of allocating goodwill and the subsequent testing of goodwill for impairment.

We first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. When assessing the qualitative factors to make this determination, we consider, among other things, the overall macroeconomic environment, drilling industry and market trends, trends in contracting costs and dayrates, developments in interest rates, the market values of drilling units, expectations of the future price of oil and our market capitalization.

During the period between June 30, 2015 and September 30, 2015 our share price fell by 43% from $10.34 to $5.90, based on the spot price (or by 34%, from $12.04 to $7.96, based on the average trailing three-month basis), partly as a result of deteriorating market conditions in the oil and gas industry and supply and demand conditions in the ultra-deepwater offshore drilling sector, including the oversupply of drilling units, and the reduction of capital expenditures by oil majors. As a result management determined that the goodwill assigned to our floaters reporting unit was likely to be impaired.

As of September 30, 2015, an interim quantitative impairment test was conducted, which resulted in us recognizing an impairment loss of $563 million relating to the floaters reporting unit, which represented all of the goodwill attributable to that reporting unit. Following our recognition of this impairment, we no longer retain any goodwill balance. The impairment is a result of deteriorating market conditions and our outlook on expected conditions through the current down-cycle. The impairment charge was allocated between Seadrill and certain non-controlling interests based upon the non-controlling interests’ share in each drilling unit within the floater segment. The overall charge to the reporting unit was first allocated to each drilling unit based upon the relative fair values of those drilling units. The percentage of the non-controlling interest in each drilling unit was then applied to the allocated charge in order to determine the portion attributable to non-controlling interests. The total impairment allocated to non-controlling interests was $95 million.

The estimated fair value of the reporting unit was derived using an income approach, using discounted future free cash flows. Our estimated future free cash flows are primarily based on our expectations around dayrates, drilling unit utilization, operating costs, capital and long-term maintenance expenditures, and applicable tax rates. The cash flows are estimated over the remaining useful economic lives of the assets but no longer than 30 years in total, and discounted using an estimated market participant weighted average cost of capital of 10%.

The assumptions used in our estimated cash flows were derived from unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the goodwill impairment test.

For each of our last annual impairment review and the interim review of goodwill, we elected to bypass the qualitative assessment given the decline in market conditions in the offshore drilling industry and performed the two-step goodwill impairment test.

As of September 30, 2015 the aggregated estimated fair value of our reporting units exceeded our market capitalization. We evaluated the difference by reviewing the implied control premium compared to other market transactions within our industry and considering other benchmark data and analysis prepared by offshore drilling industry analysts. We deem the implied control premium to be reasonable in the context of the data considered.

The assumptions used in our estimated cash flows were derived from unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the impairment test. Key assumptions that have a particularly material impact on the estimated fair value of the reporting unit include expected future market dayrates and drilling unit future utilization. While management has used external data and analysis in determining these assumptions, the assumptions are inherently subjective. The use of different judgments and assumptions

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surrounding the estimates of future cash flows of the reporting units would potentially result in materially different goodwill carrying value and operating results.

If we dispose of or deconsolidate assets that constitute a business, we allocate a portion of the reporting unit’s goodwill to that business in determining the gain or loss on the disposal of the business. The amount of goodwill that is allocated to the business is based on the relative fair values of that business and the portion of the reporting unit that will be retained.

Income Taxes
Seadrill is a Bermuda company that has a number of subsidiaries and affiliates in various jurisdictions. We are not currently required to pay income taxes in Bermuda on ordinary income or capital gains because we qualify as an exempt company. We have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 2035. Certain of our subsidiaries operate in other jurisdictions where income taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income tax rates and methods of computing taxable income vary substantially between jurisdictions. Our income tax expense is expected to fluctuate from year to year because our operations are conducted in different tax jurisdictions and the amount of pre-tax income fluctuates.

The determination and evaluation of our annual group income tax provision involves the interpretation of tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events, such as amounts, timing and the character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authority’s widely understood administrative practices and precedence. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as of the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities or valuation allowances.

Impairment of Equity Method Investees and Marketable Securities
We assess our equity method investees and marketable securities for impairment during each reporting period to evaluate whether an event or change in circumstances has occurred in that period which may have a significant adverse effect on the carrying value of the investment. We record an impairment charge for other-than-temporary declines in fair value when the fair value is not anticipated to recover above the carrying value within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in fair value are not reflected in earnings until the equity method investee is sold.

Seadrill Partners - Common units - Impairment of marketable securities
We deconsolidated Seadrill Partners in January 2014, and as a result recognized our investment in Seadrill Partners’ common units at a market value of $30.60 per unit. We also purchased additional such common units in 2014 at a similar price. In October 2014, the Seadrill Partners’ unit price began to fall below $30.60 and dropped to $9.40 on September 30, 2015, as a result of deteriorating market conditions in the oil and gas industry and supply and demand conditions in the ultra-deepwater offshore drilling sector. During the period between June 30, 2015 and September 30, 2015, Seadrill Partners’ unit price fell by approximately 20% (based on the spot price and trailing three month average basis). As of September 30, 2015 our management determined that our investment in Seadrill Partners’ common units was “other than temporarily impaired” due to the length and severity of the reduction in value below historical cost. As a result we have impaired our investment, recognizing an impairment charge of $574 million within “loss on impairment of investments” in our consolidated statement of operations. This impairment charge represents a reclassification of losses previously recognized within “other comprehensive income/(loss).” The amount reclassified out of “accumulated other comprehensive income” into earnings was determined on the basis of average cost.

During the three months ended December 31, 2015, Seadrill Partners’ unit price declined further, from approximately $9.40 at September 30, 2015 to $3.65 at December 31, 2015. As of December 31, 2015, an unrealized loss of $151 million had been recognized in “accumulated other comprehensive income,” as a result of remeasuring the value of our investment in the common units of Seadrill Partners to the market price as of December 31, 2015. Having assessed the length and severity of the implied fall in value and the prospects for Seadrill Partners, we determined that a further “other than temporary impairment” of our investment had not occurred as of December 31, 2015.

The evaluation of whether a decline in fair value is “other than temporary” requires a high degree of judgment and the use of different assumptions could materially affect our earnings.


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Seadrill Partners - Subordinated units and direct ownership interests - Impairment of equity method investment
While our investments in Seadrill Partners that are held under the equity method are not publicly traded, the reduction in value of the publicly traded common units is considered to be an indicator of impairment. As of September 30, 2015, we determined the length and severity of the reduction in value of the traded units to be representative of an “other than temporary impairment.” As such we have measured and recognized an “other than temporary impairment” of our investment in the subordinated units and direct ownership interests as of September 30, 2015.

The fair value of these investments was derived using an income approach which discounts future free cash flows, or the DCF model. The estimated future free cash flows associated with the investments are primarily based on expectations around applicable dayrates, drilling unit utilization, operating costs, capital and long-term maintenance expenditures, and applicable tax rates. The cash flows are estimated over the remaining useful economic lives of the underlying assets but no longer than 30 years in total, and discounted using an estimated market participant weighted average cost of capital of 8.5%, which was relevant to the investee. The DCF model derived an enterprise value of the investments, after which associated debt was subtracted to provide equity values. The implied valuation of Seadrill Partners derived from the DCF model was cross-checked against the market price of Seadrill Partners’ common units. We evaluated the difference by reviewing the implied control premium compared to other market transactions within the industry. We deem the implied control premium to be reasonable in the context of the data considered.

As of September 30, 2015, the carrying value of the subordinated units was found to exceed the fair value by $125 million, and the carrying value of the direct ownership interests was found to exceed the fair value by $302 million. We have recognized this impairment of the investments within “loss on impairment of investments” in our consolidated statement of operations.

The assumptions used in the DCF model were derived from unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the impairment test. Significant judgment is employed by the Company in developing these estimates and assumptions. The use of different assumptions, particularly with regard to the most sensitive assumptions concerning estimated future dayrates and utilization and the assumed market participant discount rate, would have a material impact on the impairment charge recognized and our consolidated statement of operations. In addition, if actual events differ from management’s estimates, or to the extent that these estimates are adjusted in the future, the Company’s financial condition and results of operations could be affected in the period of any such change of estimate.

Seadrill Partners - Member interest - Impairment of cost method investments
We also hold the seadrill member interest (the “Seadrill Member Interest”), which is a 0% non-economic interest, and which holds the rights to 100% of the incentive distribution rights (“IDRs”) of Seadrill Partners. The Seadrill Member Interest and the IDRs in Seadrill Partners are accounted for as cost-method investments on the basis that they do not represent common stock interests and their fair value is not readily determinable. The fair value of our interest in the Seadrill Member Interest and the attached IDRs at deconsolidation in January 2014, was determined using a Monte Carlo simulation method, or the Monte Carlo Model. The method takes into account the cash distribution waterfall, historical volatility, estimated dividend yield and the share price of the common units as of the deconsolidation date.

The reduction in value of the Seadrill Partners common units was determined to be an indicator of impairment of the Seadrill Member Interest. The fair value was determined using the Monte Carlo Model, updated for applicable assumptions as of September 30, 2015. The carrying value of the investment was found to exceed the fair value by $106 million. We have recognized this impairment within “loss on impairment of investments” in our consolidated statement of operations.

The assumptions used in the Monte Carlo Model were derived from both observable and unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the impairment test. Significant judgment is employed by the Company in developing these estimates and assumptions. The use of different assumptions would likely have a material impact on the impairment charge recognized and our consolidated statement of operations. If actual events differ from management’s estimates, or to the extent that these estimates are adjusted in the future, the Company’s financial condition and results of operations could be affected in the period of any such change of estimate.

SapuraKencana - Impairment of marketable securities
During the period from September 30, 2014, to September 30, 2015, SapuraKencana’s share price fell by approximately 45% as a result of deteriorating market conditions in the oil and gas industry. Between June 30, 2015 and September 30, 2015, the value of the investment fell by approximately 20% as a result of the declining share price and U.S. dollar to Malaysian ringgit exchange rate. At September 30, 2015, our management determined that our investment in SapuraKencana was other than temporarily impaired due to the length and severity of the reduction in value below historic cost. As a result we have impaired the investment, recognizing an impairment charge of $167 million within “loss on impairment of investments.” This impairment charge represents a reclassification of losses previously recognized within “other comprehensive income.” The amount reclassified out of “accumulated other comprehensive income” into earnings was determined on the basis of average cost.

The evaluation of whether a decline in fair value is “other than temporary” requires a high degree of judgment, and the use of different assumptions could materially affect our earnings.


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The table below summarizes the total impairments of investments made during the year ended December 31, 2015:
(In $ millions)
Year ended December 31, 2015

Impairments of investment in associated companies
 
Seadrill Partners - Total direct ownership investments
302

Seadrill Partners - Subordinated units
125

Seadrill Partners - Seadrill Member Interest and IDRs
106

Total impairment of investments in associated companies
533

 
 
Impairments of marketable securities
 
Seadrill Partners - Common units
574

SapuraKencana
167

Total impairment of marketable securities investments (reclassification from OCI)
741

 
 
Total impairment of investments
1,274


Recent Accounting Pronouncements

Recently Adopted Accounting Standards
Please see Note 2 of our Consolidated Financial Statements included herein for a list of recently adopted accounting standards.

Recently Issued Accounting Standards
The following is a summary of the recently issued accounting standards that we believe are most relevant to our Consolidated Financial Statements.

In May 2014, the Financial Accounting Standards Board (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 2015 the FASB proposed to defer the effective date of the guidance by one year. Based on this proposal, public entities would need to apply the new guidance for annual and interim periods beginning after December 15, 2017, 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. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its 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 regard 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 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update requires lessees to put most leases on their balance sheets but recognize expenses on their income statements in a manner similar to today’s accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing 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. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

Please see Note 2 of our Consolidated Financial Statements included herein for a list of recently issued accounting standards, which may impact the Company’s Consolidated Financial Statements and related disclosures when adopted.

A.
RESULTS OF OPERATIONS

We provide drilling and related services to the offshore oil and gas industry. The split of our organization into segments has historically been based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure.

We currently operate in the following segments:
 
•
Floaters: We offer services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to semi-submersible rigs and drillships for harsh and benign environments in mid-, deep- and ultra-deep waters.

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•
Jack-up rigs: We offer services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to jack-up rigs for operations in harsh and benign environments.

In prior periods, we also operated a tender rig segment, which related to services encompassing drilling, and the completion and maintenance of offshore production wells. Drilling contracts within this segment related to self-erecting tender rigs and semi-submersible tender rigs. Following the sale of the majority of the tender rig business to SapuraKencana on April 30, 2013, and the deconsolidation of Seadrill Partners on January 2, 2014, we no longer own rigs in the tender rig segment.

We also provide management services to third parties and related parties. Income and expenses from these management services are classified as “Other.”
 
Segment results are evaluated on the basis of operating profit, and the information given below is based on the internal reporting structure we have in place for reporting to our executive management and the Board of Directors. The accounting principles for the segments are the same as for our Consolidated Financial Statements.


Fiscal Year Ended December 31, 2015, Compared to Fiscal Year Ended December 31, 2014
 
The following table sets forth our operating results for 2015 and 2014.
 
Year ended December 31, 2015
 
Year ended December 31, 2014
In US$ millions
Floaters

 
 Jack-
up rigs

 
Other

Total

 
Floaters

 
 Jack-
up rigs

 
Other

Total

Total operating revenues
2,906

 
1,293

 
136

4,335

 
3,360

 
1,478

 
159

4,997

Loss/(gain) on sale of assets
(243
)
 
179

 
1

(63
)
 
632

 
—

 
—

632

Contingent consideration realized
47

 
—

 
—

47

 
—

 
—

 
—

—

Total operating expenses (excluding Loss on Goodwill impairment)
(1,807
)
 
(808
)
 
(122
)
(2,737
)
 
(2,000
)
 
(971
)
 
(147
)
(3,118
)
Goodwill impairment charge
(563
)
 
—

 
—

(563
)
 
—

 
(232
)
 
—

(232
)
Net operating income
340

 
664

 
15

1,019

 
1,992

 
275

 
12

2,279

Interest expense
 
 
 
 
 
(415
)
 
 

 
 

 
 
(478
)
Other financial items
 
 
 
 
 
(1,146
)
 
 

 
 

 
 
2,305

Income before taxes
 
 
 
 
 
(542
)
 
 

 
 

 
 
4,106

Income taxes
 
 
 
 
 
(208
)
 
 

 
 

 
 
(19
)
Net income
 
 
 
 
 
(750
)
 
 

 
 

 
 
4,087


 
Total operating revenues
In US $millions
2015

 
2014

 
Change

Floaters
2,906

 
3,360

 
(14
)%
Jack-up rigs
1,293

 
1,478

 
(13
)%
Other
136

 
159

 
(14
)%
Total operating revenues
4,335

 
4,997

 
(13
)%

Total operating revenues were $4.3 billion for 2015, compared to $5.0 billion in 2014, a decrease of $0.7 billion, or 13%. Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and other revenues. The decrease in total operating revenues compared to 2014 was primarily driven by an increase in the number of idle rigs, reductions in certain operating dayrates, the deconsolidation of the five jack-up rigs relating to SeaMex, and the sale of the West Vela and West Polaris to Seadrill Partners.

Total operating revenues in the floaters segment were $2.9 billion in 2015 compared to $3.4 billion in 2014, a decrease of $0.5 billion, or 14%. A decrease of $0.7 billion resulted from the decrease in the number of drilling units in operation during 2015 compared to 2014 mainly from the West Navigator, West Taurus, West Eclipse, West Eminence and West Venture coming off contract in 2015 and being stacked. In addition, dayrates were reduced on West Phoenix, West Pegasus and West Alpha contributing $0.2 billion of the reduction. A similar amount of decrease was attributable to the disposal of West Vela and West Polaris to Seadrill Partners. This decrease was partially offset by an increase of $0.8 billion resulting from the full-year effect of West Neptune, West Saturn and West Jupiter, which began operations in late 2014, the full-year effect of the Sevan Louisiana, which began operations in May 2014 and the West Carina, which began operations in June 2015.

Total operating revenues in the jack-up rigs segment were $1.3 billion in 2015 compared to $1.5 billion in 2014, a decrease of $0.2 billion, or 13%. The decrease was primarily due to the disposal of five jack-up rigs West Titania, West Oberon, West Defender, West Courageous and West

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Intrepid to SeaMex Limited in March 2015, and the increase in stacked rigs. However, these five jack-up rigs only operated for the latter part of 2014, and consequently the disposal of these rigs had a relatively small impact on the year-on-year comparison.
 
Other revenues predominately relate to management fee income for the provision of management services to external parties and related parties.

Gain/(loss) on disposals

In 2015 we recorded a net loss of $63 million relating to the loss on disposals of the West Polaris, West Mira and West Rigel, which was partially offset by a gain of $181 million on the disposal of our five jack-up rigs to SeaMex. In 2014, we recorded a gain of $632 million on the sale of the drillships West Auriga and West Vela to Seadrill Partners.
 
Contingent consideration realized

In 2015 we recorded contingent consideration realized of $47 million (2014: nil) relating to the disposals of the West Polaris and West Vela.

Total operating expenses
In US$ millions
2015

 
2014

 
Change

Floaters
2,370

 
2,000

 
19
 %
Jack-up rigs
808

 
1,203

 
(33
)%
Other
122

 
147

 
(17
)%
Total operating expenses
3,300

 
3,350

 
(1
)%

Total operating expenses were constant at $3.3 billion in 2015. Total operating expenses consist of vessel and rig operating expenses, loss on goodwill impairment, depreciation and amortization, reimbursable expenses and general and administrative expenses. A decrease in operating expenses resulting from our cost-cutting measures and the reduced number of drilling units in operation in 2015 was largely offset by a higher impairment charge of goodwill in 2015 compared to 2014.
 
Total operating expenses for the floaters segment were $2.4 billion in 2015 compared to $2.0 billion in 2014, an increase of $0.4 billion, or 19%. This was mainly related to the loss on impairment of goodwill of $0.6 billion relating to our floaters segment which was fully written off in 2015. This increase was partially offset by the reduction in the number of rigs in operation, and implementation of our cost-cutting program. Excluding the impairment charge to goodwill, operating expenses for the Floaters segment fell by $0.2 billion, or 10%.

Total operating expenses for the jack-up rigs segment were $0.8 billion in 2015 compared to $1.2 billion in 2014, a decrease of $0.4 billion, or 33%. This decrease was mainly due to the impairment of goodwill of $0.2 billion relating to the jack-up segment recorded in 2014. Operating costs also decreased in 2015 due to the decrease in the number of rigs in operation and due to the disposal of five jack-up rigs West Titania, West Oberon, West Defender, West Courageous and West Intrepid to SeaMex Limited in March 2015. However, these five jack-ups only began contracts in late 2014 and consequently have relatively limited impact. The decrease was also partially offset by a full year of operations for the West Linus, which began operations in May 2014. Excluding the impairment charge to goodwill in 2014, operating expenses for the jack-up segment fell by 17%.
 
Other operating expenses predominately relate to costs associated with the provision of management services to external parties and related parties.

Interest expense
 
Interest expense was $415 million in 2015 compared to $478 million in 2014, a decrease of $63 million, or 13%. This decrease is consistent with the decrease in interest-bearing debt.


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Other financial items
 
Other financial items, excluding interest expense, reported in the income statement include the following items:
 
In US$ millions
2015

 
2014

Interest income
67

 
63

Share in results of associated companies (net of tax)
190

 
34

Loss on impairment of investments
(1,274
)
 
—

Loss on derivative financial instruments
(274
)
 
(497
)
Net gain/(loss) on debt extinguishment
8

 
(54
)
Foreign exchange gain
63

 
164

Gain on realization of marketable securities
—

 
131

Gain on deconsolidation of Seadrill Partners
—

 
2,339

Gain on sale of tender rig business
22

 
—

Other financial items and other income/(expense), net
52

 
125

Total financial items and other income/(expense), net
(1,146
)
 
2,305

 
Share in results from associated companies was an income of $190 million in 2015 compared to an income of $34 million in 2014. The income in 2015 was mainly composed of our share of income from Seadrill Partners. The income in 2014 was mainly composed of our share of income from Seadrill Partners, which was partially offset by $88 million loss on our sale of a 28% limited partner interest in Seadrill Operating LP to Seadrill Partners.

During 2015 we recorded a loss on impairment of investments of $1,274 million. Please see Note 8 to our Consolidated Financial Statements included herein for further discussion.

The loss on derivative financial instruments was $274 million in 2015, compared to a loss of $497 million in 2014. The loss in 2015 was mainly related to a loss of $129 million on our interest rate swap agreements and losses of $106 million on our cross-currency interest swaps due to unfavorable movement in swap interest rates during the year and a loss on our total return swap (“TRS”) agreements of $27 million. The loss in 2014 was mainly related to a loss of $176 million on our interest rate swap agreements and losses on our cross-currency interest rate swaps of $171 million due to unfavorable movements in our interest rate swap agreements and a loss on our TRS agreements of $73 million, losses on foreign exchange swap agreements of $58 million and a loss on other derivatives of $19 million.

Foreign exchange gains amounted to $63 million in 2015 compared to gains of $164 million in 2014. This was mainly due to the revaluation of our NOK-denominated bonds to the U.S. dollar, which we believe will ultimately be favorable for us due to the weakening of the Norwegian kroner compared to the U.S. Dollar.

Included in the results for 2015 is a gain on debt extinguishment of $8 million compared to a loss of $54 million in 2014, primarily related to the extinguishment of our convertible bond. The loss in 2014 primarily relates to the incentive payment we made to holders of the convertible bonds.

Included in the results for 2014 is a gain on the realization of marketable securities of $131 million being recycled out of accumulated other comprehensive income into the income statement as a gain relating to the sale of shares in SapuraKencana. Please see Note 7 to our Consolidated Financial Statements included herein for further discussion.

Included in the results for 2014 is a gain on the deconsolidation of Seadrill Partners of $2,339 million. The gain represents the excess of the fair value of our investments in Seadrill Partners over the carrying value of the Company’s share of the net assets of Seadrill Partners deconsolidated. Please see Note 11 to our Consolidated Financial Statements included herein for further discussion.
 
Income taxes
 
Income tax expense was $208 million for the year ended December 31, 2015 compared to $19 million for the year ended December 31, 2014. The increase was mainly due to changes in uncertain tax positions taken in prior periods that were recognized during the year ended December 31, 2014.  Our effective tax rate was approximately -38% for the year ended December 31, 2015, compared to 0.5% for the year ended December 31, 2014. This means that we continue to pay tax on local operations but reported an overall loss before tax inclusive of discrete items.  The negative rate reflects no tax relief on the impairments or the derivative loss, as well as no tax chargeable on the disposal gains.  This was due to these items largely falling within the zero tax rate on Bermuda companies, compared to 2014, when there was a prior year tax benefit related to the release of an uncertain tax position.

Certain of our Norwegian subsidiaries have been party to an ongoing dispute over a tax reassessment issued in October 2011 by the Norwegian tax authorities in regard to the transfer of certain legal entities to a different tax jurisdiction and the principles for conversion of functional currency. In April 2014 these subsidiaries entered into a settlement agreement with the Norwegian tax authorities resulting in discontinued legal proceedings in the Oslo District Court. The terms of the settlement agreement included the Company making a cash payment to the tax authorities

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for the settlement of revised reassessments agreed between the parties. Following the settlement of the uncertainties arising from these matters, we recognized a $94 million positive impact on our 2014 effective tax rate.
 
Significant amounts of our income and costs are reported in non-taxable jurisdictions such as Bermuda. Our drilling rig operations are normally carried out in taxable jurisdictions.  In the tax jurisdictions where we operate, the corporate income tax rates range from 17% to 35% for earned income and the deemed tax rates vary from 4% to 10% of revenues. Further, losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, our effective tax rate may differ significantly from period to period depending on the level of activity in and mix of each of the tax jurisdictions in which our operations are conducted.

Unrealized (loss)/gain on marketable securities, net

The net unrealized loss at December 31, 2015 was $427 million compared to a loss of $982 million at December 31, 2014, presented in the statement of total comprehensive income. These unrealized losses primarily result from reductions in the market capitalization of Seadrill Partners. During 2015, an amount of $741 million was reclassified to income because the marketable securities were considered to be other than temporary impaired, Please see Note 8 to our Consolidated Financial Statements included herein for further discussion.


Fiscal Year Ended December 31, 2014, Compared to Fiscal Year Ended December 31, 2013
 
The following table sets forth our operating results for 2014 and 2013.
 
Year ended December 31, 2014
 
Year ended December 31, 2013
In US$ millions
Floaters

 
Jack-up rigs

 
Tender Rigs

 
Other

Total

 
Floaters

 
Jack-up rigs

 
Tender Rigs

 
Other

 
Total

Total operating revenues
3,360

 
1,478

 
—

 
159

4,997

 
3,698

 
1,175

 
382

 
27

 
5,282

Gain on sale of assets
632

 
—

 
—

 
—

632

 
—

 
61

 
—

 
—

 
61

Total operating expenses
(2,000
)
 
(971
)
 
—

 
(147
)
(3,118
)
 
(2,226
)
 
(786
)
 
(206
)
 
(27
)
 
(3,245
)
Net operating income
1,992

 
275

 
—

 
12

2,279

 
1,472

 
450

 
176

 
—

 
2,098

Interest expense
 

 
 

 
 

 
 
(478
)
 
 

 
 

 
 

 
 

 
(445
)
Other financial items
 

 
 

 
 

 
 
2,305

 
 

 
 

 
 

 
 

 
1,287

Income before taxes
 

 
 

 
 

 
 
4,106

 
 

 
 

 
 

 
 

 
2,940

Income taxes
 

 
 

 
 

 
 
(19
)
 
 

 
 

 
 

 
 

 
(154
)
Net income
 

 
 

 
 

 
 
4,087

 
 

 
 

 
 

 
 

 
2,786


Total operating revenues
In US$millions
2014

 
2013

 
Change

Floaters
3,360

 
3,698

 
(9
)%
Jack-up rigs
1,478

 
1,175

 
26
 %
Tender rigs
—

 
382

 
(100
)%
Other
159

 
27

 
489
 %
Total operating revenues
4,997

 
5,282

 
(5
)%

Total operating revenues were $5.0 billion in 2014, compared to $5.3 billion in 2013, a decrease of $0.3 billion, or 5%. Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and other revenues. There was an increase in revenues from the jack-up segment due to an increase of rigs in operation, improved utilization as well as an increase in average dayrates. The increase in jack-up segment was offset by a decrease in the floaters segment primarily due to the deconsolidation of Seadrill Partners. This was further offset by the sale of the tender rig business at the end of April 2013, where the tender rigs sold contributed to revenues for the first four months of 2013 compared to no revenues in 2014.
 
Total operating revenues in the floaters segment were $3.4 billion in 2014 compared to $3.7 billion in 2013, a decrease of $0.3 billion, or 9%. This decrease was mainly due to the decrease in the number of drilling units in the floaters segment to 19 as of December 31, 2014 from 22 at December 31, 2013 due to the deconsolidation of Seadrill Partners on January 2, 2014, which owned 5 floaters at the time of deconsolidation and the sale of two further drilling units the West Auriga and West Vela to Seadrill Partners during 2014. This decrease was partially offset by the addition of three new drilling units to our fleet in late 2014: the West Neptune, West Saturn and West Jupiter, in addition to the Sevan Louisiana, which began operations in May 2014.

Total operating revenues in the jack-up rigs segment were $1.5 billion in 2014 compared to $1.2 billion in 2013, an increase of $0.3 billion, or 26%. The increase was mainly due to the increased number of drilling units in the jack-up segment to 24 at December 31, 2014 from 20 at December 31, 2013 due to the addition of the newbuild rigs West Titania, West Oberon, West Telesto and West Linus, and full year operations of the AOD 1, AOD 2, AOD 3, West Tucana and West Castor.

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Total operating revenues in the tender rig segment were nil in 2014 compared to $382 million in 2013. The decrease was due to the sale of the majority of the tender rig business to SapuraKencana on April 30, 2013, and the deconsolidation of Seadrill Partners on January 2, 2014.

Other revenues predominately related to management fee income for the provision of management services to third and related parties.

Gain on disposals

In 2014 we recorded a gain of $632 million on the sale of the drillships West Auriga and West Vela to Seadrill Partners. In 2013, we recorded a gain of $61 million on the sale of the jack-up rig West Janus.

 
Total operating expenses
In US$ millions
2014

 
2013

 
Change

Floaters
2,000

 
2,226

 
(10
)%
Jack-up rigs
1,203

 
786

 
53
 %
Tender rigs
—

 
206

 
(100
)%
Other
147

 
27

 
444
 %
Total operating expenses
3,350

 
3,245

 
3
 %

Total operating expenses were $3.3 billion in 2014 compared to $3.2 billion in 2013, an increase of $0.1 billion, or 3%. Total operating expenses consist of vessel and rig operating expenses, depreciation and amortization, reimbursable expenses, and general and administrative expenses. Total general and administrative expenses were $315 million in 2014 compared to $300 million in 2013, an increase of $15 million, or 5%. The increase was mainly due to additional costs incurred related to increased management support across our business to support our growth and strategic initiatives and the addition of Sevan Drilling from July 2013. Reimbursable expenses in each segment were closely in line with reimbursable revenues.
 
Total operating expenses for the floaters segment were $2.0 billion in 2014 compared to $2.2 billion in 2013, a decrease of $0.2 billion, or 10%. This was mainly related to the decrease in the number of rigs in operation due to the deconsolidation of Seadrill Partners, which owned five floaters at the time of deconsolidation plus the sale of two additional rigs to Seadrill Partners (the West Auriga and West Vela) during 2014. This decrease was partially offset by the addition of three new rigs towards the end of 2014 (the West Neptune, West Saturn and West Jupiter) in addition to the Sevan Louisiana, which began operations in May 2014.

Total operating expenses for the jack-up rigs segment were $1.2 billion in 2014 compared to $0.8 billion in 2013, an increase of $0.4 billion, or 53%. This increase was mainly due to the impairment of goodwill of $232 million relating to the jack-up segment. Operating costs also increased in 2014 due to the increase in the number of rigs in operation, including the addition of the newbuild rigs the West Titania, West Oberon, West Telesto and West Linus, and full-year operations of the AOD 1, AOD 2, AOD 3, West Castor and West Tucana.
 
Total operating expenses for the tender rig segment were nil in 2014 compared to $206 million in 2013. The decrease was due to the sale of the majority of the tender rig business to SapuraKencana on April 30, 2013, and the deconsolidation of Seadrill Partners on January 2, 2014.

“Other” expenses predominately relate to costs associated with the provision of management services to third and related parties.

Interest expense

Interest expense was $478 million in 2014 compared to $445 million in 2013, an increase of $33 million, or 7%. The increase was mainly due to the inclusion of a full year’s interest expense relating to Sevan in 2014 compared to only half a year in 2013. In addition, more interest was capitalized in 2013 compared to 2014 according to the number of rigs under construction in each period. This increase was partially offset by deconsolidation of Seadrill Partners and a reduction in long-term debt in 2014.


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Other financial items
 
Other financial items reported in the income statement include the following items: 
In US$ millions
2014

2013

Interest income
63

24

Share in results from associated companies (net of tax)
34

(223
)
(Loss)/gain on derivative financial instruments
(497
)
133

Net gain/(loss) on debt extinguishment
(54
)
—

Foreign exchange gain
164

52

Gain on realization of marketable securities
131

—

Gain on deconsolidation of Seadrill Partners
2,339

—

Gain on sale of tender rig business
—

1,256

Other financial items and other income/(expense), net
125

45

Total financial items and other income/(expense), net
2,305

1,287


Interest income was $63 million in 2014 compared to $24 million in 2013. Interest income for the period was primarily composed of interest earned on restricted cash balances, and interest earned and accreted on deferred consideration from SapuraKencana related to the sale of the tender rig business. During 2014 we also received interest from Seadrill Partners as a result of its deconsolidation on January 2, 2014.

Share in results from associated companies was an income of $89 million in 2014 compared to a loss of $223 million in 2013. The income in 2014 was mainly composed of our share of income from Seadrill Partners, which was partially offset by a $88 million loss on our sale of a 28% limited partner interest in Seadrill Operating LP to Seadrill Partners. The loss in 2013 was mainly composed of our share of net losses in Archer during the year.

The loss on derivative financial instruments was $497 million in 2014 compared to a gain of $133 million in 2013. The loss in 2014 mainly related to a loss of $176 million on our interest rate swap agreements and a loss of $171 million on our cross-currency interest swaps due to unfavorable movements in swap interest rates during the year; loss on our TRS agreements of $73 million, a loss of $58 million on foreign exchange swap agreements and a loss on other derivatives of $19 million. Gains in 2013 were mainly related to a gain of $143 million on our interest rate swap agreements due to the favorable movement in swap interest rates during the year, gain on our TRS agreements of $19 million and gain on other derivatives of $30 million, which was partially offset by a loss on our cross-currency interest rate and foreign exchange swap agreements of $10 million.

Foreign exchange gains amounted to $164 million in 2014, compared to gains of $52 million in 2013. This was mainly due to the revaluation of our NOK-denominated bonds to the U.S. dollar and is favorable due to the weakening of Norwegian kroner compared to the U.S. Dollar.

Included in the results for 2014 is net loss on debt extinguishment of $54 million primarily relating to the extinguishment of our convertible bond. The loss primarily relates to the incentive payments we made to holders of the convertible bonds. Please see Note 23 to our Consolidated Financial Statements included herein for further discussion.

Included in the results for 2014 is a gain on the realization of marketable securities of $131 million being recycled out of accumulated other comprehensive income into the income statement as a gain relating to the sale of shares in SapuraKencana. Please see Note 7 to our Consolidated Financial Statements included herein for further discussion.

Included in the results for 2014 is a gain on the deconsolidation of Seadrill Partners of $2,339 million. The gain represents the excess of the fair value of the Company’s investments in Seadrill Partners over the carrying value of our share of the net assets of Seadrill Partners deconsolidated. Please see Note 11 to our Consolidated Financial Statements included herein for further discussion.

Included in the results for 2013 is a gain of $1,256 million on sale of the tender rig business to SapuraKencana. The sale closed on April 30, 2013. Please see Note 11 to our Consolidated Financial Statements included herein for further discussion.
 
Income taxes
 
Income tax expense was $19 million for the year ended December 31, 2014 compared to $154 million for the year ended December 31, 2013. The decrease was mainly due to changes in uncertain tax positions taken in prior periods that were recognized during the year ended December 31, 2014.  Our effective tax rate was approximately 1% for the year ended December 31, 2014 compared to 5% for the year ended December 31, 2013. The decrease in the effective rate is principally due to the non-taxable gain on the deconsolidation of Seadrill Partners.

Certain of our Norwegian subsidiaries have been party to an ongoing dispute to a tax reassessment issued in October 2011 by the Norwegian tax authorities in regard to the transfer of certain legal entities to a different tax jurisdiction and the principles for conversion of functional currency. In April 2014 these subsidiaries entered into a settlement agreement with the Norwegian tax authorities resulting in discontinued legal proceedings in the Oslo District Court. The terms of the settlement agreement included the Company making a cash payment to the tax authorities

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for the settlement of revised reassessments agreed between the parties. Following the settlement of the uncertainties arising from these matters, we recognized a $94 million positive impact on our second quarter 2014 effective tax rate.
 
Significant amounts of our income and costs are reported in non-taxable jurisdictions such as Bermuda. The drilling rig operations are normally carried out in taxable jurisdictions.  In the tax jurisdictions in which we operate, the corporate income tax rates range from 17% to 35% for earned income and the deemed tax rates vary from 4% to 10% of revenues. Further, losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, our effective tax rate may differ significantly from period to period depending on the level of activity in, and the mix of, each of tax jurisdictions in which our operations are conducted.

Unrealized (loss)/gain on marketable securities, net

The net unrealized loss at December 31, 2014 was $982 million compared to a gain of $333 million at December 31, 2013, presented in the statement of total comprehensive income. The unrealized loss in 2014 was a result of recent reductions in the market capitalization of Seadrill Partners and SapuraKencana, both entities in which we hold investments, compared to the gains made on the investment in SapuraKencana made in 2013.

B.
LIQUIDITY AND CAPITAL RESOURCES
 
Overview
We operate in a capital intensive industry. Historically our investment in newbuild drilling units, secondhand drilling units and our acquisition of other companies has been financed through borrowings from commercial banks and export credit agencies, cash generated from operations, and a combination of equity issuances, bond and convertible bond offerings. Our liquidity requirements relate to servicing and repaying our debt, funding investment in drilling units, funding working capital requirements and maintaining adequate cash reserves to mitigate the effects of fluctuations in operating cash flows. 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 in accordance with our corporate policies to maximize returns while maintaining appropriate liquidity for our operating requirements. Cash and cash equivalents are held mainly in U.S. dollars, with lesser amounts held in Norwegian Kroner and Brazilian Real.

This section discusses the most important factors affecting our liquidity and capital resources, including:
•
Summary of our borrowing activities;
•
Liquidity outlook;
•
Our newbuilding program;
•
Key financial covenants related to our borrowings;
•
Sources and uses of cash;

Summary of our borrowing activities
As of December 31, 2015, we had total outstanding borrowings under our secured credit facilities of $8.3 billion, secured by, among other things, liens on our drilling units, and unsecured bonds outstanding of $2.4 billion. In addition, we had interest bearing debt of $0.4 billion under loan agreements with related parties.

We have issued a variety of secured and unsecured borrowings. Generally the secured debt amortizes over a period of five to ten years, with a balloon payment at maturity. The debt is secured by, among other things, liens on our drilling units. In addition, all 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 bonds denominated primarily in U.S. dollars, but also in Norwegian Kroner and Swedish Kroner, with both fixed and floating rates of interest. For the floating bonds in NOK and SEK, we have entered into cross currency interest rate swaps to fix the interest and exchange rates to the dollar.

During the year ended December 31, 2015 we made external debt repayments of $3.0 billion, compared to $4.3 billion in 2014. In 2015 this included the maturity of our $700 million secured loan related to certain of our jack-up drilling units, the refinancing of our $450 million senior secured credit facility related to our acquisition of the West Eclipse facility, and maturity of our $350 million fixed interest bond, which was repaid at par. In addition our $420 million senior secured credit facility relating to the West Polaris was also derecognized when the West Polaris was sold to Seadrill Partners, and on our deconsolidation of SeaMex the $150 million senior secured credit facility credit facility relating to the West Oberon was repaid.

In 2015, we raised $1.5 billion of new external debt financing, which included our $950 million senior secured credit facility related to the West Carina and West Eclipse, and our $450 million senior secured facility for six jack-up drilling units, compared to $5.1 billion in 2014.


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As of December 31, 2015 we had a total of $462 million of undrawn borrowing capacity under our existing credit facilities. Currently, however, we are restricted from drawing down on any of this capacity due to the amendments made to our secured facilities in April 2016.

The outstanding external debt as of December 31, 2015, gross of capitalized loan fees, is repayable as follows:
(In US$ millions)
2016

2017

2018

2019

2020

2021 and thereafter

Total

Outstanding loans
1,526

2,872

2,432

2,817

1,014

—

10,661


Please refer to Note 23 - Long term debt to our Consolidated Financial Statements included in this Annual Report on Form 20-F for further detailed information on our credit facilities and bonds.

Liquidity Outlook
Our short-term liquidity requirements relate to servicing our debt amortizations, interest payments, and funding working capital requirements. Sources of liquidity include existing cash balances, short-term investments and contract and other revenues. We have historically relied on our cash generated from operations to meet our working capital needs. We believe that cash on hand, liquid investments, contract and other revenues, provided by our current contract backlog, will generate sufficient cash flow to fund our anticipated debt service and working capital requirements for the next twelve months. We currently have certain restrictions on drawing down additional amounts on our undrawn revolving credit facilities. Our long-term liquidity requirements include the repayment of long-term debt balances, and funding yard installments for new drilling units.

On April 28, 2016, we entered into agreements with our banking group to amend the financial covenants on all of our secured credit facilities. In addition to the covenant waiver we have also deferred the maturities of three facilities maturing prior to May 2017, significantly improving our liquidity profile over the next 15 months. The $450 million senior secured credit facility, related to the West Eminence, has been deferred from June 20, 2016 to December 31, 2016. The $400 million senior secured credit facility relating to four jack-up rigs has been deferred from December 8, 2016 to May 31, 2017. The $2,000 million senior secured credit facility of our consolidated subsidiary, NADL, has been deferred from April 15, 2017 to June 30, 2017. These facilities have balloon payments on maturity of $331 million, $200 million, and $950 million respectively.

This agreement is the first stage is one component of a broader effort to refinance our indebtedness, and provides a more stable platform from which to work with all parts of our capital structure to achieve a more comprehensive refinancing solution that we aim to communicate later in the year. The second stage of the effort is expected to address medium- to long-term liquidity requirements and create an investable platform for new capital.

We expect to refinance our credit facilities and other debt facilities, including the $1 billion bond due in September 2017. In addition, we expect to take additional steps to further delay newbuild deliveries until the dayrates justify taking delivery. We do not expect to take delivery of any units in 2016 and currently have $4.0 billion of newbuild yard installments due in 2017, 2018 and 2019 that we will be working with shipyards to defer. We expect that we will require external financing sources additional issuances to meet our refinancing and capital requirements. Future financings may result in higher borrowing costs, or require more restrictive covenants and terms, which may further restrict our operations.

Our newbuilding program
In 2015 we spent $0.9 billion on newbuildings, drilling units, and equipment, compared to $2.9 billion 2014. The reason for the reduction was that in 2015 we only took delivery of the West Carina, whereas in 2014 we took delivery of the West Jupiter, the West Saturn, the West Neptune, and the West Linus.

At December 31, 2015, we had contractual commitments under thirteen newbuilding contracts totaling $4.0 billion (2014: $5.4 billion). The deliveries currently contracted to take place in 2016, and 2017 are the eight jack-up rigs with Dalian, and the two drillships with Samsung. We have already successfully entered into deferral agreements with the shipyards as follows:

•
On January 22, 2015, we entered into an agreement with Dalian to defer the deliveries of eight jack-ups that were previously scheduled to be delivered in 2015 and 2016, to 2016 and 2017. On June 3, 2015, we entered into a second amendment with Dalian to defer the deliveries of four jack-ups that were previously due in 2016 to late 2016 and 2017. On April 18, 2016, we entered into agreements with Dalian to further the defer the deliveries of all eight jack-ups under construction. Following this latest deferral agreement, one unit is now scheduled to be delivered at the end of 2016, four units in 2017, and three units in 2018.
•
On July 2, 2015, we entered into an agreement with Samsung to defer the deliveries of two ultra-deepwater drillships, the West Draco and the West Dorado from 2015 to the first quarter of 2017.
•
On December 2, 2015, the Company signed an amendment with Jurong Shipyard (“Jurong”) for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel (the “Unit”). The deferral period lasts until June 2016, following completion of which, the Company and Jurong have agreed to form a Joint Asset Holding Company for joint ownership of the Unit, to be owned 23% by the Company and 77% by Jurong, in the event no employment is secured for the Unit and no alternative transaction is completed.

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Until the end of the deferral period, the Company will continue to market the unit for an acceptable drilling contract, and the Unit will remain at the Jurong Shipyard in Singapore. The Company and Jurong may also consider other commercial opportunities for the Unit during this period. However, based on current market conditions, management deems the most probable outcome to be that the Unit will be contributed to the Joint Asset Holding Company. As a result, the Company has concluded that the West Rigel drilling unit should be classified as “Held for Sale” as at December 31, 2015.
•
On January 15, 2016, we entered into an agreement with DSME to defer the delivery of two ultra-deepwater drillships, the West Aquila and West Libra, until the second quarter 2018 and first quarter of 2019, respectively.
•
On October 30, 2015, Sevan Drilling and Cosco agreed to exercise the first six-month option of the delivery deferral agreement for the Sevan Developer, which extended the deferral period to April 15, 2016. In addition, on April 15, 2016, we exercised our second six-month deferral option, until October 15, 2016. Sevan Drilling and Cosco have two remaining six-month deferral options available.

The table below shows the maturity schedule for the Newbuilding contractual commitments as of April 28, 2016, which reflects the recent deferral agreements with DSME, Samsung and Cosco and Dalian, and assumes we exercise the remaining deferral options for the Sevan Developer with Cosco:

(In US$ millions)
2016

2017

2018

2019

2020

2021 and thereafter

Total

Newbuildings
188

2,158

1,174

529

—

—

4,049


Borrowings under our current credit facilities and available cash on hand are not sufficient to pay the remaining installments related to our contracted yard commitments for all of our newbuild drilling units, which currently total $4 billion as of March 31, 2016. We expect to finance the yard installments largely through secured bank financing. We expect to secure financing for the eventual deliveries at affordable terms and rates due to our past experience and successes. We are negotiating with our shipyards to further adjust delivery dates to meet contracting demands, as we have successfully done so previously, including the potential use of various deferral arrangements. We believe that we will reach negotiated solutions with the shipyards to further defer the deliveries and final installments that are due in 2016 and 2017 into later periods.

Key financial covenants related to our borrowings
May 2015 Amendments to Senior Secured Credit Facilities
In May 2015, the Company executed an amendment to the covenants contained in all of its senior secured credit facilities. 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 senior secured credit facilities as follows:
•
.125% per annum if the leverage ratio is 4.50:1 up to and including 4.99:1;
•
.25% per annum if the leverage ratio is 5.00:1 up to and including 5.49:1;
•
.75% per annum if the leverage ratio is 5.50:1 up to and including 6.00:1

In addition, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities in May 2015, the Company is restricted from making dividend distributions, and repurchasing its own shares during the amendment period until January 1, 2017.

April 2016 Amendments to Senior Secured Credit Facilities
On April 28, 2016, the Company executed amendment and waiver agreements in respect of all of its senior secured credit facilities. The Company also executed maturity extension agreements in respect of three senior secured credit facilities maturing in the near term. The key terms and conditions of these agreements are as follows:

•
Extensions:
◦
$450 million Senior Secured Credit Facility: The maturity of the $450 million senior secured credit facility, relating to the Eminence rig, has been extended from June 20, 2016 to December 31, 2016. In addition, the margin has been reset to 250 basis points.
◦
$400 million Senior Secured Credit Facility: The maturity of the $400 million senior secured credit facility, relating to jack-up rigs West Cressida, West Callisto, West Leda and West Triton, has been extended from December 8, 2016 to May 31, 2017.

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◦
$2 billion Senior Secured Credit Facility: The maturity of the $2 billion senior secured credit facility of our majority-owned subsidiary NADL has been extended from April 15, 2017 to June 30, 2017.

•
Key amendments and waivers:
◦
Equity ratio: The Company 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: The Company 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: The Company’s secured bank credit facilities contain loan-to-value clauses, or minimum-value-clauses (“MVC”), which could require the Company 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: The Company 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: The Company has agreed to consultation, information provision and certain processes in respect of further discussions with its lenders under its senior secured credit facilities. This includes agreements in respect of progress milestones towards the agreement of, and implementation plan in respect of, a comprehensive financing package.
◦
Restrictive undertakings: The Company has agreed to additional near-term restrictive undertakings applicable during this process, including (without limitation) limitations in respect of:
▪
dividends, share capital repurchases and total return swaps;
▪
incurrence and maintenance of certain indebtedness;
▪
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: The Company has agreed to refrain from borrowing any undrawn commitments under its senior secured credit facilities.
◦
Fees: The Company has agreed to pay certain fees to its lenders in consideration of these extensions and amendments.

These extensions and amendments are designed to provide the Company and the banking group with a period of stability and certainty while a more comprehensive financing package is agreed. The Company intends to further communicate these financing plans this year.

The Company expects to remain in compliance with the amended covenants for the next twelve months.

Please refer to Note 23 - Long term debt to our Consolidated Financial Statements included herein for further information on our the covenants contained within our credit facilities and bonds.
Please refer to Item 3 Key Information - D Risk Factors for further information on the risks facing our Company and implications of a breach in financial covenants.

Sources and uses of cash
At December 31, 2015, we had cash and cash equivalents totaling $1.0 billion, compared to $0.8 billion in 2014.


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In the year ended December 31, 2015, we generated cash from operations of $1.8 billion, used $0.2 billion in investing activities, and cash outflows from financing activities were $1.4 billion, compared to $1.6 billion, $0.1 billion, and $1.5 billion outflows, respectively, in the year ended 2014.

Summary cash flow statement 
Year ended December 31,
(In US$ millions)
2015

 
2014

 
2013

Net cash provided by operating activities
1,788

 
1,574

 
1,695

Net cash (used in)/provided by investing activities
(190
)
 
66

 
(2,964
)
Net cash (used in)/provided by financing activities
(1,370
)
 
(1,521
)
 
1,695

Cash and cash equivalents held for sale
—

 
(26
)
 
—

Effect of exchange rate changes on cash
(15
)
 
(6
)
 
—

Net increase in cash and cash equivalents
213

 
87

 
426

Cash and cash equivalents at beginning of the period
831

 
744

 
318

Cash and cash equivalents at the end of period
1,044

 
831

 
744


Net cash provided by operating activities
The net cash generated from operations increased in 2015 compared to 2014 primarily due to working capital improvements in the year, including improved collections of trade receivables and related party balances. We have also spent less on long-term maintenance due to the implementation of our cost savings program. The total interest and taxes paid during 2015 is also lower than in 2014. The increase in net cash generated from operations has been partly offset by a reduction in underlying operating income, and fewer dividends received from associated companies, such as from our direct investments in the operating subsidiaries of Seadrill Partners.

Net cash used in investing activities
The net cash used in investing activities was $190 million in 2015, compared to net cash provided by investing activities of $66 million in 2014. In 2015 we spent $0.9 billion on newbuildings, drilling units, and equipment, compared to $2.9 billion in 2014, primarily due to only taking delivery of one drillship in 2015, compared to three drillships and a harsh environment jack-up drilling rig in 2014. In 2015 million we raised $1.2 billion on the disposals of businesses, including the disposal of the West Polaris to Seadrill Partners and the disposal of 50% of the interest in SeaMex. In 2014 we raised $1.1 billion on the disposals of businesses, including the disposal of the West Auriga and West Vela to Seadrill Partners. In addition, in 2014 we raised $373 million when we sold 28% of our limited partner interest in Seadrill Operating LP, a subsidiary of Seadrill Partners, to Seadrill Partners.

Net loans issued to related parties were $290 million in 2015, compared to a net $2.1 billion of related party loans repaid in 2014. The large repayment in 2014 mainly relates to when Seadrill Partners entered into an independently financed term loan, the proceeds of which were partly used to repay the related party back to back loan financing between us and Seadrill Partners. In 2015 we made investments into associated companies totaling $210 million, compared to 586 million in 2014.
 
Net cash used in financing activities
The net cash used in financing activities was $1.4 billion in 2015, compared $1.5 billion in 2014. During the year ended December 31, 2015 we made external debt repayments of $3.0 billion, compared to $4.3 billion in 2014. In 2015 this included the maturing of the $700 million facility for jack-up drilling units, the refinancing of the $450 million West Eclipse facility, and maturity of the $350 million fixed interest bond, which was repaid at par.
During the year ended December 31, 2015 we raised $1.5 billion of new external debt financing, compared to $5.1 billion in 2014. In 2015 this included the new $950 million facility for the West Carina and West Eclipse, and the new $450 million facility for six jack-up drilling units.
During the year ended December 31, 2015 we did not pay any dividends, while for the same period in 2014 we paid $1.4 billion in total cash dividends.


Dividends
For the year ended December 31, 2015 we did not pay any dividends, while for the same period in 2014 we paid $1.4 billion to shareholders of the Company in total cash dividends. On November 26, 2014, we suspended dividend distributions until further notice. In connection with the amendments to our secured loan agreements in May 2015 to increase the leverage ratio contained our senior secured credit facilities, we are restricted from paying dividends so long as the amended ratio is in effect, until January 1, 2017. In addition, in April 2016, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from making dividend distributions during the amendment period until June 30, 2017.
Please see “Item 8. Financial Information - Dividend Policy” for more information.

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Restrictions
Seadrill Limited, as the parent company of its operating subsidiaries, is not a party to any drilling contracts directly and is therefore dependent on receiving cash distributions from its subsidiaries and other investments to meet its payment obligations. Cash dividend payments are regularly transferred by the various subsidiaries. Surplus funds are deposited to maximize returns while providing us with flexibility to meet all requirements for working capital and capital investments.

Hedging of market risk
We use financial instruments to reduce the risk associated with fluctuations in interest and foreign exchange rates. Most of these agreements do not qualify for hedge accounting and any changes in the fair values of the financial instruments are included in our consolidated statement of operations under “gain/(loss) on derivative financial instruments.”

Please see “Item 11 - Quantitative and Qualitative Disclosures About Market Risk” for a more detailed discussion of how changes in the economic environment would affect us.

Please see “Note 32 - Risk management and financial instruments” to the Consolidated Financial Statements included herein, for further information on our risk management and financial instruments.

C.
RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES, ETC.

We do not undertake any significant expenditure on research and development, and have 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, the offshore drilling market is currently entering its third year of a downturn. Rig owners are bidding for available work extremely competitively with a focus on utilization over returns, which will likely drive dayrates down to or below cash breakeven levels.

The offshore drilling market continues to be oversupplied with multiple drilling rigs chasing the few opportunities that 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 are likely to be idle for a protracted period. Consequently, cold stacking and 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 needed 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 expected at some point. Offshore oil fields represent a material portion of most major oil company’s reserves and their production remains a cost competitive source of hydrocarbons.

Floaters

It is likely that the majority of 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.

Over the past 18 months 70 units have been scrapped, representing more retirements than over the prior 9 years combined, and more than any other 18 month period in history. Over the next 6 quarters, 26 of the 72 rigs rolling off contract are 5th generation or below units that will be challenged to find work for the foreseeable future as they are priced out 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 rig owners will find economic justification to keep these old assets working.

Larger drilling companies with diversified fleets will find it easier to make economic decisions and cold stack idle rigs as each individual unit represents a smaller percentage of the overall fleet. Cold stacked units will generally require an improvement in dayrates sufficient to overcome reactivation costs before they are reintroduced into marketed supply. Significant cold stacking activity would represent a positive development in the market, effectively reducing marketed supply and helping to stabilize utilization and pricing until a more fundamental recovery is in place.


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Currently 170 floaters are in contracted, representing 56% marketed utilization. It is estimated that 180-200 rigs are needed in the floater fleet to maintain current decline curves.

The current newbuilding orderbook stands at approximately 69 units. A significant number of these newbuild orders have been delayed or cancelled and we expect this trend to continue. Delayed or cancelled newbuildings will ultimately be added to the fleet, however 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.

Jack-ups

Tendering activity in the jack-up market during 2015 continued, albeit at low dayrates. The shorter term contract profile in this market lends itself to more turnover and the market has likely reached the base level of units required to maintain existing decline curves.

Globally, contracted utilization is 62%. For units built before 2006 utilization is 55% while for newer units utilization is 71%. While utilization is still far from levels required for pricing power, customers continue to demonstrate a preference for newer and more capable equipment that can provide safer and more efficient operations.

Currently there are approximately 128 idle units older than 30 years out of a total fleet of 536. Additionally there are 56 units that are rolling off contracts by the end of 2016, which are also older than 30 years. Together, these 184 rigs, or 34% of the total fleet, represent prime candidates for retirement.

122 additions to the fleet are currently under construction; however a significant portion of these orders were placed by investors with little or no operating track record. While a number of these speculators may exit projects, these units will eventually reach the market, possibly in the hands of more established companies. The deployment of this incremental supply may be somewhat rationalized in the longer term as the more established players will likely only take delivery when economically viable.

E.
OFF BALANCE SHEET ARRANGEMENTS
 
The Company had no off-balance sheet arrangements as of December 31, 2015 or 2014, other than operating lease obligations and other commitments in the ordinary course of business that we are contractually obligated to fulfill with cash under certain circumstances. These commitments include guarantees in favor of banks, suppliers and variable interest entities and guarantees towards third parties such as surety performance guarantees to customers as they relate to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these guarantees are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2015, we had not been required to make collateral deposits with respect to these agreements.

The maximum potential future payments are summarized in “Note 33–Commitments and Contingencies,” in the Notes to our Consolidated Financial Statements included herein.

F.
CONTRACTUAL OBLIGATIONS
 
At December 31, 2015, we had the following contractual obligations and commitments:
 
Payment due by period
(In US$ millions)
Less than
1 year

 
1 – 3
years

 
3 – 5
years

 
After
5 years

 
Total

Interest-bearing debt
1,526

 
5,304

 
3,831

 
—

 
10,661

Related party interest-bearing debt
—

 
—

 
—

 
415

 
415

Total debt repayments
1,526

 
5,304

 
3,831

 
415

 
11,076

Interest payments
384

 
561

 
138

 
—

 
1,083

Related party interest payments
19

 
37

 
37

 
90

 
183

Pension obligations (1)
12

 
37

 
13

 
70

 
132

Operating lease obligations
11

 
18

 
12

 
13

 
54

Total contractual obligations
1,952

 
5,957

 
4,031

 
588

 
12,528


(1)
Pension obligations are the forecasted employer’s contributions to the Company’s defined benefit plans, expected to be made over the next ten years.


In addition, the table below shows the maturity schedule for the newbuilding contractual commitments as of April 28, 2016, which reflects all recent deferral agreements with DSME, Samsung, Cosco and Dalian, and assumes we exercise the remaining deferral options for the Sevan Developer with Cosco:

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(In US$ millions)
2016

2017

2018

2019

2020

2021 and thereafter

Total

Newbuildings (1)
188

2,158

1,174

529

—

—

4,049


(1)
Newbuilding commitments relate to eight jack-up rigs totaling $1.7 billion, one semi-submersible rig totaling $0.4 billion and four drillships totaling $1.9 billion. Note that the newbuilding commitments include $0.4 billion related to the Sevan Developer that are presented as a contractual obligation in the balance sheet in the line item “Other short term liabilities.” Please see “Note 33 – Commitments and contingencies” to our Consolidated Financial Statements included herein for further information.

G.
SAFE HARBOR
 
Forward-looking information discussed in this Item 5 includes assumptions, expectations, projections, intentions and beliefs about future events. These statements are intended as “forward-looking statements.” We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material. Please see “Cautionary Statement Regarding Forward-Looking Statements” in this Annual Report.

ITEM 6.
DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
 
A.
DIRECTORS AND SENIOR MANAGEMENT
 
The following table sets forth information regarding our directors and officers, and also certain key employees within our operating subsidiaries, who are responsible for overseeing the management of our business.
 
Name
Age
Position
John Fredriksen
72
President, Director and Chairman of the Board
Kate Blankenship
51
Director and Audit Committee member
Kathrine Fredriksen
32
Director
Bert Bekker
77
Director
Paul Leand Jr.
49
Director
Ørjan Svanevik
50
Director
Hans Petter Aas
70
Director
Georgina Sousa
65
Director and Company Secretary
Per Wullf
56
Director, Chief Executive Officer and President, Seadrill Management
Mark Morris
52
Chief Financial Officer and Senior Vice President, Seadrill Management
David Sneddon
52
Chief Accounting Officer and Senior Vice President, Seadrill Management
Anton Dibowitz
43
Chief Commercial Officer and Senior Vice President, Seadrill Management
Leif Nelson
41
Chief Operating Officer and Senior Vice President
Henrik M Hansen
53
Chief Technical Officer and Senior Vice President
Svend Anton Maier
50
Senior Vice President Special Projects
José Firmo
45
Senior Vice President Brazil
Alf Ragnar Løvdal
58
Senior Vice President and CEO of North Atlantic Management
Ray Watkins
55
Senior Vice President Americas
Philip Souyris
46
Senior Vice President Mexico
Dave Morrow
44
Senior Vice President, Africa & Middle East
Alex Monsen
54
Senior Vice President Asia Pacific
Des Thurlby
51
Senior Vice President, Human Resources

Certain biographical information about each of our directors, executive officers and key officers is set forth below.
 
John Fredriksen has served as our Chairman of the Board, President and since our inception in May 2005. Mr. Fredriksen has also served since 1997 as Chairman, President, and a director of Frontline Ltd. (NYSE:FRO), or Frontline, a Bermuda company listed on the NYSE and the OSE, and from 2001 until September 2014 as Chairman of the Board, President and a director of Golar LNG Limited, or Golar, a Bermuda company listed on the Nasdaq Global Market. Mr. Fredriksen also currently serves as a director of Golden Ocean Group Limited (formerly Knightsbridge Shipping Limited), or Golden Ocean, a Bermuda company listed on the Nasdaq Stock Market and the OSE since March 2015. Mr. Fredriksen also served as a director and chairman of the board of NADL between its inception in 2011 and September 2015. Mr. Fredriksen is the father of Ms. Kathrine Fredriksen, a director of the Company.


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Kate Blankenship has served as a director of the Company 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 Secretary until October 2005. Mrs. Blankenship has been a director of Ship Finance since October 2003, Seadrill Partners since June 2012, NADL since February 2011, Independent Tankers Corporation Limited, since February 2008, Golden Ocean since March 2015, Archer since its incorporation in 2007 and Avance Gas Holding Ltd since October 2013. Mrs. Blankenship served as a director of Golar LNG Limited from July 2003 until September 2015 and Golar LNG Partners from September 2007 until September 2015. She is a member of the Institute of Chartered Accountants in England and Wales.

Kathrine Fredriksen has served as a director of the Company since September 2008. Ms. Fredriksen has also served as a director of Golar LNG Partners from April 2013 until September 2014, and served as a director of Golar LNG Limited from February 2008 until April 2013. She graduated from Wang Handels Gymnas in Norway and studied at the European Business School in London. Ms. Fredriksen is the daughter of Mr. John Fredriksen, our President and Chairman.

Bert Bekker has served as a director of the Company since April 2013. 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 B.V.). 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, 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 currently serves as a director of Wilh. Wilhelmsen Netherlands B.V., part of the Wilh. Wilhelmsen ASA Group, and has served as a director since July 2003. Mr. Bekker has served as a director of Seadrill Partners since September 2012, and Ship Finance since May 2015.

Paul Leand, Jr. has served as a director of the Company since April 2013. Mr. Leand is the Chief Executive Officer and director of AMA Capital Partners LLC, or AMA, an investment bank specializing in the maritime industry. Mr. Leand has worked extensively in U.S. capital markets in connection with AMA’s restructuring and mergers and acquisitions practices. Mr. Leand currently serves as a member of the Investment Committee of AMA Shipping funds, a series of private equity funds formed and managed by AMA. From 1989 to 1998, Mr Leand managed the Railroad Division and the International Maritime Division of First National Bank of Maryland. Mr. Leand currently also serves as a director of Ship Finance since 2003, Golar LNG Partners LP since 2011, NADL since 2012 and Eagle Bulk Shipping Inc. since 2014.

Ørjan Svanevik has served as a director of the Company since October 2014, and as a director of NADL since May 2015. Mr. Svanevik joined the Seatankers Group in July 2014 and has a broad industry background, with special knowledge of oil and gas, maritime, shipbuilding, and engineering sectors. He has extensive experience from global operations, investment management and corporate finance. Mr Svanevik was previously Managing Director for the investment advisory firm Oavik Capital from October 2008 to July 2014. Prior to this he was Head of M&A and a Partner at Aker ASA from 2005 to 2008, and COO and EVP of Kværner ASA from 2004 to 2005. Prior to this Mr Svanevik also worked in corporate advisory and investment banking for Arkwright from 1994 to 2001. He started his career at Schlumberger Limited, where he held various international financial management positions from 1991 to 1994. Mr Svanevik has an AMP from Harvard Business School and a MBA from Thunderbird School of Global Management.

Hans Petter Aas was appointed as a Director of the Company in May 2015. Mr. Aas has a long career as banker in the international shipping and offshore market, and retired from his position as Global Head of the Shipping, Offshore and Logistics Division of DnB NOR in August 2008. Mr Aas joined DnB NOR (then Bergen Bank) in 1989, and has previously worked for the Petroleum Division of the Norwegian Ministry of Industry and the Ministry of Energy, as well as for Vesta Insurance and Nevi Finance. Mr Aas is also a director and Chairman of Ship Finance, and is a director of Deep Sea Supply Plc., Golden Ocean, Knutsen Offshore Tankers ASA, Knutsen NYK Offshore Partners LP, Solvang ASA and Gearbulk Holding Limited. Mr Aas served as a director of Golar LNG Limited from September 2008 until February 2015 and of Golar LNG Partners LP from 2011 until February 2015.

Georgina Sousa has served as the Secretary of the Company since February 2006. She was appointed as a director of the Company on November 23, 2015. She is also a director and the Head of Corporate Administration for Frontline, is a director and secretary of NADL and Ship Finance, and is the secretary of Seadrill Partners and Archer. Until January 2007, she was Vice-President-Corporate Services of Consolidated Services Limited, a Bermuda Management Company, having joined the firm in 1993 as Manager of Corporate Administration.  From 1976 to 1982 Mrs Sousa was employed by the Bermuda law firm of Appleby, Spurling & Kempe as company secretary and from 1982 to 1993 she was employed by the Bermuda law firm of Cox & Wilkinson as senior company secretary.

Per Wullf was appointed Chief Executive Officer and President of Seadrill Management in July 2013 and a director of the Company in February 2016. Mr. Wullf has also served as a director of Sevan Drilling since January 2012. Previously, Mr. Wullf served as the Chief Operating Officer and Executive Vice President of Seadrill Management since 2009. Mr. Wullf has more than 36 years of experience in the international offshore and onshore drilling industry with A.P. Moller - Maersk A/S, serving as Managing Director for Maersk Drilling Norge AS from 2006 to 2009.

Mark Morris was appointed as Chief Financial Officer in September 2015. Mr Morris was most recently the chief financial officer for Rolls-Royce Group plc and held several roles in his 28 years with the company. During his career at Rolls Royce, amongst other roles, Mr Morris served as group treasurer, managing director, Rolls-Royce Capital and Treasurer of International Aero Engines, a Rolls-Royce Joint Venture.
 
David Sneddon was appointed Chief Accounting Officer and Senior Vice President of Seadrill Management in December 2013. Prior to joining Seadrill, Mr Sneddon held several senior positions in Novelis Inc., including VP of Finance in Europe. Mr Sneddon has also previously held

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various positions in Alcan Inc and KPMG. Mr Sneddon has a Master’s degree in Economics and Accountancy from Aberdeen University and is a member of the Institute of Chartered Accountants of Scotland.

Anton Dibowitz has served as Chief Commercial Officer and Senior Vice President of Seadrill Management since January 2013. He has over 15 years drilling industry experience most recently serving as Vice President Marketing and prior to that as Commercial Director, Deepwater Western Hemisphere Division. Prior to Seadrill, Mr Dibowitz held various positions within tax, process reengineering and marketing at Transocean Ltd. and Ernst & Young LLP.  He is a Certified Public Accountant and a graduate of the University of Texas at Austin where he received a Bachelor’s degree in Business Administration, and Master’s degrees in Professional Accounting (MPA) and Business Administration (MBA).

Leif Nelson was appointed Chief Operating Officer in July 2015. He has over 18 years of experience in the drilling industry, most recently as our Vice President Operations Performance. Prior to joining the Company, Mr Nelson held various operational positions for Transocean Ltd. Mr Nelson is a graduate of the Colorado School of Mines and holds a BSc in Petroleum Engineering. Mr Nelson sits on the board of the Well Control Institute.

Henrik M Hansen was appointed Chief Technical Officer in July 2015. He has over 25 years of experience in the drilling industry most recently as Vice President Operational Excellence. Prior to joining the Company, Mr Hansen held various operational positions within Maersk Drilling. He is a marine engineer and holds a Bachelor of Technology Management in Marine Engineering.

Svend Anton Maier was appointed our Senior Vice President of Special Projects since January 2016. Previously Mr Maier served as our Senior Vice President of the Americas region, from February 2015 until December 2015, as Senior Vice President of Russia for NADL from August 2014 until February 2015, and as Senior Vice President of Africa and Middle-East from January 2011 until August 2014. Mr. Maier also serves as a director of Sevan Drilling. Mr. Maier joined the Company in February 2007 as Vice President, Deepwater Eastern Hemisphere. Mr. Maier has more than 20 years of experience in the offshore drilling industry. Prior to joining the Company, Mr. Maier held several senior positions in Transocean Ltd., including operations manager in Egypt, Equatorial Guinea and Gabon. Mr Maier also has been a non-executive director of SapuraKencana since October 2015. Mr. Maier graduated from the Maritime Institute of Tønsberg with a degree in marine engineering.

José Firmo was appointed Senior Vice President of our Brazil region in October 2014. Mr Firmo has over 25 years of experience in the Oilfield Services industry. Since 1992 when he joined Schlumberger Limited he has held numerous positions, including Testing & Wireline Field Engineer offshore Brazil, Field Manager positions in the North and South America, Global Business Development for Completions, Testing Global Human Resources Director, and Vice President of Operations Latin America for Testing Services. Born in Rio de Janeiro, he holds a Master’s degree in Business Administration from the Rotterdam School of Management, Erasmus University.

Alf Ragnar Løvdal has been the chief executive officer of North Atlantic Management AS since January 2013. Mr. Løvdal has previously served as our senior vice president in Asia Pacific from April 2009 until December 2012. Mr. Løvdal has also held several other senior positions at the Company, including serving as general manager of operations for our mobile units. Mr. Løvdal has close to 35 years of experience from the oil and gas industry, including 10 years in the well services business of the drilling contractor Smedvig, which we acquired in early 2006. Prior to his engagement with Smedvig and Seadrill, Mr. Løvdal held various positions in different oil service companies, including five years of offshore field experience with Schlumberger Limited, and serving as chief executive officer of Seawell Management AS. Mr. Løvdal has a degree in mechanical engineering from Horten Engineering Academy in Norway.

Ray Watkins was appointed Senior Vice President of our Americas Region in January 2016. Mr Watkins previously served as our Vice President of the Asia Pacific region from May 2013 until December 2015. Mr Watkins has more than 30 years of international experience in the drilling industry. He has served as our director of operations for the West Africa region from February 2011 to April 2013. Prior to joining the Company, Mr Watkins held several senior positions in Maersk Drilling and Maersk FPSOs including managing director, director of global operations and regional manager. Mr Watkins is a certified Mechanical Engineer.

Philip Souyris has served as Senior Vice President Mexico region since January 2015. Mr Souyris has 17 years in the offshore drilling industry, including 14 years specializing on the deepwater sector. Prior to joining the Company, Mr Souyris held several senior positions in Schlumberger Limited since 1998, including drilling engineer, drilling manager for Brazil, and operations manager in East Mediterranean Europe. Mr Souyris graduated from Universidad Nacional del Sur as Industrial Engineer and also holds a Masters specialization of Industrial Organization from the same institution.

Dave Morrow was appointed Senior Vice President of the Africa Middle East region in November 2015. He has over 17 years in the drilling industry, most recently serving as our Vice President of Marketing in the Eastern Hemisphere. Prior to the Company, Mr. Morrow held various senior management positions at Ensco plc and Nabors Industries Ltd. in operations, and commercial and general management. He has a BBA in Marketing and Economics from the University of New Mexico.

Alex Monsen was appointed Senior Vice President of the Asia Pacific region in January 2016. Mr Monsen has been at Seadrill since June 2006 and previously served as our Senior Vice President of Asset Development. Mr Monsen has more than 20 years of experience in the drilling industry and has held several senior positions in Stena Drilling Ltd, most recently as Project Manager for Stena Drilling’s DrillMax project. He has a bachelor’s degree in Naval Architecture from the University of Strathclyde and a Master’s degree from Strathclyde Business School.

Des Thurlby was appointed Senior Vice President of Human Resources in July 2015. He joined Seadrill in September 2013. Prior to joining the Company Mr Thurlby was Global Human Resources Director of Jaguar Land Rover Limited for six years. Prior to joining Jaguar Land

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Rover, Mr Thurlby held several HR roles with Ford Motor Company. Mr Thurlby has an MBA from London Business School and a degree in Politics and Economics from Newcastle University.

B.
COMPENSATION

During the year ended December 31, 2015, we paid our directors and executive officers aggregate compensation of $19 million, including compensation in the form of options exercised. In addition, we have incurred compensation expense in the aggregate amount of $1 million for their pension and retirement benefits.
 
In addition to cash compensation, during 2015 we also recognized an expense of $2 million relating to stock options and restricted stock units granted to certain of our directors and executive officers. The options were granted in 2010, 2011, 2012, 2013 and 2015, and vest over a two to four years period and expire between May 2014 and December 2017. The exercise price of the options at December 31, 2015, was in the range NOK137.40 to NOK273.00 (equivalent to $18.46 to $36.67) per share, and will for most options be reduced by the amount of any future dividends declared with respect to the common shares. Restricted stock units were granted in 2013, 2014 and 2015, and have fair values of $46.07, $11.00 and $3.67, respectively.

C.
BOARD PRACTICES
 
Our Board is elected annually by a vote of a majority of the common shares represented at the meeting at which one or more holders of one-third of our outstanding common shares constitutes a quorum. In addition, the maximum and minimum number of directors is determined by a resolution of our shareholders, but no less than two directors shall serve at any given time. Each director shall hold office until the next annual general meeting following his or her election or until his or her successor is elected.
 
Our Board currently consists of nine directors. Georgina Sousa and Per Wullf were appointed to the Board in November 2015 and February 2016, respectively.

Four of our directors, Kate Blankenship, Hans Petter Aas, Paul Leand Jr. and Bert Bekker, are considered independent pursuant to Rule 10A-3 of the Securities Exchange Act of 1934, as amended.
 
We currently have an audit committee, which is responsible for overseeing the quality and integrity of the Company’s financial statements and its accounting, auditing and financial reporting practices; our compliance with legal and regulatory requirements; the independent auditor’s qualifications, independence and performance; and our internal audit function. Our audit committee consists of Mrs. Blankenship.
 
We currently have a compensation committee responsible for establishing and reviewing the executive officers’ and senior managements’ compensation and benefits. Our committee consists of Mr. Svanevik and Mrs. Blankenship.
 
In lieu of a nomination committee, our Board is responsible for identifying and recommending potential candidates to become board members and recommending directors for appointment to board committees.

There are no service contracts between us and any of our directors providing for benefits upon termination of their employment or service.
 
As a foreign private issuer we are exempt from certain requirements of the NYSE that are applicable to U.S. listed companies. For a listing and further discussion of how our corporate governance practices differ from those required of U.S. companies listed on the NYSE, please see “Item 16G. Corporate Governance,” or visit the corporate governance section of our website at www.seadrill.com.
 
D.
EMPLOYEES
 
As of December 31, 2015, we had approximately 6,995 employees.
 
Some of our employees and our contracted labor, most of whom work in Brazil, Nigeria, Norway and the United Kingdom, are represented by collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and have restricted 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.
 
We consider our relationships with the various unions as stable, productive and professional. At present, there are no ongoing negotiations or outstanding issues, other than as disclosed in “Note 33–Commitments and contingencies” to the Notes of our Consolidated Financial Statements included herein.
 

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Total employees (including contracted-in staff )
December 31,
2015

 
December 31,
2014

 
December 31,
2013

Operating segments:
 
 
 
 
 
Floaters
2,995

 
4,505

 
5,100

Jack-up rigs
2,075

 
2,985

 
2,650

Tender rigs
—

 
—

 
1,115

Other
1,755

 
1,850

 
—

Corporate
170

 
110

 
100

Total employees
6,995

 
9,450

 
8,965

Geographical location:
 

 
 

 
 

Norway
1,080

 
1,455

 
1,695

Rest of Europe
170

 
110

 
100

North America and Mexico
1,535

 
2,485

 
1,990

South America
1,145

 
1,155

 
1,015

Asia Pacific
575

 
1,130

 
1,355

Africa and Middle East
2,490

 
3,115

 
2,810

Total employees
6,995

 
9,450

 
8,965


In addition to employees working on the rigs, certain employees are involved in providing management services to our associated companies in which we hold investments, including Seadrill Partners. Employees involved in providing management services are not directly related to our operating or reporting segments and are presented under the “Other” category above.

The number of employees has decreased during the year ended December 31, 2015 as a result of the decrease in our operating fleet of drilling units as well as recent cost cutting measures announced by the Company.
 
E.
SHARE OWNERSHIP

The table below shows the number of common shares beneficially owned and the percentage owned of our outstanding common shares for our directors, officers and key employees as of April 28, 2016 and the percentage held of the total common shares in issue. Also shown are their interests in share options awarded to them under the Option Scheme which was approved by the Company in May 2005 and restricted stock units (RSUs) awarded to them under Seadrill’s Restricted Stock Units Plan approved by the Company in October 2013. The subscription price for options granted under the scheme will normally be reduced by the amount of all dividends declared by the Company in the period from the date of grant until the date the option is exercised.

On April 25, 2016, the Board approved the issuance of 551,341 restricted stock units vesting on December 1, 2018 to key employees of the Company in lieu of a portion of their 2015 performance bonus.

Director or Key Employee
Beneficial Interest in
Common Shares of
$2.00 each
 
Interest in Options and Restricted Stock Units (RSUs)
 
 Number of shares

 
 %
 
Scheme

 
Total number of options / Total number of units

 
Number of options vested

 
Exercise price

 
Expiry date/ Vesting date

John Fredriksen (Note 2)
(Note 2)

 
(Note 2)
 
Options

 
180,000

 
—

 
NOK 93.70

 
May 2018

Kate Blankenship
—

 
(Note 1)
 
Options

 
30,000

 
—

 
NOK 93.70

 
May 2018

Kathrine Fredriksen
—

 
(Note 1)
 
Options

 
30,000

 
—

 
NOK 93.70

 
May 2018

Bert Bekker
—

 
(Note 1)
 
Options

 
30,000

 
—

 
NOK 93.70

 
May 2018

Paul Leand Jr.
—

 
(Note 1)
 
Options

 
30,000

 
—

 
NOK 93.70

 
May 2018

Ørjan Svanevik
—

 
(Note 1)
 
Options

 
30,000

 
—

 
NOK 93.70

 
May 2018

Hans Petter Aas
—

 
(Note 1)
 
Options

 
30,000

 
—

 
NOK 93.70

 
May 2018

Georgina Sousa
—

 
(Note 1)
 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Per Wullf
—

 
(Note 1)
 
Options

 
60,000

 
45,000

 
NOK 138.49

 
November 2016

 
 
 
 
Options

 
130,000

 
65,000

 
NOK 249.13

 
November 2017

 
 
 
 
Options

 
180,000

 
—

 
NOK 93.70

 
May 2018

 
 
 
 
RSUs

 
239,828

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark Morris
—

 
(Note 1)
 
Options

 
60,000

 
—

 
NOK 93.70

 
May 2018

 
 
 
 
RSUs

 
17,726

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Director or Key Employee
Beneficial Interest in
Common Shares of
$2.00 each
 
Interest in Options and Restricted Stock Units (RSUs)
 
 Number of shares

 
 %
 
Scheme

 
Total number of options / Total number of units

 
Number of options vested

 
Exercise price

 
Expiry date/ Vesting date

David Sneddon
—

 
(Note 1)
 
RSUs

 
15,000

 
—

 
—

 
December 2016

 
 
 
 
RSUs

 
4,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
38,408

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Anton Dibowitz
—

 
(Note 1)
 
Options

 
35,000

 
26,250

 
NOK 202.05

 
December 2016

 
 
 
 
Options

 
60,000

 
30,000

 
NOK 273.00

 
December 2017

 
 
 
 
Options

 
80,000

 
—

 
NOK 93.70

 
May 2018

 
 
 
 
RSUs

 
98,168

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Henrik M. Hansen
—

 
(Note 1)
 
Options

 
30,000

 
22,500

 
NOK 138.49

 
November 2016

 
 
 
 
RSUs

 
6,000

 
—

 
—

 
December 2016

 
 
 
 
RSUs

 
3,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
5,000

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
31,693

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leif Nelson
—

 
(Note 1)
 
Options

 
20,000

 
15,000

 
NOK 202.05

 
November 2016

 
 
 
 
RSUs

 
6,000

 
—

 
—

 
December 2016

 
 
 
 
RSUs

 
3,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
8,000

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
20,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
36,037

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Svend Anton Maier
—

 
(Note 1)
 
RSUs

 
4,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jose Firmo
—

 
(Note 1)
 
RSUs

 
10,000

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
7,232

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alf Ragnar Løvdal
—

 
(Note 1)
 
Options

 
45,000

 
30,000

 
NOK 202.05

 
December 2016

 
 
 
 
RSUs
(Note 3)

 
7,185

 
—

 
—

 
December 2016

 
 
 
 
RSUs
(Note 3)

 
3,145

 
—

 
—

 
December 2017

 
 
 
 
RSUs
(Note 3)

 
28,310

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ray Watkins
—

 
(Note 1)
 
Options

 
20,000

 
15,000

 
NOK 202.05

 
December 2016

 
 
 
 
RSUs

 
10,000

 
—

 
—

 
December 2016

 
 
 
 
RSUs

 
4,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
23,781

 
—

 
—

 
December 2018


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Director or Key Employee
Beneficial Interest in
Common Shares of
$2.00 each
 
Interest in Options and Restricted Stock Units (RSUs)
 
 Number of shares

 
 %
 
Scheme

 
Total number of options / Total number of units

 
Number of options vested

 
Exercise price

 
Expiry date/ Vesting date

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Philip Souyris
 
 
(Note 1)
 
RSUs

 
8,000

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
19,034

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alex Monsen
—

 
(Note 1)
 
Options

 
40,000

 
30,000

 
NOK 202.05

 
November 2016

 
 
 
 
RSUs

 
10,000

 
—

 
—

 
December 2016

 
 
 
 
RSUs

 
3,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
14,000

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Des Thurlby
—

 
(Note 1)
 
RSUs

 
5,000

 
—

 
—

 
December 2016

 
 
 
 
RSUs

 
3,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
22,070

 
—

 
—

 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dave Morrow
—

 
(Note 1)
 
Options

 
15,000

 
11,250

 
NOK 202.05

 
November 2016

 
 
 
 
Options

 
15,000

 
7,500

 
NOK 219.13

 
March 2017

 
 
 
 
RSUs

 
7,500

 
—

 
—

 
December 2016

 
 
 
 
RSUs

 
3,500

 
—

 
—

 
December 2017

 
 
 
 
RSUs

 
17,000

 
—

 
—

 
December 2018

 
 
 
 
RSUs

 
17,364

 
 
 
 
 
December 2018

 
 
 
 
 
 
 
 
 
 
 
 
 
 

(1)
Less than 1%

(2)
Hemen Holding Limited, a Cyprus holding company, and other related companies are collectively referred to herein as Hemen. These shares are indirectly 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 of our common stock held by Hemen, 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 and options contained in the table above, as of March 31, 2016, Hemen is party to separate TRS agreements relating to 3,900,000 of our common shares.
 
(3)
These RSUs awarded to Alf Ragnar Løvdal are part of the NADL RSU plan.

ITEM 7.
MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.
MAJOR SHAREHOLDERS

The following table presents certain information as of March 31, 2016, regarding the ownership of our common shares with respect to each shareholder whom we know to beneficially own more than 5% of our outstanding common shares.
 
 
Common Shares Held
Shareholder
Number

 
%

Hemen (1)
119,097,583

 
24.2
%
Tong Jinquan (2)
35,437,289

 
7.2
%

(1)
For further information regarding Hemen, please see “Item 6. Directors, Senior Management and Employees–E. Share Ownership.”

(2)
This information was derived from Schedule 13G filed with the Commission on July 13, 2015, which in addition to Mr. Jinquan includes Wealthy Fountain Holdings Inc., Skyline Horizon Consortium Ltd, Starray Global Limited and Shanghai Summit Pte Ltd as beneficial owners.

We had a total of 493,078,680 common shares outstanding of which 318,740 were held as treasury shares, as of March 31, 2016.
 
Our major shareholders have the same voting rights as our other shareholders. No corporation or foreign government owns more than 50% of our outstanding common shares. We are not aware of any arrangements, the operation of which may at a subsequent date result in a change in control of Seadrill.

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B.
RELATED PARTY TRANSACTIONS

The significant related parties of the Company are as follows:
•
Transactions with investees and associates, over which the Company has significant influence:
◦
Seadrill Partners
◦
Archer
◦
SeaMex
◦
Seabras Sapura
•
Transactions with those holding significant influence over the Company:
◦
Hemen and affiliated companies

Full disclosure of related party transactions for the years ended December 31, 2015, 2014 and 2013 are presented in “Note 31–Related Party Transactions” to the Consolidated Financial Statements contained herein.

The following sections describe the relationships of the related parties to the Company, and summarizes the significant agreements.

Seadrill Partners
As of January 2, 2014, the date of deconsolidation, Seadrill Partners was considered to be a related party and not a controlled subsidiary of the Company. The following is a summary of the agreements with Seadrill Partners.

(i) Omnibus Agreement with Seadrill Partners
In connection with the closing of the initial public offering of Seadrill Partners on October 24, 2012, Seadrill entered into an omnibus agreement with Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating LP, Seadrill Operating GP LLC and Seadrill Capricorn Holdings LLC. The omnibus agreement outlines certain provisions, including:
•
a non-competition agreement with Seadrill Partners for any drilling rig operating under a contract for five or more years;
•
rights of first offer on any proposed sale, transfer or other disposition of drilling rigs;
•
rights of first offer on any proposed transfer, assignment, sale or other disposition of any equity interests in OPCO;
•
indemnification—Seadrill has agreed to indemnify Seadrill Partners against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to Seadrill Partners, and also certain tax liabilities;

For further information and a copy of the omnibus agreement, please see Exhibit 4.4 of the Company’s annual report on Form 20-F, filed on April 21, 2015 and incorporated by reference.

(ii) Sale of drilling units to Seadrill Partners
The following drilling units have been sold to Seadrill Partners since Seadrill Partners was deconsolidated.

West Auriga Disposal
On March 21, 2014, the Company sold the entities that own and operate the West Auriga to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners that is 49% owned by the Company. Please see “Note 11–Disposals of businesses” of the Notes to the Consolidated Financial Statements included herein for more information.

West Vela Disposal
On November 4, 2014, the Company sold the entities that own and operate the West Vela to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners and 49% owned by the Company. Please see “Note 11–Disposals of businesses” of the Notes to the Consolidated Financial Statements included herein for more information.

West Polaris Disposal
On June 19, 2015, the Company sold the entities that owned and operated the West Polaris, to Seadrill Operating LP (“Seadrill Operating”), a consolidated subsidiary of Seadrill Partners LLC and 42% owned by the Company. Please see “Note 11–Disposals of businesses” of the Notes to the Consolidated Financial Statements included herein for more information.


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(iii) Management, administrative and technical service agreements with Seadrill Partners
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, pursuant to which Seadrill Management provides Seadrill Partners 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 five years and can be terminated by providing 90 days written notice. In addition, in connection with the IPO, subsidiaries of Seadrill Partners entered into certain advisory, technical and/or administrative services agreements with subsidiaries of the Company. The services provided by the Company’s subsidiaries are charged at cost plus service fee equal to approximately 5% of costs and expenses incurred in connection with providing these services.

(iv) Loans provided to Seadrill Partners
Seadrill has provided Seadrill Partners various rig financing agreements and discount notes along with a vendor financing loan, and revolving credit facility to support the growth of Seadrill Partners. Full disclosure of loans issued to Seadrill Partners for the years ended December 31, 2015, 2014, and 2013 are presented in “Note 31–Related Party Transactions” of the Notes to the Consolidated Financial Statements contained herein.

Below is a summary of the significant movements and outstanding loans for the year ended December 31, 2015.

Rig Financing Agreements
In September 2012 prior to the IPO of Seadrill Partners, each of Seadrill Partners controlled subsidiaries that owns the West Capricorn, the West Vencedor, the West Aquarius, and the West Capella, or the rig owning subsidiaries, entered into intercompany loan agreements with the Company in the amount of approximately $523 million, $115 million, $305 million and $295 million respectively, corresponding to the aggregate principal amount outstanding under the external facilities allocable to the West Capricorn, the West Vencedor, the West Aquarius, and the West Capella respectively. During 2013, the rig owning companies of the T-15, T-16, West Leo and West Sirius entered into intercompany loan agreements with Company in the amount of approximately $101 million, $93 million, $486 million and $220 million respectively, corresponding to the aggregate principal amount outstanding under the facilities allocable to the T-15, T-16, West Leo and West Sirius respectively. The Company refers to these arrangements collectively as “Rig Financing Agreements.” Pursuant to these intercompany loan agreements, each rig owning subsidiary can make payments of principal and interest to Seadrill or directly to the third party lenders under each facility, corresponding to payments of principal and interest due under each Rig Financing Agreement that are allocable to each rig.

The total amounts owed under the remaining Rig Financing Agreement totaled $139 million as at December 31, 2015 (December 31, 2014: $159 million) and solely relate to the T-15 and T-16. Certain subsidiaries of Seadrill Partners are guarantors under the external facilities in which these rigs 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. The Company has provided an indemnification to Seadrill Partners for any payments or obligations related to these facilities for any losses incurred which do not relate to the T-15 and T-16.

West Vencedor Loan Agreement - The West Vencedor Loan Agreement between the Company and Seadrill Partners was scheduled to mature in June 2015 and all outstanding amounts thereunder would be due and payable, including a balloon payment of $70 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 $21 million due at maturity in June 2018. The total amount owed by Seadrill Partners to the Company under the remaining West Vencedor Loan agreement as of December 31, 2015, was $58 million (December 31, 2014: $78 million).

West Vela facility - Under the terms of the $1,450 million secured credit facility agreement, certain subsidiaries of Seadrill and Seadrill Partners 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. Seadrill has provided an indemnity to Seadrill Partners for any payments or obligations related to this facility that are not related to the West Vela.

West Polaris facility - In June 2015, the Company completed the sale of the entities that own and operate the West Polaris to Seadrill Partners. One of the entities sold was the sole borrower under a $420 million senior secured credit facility. Seadrill Limited continues to act as a guarantor under the facility.

$109.5 million Vendor financing loan
In May, 2013, Seadrill Partners borrowed from the Company $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 at December 31, 2015 was $109.5 million (December 31, 2014: $109.5 million).


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Revolving credit facility
In October 2012 Seadrill Partners entered into a $300 million revolving credit facility with the Company. 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. In March 2014 the facility was reduced to a maximum of $100 million. The outstanding balance of $125.9 million was repaid in full in March 2014. The outstanding balance as at December 31, 2015 was nil (December 31, 2014: nil).

(v) Investments in Seadrill Partners
Purchase of additional limited partner interest in Seadrill Operating LP
On July 21, 2014, the Company sold a 28% limited partner interest in Seadrill Operating LP, a subsidiary of Seadrill Partners, to Seadrill Partners for cash consideration of $373 million. This resulted in a loss on sale of investment of $88 million, which has been recognized within “share in results from associated companies” in the Company’s consolidated statement of operations. Please see “Note 17–Investments in Associated Companies” of our Consolidated Financial Statements included herein.

Related parties to Hemen Holding Limited (“Hemen”)
Since our formation, our largest shareholder has been Hemen, which currently holds approximately 24.2% of our shares.  The Company transacts business with the following related parties, being companies in which Hemen has a significant interest:
•
Ship Finance International Limited (“Ship Finance”);
•
Metrogas Holdings Inc (“Metrogas”);
•
Archer Limited (“Archer”);
•
Frontline Management (Bermuda) Limited (“Frontline”); and
•
Seatankers Management Norway AS (“Seatankers”).

Ship Finance Transactions
The Company has entered into sale and leaseback contracts for several drilling units with subsidiaries of Ship Finance. The Company has determined that the Ship Finance subsidiaries, which own the units, are variable interest entities (VIEs), and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company’s consolidated accounts. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in the Company’s consolidated accounts. Please see “Note 35–Variable Interest Entities” of the Notes to the Consolidated Financial Statements included herein for more information.

The units that are currently leased back from Ship Finance are the West Taurus, West Hercules, and West Linus. The West Polaris was previously leased back from Ship Finance, but was repurchased in 2014, before subsequently being sold to Seadrill Partners.
 
On December 30, 2014 we entered into a share sale and purchase agreement with Ship Finance, through which we acquired 100% of the equity interests in SFL West Polaris Limited, which was the owner of West Polaris. In addition the Company purchased an outstanding loan of SFL West Polaris Limited of $97 million from Ship Finance. The acquisition price for the shares and the loan amounted to $111 million. The consideration for the shares and loan was settled on January 5, 2015.

On June 28, 2013, our subsidiary NADL sold the entity that owns the newbuild jack-up, West Linus, to the Ship Finance subsidiary SFL Linus Ltd. The purchase consideration for this reflected the market value of the rig as of the delivery date, which was $600 million. This rig was simultaneously chartered back over a period of 15 years to NADL. Upon closing, SFL Linus Ltd received a $195 million loan from Ship Finance which bears interest at the rate of 4.5% per annum and matures in 2029. During 2014 the loan was reduced to $125 million, and is reported as long-term debt due to related parties in our balance sheet as of December 31, 2015.

On July 1, 2010 our consolidated VIEs, SFL Deepwater Ltd and SFL Polaris Ltd, paid a dividend of $290 million and $145 million, respectively, to Ship Finance. Ship Finance simultaneously granted loans to SFL Deepwater Ltd and SFL Polaris Ltd for the same amounts. The loans bear interest at 4.5% per annum and are reported as long-term debt due to related parties in our balance sheet as the loans mature in 2023. The loan relating to SFL Polaris Ltd was repaid when the company was repurchased from Ship Finance on December 30, 2014, as described above.

As at December 31, 2015 the VIEs had gross loans outstanding to Ship Finance amounting to $415 million and net loans of $387 million, due to due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis (December 31, 2014: gross loans of $415 million and net loans of $351 million). The net related party loans are disclosed as “Long-term debt due to related parties” on the balance sheet. The loans bear interest at a fixed rate of 4.5% per annum. The total interest expense of the loans for 2015 was $19 million (2014: $24 million; 2013: $20 million).



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Metrogas transactions
In the past we have entered into agreements with Metrogas primarily to manage short-term working capital requirements. Full disclosure of transactions with Metrogas for the years ended December 31, 2015, 2014 and 2013 are presented in “Note 31–Related Party Transactions” of the Notes to the Consolidated Financial Statements included herein.

Archer transactions
From time to time, we may enter into transactions with Archer our former consolidated subsidiary and current associate investment. Seadrill has provided a range of support for Archer including loans, guarantees and other financial commitments, in order to support the best interests of Archer and Seadrill.

Full disclosure of transactions with Archer for the years ended December 31, 2015, 2014, and 2013 are presented in “Note 31–Related Party Transactions” of the Notes to the Consolidated Financial Statements included herein. Significant transactions with Archer for the year ended December 31, 2015 are summarized below.

Loan agreements
On March 6, 2015, the Company purchased a $50 million subordinated loan made by Metrogas, a related party, to Archer, a related party. The aggregate consideration paid for the loan by the Company to Metrogas was $51 million, which is equal to the sum of the outstanding principal amount of $50 million and $1 million accrued commitment fee and interest on the loan. The loan bears interest at a rate of 7.5% per annum and has a commitment fee of 1% on any undrawn amount. As of the date of the purchase by the Company there was no undrawn amount. Interest and any commitment fee is due upon maturity of the loan on June 30, 2018.

In the year ended December 31, 2015, the Company’s $50 million subordinated loan to Archer was written down to nil due to the Company’s share of net losses of Archer reducing the investment balance. The Company’s accounting policy, once its investment in the common stock of an investee has reached nil, is to apply the equity method to other investments in the investee’s securities, loans and or advances based on seniority and liquidity. The Company’s share of equity method losses or gains is determined based on the change in the Company’s claim on net assets of the investee. Archer’s net losses and other comprehensive income were therefore applied to the Company’s loan to Archer at its invested ownership of 39.89%.

Guarantees
We provide various financial and performance guarantees on behalf of Archer. The total amount of outstanding guarantees to Archer as at December 31, 2015 was $326 million. We generally charge Archer a guarantee fee of 1.25% per annum on the amount of outstanding guarantees.

Archer’s refinancing and future commitments
In December 2015, Archer announced that it signed a fifth amendment and restatement of its multi-currency revolving facility agreement (“MRCFA”) with its banking group, which will provide Archer additional financial flexibility. The amendments include, among other things:
•
an immediate non-cash cancellation of the total commitment under the MRCFA from $750 million to $687.5 million;
•
relaxation of certain financial covenants on the bank loan until June 30, 2016; and
•
a further repayment and cancellation of the commitment under the MRCFA from $687.5 million to $625 million by April 30, 2016.

In order to ensure that Archer was able to agree upon these amendments with its lenders, Seadrill has also agreed to provide additional capital to Archer in an aggregate amount of up to $75 million in the event that Archer will not have sufficient funds for the above-mentioned repayment and cancellation of the commitments under the facilities by April 30, 2016. By ensuring that Archer was able to reach a solution with its lenders the Company believes it has significantly reduced the probability of its guarantees over Archer’s debt being called.

We do not deem it probable that we will be required to honor these guarantees, and as such, we have not recognized any related loss contingency in our Consolidated Financial Statements as at December 31, 2015.

We have not recognized a liability for the $75 million commitment described above, as no current obligation existed at the balance sheet date. However, it is probable that we will be required to provide these funds after April 30, 2016.

Frontline Management Transactions
Frontline provides management support and administrative services for the Company, and charged the Company fees of $4 million, $3.8 million and $2 million for these services in the years 2015, 2014 and 2013, respectively. These amounts are included in “general and administrative expenses.”


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Seatankers Management Transactions
The Company and its subsidiaries receive services from Seatankers Management Norway AS, an affiliate of Hemen. The fee was $0.6 million, nil, and nil for the years ended December 31, 2015, 2014 and 2013, respectively.

Other Related Parties

SeaMex Limited
SeaMex is a drilling company based in Mexico which owns and operates five jack-up drilling rigs under contract with Pemex. As of March 10, 2015, the date of deconsolidation, SeaMex Limited is considered to be a related party and not a controlled subsidiary of the Company. Please see “Note 11–Disposals of businesses and deconsolidation of subsidiary” of the Notes to our Consolidated Financial Statements included herein for more information regarding the deconsolidation.

The following is a summary of the related party agreements and transactions with SeaMex.

Management and administrative service agreements
In connection with the joint venture agreement, SeaMex entered into a management support agreement with Seadrill Management, a wholly owned subsidiary of the Company, pursuant to which Seadrill Management provides SeaMex certain management and administrative services. The services provided by Seadrill Management are charged at cost plus management fee of 8%. The agreement can be terminated by providing 60 days’ written notice. Income recognized under the management and administrative agreement for the year ended December 31, 2015 was $11 million (2014: nil; 2013: nil).

It is also agreed that Seadrill Jack Up Operations De Mexico, which is a 100% owned subsidiary of SeaMex and provides support services to the rigs acquired by the joint venture, will continue to provide management services to the Company in respect of the rigs West Pegasus and West Freedom and charge a fee of 5% plus costs incurred in connection with managing the rigs on its behalf. Seadrill Jack Up Operations De Mexico has charged the Company fees, under the above agreements for the year ended December 31, 2015 of $10 million (2014: nil; 2013: nil). These amounts are included in vessel and rig expenses.

Loans
$250 million Seller’s credit - In March 2015, SeaMex borrowed from the Company $250 million as Seller’s credit. The loan is divided into two facilities, (a) a term loan facility for an amount up to $230 million and (b) a revolving loan facility of up to $20 million. Both facilities bear interest at a rate of LIBOR plus a margin of 6.5% and mature in December 2019. Interest on the loan is payable quarterly in arrears. The outstanding balance as at December 31, 2015 was $250 million (2014: nil).

$162 million consideration receivable - SeaMex agreed to pay to the Company an amount of $162 million being consideration receivable in respect of disposal that was payable at the time of allocation of rig contract in relation to West Titania to the joint venture. This amount was paid in full in July 2015.

Seadrill has made available a fully subordinated unsecured credit facility of $20 million which will expire at the anniversary of the first drawdown of this amount or a portion thereof. The facility is to be provided by both Seadrill and Fintech at a ratio of 50.0% each. The facility bears interest at a rate of LIBOR plus a margin of 6.5%. The facility will be repayable once SeaMex has complied with certain conditions with regards to its lenders and all amounts outstanding, including any accrued interest, are to be repaid no later than December 31, 2016. As of December 31, 2015 the facility remained undrawn. Seadrill and Fintech have also provided loan facilities (sponsor loans) for the two bank guarantee amounts (as detailed below), which were undrawn as at December 31, 2015.

Capital contributions
During the year ended December 31, 2015 both the joint venture partners each made an additional $19 million of equity investment in SeaMex while retaining their 50% share in the joint venture.

Guarantees
During the latter part of 2015, SeaMex experienced issues regarding the delayed payment of invoices by its sole customer. The customer deferred payment into 2016 and SeaMex has recovered the majority of the overdue balances since the year end. The customer has not disputed the invoices and is not believed to have any liquidity concerns. The amounts are therefore deemed fully recoverable. However, in order to ease the resulting cash flow impact on SeaMex, the Company, along with Fintech, its joint venture partner, has agreed to provide certain support to Seamex. Simultaneously, SeaMex’s lenders have amended its bank facilities to provide some additional flexibility.

The Company and Fintech have provided a joint and several guarantee for $30 million to the lenders of SeaMex’s external bank facility. The guarantee will continue to be in place until April 30, 2016. The Company and Fintech have also provided a joint and several guarantee for

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potential prepayment deficits that SeaMex might face under its loan agreements. This guarantee will remain in place for 90 days from June 30, 2016. The relevant amount as of December 31, 2015 was approximately $51 million. As of the balance sheet date, we have not recognized a liability as we do not consider it probable the guarantees will be called.

The Company has also provided performance guarantees for the SeaMex drilling units, up to a total of $30 million as of December 31, 2015.

In respect of the guarantees and facilities described above, Seadrill has also obtained an indemnity from Fintech in order to be able to recover up to 50% of its funding and costs, should Seadrill be called to make a contribution greater than its 50% share. Similarly, Seadrill has provided an indemnity to reimburse Fintech any sums that Fintech might be called to pay over and above its share of 50%.

Seabras Sapura transactions
Seabras Sapura Participacoes SA and Seabras Sapura Holdco Ltd, together referred to as Seabras Sapura, are joint ventures based in Brazil that construct and operate pipe-laying vessels, which are each owned 50% by the Company. The following is a summary of the significant transactions with Seabras Sapura for the year ended December 31, 2015.

Yard guarantees
The Company provided a yard guarantee in relation to the Seabras Sapura Participacoes pipe-laying vessels that are still under construction of EUR 47 million, ($51 million) was provided on a 50:50 basis with TL Offshore (our joint venture partner). During 2015 the unit was delivered and the yard obligations were fulfilled. The Company therefore no longer has any further obligations.

The Company has provided yard guarantees in relation to Seabras Sapura Holdco pipe-laying vessels that are still under construction totaling $125 million as at December 31, 2015 (December 31, 2014: $375 million), which have been provided on a 50:50 basis with TL Offshore. The guarantees continue to be in place until the yard obligations have been fulfilled, which is expected to be during 2016 for the final vessel under construction.As of the balance sheet date, we have not recognized a liability as we do not consider it probable the guarantees will be called.

Loans
Seadrill has provided the Seabras Sapura joint venture with various loans to finance working capital. The total amount outstanding as at December 31, 2015 was $46 million.

Financial guarantees
In December 2013 certain subsidiaries of the joint venture entered into a $543 million senior secured credit facility agreement in order to partially fund the acquisition of the Sapura Diamante, and Sapura Topazio pipe-laying support vessels. As a condition to the lenders making the loan available to each of the borrowers, the Company provides a sponsor guarantee on a 50:50 basis with the joint venture partner, SapuraKencana, in respect of the obligations of the borrowers during certain defined time periods, the release of such guarantees being subject to the satisfaction of certain defined conditions. The guarantees cover periods including (a) between delivery of the vessel from the shipyard and customer acceptance and (b) between the expiration of the pipe-laying support vessels charter contracts and contract renewal. The total amount guaranteed as at December 31, 2015 was $242 million.

In April 2015 certain subsidiaries of the joint venture entered into a $780 million senior secured credit facility agreement in order to partially fund the acquisition of the Sapura Onix, Sapura Jade and Sapura Rubi pipe-laying support vessels. As a condition to the lenders making the loan available to each of the borrowers, the Company provides a sponsor guarantee, on a 50:50 basis with the joint venture partner, SapuraKencana, in respect of the obligations of the borrowers during certain defined time periods, the release of such guarantees being subject to the satisfaction of certain defined conditions. The guarantees cover periods including (a) between delivery of the vessel from the shipyard and customer acceptance and (b) between the expiration of the pipe-laying support vessels charter contracts and contract renewal. The amount guaranteed as at December 31, 2015 was $256 million.

In addition, Seadrill provides bank guarantees in relation to the above credit facilities to cover six months of debt service costs and three months of operating expenses under retention accounts. The total amount guaranteed as at December 31, 2015 was $52 million.

As of the balance sheet date, we have not recognized a liability as we do not consider it probable the guarantees will be called.

C.
INTEREST OF EXPERTS AND COUNSEL

Not applicable.
 
ITEM 8.
FINANCIAL INFORMATION
 

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A.
CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

Please see the section of this Annual Report on Form 20-F entitled “Item 18. Financial Statements.”
 
Legal Proceedings

The Company is a party, as plaintiff or defendant, to some lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the construction or operation of its drilling units, in the ordinary course of business or in connection with its acquisition activities.  The Company believes that the resolution of such claims will not have a material adverse effect on the Company’s operations or financial condition either individually or in the aggregate. The Company’s best estimate of the outcome of the various disputes has been reflected in the financial statements of the Company as of December 31, 2015 which is not material except as disclosed otherwise.

In December 2014, a purported shareholder class action lawsuit, Fuchs et al. v. Seadrill Limited et al., No. 14-cv-9642 (LGS)(KNF), was filed in the U.S. District Court for the Southern District of New York, alleging, among other things, that Seadrill and certain of its executives made materially false and misleading statements in connection with the payment of dividends.  In January 2015, a second purported shareholder class action lawsuit,  Heron v. Seadrill Limited et al., No. 15-cv-0429 (LGS)(KNF), was filed in the same court on similar grounds.  In March 2015, a third purported shareholder class action lawsuit, Glow v. Seadrill Limited et al., No. 15-cv-1770 (LGS)(KNF), was filed in the same court on similar grounds.  On March 24, 2015, the court consolidated these complaints into a single action.  On June 23, 2015 the court appointed co-lead plaintiffs and co-lead counsel and ordered the co-lead plaintiffs to file a single consolidated amended by complaint by July 23, 2015.

The amended complaint was filed on July 23, 2015 alleging, among other things, that the Company, NADL and certain of their executives made materially false and misleading statements in connection with the payment of dividends, the failure to disclose the risks to the Rosneft transaction as a result of various enacted government sanctions and the inclusion in backlog of $4.1 billion attributable to the Rosneft transaction.

The defendants filed their Motion to Dismiss the Complaint on October 13, 2015. The plaintiffs, in turn, filed their Opposition to the Motion to Dismiss on November 12, 2015 and the defendants’ Reply Brief was served on December 4, 2015.

Although we intend to defend this action vigorously, we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss.  Accordingly, no loss contingency has been recognized in the financial statements. 

In addition, the Company has received voluntary requests for information from the Commission concerning, among other things, statements in connection with its payment of dividends, the inclusion of contracts in the Company’s backlog and its contracts with Rosneft.


West Mira

On September 14, 2015, the Company cancelled the construction contract for the West Mira with HSHI, due to its inability to deliver the unit within the timeframe required under the contract. The carrying value of the newbuild at the date of cancellation was $315 million, which included $170 million of pre-delivery installments paid to HSHI, with the remainder relating to purchased equipment, internally capitalized construction costs and capitalized interest. Under the contract terms, the Company has the right to recoup the $170 million in pre-delivery installments, plus accrued interest. On October 12, 2015, HSHI launched arbitration proceedings under the contract and submitted its claim submissions on 12 March 2016. HSHI have claimed that the Company’s cancellation was a repudiatory breach and claim they were due various extensions of time. The Company refutes this vigorously, and believes it has the contractual right to recover the $170 million in pre-delivery installments, plus accrued interest. The recovery is, however, now not expected until the conclusion of an arbitration process under English law, which is expected to take up to two years. Based both on management’s assessment of the facts and circumstances, and advice from external counsel, who have been engaged for the arbitration process, the Company believes the recovery of the installment, plus accrued interest, is probable, as defined by U.S. GAAP. As such, the Company has reclassified from “Newbuildings,” a receivable of $170 million plus accrued interest of $29 million, which is presented in “Other non-current assets” on the balance sheet. The Company will continue to assess the recoverability throughout the arbitration process. The Company will redeploy equipment, totaling $48 million, within Seadrill’s remaining fleet, and has not written off these amounts. The resulting net loss on disposal recognized was $78 million, which is included in “Loss on disposal” in the Statement of Operations.


Other matters

Sevan Drilling is a majority-owned subsidiary of the Company. On June 29, 2015, Sevan Drilling disclosed that it had initiated an internal investigation into activities with an agent under certain drilling contracts with Petrobras in Brazil, which were entered prior to the separation from the Sevan Marine Group. On October 16, 2015, Sevan Drilling further disclosed that Sevan Drilling ASA, previously the parent company of Sevan Drilling, had been accused of breaches of Sections 276 a and 276 b of the Norwegian Criminal Code in respect of payments made in connection with the performance during 2012 to 2015 of drilling contracts originally awarded by Petrobras to Sevan Marine ASA in the period between 2005–2008. For further details please see the Sevan Drilling Interim Financial Report Fourth Quarter 2015 which is publicly available. We cannot predict whether any other governmental authority will seek to investigate this matter, or if a proceeding were to be opened, the scope or ultimate outcome of any such investigation and as a result no loss contingency has been recognized in Seadrill’s consolidated financial statements.
 

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In February 2016, NADL was notified of certain customer claims. After an initial assessment including advice from external counsel, NADL fully refutes the validity of these claims and will take appropriate actions related to its position. The client has withheld amounts from invoice payments due in the first quarter of 2016, which total $36.2 million. No provision has been recognized in relation to these claims.

North Atlantic Drilling, and all other offshore contractors that are members of the Norwegian Shipowners’ Association, lost a Norwegian court case in July 2015 concerning the pension rights of night shift compensation for offshore workers. The case has been appealed to the Supreme Court of Norway by the members of the Norwegian Shipowners’ Association, and the hearings are expected to be held in June 2016. Due to the uncertainty of the appeal we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized within the Company’s financial statements as at December 31, 2015.


Dividend Policy

Under our bye-laws, our Board may declare cash dividends or distributions, and may also pay a fixed cash dividend biannually or on other dates. The objective of our Board is to generate competitive returns for our shareholders. Any dividends declared will be in the sole discretion of our Board and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities. Under Bermuda law, a company may not declare or pay a dividend, or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) it is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of our assets would thereby be less than its liabilities.

In addition, since we are a holding company with no material assets other than the shares of our subsidiaries through which we conduct our operations, our ability to pay dividends will depend on our subsidiaries distributing to us their earnings and cash flow.
 
On November 26, 2014, the Company suspended dividend distributions until further notice. The Company cannot assure you when it will resume paying dividends, if at all. In May 2015, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from making dividend distributions during the amendment period until January 1, 2017. In addition, in April 2016, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from making dividend distributions during the amendment period until June 30, 2017.

For the years ended December 31, 2015, 2014 and 2013, we paid aggregate dividends to our shareholders in the amounts of nil, $1,415 million ($2.98 per share) and $1,287 million ($2.74 per share), respectively.


We have paid dividends as follows:
Payment date
Amount per share

 
 
2014
 
March 20, 2014
$
0.98

June 19, 2014
$
1.00

September 18, 2014
$
1.00

 
 
2013
 
June 20, 2013
$
0.88

September 20, 2013
$
0.91

December 20, 2013
$
0.95


B.
SIGNIFICANT CHANGES
 
There have been no significant changes since the date of our Consolidated Financial Statements included herein, other than as described in “Note 39–Subsequent Events” of the Notes to our Consolidated Financial Statements included herein.
 
ITEM 9.
THE OFFER AND LISTING

A.
OFFER AND LISTING DETAILS

Shares of our common stock, par value $2.00 per share, have traded on the OSE since November 22, 2005 and on the NYSE since April 15, 2010, under the symbol “SDRL.”
 
The NYSE listing is intended to be the Company’s “primary listing” and the OSE listing is intended to be the Company’s secondary listing.
 

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The following table sets forth the high and low closing prices of our common shares for the five most recent fiscal years.
 
NYSE
 
OSE
 
High
(US$)

 
Low
(US$)

 
High
(NOK)

 
Low
(NOK)

Fiscal year ended December 31
 
 
 
 
 
 
 
2015
15.44

 
3.31

 
115.80

 
30.55

2014
40.84

 
10.66

 
250.00

 
80.65

2013
47.78

 
34.75

 
289.00

 
202.00

2012
42.07

 
32.07

 
244.20

 
192.90

2011
38.24

 
25.88

 
215.00

 
148.00


The following table sets forth the high and low closing prices of our common shares for each full financial quarter for the two most recent fiscal years.
 
NYSE
 
OSE
 
High
(US$)

 
Low
(US$)

 
High
(NOK)

 
Low
(NOK)

First quarter ended March 31, 2016
7.49

 
1.57

 
49.00

 
13.29

 
 
 
 
 
 
 
 
Fiscal year ended December 31, 2015
 
 
 
 
 
 
 
First quarter 2015
14.49

 
8.58

 
108.60

 
70.50

Second quarter 2015
15.44

 
9.30

 
115.80

 
74.30

Third quarter 2015
10.39

 
5.60

 
83.55

 
47.40

Fourth quarter 2015
7.93

 
3.31

 
64.85

 
30.55

 
 
 
 
 
 
 
 
Fiscal year ended December 31, 2014
 
 
 
 
 
 
 
First quarter 2014
40.84

 
32.93

 
250.00

 
197.50

Second quarter 2014
40.37

 
32.75

 
246.50

 
195.60

Third quarter 2014
40.22

 
26.58

 
248.30

 
172.30

Fourth quarter 2014
25.47

 
10.66

 
170.60

 
80.65


The following table sets forth the high and low closing prices of our common shares for the six most recent months:
 
 
NYSE
 
OSE
 
High
(US$)

 
Low
(US$)

 
High
(NOK)

 
Low
(NOK)

October 2015
7.93

 
5.80

 
64.85

 
48.56

November 2015
7.27

 
5.90

 
62.30

 
51.35

December 2015
6.13

 
3.31

 
52.90

 
30.55

January 2016
3.55

 
1.60

 
31.92

 
14.25

February 2016
2.25

 
1.57

 
19.55

 
13.29

March 2016
7.49

 
2.11

 
49.00

 
18.40

April 27, 2016 *
4.45

 
2.85

 
36.50

 
23.76


* For the period through and including April 27, 2016.
 

B.
PLAN OF DISTRIBUTION

Not applicable.

C.
MARKETS

Our common shares currently trade on the NYSE and the OSE under the symbol “SDRL.”


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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 OF ASSOCIATION AND BYE-LAWS
 
The Memorandum of Association of the Company was filed as Exhibit 1.1 to the Company’s Registration Statement on Form 20-F (Registration No. 001-34667), which was filed with the Commission on March 25, 2010, and is hereby incorporated by reference into this Annual Report. Our Amended and Restated Bye-laws are incorporated by reference to the Company’s annual report on Form 20-F, filed on April 23, 2014.

Our Company was incorporated by registration under the Companies Act. The object of our business, as stated in section 6 of our Memorandum of Association, is to carry on business as the owners, operators and managers of ocean drilling ships, vessels, platforms, rigs and equipment of all kinds, and to act as a holding company. Our Company may not engage in insurance or reinsurance business or carry on business as a mutual fund. Our Memorandum of Association and bye-laws do not impose any limitations on the ownership rights of our shareholders.

Shareholder Meetings. Under our Bye-laws, annual shareholder meetings will be held in accordance with the Companies Act at a time and place (other than Norway or the United Kingdom) selected by the Board. The quorum at any annual or general meeting is equal to one or more shareholders, either present in person or represented by proxy, holding in the aggregate shares carrying 33 1/3% of the exercisable voting rights. Special meetings may be called at the discretion of the Board and at the request of shareholders holding at least one-tenth of all outstanding shares entitled to vote at a meeting. Annual shareholder meetings and special meetings must be called by not less than seven days’ prior written notice specifying the place, day and time of the meeting. The Board may fix any date as the record date for determining those shareholders eligible to receive notice of and to vote at the meeting.
 
The Companies Act provides that a company must have a general meeting of its shareholders in each calendar year unless that requirement is waived by resolution of the shareholders. The Companies Act does not impose any general requirements regarding the number of voting shares which must be present or represented at a general meeting in order for the business transacted at the general meeting to be valid. The Companies Act generally leaves the quorum for shareholders meeting to the company to determine in its Bye-laws. The Companies Act specifically imposes special quorum requirements where the shareholders are being asked to approve the modification of rights attaching to a particular class of shares (33.33%) or an amalgamation or merger transaction (33.33%) unless in either case the Bye-laws provide otherwise. The Company’s Bye-laws provide that the quorum required for shareholder meetings is one or more shareholders present or represented holding shares carrying 33.33% of the voting rights entitled to be exercised at such meeting.

There are no limitations on the right of non-Bermudians or non-residents of Bermuda to hold or vote our common shares.
 
The key powers of our shareholders include the power to alter the terms of the Company’s Memorandum of Association and to approve and thereby make effective any alterations to the Company’s Bye-laws made by the directors. Dissenting shareholders holding 20% of the Company’s shares may apply to the Court to annul or vary an alteration to the Company’s Memorandum of Association. A majority vote against an alteration to the Company’s Bye-laws made by the directors will prevent the alteration from becoming effective. Other key powers are to approve the alteration of the Company’s capital including a reduction in share capital, to approve the removal of a director, to resolve that the Company be wound up or discontinued from Bermuda to another jurisdiction or to enter into an amalgamation, merger transaction or winding up. Under the Companies Act, all of the foregoing corporate actions require approval by an ordinary resolution (a simple majority of votes cast), except in the case of an amalgamation or merger transaction, which requires approval by 75% of the votes cast, unless the Bye-Laws provide otherwise). The Company’s Bye-laws only require an ordinary resolution to approve an amalgamation or merger transaction. In addition, the Company’s Bye-laws confer express power on the board to reduce its issued share capital selectively with the authority of an ordinary resolution.
 
The Companies Act provides shareholders holding 10% of the Company’s voting shares the ability to request that the Board shall convene a meeting of shareholders to consider any business which the shareholders wish to be discussed by the shareholders including (as noted below) the removal of any director. However, the shareholders are not permitted to pass any resolutions relating to the management of the Company’s business affairs unless there is a pre-existing provision in the Company’s Bye-Laws which confers such rights on the shareholders. Subject to compliance with the time limits prescribed by the Companies Act, shareholders holding 20% of the voting shares (or alternatively, 100

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shareholders) may also require the directors to circulate a written statement not exceeding 1,000 words relating to any resolution or other matter proposed to be put before, or dealt with at, the annual general meeting of the Company.
 
Majority shareholders do not generally owe any duties to other shareholders to refrain from exercising all of the votes attached to their shares. There are no deadlines in the Companies Act relating to the time when votes must be exercised.
 
The Companies Act provides that a company shall not be bound to take notice of any trust or other interest in its shares. There is a presumption that all the rights attaching to shares are held by, and are exercisable by, the registered holder, by virtue of being registered as a member of the company. The company’s relationship is with the registered holder of its shares. If the registered holder of the shares holds the shares for someone else (the beneficial owner) then if the beneficial owner is entitled to the shares, the beneficial owner may give instructions to the registered holder on how to vote the shares. The Companies Act provides that the registered holder may appoint more than one proxy to attend a shareholder meeting, and consequently where rights to shares are held in a chain the registered holder may appoint the beneficial owner as the registered holder’s proxy.

Directors. The Companies Act provides that the directors shall be elected or appointed by the shareholders. A director may be elected by a simple majority vote of shareholders, at a meeting where shareholders holding not less than 33.33% of the voting shares are present in person or by proxy. A person holding 50% or more of the voting shares of the Company will be able to elect all of the directors, and to prevent the election of any person whom such shareholder does not wish to be elected. There are no provisions for cumulative voting in the Companies Act or the Bye-Laws and the Company’s Bye-Laws do not contain any super-majority voting requirements. The appointment and removal of directors is covered by Bye-laws 89, 90 and 91.
 
There are procedures for the removal of one or more of the directors by the shareholders before the expiration of his term of office. Shareholders holding 10% or more of the voting shares of the Company may require the Board to convene a shareholder meeting to consider a resolution for the removal of a director. At least 14 days’ written notice of a resolution to remove a director must be given to the director affected, and that director must be permitted to speak at the shareholder meeting at which the resolution for his removal is considered by the shareholders. Any vacancy created by such a removal may be filled at the meeting by the election of another person by the shareholders or in the absence of such election, by the Board.
 
The Companies Act stipulates that an undischarged bankruptcy of a director (in any country) shall prohibit that director from acting as a director, directly or indirectly, and taking part in or being concerned with the management of a company, except with leave of the court. The Company’s Bye-Law 92 is more restrictive in that it stipulates that the office of a Director shall be vacated upon the happening of any of the following events (in addition to the Director’s resignation or removal from office by the shareholders):

•
If he becomes of unsound mind or a patient for any purpose of any statute or applicable law relating to mental health and the Board resolves that he shall be removed from office;

•
If he becomes bankrupt or compounds with his creditors;

•
If he is prohibited by law from being a Director; or

•
If he ceases to be a Director by virtue of the Companies Act (as defined in the Company’s Bye-laws.
 
Under the Company’s Bye-laws, the minimum number of directors comprising the Board at any time shall be two. The Board currently consists of nine directors. The minimum and maximum number of directors comprising the Board from time to time shall be determined by way of an ordinary resolution of the shareholders of the Company. The shareholders may, at the annual general meeting by ordinary resolution, determine that one or more vacancies in the Board be deemed casual vacancies. The Board, so long as a quorum remains in office, shall have the power to fill such casual vacancies. Each director will hold office until the next annual general meeting or until his successor is appointed or elected. A majority of the directors must not be residents of the United Kingdom.

The Company’s Bye-laws do not prohibit a director from being a party to, or otherwise having an interest in, any transaction or arrangement with the Company or in which the Company is otherwise interested. The Company’s Bye-laws provide that a director who has an interest in any transaction or arrangement with the Company and who has complied with the provisions of the Companies Act and with its Bye-Laws with regard to disclosure of such interest shall be taken into account in ascertaining whether a quorum is present, and will be entitled to vote in respect of any transaction or arrangement in which he is so interested. The Company’s Bye-law 97 provides its Board the authority to exercise all of the powers of the Company to borrow money and to mortgage or charge all  or any part of our property and assets as collateral security for any debt, liability or obligation. The Company’s directors are not required to retire because of their age, and the directors are not required to be holders of the Company’s common shares. Directors serve for one year terms, and shall serve until re-elected or until their successors are appointed at the next annual general meeting. The Company’s Bye-laws provide that no director, alternate director, officer, person or member of a committee, if any, resident representative, or his heirs, executors or administrators, which we refer to collectively as an indemnitee, is liable for the acts, receipts, neglects, or defaults of any other such person or any person involved in our formation, or for any loss or expense incurred by us through the insufficiency or deficiency of title to any property acquired by us, or for the insufficiency of deficiency of any security in or upon which any of our monies shall be invested, or for any loss or damage arising from the bankruptcy, insolvency, or tortious act of any person with whom any monies, securities, or effects shall be deposited, or for any loss occasioned by any error of judgment, omission, default, or oversight on his part, or for any other loss, damage or misfortune whatever which shall happen in relation to the execution of his duties, or supposed duties, to us or otherwise in relation thereto. Each indemnitee will be indemnified and held harmless out of our funds to the fullest extent permitted by Bermuda

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law against all liabilities, loss, damage or expense (including but not limited to liabilities under contract, tort and statute or any applicable foreign law or regulation and all reasonable legal and other costs and expenses properly payable) incurred or suffered by him as such director, alternate director, officer, person or committee member or resident representative (or in his reasonable belief that he is acting as any of the above). In addition, each indemnitee shall be indemnified against all liabilities incurred in defending any proceedings, whether civil or criminal, in which judgment is given in such indemnitee’s favor, or in which he is acquitted. The Company is authorized to purchase insurance to cover any liability it may incur under the indemnification provisions of its Bye-laws. Each shareholder has agreed in Bye-law 144 to waive to the fullest extent permitted by Bermuda law any claim or right of action he might have whether individually or derivatively in the name of the Company against each indemnitee in respect of any action taken by such indemnitee or the failure by such indemnitee to take any action in the performance of his duties to the Company. The indemnification and waiver provisions are covered by Bye-laws 138 through 146.

Dividends. Holders of common shares are entitled to receive dividend and distribution payments, pro rata based on the number of common shares held, when, as and if declared by the Board, in its sole discretion. Any future dividends declared will be at the discretion of the Board and will depend upon our financial condition, earnings and other factors.
 
As a Bermuda exempted company, we are subject to Bermuda law relating to the payment of dividends. We may not pay any dividends if, at the time the dividend is declared or at the time the dividend is paid, there are reasonable grounds for believing that, after giving effect to that payment;

•
we will not be able to pay our liabilities as they fall due; or

•
the realizable value of our assets is less than our liabilities.

In addition, since we are a holding company with no material assets, and conduct our operations through subsidiaries, our ability to pay any dividends to shareholders will depend on our subsidiaries’ distributing to us their earnings and cash flow. Some of our loan agreements currently limit or prohibit our subsidiaries’ ability to make distributions to us and our ability to make distributions to our shareholders.
 
Oslo Stock Exchange. The Company’s Bye-laws provide that any person, other than its registrar, who acquires or disposes of an interest in shares which triggers a notice requirement of the OSE must notify the Company’s registrar immediately of such acquisition or disposal and the resulting interest of that person in shares.
 
The Company’s Bye-law 39 requires the Company to provide notice to the OSE if a person (other than the Company’s registrar) resident for tax purposes in Norway (or such other jurisdiction as the Board may nominate from time to time) is found to hold 50% or more of the Company’s aggregate issued share capital, or holds shares with 50% or more of the outstanding voting power.
 
The Company’s Bye-laws also require it to comply with requirements that the OSE may impose from time to time relating to notification of the OSE in the event of specified changes in the ownership of the Company’s common shares.
 
Shares and preemptive rights. Subject to certain balance sheet restrictions, the Companies Act permits a company to purchase its own shares if it is able to do so without becoming cash flow insolvent as a result. The restrictions are that the par value of the share must be charged against the company’s issued share capital account or a company fund which is available for dividend or distribution or be paid for out of the proceeds of a fresh issue of shares. Any premium paid on the repurchase of shares must be charged to the company’s current share premium account or charged to a company fund which is available for dividend or distribution. The Companies Act does not impose any requirement that the directors shall make a general offer to all shareholders to purchase their shares pro rata to their respective shareholdings. The Company’s Bye-Laws do not contain any specific rules regarding the procedures to be followed by the Company when purchasing its own shares, and consequently the primary source of the Company’s obligations to shareholders when the Company tenders for its shares will be the rules of the listing exchanges on which the Company’s shares are listed. The Company’s power to purchase its own shares is covered by Bye-laws 9, 10 and 11.
 
The Companies Act and our Bye-Laws do not confer any pre-emptive, redemption, conversion or sinking fund rights attached to our common shares. Holders of common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Unless a different majority is required by law or by our Bye-laws, resolutions to be approved by holders of common shares require approval by a simple majority of votes cast at a meeting at which a quorum is present.

Bye-Law 8 specifically provides that the issuance of more shares ranking pari passu with the shares in issue shall not constitute a variation of class rights, unless the rights attached to shares in issue state that the issuance of further shares shall constitute a variation of class rights. Bye-Law 12 confers on the directors the right to dispose of any number of unissued shares forming part of the authorized share capital of the Company without any requirement for shareholder approval. The Company’s power to issue shares is covered by Bye-laws 12, 13, 14, 15 and 97.
 
Liquidation. In the event of our liquidation, dissolution or winding up, the holders of common shares are entitled to share in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.
 

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Anti-Takeover Effects of Provisions of Our Constitutional Documents
 
Several provisions of our bye-laws may have anti-takeover effects. These provisions are intended to avoid costly takeover battles, lessen our vulnerability to a hostile change of control and enhance the ability of our Board to maximize shareholder value in connection with any unsolicited offer to acquire us. However, these anti-takeover provisions, which are summarized below, could also discourage, delay or prevent (1) the merger, amalgamation or acquisition of our company by means of a tender offer, a proxy contest or otherwise, that a shareholder may consider in its best interest and (2) the removal of our incumbent directors and executive officers.
 
Should a person or persons resident for tax purposes in Norway, other than Nordea Bank Norge ASA, become the holder of 50% or more of the aggregate of our issued and outstanding common stock, being held or owned directly or indirectly, we will be entitled to dispose of such number of shares that would reduce the person or persons ownership of our common stock to under 50%.
 
Where a person or entity becomes the owner of more than 30% of our issued and outstanding common stock, our Board can decline to register the acquired common shares in excess of 30% unless the acquirer makes an offer to purchase our remaining shares of common stock or agrees to sell part of the shares of common stock acquired to reduce the number of our common shares held by them to below 30% of our issued and outstanding common stock. Sale of the acquirer’s shares over 30% of the issued and outstanding common stock must take place no later than two weeks from when his total share ownership rose above 30%, the acquisition date. Offers to purchase our remaining shares must occur within four weeks of the acquisition date and the offer price must be at least as high as the highest price paid by the acquirer in the six months prior to the acquisition date. Should the acquirer fail to reduce his common shares or make an offer for the outstanding common shares with the time period, the acquirer will not be able to exercise any rights associated with the shares in excess of 30% of our outstanding and issued common stock.
 
There is a statutory remedy under Section 111 of the Companies Act, which provides that a shareholder may seek redress in the Bermuda courts as long as such shareholder can establish that a company’s affairs are being conducted, or have been conducted, in a manner oppressive or prejudicial to the interests of some part of the shareholders, including such shareholder.
 
C.
MATERIAL CONTRACTS

Attached as exhibits to this Annual Report are the contracts we consider to be both material and not in the ordinary course of business. Descriptions of these contracts are included within “Item 4. Information on the Company” and “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions.” Other than these contracts, we have no material contracts other than those entered in the ordinary course of business. 

D.
EXCHANGE CONTROLS
 
The Bermuda Monetary Authority, or the BMA, must give permission for all issuances and transfers of securities of a Bermuda exempted company like ours, unless the proposed transaction is exempted by the BMA’s written general permissions. We have received general permission from the BMA to issue any unissued common shares and for the free transferability of our common shares as long as our common shares are listed on an “appointed stock exchange.” Our common shares are listed on the OSE and the NYSE, each of which is an “appointed stock exchange.” Our common shares may therefore be freely transferred among persons who are residents and non-residents of Bermuda.

Although we are incorporated in Bermuda, we are classified as a non-resident of Bermuda for exchange control purposes by the BMA. Other than transferring Bermuda Dollars out of Bermuda, there are no restrictions on our ability to transfer funds into and out of Bermuda or to pay dividends to U.S. residents who are holders of Common Shares or other non-residents of Bermuda who are holders of our common shares in currency other than Bermuda Dollars.
 
In accordance with Bermuda law, share certificates may be issued only in the names of corporations, individuals or legal persons. In the case of an applicant acting in a special capacity (for example, as an executor or trustee), certificates may, at the request of the applicant, record the capacity in which the applicant is acting. Notwithstanding the recording of any such special capacity, we are not bound to investigate or incur any responsibility in respect of the proper administration of any such estate or trust.
 
We will take no notice of any trust applicable to any of our shares or other securities whether or not we had notice of such trust.

As an “exempted company,” we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermudians, but as an exempted company, we may not participate in certain business transactions including: (i) the acquisition or holding of land in Bermuda (except that required for its business and held by way of lease or tenancy for terms of not more than 21 years) without the express authorization of the Bermuda legislature; (ii) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Economic Development of Bermuda; (iii) the acquisition of any bonds or debentures secured on any land in Bermuda except bonds or debentures issued by the Government of Bermuda or by a public authority in Bermuda; or (iv) the carrying on of business of any kind in Bermuda, except in so far as may be necessary for the carrying on of its business outside Bermuda or under a license granted by the Minister of Economic Development of Bermuda.
 
The Bermuda government actively encourages foreign investment in “exempted” entities like us that are based in Bermuda but do not operate in competition with local business. In addition to having no restrictions on the degree of foreign ownership, we are subject neither to taxes on our income or dividends nor to any exchange controls in Bermuda. In addition, there is no capital gains tax in Bermuda, and profits can be

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accumulated by us, as required, without limitation. There is no income tax treaty between the United States and Bermuda pertaining to the taxation of income other than applicable to insurance enterprises.
 
E.
TAXATION
 
The following is a discussion of the material Bermuda, United States federal income and other tax considerations with respect to the Company and holders of common stock. This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, investors whose functional currency is not the United States Dollar and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common stock, may be subject to special rules. This discussion deals only with holders who hold the common stock as a capital asset, generally for investment purposes. Shareholders are encouraged to consult their own tax advisors concerning the overall tax consequences arising in their own particular situation under United States federal, state, local or foreign law of the ownership of common stock.
 
If an entity or arrangement treated as a partnership for U.S. federal income tax purposes holds common stock, the U.S. federal income tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership.  Partners of partnerships holding the common stock are encouraged to consult their own tax advisors.
 
Bermuda and Other Non-U.S. Tax Considerations
 
As of the date of this Annual Report, whilst Seadrill is resident in Bermuda, we are not subject to taxation under the laws of Bermuda. Distributions we receive from our subsidiaries also are not subject to any Bermuda tax. As of the date of this Annual Report, there is no Bermuda income, corporation or profits tax, withholding tax, capital gains tax, capital transfer tax, or estate duty or inheritance tax payable by non-residents of Bermuda in respect of capital gains realized on a disposition of our common stock or in respect of distributions they receive from us with respect to our common stock. This discussion does not, however, apply to the taxation of persons ordinarily resident in Bermuda. Bermuda shareholders should consult their own tax advisors regarding possible Bermuda taxes with respect to dispositions of, and distributions on, our common stock.

We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, the imposition of any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035. This assurance is subject to the proviso that it is not to be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967.  The assurance does not exempt us from paying import duty on goods imported into Bermuda.  In addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government.  We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government.
 
Bermuda currently has no tax treaties in place with other countries in relation to double-taxation or for the withholding of tax for foreign tax authorities.
 
Dividends distributed by Seadrill Limited out of Bermuda
 
Currently, there is no withholding tax payable in Bermuda on dividends distributed from Seadrill Limited to its shareholders.

Taxation of rig owning entities
 
The majority of our drilling rigs are owned in tax-free jurisdictions such as Bermuda. There is no taxation of the rig owners’ income in these jurisdictions. The remaining drilling rigs are owned in jurisdictions with income or tonnage taxation of the rig owners’ income. These jurisdictions are Hungary, Norway and Singapore.
 
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 elect the appropriate structure with due regard to the applicable legislation of each country where the drilling operations occur.
 
Taxation may also extend to the rig owning entity in some of the countries where the drilling operations are performed.
 

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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 located in Bermuda and Singapore, no capital gains tax is payable in these countries upon the sale or disposition of a rig. However, some countries may impose a capital gains tax or a claw-back of tax depreciation (on a full or partial basis) upon the sale of a rig during or attributable to such time as the rig is operating within such country, or within a certain time after completion of such drilling operations, or when the rig is exported after completion of such drilling operations.
 
Other taxes
 
Our operations may be subject to sales taxes, value added taxes, or other similar taxes in various countries.

Taxation of shareholders
 
Taxation of shareholders will depend upon the jurisdiction where the shareholder is a tax resident. Shareholders should seek advice from their tax advisor to determine the taxation to which they may be subject based on the shareholder’s circumstances.
 

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United States Federal Income Tax Considerations
 
The following are the material United States federal income tax consequences to us of our activities and to U.S. Holders and Non-U.S. Holders, each as defined below, of the ownership of our common stock.  This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, banks, financial institutions, tax-exempt entities, insurance companies, pension funds, US expatriates, real estate investment trusts, regulated investment companies, investors holding common stock as part of a straddle, hedging or conversion transaction, investors subject to the alternative minimum tax, investors who acquired their common stock pursuant to the exercise of employee stock options or otherwise as compensation, investors whose functional currency is not the United States Dollar and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common stock, may be subject to special rules.  The following discussion of United States federal income tax matters is based on the United States Internal Revenue Code of 1986, as amended, or the Code, judicial decisions, administrative pronouncements, and existing and proposed regulations issued by the United States Department of the Treasury, or the Treasury Regulations, all of which are subject to change, possibly with retroactive effect.  The discussion below is based, in part, on the description of our business in this Annual Report and assumes that we conduct our business as described.  Unless otherwise noted, references in the following discussion to the “Company,” “we” and “us” are to Seadrill Limited and its subsidiaries on a consolidated basis.

United States Federal Income Taxation of U.S. Holders
 
As used herein, the term “U.S. Holder” means a beneficial owner of common stock that is (1) a U.S. citizen or resident for U.S. federal income tax purposes, (2) U.S. corporation or other U.S. entity taxable as a corporation, (3) an estate the income of which is subject to U.S. federal income taxation regardless of its source or (4) a trust if 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.
 
If an entity or arrangement treated as a partnership holds our common stock, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner in a partnership holding our common stock, you are encouraged to consult your tax advisor.
 
Distributions
 
Subject to the discussion of PFICs below, any distributions made by us with respect to our common stock to a U.S. Holder will generally constitute dividends, which may be taxable as ordinary income or “qualified dividend income” as described in more detail below, to the extent of our current or accumulated earnings and profits, as determined under United States federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in his common stock on a dollar-for-dollar basis and thereafter as capital gain. Because we are not a United States corporation, U.S. Holders that are corporations will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. Dividends paid with respect to our common stock will generally be treated as “passive category income” or, in the case of certain types of U.S. Holders, “general category income” for purposes of computing allowable foreign tax credits for United States foreign tax credit purposes.

Dividends paid on our common stock to a U.S. Holder who is an individual, trust or estate, or a “U.S. Individual Holder” will generally be treated as “qualified dividend income” that is taxable to such U.S. Individual Holders at preferential tax rates provided that (1) the common stock is readily tradable on an established securities market in the United States (such as the NYSE, on which our common stock is traded); (2) we are not a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (which, as discussed below, we are not and do not anticipate being in the future); (3) the U.S. Individual Holder has owned the common stock for more than 60 days in the 121-day period beginning 60 days before the date on which the common stock becomes ex-dividend; and (4) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property. There is no assurance that any dividends paid on our common stock will be eligible for these preferential rates in the hands of a U.S. Individual Holder. Any dividends paid by the Company which 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 “extraordinary dividend,” generally, a dividend paid by us in an amount which is equal to or in excess of 10% of a shareholder’s adjusted tax basis (or fair market value in certain circumstances) in a share of common stock. If we pay an “extraordinary dividend” on our common stock that is treated as “qualified dividend income,” then any loss derived by a U.S. Individual Holder from the sale or exchange of such common stock will be treated as long-term capital loss to the extent of such dividend.
 
Sale, Exchange or other Taxable Disposition of Common Stock
 
Assuming we do not constitute a PFIC for any taxable year, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other taxable disposition of our common stock in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other taxable disposition and the U.S. Holder’s tax basis in such stock. 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. Such capital gain or loss will generally be treated as United States source income or loss, as applicable, for United States foreign tax credit purposes. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations.


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3.8% Tax on Net Investment Income
 
Certain U.S. Holders, including individuals, estates, or, in certain cases, trusts, will generally be subject to a 3.8% tax on the lesser of (1) the U.S. Holder’s net investment income for the taxable year and (2) the excess of the U.S. Holder’s modified adjusted gross income for the taxable year over a certain threshold (which in the case of individuals is between $125,000 and $250,000).  A U.S. Holder’s net investment income will generally include distributions made by us which constitute a dividend for U.S. federal income tax purposes and gain realized from the sale, exchange or other taxable disposition of our common stock.  This tax is in addition to any income taxes due on such investment income.
 
If you are a U.S. Holder that is an individual, estate or trust, you are encouraged to consult your tax advisors regarding the applicability of the 3.8% tax on net investment income to the ownership and disposition of our common stock.
 
Passive Foreign Investment Company Status and Significant Tax Consequences

Special United States federal income tax rules apply to a U.S. Holder that holds stock in a foreign corporation classified as a PFIC for United States federal income tax purposes. In general, a foreign corporation will be treated as a PFIC with respect to a United States shareholder, if, for any taxable year in which such shareholder holds stock in such foreign corporation, either:
 
•
at least 75% of the corporation’s gross income for such taxable year consists of passive income (e.g. dividends, interest, capital gains 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 corporation during such taxable year produce, or are held for the production of, passive income.

For purposes of determining whether a foreign corporation is a PFIC, it will be treated as earning and owning its proportionate share of the income and assets, respectively, of any of its subsidiary corporations in which it owns, directly or indirectly, at least 25% of the value of the subsidiary’s stock.
 
Income earned by a foreign corporation in connection with the performance of services would not constitute passive income. By contrast, rental income would generally constitute “passive income” unless the foreign corporation is treated under specific rules as deriving its rental income in the active conduct of a trade or business or is received from a related party.
 
Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we intend to take the position that we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. Our position is based on valuations and projections regarding our assets and income. While we believe these valuations and projections to be accurate, such valuations and projections may not continue to be accurate. Moreover, as we have not sought a ruling from the Internal Revenue Service, or IRS, on this matter, the IRS or a court could disagree with our position. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the nature of our operations may change in the future, and if so, we may not be able to avoid PFIC status in the future.
 
As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different United States federal income taxation rules depending on whether the U.S. Holder makes an election to treat us as a “Qualified Electing Fund,” which election we refer to as a “QEF election.” As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market” election with respect to our common stock, as discussed below. In addition, if we were to be treated as a PFIC for any taxable year a U.S. Holder would be required to file an annual report with the United States Internal Revenue Service, or the IRS, for that year with respect to such U.S. Holder’s common stock.

Taxation of U.S. Holders Making a Timely QEF Election
 
If a U.S. Holder makes a timely QEF election, which U.S. Holder we refer to as an “Electing Holder,” the Electing Holder must report each year for United States federal income tax purposes his pro rata share of our ordinary earnings and our net capital gain, if any, for our taxable year that ends with or within the taxable year of the Electing Holder, regardless of whether or not distributions were received from us by the Electing Holder. The Electing Holder’s adjusted tax basis in the common stock would be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that had been previously taxed would result in a corresponding reduction in the adjusted tax basis in the common stock and would not be taxed again once distributed. An Electing Holder would generally recognize capital gain or loss on the sale, exchange or other disposition of our common stock. A U.S. Holder would make a QEF election with respect to any taxable year during which the Company is a PFIC by filing a valid IRS Form 8621 with his United States federal income tax return. If we were aware that we or any of our subsidiaries were to be treated as a PFIC for any taxable year, we would, if possible, provide each U.S. Holder with all necessary information in order to make the QEF election described above.  If we were to be treated as a PFIC, a U.S. Holder would be treated as owning his proportionate share of stock in each of our subsidiaries which is treated as a PFIC and a separate QEF election would be necessary with respect to each subsidiary.  It should be noted that we may not be able to provide such information if we did not become aware of our status as a PFIC in a timely manner.


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Taxation of U.S. Holders Making a “Mark-to-Market” Election
 
Alternatively, if we were to be treated as a PFIC for any taxable year and, as we anticipate, our stock is treated as “marketable stock,” a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our common stock, provided the U.S. Holder completes and files a valid IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations.  The “mark-to-market” election will not be available for any of our subsidiaries. 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 common stock at the end of the taxable year over such holder’s adjusted tax basis in the common stock. The U.S. Holder would also be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common stock over its fair market value 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 his common stock would be adjusted to reflect any such income or loss amount. Gain realized on the sale, exchange or other disposition of our common stock would be treated as ordinary income, and any loss realized on the sale, exchange or other disposition of the common stock would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included as ordinary income by the U.S. Holder.  It should be noted that the mark-to-market election would likely not be available for any of our subsidiaries which are treated as PFICs.
 
Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election
 
Finally, if we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a “mark-to-market” election for that year, whom we refer to as a “Non-Electing Holder,” would be subject to special rules with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common stock 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 stock), and (2) any gain realized on the sale, exchange or other disposition of our common stock. Under these special rules:

•
the excess distribution or gain would be allocated ratably over the Non-Electing Holders’ aggregate holding period for the common stock;

•
the amount allocated to the current taxable year and any taxable year before we became a PFIC 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 taxpayer for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.
 
These penalties would not apply to a pension or profit sharing trust or other tax-exempt organization that did not borrow funds or otherwise utilize leverage in connection with its acquisition of our common stock. If a Non-Electing Holder who is an individual dies while owning our common stock, such Non-Electing Holder’s successor generally would not receive a step-up in tax basis with respect to such common stock.

United States Federal Income Taxation of “Non-U.S. Holders”
 
A beneficial owner of our common stock that is not a U.S. Holder is referred to herein as a “Non-U.S. Holder.”

Dividends on Common Stock
 
Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on dividends received from us with respect to our common stock, unless that income is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to those dividends, that income is subject to United States federal income tax only if it is attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States.
 
Sale, Exchange or Other Disposition of Common Stock
 
Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on any gain realized upon the sale, exchange or other taxable disposition of our common stock, unless:

•
the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to that gain, that gain is subject to United States federal Income tax only if it is attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States; or

•
the Non-U.S. Holder is an individual who is present in the United States for 183 days or more during the taxable year of disposition and other conditions are met.
 
If a Non-U.S. Holder is engaged in a United States trade or business for United States federal income tax purposes, the income from the common stock, including dividends and the gain from the sale, exchange or other taxable disposition of the common stock that is effectively connected with the conduct of that United States trade or business will generally be subject to United States federal income tax in the same manner as discussed in the previous section relating to the United States federal income taxation of U.S. Holders. In addition, if the Non-U.S. Holder is a

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corporation, the Non-U.S. Holder’s earnings and profits that are attributable to the effectively connected income, subject to certain adjustments, may be subject to an additional United States federal branch profits tax at a rate of 30%, or at a lower rate as may be specified by an applicable United States income tax treaty.
 
Backup Withholding and Information Reporting
 
In general, dividend payments, and other taxable distributions, made by the Company to you within the United States will be subject to information reporting requirements. Such payments will also be subject to backup withholding if paid to a U.S. Individual Holder who:

•
fails to provide an accurate taxpayer identification number;

•
is notified by the IRS that he has failed to report all interest or dividends required to be shown on his United States 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 an applicable IRS Form W-8.
 
If a Non-U.S. Holder sells his common stock to or through a United States office of a broker, the payment of the proceeds is subject to both United States backup withholding and information reporting unless the Non-U.S. Holder certifies that he is a non-United States person, under penalties of perjury, or otherwise establishes an exemption. If a Non-U.S. Holder sells his common stock through a non-United States office of a non-United States broker and the sales proceeds are paid to the Non-U.S. Holder outside the United States then information reporting and backup withholding generally will not apply to that payment.  However, United States information reporting requirements, but not backup withholding, will apply to a payment of sales proceeds, even if that payment is made to a Non-U.S. Holder outside the United States, if the Non-U.S. Holder sells his common stock through a non-United States office of a broker that is a United States person or has some other connection to the United States.

Backup withholding is not an additional tax.  Rather, a taxpayer generally may obtain a refund of any amounts withheld under backup withholding rules that exceed the taxpayer’s United States federal income tax liability by properly filing a refund claim with the IRS.
 
Individuals who are U.S. Holders (and to the extent specified in the applicable Treasury Regulations, certain individuals who are non-U.S. Holders and certain U.S. entities) who hold “specified foreign financial assets” (as defined in section 6038D of the Code and the applicable Treasury Regulations) are required to file IRS Form 8938 (Statement of Specified Foreign Financial Assets) with information relating to each such asset for each taxable year in which the aggregate value of all such assets exceeds $75,000 at any time during the taxable year or $50,000 on the last day of the taxable year.  Specified foreign financial assets would include, among other assets, our common stock, unless the common stock were held through an account maintained with certain financial institutions.  Substantial penalties apply to any failure to timely file IRS Form 8938, unless the failure is shown to be due to reasonable cause and not due to willful neglect.  Additionally, the statute of limitations on the assessment and collection of U.S. federal income tax with respect to a taxable year for which the filing of IRS Form 8938 is required may not close until three years after the date on which IRS Form 8938 is filed.  U.S. Holders and Non-U.S. Holders are encouraged to consult their own tax advisors regarding their reporting obligations under section 6038D of the Code.
 
Other Tax Considerations
 
In addition to the tax consequences discussed above, we may be subject to tax in one or more other jurisdictions where we conduct activities.  The amount of any such tax imposed upon our operations may be material.
 
F.
DIVIDENDS AND PAYING AGENTS

Not applicable.
 
G.
STATEMENT BY EXPERTS

Not applicable.
 

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H.
DOCUMENTS ON DISPLAY

We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. In accordance with these requirements we file reports and other information with the Commission. These materials, including this Annual Report on Form 20-F 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 on Form 20-F may be inspected at our principle executive offices at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda and at the offices of Seadrill Management Ltd., at Building 11, Chiswick Park, 566 Chiswick High Road, London, W4 5YA, United Kingdom.
 
I.
SUBSIDIARY INFORMATION

Not applicable.
 
ITEM 11.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We are exposed to various market risks, including changes in interest rates, foreign currency fluctuations, and equity and credit risk. Our policy is to hedge our exposure to these risks where possible, within boundaries deemed appropriate by management and the Board . We accomplish this by entering into a variety of derivative instruments and contracts to maintain the desired level of risk exposure. We may enter into derivative instruments from time to time for speculative purposes.

Interest Rate Risk

A significant portion of our debt obligations and surplus funds placed with financial institutions are subject to movements in interest rates. It is our policy to obtain the most favorable interest rates available without increasing our foreign currency exposure. In keeping with this approach, our surplus funds are used to repay the revolving credit tranches under our credit facilities, or placed in accounts or fixed deposits with reputable financial institutions in order to maximize returns, while providing the Company with the flexibility to meet working capital and capital investments.
 
This section should be read in conjunction with “Note 32–Risk management and financial instruments” of the Notes to the Consolidated Financial Statements included herein.

We use interest rate swaps to manage our exposure to interest rate risks. Interest rate swaps are used to convert floating rate debt obligations to a fixed rate in order to achieve an overall desired position of fixed and floating rate debt. The extent to which interest rate swaps are used is determined by reference to our net debt exposure. Most of our interest rate swaps do not qualify for hedge accounting and movements in their fair values are reflected in the statement of operations under “gain/(loss) on derivative financial instruments.” Interest rate swap agreements that have a positive fair value are recorded as “Other non-current assets,” while swaps with a negative fair value are recorded as “Other current liabilities.”

As of December 31, 2015, we were party to interest rate swap agreements with a combined outstanding principal amount of approximately $7.1 billion (excluding the interest rate swap agreements qualified for hedge accounting described below), compared to $7.9 billion in 2014, at rates between 0.74% per annum and 3.83% per annum. The swap agreements mature between January 6, 2016 and January 29, 2027. The net fair values of our interest rate swaps as of December 31, 2015, and December 31, 2014, were as follows:
 
Interest rate swaps - not qualified for hedge accounting
December 31, 2015
 
December 31, 2014
(In millions of U.S. dollars)
Outstanding principal

 
Fair value

 
Outstanding principal

 
Fair Value

Other non-current assets (current liabilities)
7,088

 
(122
)
 
7,918

 
(134
)



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In addition to the above interest rate swaps, one of our consolidated VIEs has executed interest rate cash flow hedges in the form of interest rate swaps. These interest rate swaps qualify for hedge accounting under U.S. GAAP, and the instruments have been formally designated as a hedge to the underlying loan. Movements in their fair value are reflected in “Accumulated other comprehensive income (loss),” with their fair value recorded as “Other non-current assets” or “Other non-current liabilities.” As of December 31, 2015, the consolidated VIEs had entered into interest rate swap agreements with a combined outstanding principal amount of $200 million, compared to $224 million in 2014, at rates between 1.77% to 2.01% per annum. These swap agreements mature between October and December 2018, and the fair values as of December 31, 2015, and December 31, 2014, were as follows:

Interest rate swaps - qualified for hedge accounting
December 31, 2015
 
December 31, 2014
(In millions of U.S. dollars)
Outstanding principal

 
Fair value

 
Outstanding principal

 
Fair Value

Other non-current assets (non-current liabilities)
200

 
(2
)
 
224

 
(3
)


At December 31, 2015 we also had outstanding cross-currency interest rate swaps with a principal amount of $807 million (December 31, 2014: $807 million) with maturity dates between March 2018 and March 2019 at rates ranging from 4.94% to 6.18% per annum. The fair value of our cross currency interest rate swap contracts as of December 31, 2015, and December 31, 2014, was as follows:
Cross currency interest rate swaps
December 31, 2015
 
December 31, 2014
(In millions of U.S. dollars)
Outstanding principal

 
Fair value

 
Outstanding principal

 
Fair Value

Other current liabilities
807

 
(291
)
 
807

 
(201
)

As of December 31, 2015, our net exposure to floating interest rate fluctuations on our outstanding debt was $0.55 billion, compared with $1.3 billion as of December 31, 2014, based on our total net interest-bearing debt including related party debt of $11.1 billion less the $8.1 billion total notional principal of our floating to fixed interest rate swaps and cross-currency swaps, less the $2.45 billion in fixed interest loans. A 1% change in short-term interest rates would thus increase or decrease our net income by approximately $6 million on an annual basis as of December 31, 2015, compared to approximately $13 million in 2014.


Foreign Exchange Risk
 
The Company and the majority 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. We do, however, earn revenue and incur expenses in other currencies and there is thus a risk that currency fluctuations could have an adverse effect on the value of our cash flows.

This section should be read in conjunction with “Note 32–Risk management and financial instruments” of the Notes to our Consolidated Financial Statements included herein.

Our foreign currency risk arises from:
•
the measurement of debt and other monetary assets and liabilities denominated in foreign currencies converted into U.S. dollars, with the resulting gain or loss recorded as “Other financial items”;
•
changes in the fair value of foreign currency forward contracts, which are recorded as “Other financial items”;
•
the impact of fluctuations in exchange rates on the reported amounts of our revenues and expenses that are contracted in foreign currencies; and
•
foreign subsidiaries whose accounts are not maintained in U.S. dollars, which when converted into U.S. dollars can result in exchange adjustments that are recorded as a component in shareholders’ equity.
 
We use foreign currency forward contracts and cross-currency interest rate swaps (as mentioned above) to manage our exposure to foreign currency risk on certain assets, liabilities and future anticipated transactions. Such derivative contracts do not qualify for hedge accounting treatment and are recorded in the balance sheet under “Other current assets” if the contracts have a net positive fair value, and under “Other current liabilities” if the contracts have a net negative fair value, with changes in the fair value recorded in the consolidated statement of operations under “Other financial items - Gain/(loss) on derivative financial instruments.”
 

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At December 31, 2015, we did not have any outstanding Norwegian kroner currency forward contracts. The fair value of our Norwegian kroner currency forward contracts as of December 31, 2015, and December 31, 2014, was as follows:
 
Foreign currency forward contracts - NOK
December 31, 2015
 
December 31, 2014
(In millions of U.S. dollars)
Notional Amount

 
Fair value

 
Notional Amount

 
Fair Value

Other current liabilities
—

 
—

 
260

 
(24
)
 
At December 31, 2015, we did not have any outstanding British pound sterling currency forward contracts. The fair value of our British pound sterling currency forward contracts as of December 31, 2015, and December 31, 2014, was as follows:

Foreign currency forward contracts - GBP
December 31, 2015
 
December 31, 2014
(In millions of U.S. dollars)
Notional Amount

 
Fair value

 
Notional Amount

 
Fair Value

Other current liabilities
—

 
—

 
49

 
(3
)
 
A 1% change in the exchange rate between the U.S. dollar and the bought forward currencies would result in a fair value gain or loss of $8 million that would be reflected in our consolidated statements of operations, based on our cross currency interest rate swaps and currency forward contracts as of December 31, 2015, compared to approximately $11 million in 2014.

Equity price risk
 
As of December 31, 2015, we had entered into a TRS contract indexed to 4,000,000 of our own shares, whereby we carry the risk of fluctuations in the market price of our shares. The settlement amount for the contract will be (A) the market value of the shares at the date of settlement plus the amount of dividends paid on the shares by us between entering into and settling the contract, less (B) the reference price of the shares agreed at the inception of the contract plus the counterparty’s financing costs. Settlement will be either a payment from or to the counterparty, depending on whether (A) is more or less than (B). The contract was scheduled to expire on March 3, 2016 and the agreed reference price was NOK49.60 per common share. The open position at December 31, 2015, exposes us to market risk associated with our share price, and it is estimated that a 10% reduction in the price below the value at December 31, 2015, would generate an adverse fair value adjustment of up to $2 million, which would be recorded in the consolidated statement of operations. Subsequent to the year end, on March 3, 2016, the TRS agreement related to 4 million shares was rolled over with a new expiration date of June 3, 2016, and a new reference price of 21.1611 per share.
 
In addition to the above TRS agreement, which has our own share as underlying security, we may from time to time enter into short-term TRS arrangements relating to securities in other companies.
 
We hold equity investments in several other companies in our industry that own and/or operate offshore drilling units with similar characteristics to our own fleet of rigs or deliver various oil services. These investments provide us with additional exposure to market segments in which we operate or other oil services. As at December 31, 2015, these included:

•
a 39.9% equity interest in Archer (OSE:ARCHER), a Bermuda oil service company;
•
a 8.2% equity interest in SapuraKencana (BURSA: SKPETRO), a Malaysian oil services company;
•
a 50% equity interest in Seabras Participacoes SA, a Brazilian holding company, which owns the vessel-owning company of one pipe-laying vessel currently under construction;
•
a 50% equity interest in Seabras Sapura Holding GmbH, an Austria holding company, which owns the vessel-owning entities of five pipe-laying vessels currently under construction;
•
a 30% equity interest in Itaunas, a Holland vessel-owning company of one drillship currently under construction;
•
a 30% equity interest in Camburi, a Holland vessel-owning company of one drillship currently under construction;
•
a 30% equity interest in Sahy, a Holland vessel-owning company of one drillship currently under construction;
•
a 46.6% equity interest in Seadrill Partners, which included our ownership interest in both its common and subordinated units;
•
direct ownership interests in the following entities controlled by Seadrill Partners:
i.42% in Seadrill Operating LP;
ii.49% in Seadrill Capricorn Holdings LLC; and
iii.39% in Seadrill Deepwater Drillship Ltd and 39% indirect interest in Seadrill Mobile Units (Nigeria) Ltd; and
•
a 50% equity interest in SeaMex Limited, a joint venture in Mexico.
 
If the market value of any of these investments should fall below the recorded book value, and this decrease in market value is determined to be other than temporary, there could be an impairment charge recognized in our consolidated statement of operations.


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During the year ended December 31, 2015 we have recorded a loss on impairment of our investments in Seadrill Partners and SapuraKencana totaling $1,274 million. Please see “Note 8–Impairment loss on marketable securities and investments in associated companies” of the Notes to our Consolidated Financial Statements included herein for further discussion.
 
Please see Notes 14 and 17 of the Notes to our Consolidated Financial Statements included herein for information on our investments.

Concentration of credit risk
The market for our services is the offshore oil and gas industry, and our customers consist primarily of major integrated oil companies, independent oil and gas producers and government-owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral in our business agreements. Reserves for potential credit losses are maintained when necessary.

The following table shows those of our customers that have generated 10% or more of our contract revenues in any of the periods shown:
 
Year ended December 31,
Customer
2015

 
2014

 
2013

Petrobras
19
%
 
20
%
 
16
%
Total
16
%
 
13
%
 
14
%
ExxonMobil
14
%
 
10
%
 
12
%
Statoil
12
%
 
13
%
 
14
%
Other customers
39
%
 
44
%
 
44
%
 
100
%
 
100
%
 
100
%

We may also face credit-related losses in the event that counterparties to our derivative financial instrument contracts do not perform according to the terms of the contract. The credit risk arising from these counterparties relates to unrealized profits from foreign exchange forward contracts and interest rate swaps. We generally do not require collateral for our financial instrument contracts. We do, however, enter into master netting agreements with our counterparties to derivative financial instrument contracts to mitigate our exposure to counterparty credit risks. These agreements provide us with the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting against them any amounts that the counterparty may owe us.

In the opinion of management, our counterparties are creditworthy financial institutions, and we do not expect any significant loss to result from their nonperformance. The credit exposure of interest rate swap agreements, currency option contracts and foreign currency contracts is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements.

ITEM 12.
DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A.
DEBT SECURITIES
 
Not applicable.

B.
WARRANTS AND RIGHTS
 
Not applicable.

C.
OTHER SECURITIES
 
Not applicable.

D.
AMERICAN DEPOSITORY SHARES
 
Not applicable.
 
PART II
 
ITEM 13.     DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

Neither we nor any of our subsidiaries have been subject to a material default in the payment of principal, interest, a sinking fund or purchase fund installment or any other material default that was not cured within 30 days. In addition, the payments of our dividends are not and have not been in arrears, nor have they been subject to material delinquency that was not cured within 30 days.
 
ITEM 14.     MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.
 

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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) of the Exchange Act as of December 31, 2015. Based upon that evaluation the Principal Executive Officer and Principal Financial Officers concluded that the Company’s disclosure controls and procedures are effective as of the evaluation date.

B.     Management’s Annual Report on Internal Controls over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) promulgated under the Exchange Act.

Internal control over financial reporting is defined in Rule 13a-15(f) or 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, 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 our receipts and expenditures are being made only in accordance with authorizations of the company’s management and directors; and

•
provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of our 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.
 
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).”
 
Our management with the participation of our Principal Executive Officer and Principal Financial Officers assessed the effectiveness of the design and operation of the Company’s internal controls 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 Officer and Principal Financial Officers, concluded that the Company’s internal controls over financial reporting are effective as of December 31, 2015.

The effectiveness of the Company’s 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.
 
C.     Attestation Report of the Registered Public Accounting Firm
 
The independent registered public accounting firm that audited the Consolidated Financial Statements, PricewaterhouseCoopers LLP, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015, appearing under Item 18, and such report is incorporated herein by reference.
 
D.     Changes in internal control over financial reporting

There were no changes in our internal controls over financial reporting that occurred during the period covered by this Annual Report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
ITEM 16.     RESERVED

ITEM 16A.     AUDIT COMMITTEE FINANCIAL EXPERT.
 
Our Board has determined that the sole member of the audit committee, Mrs. Kate Blankenship, is an independent Director and is the Audit Committee Financial Expert.
 

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ITEM 16B.     CODE OF ETHICS
 
We have adopted a Code of Ethics that applies to all entities controlled by the Company and its employees, directors, officers and agents of the Company. We will provide any person, free of charge, a copy of our Code of Ethics upon written request to our registered office.

ITEM 16C.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our principal accountant for the fiscal years ended December 31, 2015 and 2014 was PricewaterhouseCoopers LLP in the United Kingdom. The following table sets forth the fees related to audit and other services provided by the principal accountants.
 
(in U.S. dollars)
2015

 
2014

Audit fees(1)
4,300,673

 
5,781,969

Audit-related fees(2)
—

 
—

Taxation fees(3)
12,000

 
24,565

All other fees(4)
35,493

 
550,934

Total
4,348,166

 
6,357,468


(1) Audit fees represent professional services rendered for the audit of our annual financial statements and services provided by the principal accountant in connection with statutory and regulatory filings or engagements.
 
(2) Audit-related fees consist of assurance and related services rendered by the principal accountant related to the performance of the audit or review of our financial statements which have not been reported under Audit fees above.
 
(3) Taxation fees represent fees for professional services rendered by the principal accountant for tax compliance, tax advice and tax planning.

(4) All other fees include services other than audit fees, audit-related fees and taxation fees set forth above, primarily including information security and network penetration testing services.
 
Audit Committee’s Pre-Approval Policies and Procedures
 
Our Board has adopted pre-approval policies and procedures in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X that require the Board to approve the appointment of our independent auditor before such auditor is engaged, and approve each of the audit and non-audit-related services to be provided by such auditor under such engagement by the Company. All services provided by the principal auditor in 2015, 2014 and 2013 were approved by the Board pursuant to the pre-approval policy.
 
ITEM 16D.     EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
 
Not applicable.
 
ITEM 16E.     PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
 
A share repurchase program was approved by the Board in 2007, authorizing us to buy back shares that may either be cancelled or held as treasury shares to meet our obligations relating to our share option scheme.

In November 2014 the Board authorized a share buyback program under which the Company may repurchase up to approximately 10% of shares outstanding. The Company may repurchase shares from time to time in open market transactions or private transactions in accordance with applicable securities laws. The timing and amount of any repurchases will be determined by our management based on its evaluation of market conditions, capital allocation opportunities and other factors. The program does not require the Company to repurchase any specific number of shares and may be modified, suspended, extended or terminated by the Company at any time without prior notice. In connection with the amendments to our secured loan agreements in April 2016 to increase the leverage ratio contained within the Company’s senior secured credit facilities, the Company is restricted from buying back any shares so long as the amended ratio is in effect, until June 30, 2017.

There were no repurchases of our equity securities for the year ended December 31, 2015.

ITEM 16F.     CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.
 

87
Table of Contents

ITEM 16G.     CORPORATE GOVERNANCE
 
Pursuant to an exception under the NYSE listing standards available to foreign private issuers, we are not required to comply with all of the corporate governance practices followed by U.S. companies under the NYSE listing standards, which are available at www.nyse.com.  Pursuant to Section 303.A.11 of the NYSE Listed Company Manual, we are required to list the significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies. Set forth below is a list of those differences:
 
•
Independence of Directors. The NYSE requires that a U.S. listed company maintain a majority of independent directors. As permitted under Bermuda law and our bye-laws, four members of our Board (Mrs. Kate Blankenship, Mr. Hans Petter Aas, Mr. Paul Leand Jr. and Mr. Bert Bekker) are independent according to the NYSE’s standards for independence applicable to a foreign private issuer.

•
Executive Sessions.  The NYSE requires that non-management directors meet regularly in executive sessions without management. The NYSE also requires that all independent directors meet in an executive session at least once a year. As permitted under Bermuda law and our bye-laws, our non-management directors do not regularly hold executive sessions without management and we do not expect them to do so in the future.

•
Nominating/Corporate Governance Committee.  The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Bermuda law and our bye-laws, we do not currently have a nominating or corporate governance committee.

•
Audit Committee.  The NYSE requires, among other things, that a listed U.S. company have an audit committee with a minimum of three members, all of whom are independent. As permitted by Rule 10A-3 under the Exchange Act, our audit committee consists of one independent member of our Board, Mrs. Kate Blankenship.

•
Corporate Governance Guidelines.  The NYSE requires that a listed U.S. company adopt and disclose corporate governance guidelines. The guidelines must address, among other things, director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Bermuda law and we have not adopted such guidelines.
 
We believe that our established corporate governance practices satisfy the NYSE listing standards.
 
ITEM 16H.     MINE SAFETY DISCLOSURE
 
Not applicable.

PART III
 
ITEM 17.                   FINANCIAL STATEMENTS
 
See “Item 18. Financial Statements” below.
 
ITEM 18.     FINANCIAL STATEMENTS


The following financial statements listed below and set forth on pages F-1 through
are filed as part of this Annual Report on Form
20-F.
 
 
 
Consolidated Financial Statements of Seadrill Limited
 
 

88
Table of Contents

ITEM 19.    EXHIBITS
Exhibit
Number
Description
1.1
Memorandum of Association of Seadrill Limited (1)
1.2
Bye-Laws of Seadrill Limited as adopted by the sole shareholder on May 13, 2005 and as amended by resolution of the shareholders at the Annual General Meeting held on December 1, 2006 and as further amended by resolution of the shareholders at the Annual General Meeting held on September 28, 2007 (1)
1.3
Amended and Restated Bye-Laws of Seadrill Limited, as amended by resolution of the shareholders at the Annual General Meeting held on September 20, 2013 (3)
1.4
Certificate of Incorporation of Seadrill Limited delivered May 10, 2005 (1)
1.5
Certificate of Deposit of Memorandum of Increase of Share Capital delivered May 13, 2005 (1)
1.6
Certificate of Deposit of Memorandum of Increase of Share Capital delivered August 8, 2005 (1)
1.7
Certificate of Deposit of Memorandum of Increase of Share Capital delivered December 20, 2006 (1)
1.8
Certificate of Incorporation on Name Change delivered December 20, 2006 (1)
2.1
Form of Common Stock Certificate (1)
4.1
Share Option Scheme dated December 1, 2006 (1)
4.2
Bermuda Tax Assurance, dated May 25, 2011
4.3
Rules of the Seadrill Limited Restricted Stock Unit Plan (4)
4.4
Omnibus Agreement among Seadrill Limited, Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating LP, Seadrill Operating GP LLC, and Seadrill Capricorn Holdings LLC, dated as of October 24, 2012 (5)
4.5
Framework agreement by and among Rosneft Oil Company, Seadrill Limited and North Atlantic Drilling Ltd., dated August 20, 2014, as amended by the first letter amendment dated November 7, 2014, and the second letter amendment dated April 15, 2015. (5) †
4.6
Framework agreement by and among Rosneft Oil Company, Seadrill Limited and North Atlantic Drilling Ltd., third letter amendment dated June 2015
4.7
Amendment No. 1 to the Agreement for the Construction of the West Rigel, dated December 2, 2015, by and between Jurong Shipyard Pte. Ltd. and North Atlantic Rigel Ltd., including the Joint Asset Holding Agreement between Jurong Shipyard Pte. Ltd. and North Atlantic Drilling Ltd., included as Appendix 1 thereto †
8.1
Subsidiaries of the Company
11.1
Code of Ethics (2)
12.1
Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
12.2
Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
12.3
Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
13.1
Certification of the Principal Executive Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
13.2
Certification of the Principal Financial Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
13.3
Certification of the Principal Financial Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema 
101.CAL
XBRL Taxonomy Extension Schema Calculation Linkbase
101.DEF
XBRL Taxonomy Extension Definition Linkbase
101.LAB
XBRL Taxonomy Extension Label Linkbase
101.PRE
XBRL Taxonomy Extension Presentation Linkbase

(1)
Incorporated by reference to the Company’s registration statement on Form 20-F, filed on March 18, 2010
(2)
Incorporated by reference to the Company’s annual report on Form 20-F, filed on May 5, 2010
(3)
Incorporated by reference to the Company’s annual report on Form 20-F, filed on April 23, 2014
(4)
Incorporated by reference to Amendment No. 1 to the Company’s annual report on Form 20-F, filed on May 5, 2014
(5)
Incorporated by reference to the Company’s annual report on Form 20-F, filed on April 21, 2015
†
Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Commission.

89
Table of Contents

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 Limited
(Registrant)


Date: April 28, 2016

 
By:
/s/ Per Wullf
 
Name:
Per Wullf
 
Title:
Chief Executive Officer of Seadrill Management Ltd
(Principal Executive Officer of Seadrill Limited)


Table of Contents

Seadrill Limited
Index to Consolidated Financial Statements

Consolidated Financial Statements of Seadrill Limited
 

F-1
Table of Contents



Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Seadrill Limited

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive (loss)/income, of cash flows and of changes in shareholders’ equity present fairly, in all material respects, the financial position of Seadrill Limited and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these 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). Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.

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, 2016



F-2
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF OPERATIONS
for the years ended December 31, 2015, 2014 and 2013
(In US$ millions, except per share data)
 
 
2015

 
2014

 
2013

Operating revenues
 
 
 
 
 
 
Contract revenues
 
3,957

 
4,518

 
4,892

Reimbursable revenues
 
113

 
190

 
278

Other revenues
*
265

 
289

 
112

Total operating revenues
 
4,335

 
4,997

 
5,282

 
 
 
 
 
 
 
(Loss)/gain on disposals
*
(63
)
 
632

 
61

Contingent consideration realized
*
47

 
—

 
—

 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
Vessel and rig operating expenses
*
1,611

 
1,938

 
1,977

Reimbursable expenses
 
99

 
172

 
257

Depreciation and amortization
 
779

 
693

 
711

Loss on Goodwill impairment
 
563

 
232

 
—

General and administrative expenses
*
248

 
315

 
300

Total operating expenses
 
3,300

 
3,350

 
3,245

 
 
 
 
 
 
 
Operating income
 
1,019

 
2,279

 
2,098

 
 
 
 
 
 
 
Financial items and other income/(expense), net
 
 
 
 

 
 
Interest income
*
67

 
63

 
24

Interest expense
*
(415
)
 
(478
)
 
(445
)
Share in results from associated companies (net of tax)
 
190

 
34

 
(223
)
Loss on impairment of investments
 
(1,274
)
 
—

 
—

(Loss)/gain on derivative financial instruments
*
(274
)
 
(497
)
 
133

Net gain/(loss) on debt extinguishment
 
8

 
(54
)
 
—

Foreign exchange gain
 
63

 
164

 
52

Gain on realization of marketable securities
 
—

 
131

 
—

Gain on deconsolidation of Seadrill Partners
 
—

 
2,339

 
—

Gain on sale of tender rig business
 
22

 
—

 
1,256

Other financial items and other income/(expense), net
*
52

 
125

 
45

Total financial items and other income/(expense), net
 
(1,561
)
 
1,827

 
842

 
 
 
 
 
 
 
(Loss)/income before income taxes
 
(542
)
 
4,106

 
2,940

 
 
 
 
 
 
 
Income tax expense
 
(208
)
 
(19
)
 
(154
)
Net (loss)/income
 
(750
)
 
4,087

 
2,786

 
 
 
 
 
 
 
Net (loss)/income attributable to the non-controlling interest
 
(12
)
 
108

 
133

Net (loss)/income attributable to the parent
 
(738
)
 
3,979

 
2,653

 
 
 
 
 
 
 
Basic (loss)/earnings per share (U.S. dollar)
 
(1.49
)
 
8.32

 
5.66

Diluted (loss)/earnings  per share (U.S. dollar)
 
(1.49
)
 
8.30

 
5.47

Declared regular dividend per share (U.S. dollar)
 
—

 
2.00

 
3.72

* Includes transactions with related parties. Refer to Note 31.
See accompanying notes that are an integral part of these Consolidated Financial Statements.

F-3
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) / INCOME
for the years ended December 31, 2015, 2014 and 2013
(In US$ millions)
 
 
2015

 
2014

 
2013

 
 
 
 
 
 
Net (loss)/income
(750
)
 
4,087

 
2,786

 
 
 
 
 
 
Other comprehensive income/(loss), net of tax:
 

 
 

 
 

Change in unrealized (loss)/gain on marketable securities, net
(427
)
 
(982
)
 
333

Other than temporary impairment of marketable securities,
reclassification to statement of operations
741

 
—

 
—

Change in unrealized foreign exchange differences
(15
)
 
(22
)
 
6

Change in actuarial gain/(loss) relating to pension
27

 
(28
)
 
(7
)
Change in unrealized gain on interest rate swaps in VIEs and subsidiaries
—

 
1

 
3

Share of other comprehensive income from associated
companies
10

 
—

 
—

Other comprehensive income/(loss):
336

 
(1,031
)
 
335

 
 
 
 
 
 
Total comprehensive (loss)/income for the period
(414
)
 
3,056

 
3,121

 
 
 
 
 
 
Comprehensive (loss)/income attributable to the non-controlling interest
(4
)
 
53

 
134

Comprehensive (loss)/income attributable to the parent
(410
)
 
3,003

 
2,987


Note: All items of other comprehensive income/(loss) are stated net of tax.
 
See accompanying notes that are an integral part of these Consolidated Financial Statements.



F-4
Table of Contents

Seadrill Limited
CONSOLIDATED BALANCE SHEETS
As at December 31, 2015 and 2014
(In US$ millions)
 
2015

 
2014

ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
1,044

 
831

Restricted cash
50

 
268

Marketable securities
96

 
426

Accounts receivables, net
718

 
1,017

Amount due from related party - current
639

 
402

Assets held for sale - current
—

 
134

Other current assets
395

 
222

Total current assets
2,942

 
3,300

 
 
 
 
Non-current assets
 
 
 
Investment in associated companies
2,590

 
2,898

Marketable securities
228

 
325

Newbuildings
1,479

 
2,030

Drilling units
14,930

 
15,145

Goodwill
—

 
604

Restricted cash
198

 
181

Deferred tax assets
81

 
39

Equipment
46

 
46

Amount due from related party - non-current
517

 
313

Assets held for sale - non-current
128

 
1,105

Other non-current assets
331

 
311

Total non-current assets
20,528

 
22,997

Total assets
23,470

 
26,297

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
1,489

 
2,267

Trade accounts payable
141

 
84

Short-term amounts to related party
152

 
189

Liabilities associated with assets held for sale - current
—

 
58

Other current liabilities
1,684

 
1,934

Total current liabilities
3,466

 
4,532

 
 
 
 
Non-current liabilities
 
 
 
Long-term debt
9,054

 
10,208

Long-term debt due to related parties
438

 
351

Deferred tax liabilities
136

 
67

Liabilities associated with assets held for sale - non-current
—

 
50

Other non-current liabilities
401

 
699

Total non-current liabilities
10,029

 
11,375

 
 
 
 
Commitments and contingencies (see note 33)
—

 
—






F-5
Table of Contents



Seadrill Limited
CONSOLIDATED BALANCE SHEETS (continued)
As at December 31, 2015 and 2014
(In US$ millions except common share and per share data)
Equity
2015

 
2014

Common shares of par value US$2.00 per share: 800,000,000 shares authorized 492,759,940 outstanding at December 31, 2015 (December 31, 2014, 492,759,938)
985

 
985

Additional paid in capital
3,275

 
3,258

Contributed surplus
1,956

 
1,956

Accumulated other comprehensive loss
(120
)
 
(448
)
Retained earnings
3,275

 
4,013

Total Shareholder’s equity
9,371

 
9,764

Non-controlling interest
604

 
626

Total equity
9,975

 
10,390

Total liabilities and equity
23,470

 
26,297

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

F-6
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31, 2015, 2014 and 2013
(In US$ millions)
 
 
2015

 
2014

 
2013

Cash Flows from Operating Activities
 
 
 
 
 
Net (loss)/income
(750
)
 
4,087

 
2,786

Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
779

 
693

 
711

Amortization of deferred loan charges
39

 
54

 
43

Amortization of unfavorable and favorable contracts
(116
)
 
(131
)
 
(65
)
Share of results from associated companies
(190
)
 
(121
)
 
223

Loss on sale of investments in associated companies
—

 
89

 
—

Share-based compensation expense
7

 
10

 
7

Gain/(loss) on disposals and deconsolidations
63

 
(2,971
)
 
(1,367
)
Contingent consideration realized
(47
)
 
—

 
—

Unrealized loss/(gain) related to derivative financial instruments
42

 
197

 
(249
)
Loss on Goodwill impairment
563

 
232

 
—

Loss on impairment of investments
1,274

 
—

 
—

Gain on realization of marketable securities
—

 
(138
)
 
—

Dividends received from associated companies
253

 
526

 
15

Deferred income tax
29

 
(6
)
 
(47
)
Unrealized foreign exchange gain on long-term debt
(95
)
 
(165
)
 
(47
)
Payments for long-term maintenance
(106
)
 
(295
)
 
(190
)
Net gain on debt extinguishment
(8
)
 
(12
)
 
—

Other
(31
)
 
(17
)
 
—

Changes in operating assets and liabilities, net of effect of acquisitions and disposals
 
 
 
 
 
Trade accounts receivable
267

 
(295
)
 
(206
)
Trade accounts payable
58

 
21

 
(29
)
Net related party balances
1

 
(247
)
 
(114
)
Prepaid expenses/accrued revenue
(12
)
 
13

 
(45
)
Deferred revenue
(95
)
 
171

 
90

Other assets and liabilities, net
(137
)
 
(121
)
 
179

Net cash provided by operating activities
1,788

 
1,574

 
1,695



F-7
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
for the years ended December 31, 2015, 2014 and 2013
(In US$ millions)
 
 
2015

 
2014

 
2013

Cash Flows from Investing Activities
 
 
 
 
 
Additions to newbuildings
(613
)
 
(2,508
)
 
(3,884
)
Additions to drilling units and equipment
(322
)
 
(365
)
 
(389
)
Refund of yard installments
29

 
—

 
—

Contingent consideration received
27

 
—

 
—

Sale of rigs and equipment
—

 
—

 
48

Business combinations and step acquisitions, net of cash acquired
—

 
—

 
(554
)
Sale of business, net of cash disposed
1,214

 
1,138

 
1,958

Cash in deconsolidated subsidiary
—

 
(90
)
 
—

Change in restricted cash
(25
)
 
(131
)
 
123

Investment in associated companies
(210
)
 
(586
)
 
(151
)
Proceeds from disposal of investments in associated companies
—

 
373

 
—

Purchase of marketable securities
—

 
(150
)
 
—

Loans granted to related parties
(523
)
 
(18
)
 
(125
)
Payments received from loans granted to related parties
233

 
2,096

 
10

Proceeds from disposal of marketable securities
—

 
307

 
—

Net cash (used in)/provided by investing activities
(190
)
 
66

 
(2,964
)
 
 
 
 
 
 
Cash Flows from Financing Activities
 
 
 
 
 
Proceeds from debt
1,516

 
5,072

 
7,703

Repayments of debt
(2,999
)
 
(4,344
)
 
(4,919
)
Debt fees paid
(16
)
 
(65
)
 
(93
)
Proceeds from debt to related party
143

 
90

 
756

Repayments of debt to related party
—

 
(910
)
 
(1,181
)
Dividends paid to non-controlling interests
(14
)
 
(51
)
 
(69
)
Contribution from non-controlling interests, net of issuance cost
—

 
115

 
365

Proceeds relating to share forward contracts and other derivatives
—

 
—

 
453

Purchase of treasury shares
—

 
(18
)
 
(39
)
Proceeds from sale of treasury shares
—

 
—

 
6

Dividends paid
—

 
(1,415
)
 
(1,287
)
Employee stock options exercised
—

 
5

 
—

Net cash (used in)/provided by financing activities
(1,370
)
 
(1,521
)
 
1,695

 
 
 
 
 
 
Cash reclassified as held for sale
—

 
(26
)
 
—

Effect of exchange rate changes on cash and cash equivalents
(15
)
 
(6
)
 
—

 
 
 
 
 
 
Net increase in cash and cash equivalents
213

 
87

 
426

Cash and cash equivalents at beginning of the year
831

 
744

 
318

Cash and cash equivalents at the end of year
1,044

 
831

 
744

 
 
 
 
 
 
Supplementary disclosure of cash flow information
 
 
 
 
 
Interest paid, net of capitalized interest
(458
)
 
(493
)
 
(336
)
Taxes paid
(136
)
 
(227
)
 
(109
)
See accompanying notes that are an integral part of these Consolidated Financial Statements.

F-8
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
for the years ended December 31, 2015, 2014 and 2013
(In US$ millions)

 
 
Common shares

 
Additional paid in capital

 
Contributed surplus

 
Accumulated other comprehensive (loss)/income

 
Retained Earnings

 
Total equity before NCI

 
Non-controlling interest

 
Total equity

Balance at December 31, 2012
 
938

 
2,332

 
1,956

 
194

 
83

 
5,503

 
521

 
6,024

Sale of treasury shares
 
—

 
6

 
—

 
—

 
—

 
6

 
—

 
6

Purchase of treasury shares
 
—

 
(39
)
 
—

 
—

 
—

 
(39
)
 
—

 
(39
)
Share-based compensation
 
—

 
7

 
—

 
—

 
—

 
7

 
—

 
7

Establishment of non-controlling interest
 
—

 
—

 
—

 
—

 
—

 
—

 
297

 
297

Issuance of common units by Seadrill Partners to public
 
—

 
228

 
—

 
—

 
—

 
228

 
137

 
365

Issuances of common units by Seadrill Partners and impact on non-controlling interest
 
—

 
(102
)
 
—

 
—

 
—

 
(102
)
 
102

 
—

Sale of drilling units to Seadrill Partners
 
—

 
209

 
—

 
—

 
—

 
209

 
(209
)
 
—

Other comprehensive income
 
—

 
—

 
—

 
334

 
—

 
334

 
1

 
335

Dividends declared
 
—

 
—

 
—

 
—

 
(1,287
)
 
(1,287
)
 
(69
)
 
(1,356
)
Dividend to Non-controlling interests in VIEs
 
—

 
—

 
—

 
—

 
—

 
—

 
(223
)
 
(223
)
Net income
 
—

 
—

 
—

 
—

 
2,653

 
2,653

 
133

 
2,786

Balance at December 31, 2013
 
938

 
2,641

 
1,956

 
528

 
1,449

 
7,512

 
690

 
8,202

Sale and purchase of treasury shares, net
 
(1
)
 
(22
)
 
—

 
—

 
—

 
(23
)
 
—

 
(23
)
Share-based compensation charge
 
—

 
10

 
—

 
—

 
—

 
10

 
—

 
10

Employee stock options issued
 
1

 
4

 
—

 
—

 
—

 
5

 
—

 
5

Conversion of convertible bond
 
47

 
568

 
—

 
—

 
—

 
615

 
—

 
615

Deconsolidation of Seadrill Partners
 
—

 
—

 
—

 
—

 
—

 
—

 
(115
)
 
(115
)
Initial public offering of NADL
 
—

 
63

 
—

 
—

 
—

 
63

 
52

 
115

Acquisition of West Polaris
 
—

 
(6
)
 
—

 
—

 
—

 
(6
)
 
(7
)
 
(13
)
Sale of NCI
 
—

 
—

 
—

 
—

 
—

 
—

 
4

 
4

Other comprehensive loss
 
—

 
—

 
—

 
(976
)
 
—

 
(976
)
 
(55
)
 
(1,031
)
Dividends declared
 
—

 
—

 
—

 
—

 
(1,415
)
 
(1,415
)
 
(51
)
 
(1,466
)
Net income
 
—

 
—

 
—

 
—

 
3,979

 
3,979

 
108

 
4,087

Balance at December 31, 2014
 
985

 
3,258

 
1,956

 
(448
)
 
4,013

 
9,764

 
626

 
10,390

Sale and purchase of treasury shares, net
 
—

 
10

 
—

 
—

 
—

 
10

 
—

 
10

Share-based compensation charge
 
—

 
7

 
—

 
—

 
—

 
7

 
—

 
7

Sale of NCI
 
—

 
—

 
—

 
—

 
—

 
—

 
(4
)
 
(4
)
Other comprehensive income
 
—

 
—

 
—

 
328

 
—

 
328

 
8

 
336

Distributions to Non-controlling interests
 
—

 
—

 
—

 
—

 
—

 
—

 
(14
)
 
(14
)
Net loss
 
—

 
—

 
—

 
—

 
(738
)
 
(738
)
 
(12
)
 
(750
)
Balance at December 31, 2015
 
985

 
3,275

 
1,956

 
(120
)
 
3,275

 
9,371

 
604

 
9,975

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



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Seadrill Limited
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – General information
 
Seadrill Limited is incorporated in Bermuda and is a publicly listed company on the New York Stock Exchange and the Oslo Stock Exchange. We provide offshore drilling services to the oil and gas industry. As of December 31, 2015 the Company owned and operated 38 offshore drilling units, had 13 offshore drilling units under construction and an additional unit classified as held for sale. Our fleet consists of drillships, jack-up rigs and semi-submersible rigs for operations in shallow and deepwater areas, as well as benign and harsh environments. Following the sale of the majority of the tender rig business to SapuraKencana, which closed on April 30, 2013, and further the deconsolidation of Seadrill Partners on January 2, 2014 we no longer operate in the tender rig segment. We also provide management services to our related parties Seadrill Partners and SeaMex, refer to Note 31 for further details.
 
As used herein, and unless otherwise required by the context, the term “Seadrill” refers to Seadrill Limited and the terms “Company,” “we,” “Group,” “our” and words of similar import refer to Seadrill and its consolidated companies. The use herein of such terms as group, organization, we, us, our and its, or references to specific entities, is not intended to be a precise description of corporate relationships.
 
Basis of presentation
 
The financial statements are presented in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). The amounts are presented in United States dollar (U.S. dollar) rounded to the nearest million, unless otherwise stated.
 
The accompanying consolidated financial statements present the financial position of Seadrill Limited, the consolidated subsidiaries and the group’s interest in associated entities. Investments in companies in which the Company controls, or directly or indirectly holds more than 50% of the voting control are consolidated in the financial statements, as well as certain variable interest entities of which the Company is deemed to be the primary beneficiary.

The accounting policies set out below have been applied consistently to all periods in these consolidated financial statements, unless otherwise noted.
 
Basis of consolidation
 
The consolidated financial statements include the assets and liabilities of the Company, its majority owned and controlled subsidiaries and certain variable interest entities, (“VIE”s) in which the Company is deemed to be the primary beneficiary. All intercompany balances and transactions have been eliminated on consolidation.
 
A VIE is defined as a legal entity where either (a) the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated support; (b) equity interest holders as a group lack either i) the power to direct the activities of the entity that most significantly impact on its economic success, ii) the obligation to absorb the expected losses of the entity, or iii) the right to receive the expected residual returns of the entity; or (c) the voting rights of some investors in the entity are not proportional to their economic interests and the activities of the entity involve or are conducted on behalf of an investor with a disproportionately small voting interest. U.S. GAAP requires a VIE to be consolidated by its primary beneficiary, being the interest holder, if any, which has both (1) the power to direct the activities of the entity which most significantly impact on the entity’s economic performance, and (2) the right to receive benefits or the obligation to absorb losses from the entity which could potentially be significant to the entity. We evaluate our subsidiaries, and any other entities in which we hold a variable interest, in order to determine whether we are the primary beneficiary of the entity, and where it is determined that we are the primary beneficiary we consolidate the entity.
 
Investment in companies in which we hold an ownership interest of between 20% and 50%, and over which we exercise significant influence, but do not consolidate, are accounted for using the equity method and classified within “Investments in associated companies.” The Company records its share of earnings or losses from associated companies in the consolidated statements of operations as “Share in results from associated companies.” The excess, if any, of purchase price over book value of the Company’s investments in equity method investees is included in the accompanying consolidated balance sheets in “Investment in associated companies.”
 
Investments in companies in which our ownership is less than 20% are valued at fair value and classified within “Marketable Securities” unless it is not possible to estimate fair value, then the cost method is used.
 
Intercompany transactions and internal sales have been eliminated on consolidation. Unrealized gains and losses arising from transactions with associates are eliminated to the extent of the Company’s interest in the entity.
 


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Note 2 – Accounting policies
 
Use of estimates
 
Preparation of financial statements in accordance with U.S. GAAP 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’s revenues are derived from dayrate based drilling contracts (which may include lump sum fees for mobilization and demobilization) and other service contracts. Both dayrate based and lump sum fee revenues are recognized ratably over the contract period when services are rendered. Under some contracts, the Company is entitled to additional payments for meeting or exceeding certain performance targets. Such additional payments are recognized when any contingencies are resolved or upon completion of the drilling program.
 
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 contract term, excluding 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 over contract term, excluding option periods not exercised by our customers. 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 contract term, excluding option periods not exercised.

In certain countries in which we operate, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We record our tax-assessed revenue transactions on a net basis in our consolidated statement of income.

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

Other revenues
 
In a business combination there may exist favorable and unfavorable drilling contracts which are recorded at fair value at the date of acquisition. A favorable or unfavorable drilling contract is a contract that has a dayrate which differs from prevailing market rates at the time of acquisition. The net present value of such contracts is recorded as an asset or a liability at the purchase date and subsequently recognized as revenue or reduction to revenue over the contract term.

Related party revenues relate to management support and administrative services provided to our associates in which we maintain an investment.

External management fees relate to the operational, administrative and support services we provide to third parties.
 
Mobilization and demobilization expenses
  
Mobilization costs incurred as part of a drilling contract are capitalized and recognized as expense over the contract term, excluding option periods not exercised by our customers. The 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 rig to a safe harbor or different geographic area and are expensed as incurred.
 
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, supplies, insurance costs, expenses for repairs and maintenance as well as costs related to onshore personnel in various locations where we operate the drilling units and are expensed as incurred.

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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 5 years. Related costs are primarily yard costs and the cost of employees directly involved in the work. 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 the majority of its subsidiaries use the U.S. dollars 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. For subsidiaries that maintain their accounts in currencies other than U.S. dollars, the Company uses the current method of translation whereby the statements of operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in shareholders’ equity.
 
Transactions in foreign currencies 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.
 
Current and non-current classification
 
Assets and liabilities (excluding deferred taxes) are classified as current assets and liabilities respectively, if their maturity is within 1 year of the balance sheet date. Otherwise, they are classified as non-current assets and liabilities.

In November 2015, 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 require 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 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 did not have a material impact on Company’s consolidated financial statements and related disclosures.
 
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.
 
Restricted cash
 
Restricted cash consists of bank deposits which have been pledged as collateral for certain guarantees issued by a bank or minimum deposits which must be maintained in accordance with contractual arrangements. Restricted cash amounts with maturities longer than one year are classified as non-current assets.

Equity method investments

Investments in common stock are accounted for using the equity method of accounting if the investment gives the Company the ability to exercise significant influence, but not control over, the investee. Significant influence is generally deemed to exist if the Company has an ownership interest in the voting stock of the investee between 20% and 50%, although other factors such as representation on the investee’s Board of Directors and the nature of commercial arrangements are considered in determining whether the equity method of accounting is appropriate. Under the equity method of accounting, the Company records its investments in equity-method investees in the consolidated balance sheet under “Investment in associated companies” and its share of the investees’ earnings or losses together with other-than-temporary impairments in value and gain/loss on sale of investments under “Share in results from associated companies (net of tax)” in the consolidated statements of income.
All other equity investments, which consist of investments for which the Company does not have the ability to exercise significant influence, or are not investments in common stock, are accounted for under the cost method or at fair value if readily determinable.

The Company analyzes its equity method investees for impairment at each reporting period to evaluate whether an event or change in circumstances has occurred in that period that may have a significant adverse effect on the value of the investment. The Company records an impairment charge for other-than-temporary declines in value when the value is not anticipated to recover above the cost within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in value are not reflected in earnings until sale of the equity method investee occurs.


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Table of Contents

Marketable securities
 
Marketable equity securities held by the Company which do not give the Company the ability to exercise significant influence are considered to be available-for-sale. These are remeasured at fair value each reporting period with resulting unrealized gains and losses recorded as a separate component of accumulated other comprehensive income in shareholders’ equity. Gains and losses are not realized until the securities are sold or subject to an other than temporary impairment. Gains and losses on forward contracts to purchase marketable equity securities that do not meet the definition of a derivative are accounted for as available-for-sale.

The Company analyzes its available-for-sale securities for impairment at each reporting period to evaluate whether an event or change in circumstances has occurred in that period that may have a significant adverse effect on the value of the securities. The Company records an impairment charge for other-than-temporary declines in value when the value is not anticipated to recover above the cost within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in value are not reflected in earnings until sale of the securities held as available for sale occurs.

Receivables
 
Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. The Company establishes 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 considers 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.
 
Newbuildings
 
The carrying value of drilling units under construction (“Newbuildings”) represents the accumulated costs at the balance sheet date. Cost components include payments for yard installments and variation orders, construction supervision, equipment, spare parts, capitalized interest, costs related to first time mobilization and commissioning costs. No charge for depreciation is made until commissioning of the newbuilding has been completed and it is ready for its intended use.
 
The Company may have option agreements with shipyards to order new drilling units at fixed or variable prices which require some or no additional payment upon exercise. Payments for drilling unit purchase options are capitalized at the time when option contracts are acquired or entered into. The Company reviews the expected future cash flows, which would result from the exercise of each option contract on a contract by contract basis to determine whether the carrying value of the option is recoverable.
 
Capitalized interest
 
Interest expense is capitalized during construction of newbuildings based on accumulated expenditures for the applicable project at the Company’s current rate of borrowing. The amount of interest expense capitalized in an accounting period shall be determined by applying an interest rate (“the capitalization rate”) to the average amount of accumulated expenditures for the asset during the period. The capitalization rates used in an accounting period shall be based on the rates applicable to borrowings outstanding during the period. The Company does not capitalize amounts beyond the actual interest expense incurred in the period.
 
If the Company’s financing plans associate a specific new borrowing with a qualifying asset, the Company uses the rate on that borrowing as the capitalization rate to be applied to that portion of the average accumulated expenditures for the asset that does not exceed the amount of that borrowing. If average accumulated expenditures for the asset exceed the amounts of specific new borrowings associated with the asset, the capitalization rate to be applied to such excess shall be a weighted average of the rates applicable to other borrowings of the Company.

Drilling units
 
Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated residual value is taken to be offset by any decommissioning costs that may be incurred. The estimated economic useful life of the Company’s floaters and, jack-up rigs, when new, is 30 years.
 
Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset’s value for its remaining useful life are capitalized and depreciated over the remaining life of the asset.

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.

Assets held for sale

Assets are classified as held for sale when all of the following criteria are met: Management, having the authority to approve the action, commits to a plan to sell the asset (disposal group), the asset (disposal group) is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets (disposal groups), an active program to locate a buyer and other actions required to complete the plan to sell the asset (disposal group) have been initiated, the sale of the asset (disposal group) is probable, and transfer of the asset (disposal

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group) is expected to qualify for recognition as a completed sale, within 1 year. The term probable refers to a future sale that is likely to occur, the asset (disposal group) is being actively marketed for sale at a price that is reasonable in relation to its current fair value and actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

Discontinued operations

The Company will present the results of operations of a component of the Company as defined by U.S. GAAP, that either has been disposed of or is classified as held for sale, as discontinued operations, if that component represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results.

Equipment
 
Equipment is recorded at historical cost less accumulated depreciation and is depreciated over its estimated remaining useful life. The estimated economic useful life of Equipment, when new, is between 3 and 5 years depending on the type of asset.
 
Goodwill
 
The Company allocates the purchase price of acquired businesses to the identifiable tangible and intangible assets and liabilities acquired, with any remaining amount being recorded as goodwill. Goodwill is tested for impairment at least annually at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. The Company has determined that its reporting units are the same as its operating segments for the purpose of allocating goodwill and the subsequent testing of goodwill for impairment.
 
The Company tests goodwill for impairment on an annual basis as of December 31 each year or when events or circumstances indicate that a potential impairment exists. The Company may first assess qualitative factors to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two step goodwill impairment test.

If the qualitative factors indicate possible impairment, the Company performs a quantitative assessment to estimate fair value of its reporting units compared to their carrying value.  In the event that the fair value is less than carrying value, the Company must perform an exercise similar to a purchase price allocation in a business combination in order to determine the amount of the impairment charge. The quantitative goodwill impairment test for a reporting unit is based on discounted cash flows. The Company uses estimated future cash flows applying contract dayrates during the firm contract periods and estimated forecasted dayrates for the periods after expiry of firm contract periods. The estimated future cash flows will be based on remaining economic useful lives for the assets, and discounted using a weighted average cost of capital (“WACC”).
 
Other intangible assets and liabilities
 
Other intangible assets and liabilities are recorded at fair value on the date of acquisition less accumulated amortization. The amounts of these assets and liabilities less the estimated residual value, if any, is generally amortized on a straight-line basis over the estimated remaining economic useful life or contractual period. Other intangible assets include technology, customer relationships and favorable drilling contracts. Other intangible liabilities include unfavorable drilling contracts.

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 events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. The Company first 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, the Company then compares the carrying value of the intangible asset with the discounted future net cash flows, using relevant WACC to determine an impairment loss to be recognized during the period.

Defined benefit pension plans
 
The Company has several defined benefit plans which provide retirement, death and early termination benefits. The Company’s net obligation is calculated separately for each plan by estimating the amount of the future benefit that employees have earned in return for their cumulative service.
 
The aggregated projected future benefit obligation is discounted to a present value, and the aggregated fair value of any plan assets is deducted. The discount rate is the market yield at the balance sheet date on government bonds in the relevant currency and based on terms consistent with the post-employment benefit obligations. The retirement benefits are generally a function of number of years of employment and amount of employees’ remuneration. The plans are primarily funded through payments to insurance companies. The Company records its pension costs in the period during which the services are rendered by the employees. Actuarial gains and losses are recognized in the statement of operations when the net cumulative unrecognized actuarial gains or losses for each individual plan at the end of the previous reporting year exceed 10 percent of the higher of the present value of the defined benefit obligation and the fair value of plan assets at that date. These gains and losses are recognized over the expected remaining working lives of the employees participating in the plans. Otherwise, recognition of actuarial gains

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Table of Contents

and losses is included in other comprehensive income.  Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income.

On retirement, or when an employee leaves the Company, the member’s pension liability is transferred to the life insurance company administering the plan, and the pension plan no longer retains an obligation relating to the leaving member. This action is deemed to represent a settlement under U.S. GAAP, as it represents the elimination of significant risks relating to the pension obligation and related assets. Under settlement accounting U.S. GAAP requires a portion of the net unrealized actuarial gains/losses to be recognized through the statement of operations. The portion corresponds to the relative value of the obligation reduction as a result of the settlement. However settlement accounting is not required if the cost of all settlements in a year is not deemed to be significant in the context of the plan. The Company deems the settlement not to be significant when the cost of settlements in the year is less than the sum of service cost and interest cost in the year. In this case the difference between the reduction in benefit obligation and the plan assets transferred to the life insurance company is recognized within “other comprehensive income,” rather than being recognized in the statement of operations.
 
Treasury shares
 
Treasury shares are recognized at cost as a component of equity. The purchase of treasury shares reduces the Company’s share capital by the nominal value of the acquired treasury shares. The amount paid in excess of the nominal value is treated as a reduction of additional paid-in capital.
 
Derivative Financial Instruments and Hedging Activities
 
The Company’s primary derivative instruments include interest-rate swap agreements, foreign currency options and forward exchange contracts which are recorded at fair value. Changes in the fair value of these derivatives, which have not been designated as hedging instruments, are recorded as a gain or loss as a separate line item within financial items in our consolidated statement of operations.
 
Changes in the fair value of any derivative instrument that we have formally designated as a hedge, are recognized in Accumulated other comprehensive income in the consolidated balance sheets. Any change in fair value relating to an ineffective portion of a designated hedge is recognized, in the consolidated statement of operations. When the hedged item affects the income statement, the gain or loss included in Accumulated other comprehensive income is reported on the same line in the consolidated statements of operations as the hedged item.
  
Income taxes
 
Seadrill is a Bermuda company that has a number of subsidiaries and affiliates in various jurisdictions. Currently, the Company and its Bermudan subsidiaries and affiliates are not required to pay taxes in Bermuda on ordinary income or capital gains as they qualify as exempt companies. The Company and its subsidiaries and affiliates have received written assurance from the Minister of Finance in Bermuda that it will be exempt from taxation until March 2035. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income and statutory tax rates in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned.

The determination and evaluation of our annual group income tax provision involves interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amounts, timing and character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authority’s widely understood administrative practices and precedence. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments.

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.

Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as of the Valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances. 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.


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Table of Contents


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.
 
Convertible debt
 
Convertible bond loans issued by the Company include both a loan component (host contract) and an option to convert the loan to shares (embedded derivative).
 
An embedded derivative, such as a conversion option, may be separated from its host contract and accounted for separately if certain criteria are met (including if the contract that embodies both the embedded derivative and the host contract is not measured at fair value, the economic characteristics and risks of the embedded derivative instrument are not clearly and closely related to the economic characteristics and risks of the host contract and if a separate instrument with the same terms as the embedded instrument would be a derivative).
 
If an embedded derivative instrument is separated from its host contract, the host contract shall be accounted for based on generally accepted accounting principles applicable to instruments of that type which do not contain embedded derivative instruments.
 
Total Return Equity Swaps
 
From time to time, the Company enters into total return equity swaps (“TRS”) indexed to the Company’s own shares, where the counterparty acquires shares in the Company and the Company carries the risk of fluctuations in the share price of the acquired shares. The fair value of each TRS is recorded as an asset or liability, with the changes in fair value recorded in the consolidated statement of operations. The Company may, from time to time, enter into TRS arrangements indexed to shares in other companies which are accounted for in a similar manner.
 
Share-based compensation
 
The Company has established an employee share ownership plan under which employees, directors and officers of the Group may be allocated options to subscribe for new shares in the ultimate parent, Seadrill Limited. The compensation cost for share options is recognized as an expense over the service period based on the fair value of the options granted.
 
The fair value of the share options issued under the Company’s employee share option plans is determined at grant date taking into account the terms and conditions upon which the options are granted, and using a valuation technique that is consistent with generally accepted valuation methodologies for pricing financial instruments, and that incorporates all factors and assumptions that knowledgeable, willing market participants would consider in determining fair value. The fair value of the share options is recognized as personnel expenses with a corresponding increase in equity over the period during which the employees become unconditionally entitled to the options. Compensation cost is initially recognized based upon options expected to vest with appropriate adjustments to reflect actual forfeitures. National insurance contributions arising from such incentive programs are expensed when the options are exercised.

The Company has also established a Restricted Stock Units (“RSU”) plan where the holder of an award is entitled to receive shares if still employed at the end of the three year vesting period. There is no requirement for the holder to pay for the share on grant or vesting of the award.

The fair value of the RSU award is calculated as the market share price on grant date. The fair value of the awards expected to vest is recognized as compensation cost straight-line over the vesting period.

Provisions

A provision is recognized in the balance sheet when the Company has 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.
 


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Earnings per share
 
Basic earnings per share (“EPS”) is calculated based on the income/(loss) for the period available to common stockholders divided by the weighted average number of shares outstanding for basic EPS for the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments which for the Company includes share options, restricted stock units and convertible debt. The determination of dilutive earnings per share requires the Company to potentially make certain adjustments to net income and for the weighted average shares outstanding used to compute basic earnings per share unless anti-dilutive.
 

Recently Adopted Accounting Standards

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 at 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, $42 million of debt issuance costs have been reclassified from Other current assets to a direct deduction from Current portion of long-term debt as at December 31, 2014 and $103 million of debt issuance costs have been reclassified from Other non-current assets to a direct deduction from Long-term debt as at the same date. Similarly, as at December 31, 2015, $37 million of debt issuance costs have been presented as a direct deduction from the current portion of long-term debt and $81 million of debt issuance costs have been presented as a direct deduction from long-term debt as at that date. Refer to Note 23 – Long term debt, included herein, for further details.

In April 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which amends the criteria for reporting discontinued operations to include only disposals representing a strategic shift in operations. The ASU also requires expanded disclosures regarding the assets, liabilities, income, and expenses of discontinued operations. Seadrill adopted this guidance in the period, which was effective for the discontinued operations occurring after January 1, 2015. The adoption of this guidance did not have a material impact on Company’s consolidated financial statements and related disclosures.

In June 2014, the FASB issued ASU 2014-11, Transfers and Servicing (Topic 860): Repurchase-to-Maturity Transactions, Repurchase Financings, and Disclosures, which required two accounting changes. First, the amendments in this Update changed the accounting for repurchase-to-maturity transactions to secured borrowing accounting. Second, for repurchase financing arrangements, the amendments required separate accounting for a transfer of a financial asset executed contemporaneously with a repurchase agreement with the same counterparty, which would result in secured borrowing accounting for the repurchase agreement. The ASU also requires for certain transactions comprising (1) a transfer of a financial asset accounted for as a sale and (2) an agreement with the same transferee entered into in contemplation of the initial transfer that results in the transferor retaining substantially all of the exposure to the economic return on the transferred financial asset throughout the term of the transaction. Seadrill adopted this guidance in the period. The ASU is effective periods beginning after December 15, 2014. However, the adoption of this guidance does not have a material impact on Company’s consolidated financial statements and related disclosures.

In November 2015, 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 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 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 did not have a material impact on Company’s consolidated financial statements and related disclosures.


Recently Issued Accounting Standards

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 2015 the FASB proposed to defer the effective date of the guidance by one year. Based on this proposal, public entities would need to apply the new guidance for annual and interim periods beginning after December 15, 2017, 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. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its 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.


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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 therein, 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.

In April 2015, the FASB issued ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement, which provides explicit guidance about a customer’s accounting for fees paid in a cloud computing arrangement. This ASU will be effective for the first interim period 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.
 
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 does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

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 US GAAP. The guidance will be effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years and early adoption is permitted in some cases. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

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. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-07, Investments-Equity Method 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 use of the equity method. The guidance will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years 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.

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 accounting of the new revenue standard. The guidance will be effective for annual and interim periods beginning after December 15, 2017, 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. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The update simplifies the accounting for share based payment transactions. The guidance will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years 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.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. The update provide more clarification about identifying performance obligations and licensing. The guidance will be effective for annual and interim periods beginning after December 15, 2017, and shall be applied, at the Company’s option, retrospectively to each period

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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 is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.


Note 3 – Segment information
 
Operating segments
 
The Company provides drilling and related services to the offshore oil and gas industry. Our business has been organized into three operating segments: (1) Floaters, which includes drillships and semi-submersible rigs, (2) jack-up rigs and (3) other, which consists primarily of rig management services. The Company presents the following two reportable segments:

•
Floaters: Services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to semi-submersible rigs and drillships for harsh and benign environments in mid-, deep- and ultra-deep waters.

•
Jack-up rigs: Services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to jack-up rigs for operations in harsh and benign environment.

Segment results are evaluated on the basis of operating income, and the information given below is based on information used for internal management reporting.
 
In prior periods, the company reported a tender rigs segment, which related to services encompassing drilling, completion and maintenance of offshore production wells in Southeast Asia, West Africa and the Americas. In these periods, the Company had drilling contracts related to self-erecting tender rigs and semi-submersible tender rigs. Following the sale of the majority of the tender rig business to SapuraKencana, which closed on April 30, 2013, and further the deconsolidation of Seadrill Partners LLC (“Seadrill Partners”) as of January 2, 2014, the Company no longer has any drilling contracts in the tender rig segment. Accordingly, the Company did not report this segment for the years ended December 31, 2015 and December 31, 2014. The Company however provides management services to Seadrill Partners and SeaMex which are recognized within the Other segment.
 
Revenues
(In US$ millions)
2015

 
2014

 
2013

Floaters
2,906

 
3,360

 
3,698

Jack-up rigs
1,293

 
1,478

 
1,175

Tender Rigs
—

 
—

 
382

Other
136

 
159

 
27

Total
4,335

 
4,997

 
5,282


Depreciation and amortization
(In US$ millions)
2015

 
2014

 
2013

Floaters
571

 
508

 
531

Jack-up rigs
208

 
185

 
163

Tender Rigs
—

 
—

 
17

Total
779

 
693

 
711


Operating income – net income
(In US$ millions)
2015

 
2014

 
2013

Floaters
340

 
1,992

 
1,472

Jack-up Rigs
664

 
275

 
450

Tender Rigs
—

 
—

 
176

Other
15

 
12

 
—

Operating income
1,019

 
2,279

 
2,098

Unallocated items:
 

 
 

 
 

Total financial items and other
(1,561
)
 
1,827

 
842

Income tax expense
(208
)
 
(19
)
 
(154
)
Net income
(750
)
 
4,087

 
2,786


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Drilling Units and Newbuildings - Total assets
(In US$ millions)
2015

 
2014

Floaters
12,189

 
12,849

Jack-up Rigs
4,220

 
4,326

Tender Rigs
—

 
—

Total Drilling Units and Newbuildings
16,409

 
17,175

Assets held for sale
128

 
1,239

Investments in Associated companies
2,590

 
2,898

Marketable securities
324

 
751

Goodwill
—

 
604

Cash and restricted cash
1,292

 
1,280

Other assets
2,727

 
2,350

Total
23,470

 
26,297


Goodwill
(In US$ millions)
2015

 
2014

Floaters
—

 
604

Total
—

 
604

 
 Capital expenditures – fixed assets
(In US$ millions)
2015

 
2014

 
2013

Floaters
950

 
2,327

 
3,178

Jack-up Rigs
95

 
776

 
1,371

Tender Rigs
—

 
—

 
150

Total
1,045

 
3,103

 
4,699


Geographic segment data
 
Revenues are attributed to geographical segments based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents the Company’s revenues and fixed assets by geographic area:

Revenues
(In US$ millions)
2015

 
2014

 
2013

Brazil
877

 
991

 
825

Norway
641

 
1,071

 
1,198

Angola
527

 
707

 
734

Nigeria
499

 
21

 
207

Others *
1,791

 
2,207

 
2,318

Total Revenue
4,335

 
4,997

 
5,282


* Other countries represents countries in which we operate that individually had revenues representing less than 10 percent of total revenues earned for any of the periods presented.

Major customers

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In the years ended December 31, 2015, 2014 and 2013, the Company had the following customers with contract revenues greater than 10% in any of the years presented:

(US$ millions)
 
2015

 
2014

 
2013

Petroleo Brasileiro S.A ("Petrobras")
 
19
%
 
20
%
 
16
%
Total S.A Group ("Total")
 
16
%
 
13
%
 
14
%
Exxon Mobil Corp ("Exxon")
 
14
%
 
10
%
 
12
%
Statoil ASA ("Statoil")
 
12
%
 
13
%
 
14
%


Fixed assets – operating drilling units (1)
(In US$ millions)
2015

 
2014

Brazil
4,074

 
2,798

Norway
2,094

 
2,252

Angola
1,452

 
1,852

Others *
7,310

 
8,243

Total
14,930

 
15,145


(1) The fixed assets referred to in the table are the Company’s operating drilling units. 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.

* Other countries represents countries in which we operate that individually had fixed assets representing less than 10 percent of total fixed assets for any of the periods presented.


Note 4 – Other revenues
 
Other revenues consist of the following:
 
Year ended December 31
 
(In US$ millions)
2015

 
2014

 
2013

Amortization of unfavorable contracts
116

 
130

 
67

Amortization of favorable contracts
—

 
—

 
(2
)
Revenues related party
119

 
97

 
2

External management fees with third parties
30

 
62

 
45

Total
265

 
289

 
112

 
The unfavorable contract values in 2015, 2014 and 2013 arose from our acquisitions of the Songa Eclipse and Sevan Drilling ASA, see Notes 12 and 21.

Related party revenues were related to management support and administrative services during the year provided to our associates in which we maintain an investment. Refer to Note 31 for more information

External management fees relate to the operational, administrative and support services we provide to SapuraKencana as part of the agreement we entered into when we sold majority of the tender rig business. Refer to Note 11 for more information.



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Note 5 – (Loss)/gain on disposals
 
The Company has recognized the following (losses)/gains on disposals:
(In US$ millions)
 
Net proceeds/recoverable amount

 
Book value on
disposal

 
(Loss)/gain

Year ended December 31, 2015:
 
 
 
 
 
Cancellation of West Mira
199

 
279

 
(80
)
West Rigel Transferred to Asset held for sale
128

 
210

 
(82
)
Sale of West Polaris
235

 
312

 
(77
)
SeaMex Limited
1,240

 
1,059

 
181

Assets written off
—

 
5

 
(5
)
Total for year ended December 31, 2015
1,802

 
1,865

 
(63
)
 
 
 
 
 
 
Year ended December 31, 2014:


 


 


Sale of West Auriga business
466

 
26

 
440

Sale of West Vela business
536

 
344

 
192

Total for year ended December 31, 2014
1,002

 
370

 
632

 
 
 
 
 
 
Year ended December 31, 2013:


 


 


Sale of Jack-up rig West Janus
73

 
12

 
61

Total for year ended December 31, 2013
73

 
12

 
61


Cancellation of the West Mira

On September 14, 2015, the Company cancelled the construction contract for the West Mira with Hyundai Samho Heavy Industries Co Ltd. (“HSHI”), due to the Shipyard’s inability to deliver the unit within the timeframe required under the contract. The carrying value of the newbuild at the date of cancellation was $315 million, which included $170 million of pre-delivery installments paid to HSHI, with the remainder relating to purchased equipment, internally capitalized construction costs and capitalized interest. Under the contract terms, the Company has the right to recoup the $170 million in pre-delivery installments, plus accrued interest.

On October 12, 2015, HSHI launched arbitration proceedings under the contract. HSHI have claimed that Seadrill’s cancellation was a repudiatory breach and claim they were due various extensions of time. The Company refutes this vigorously, and believes it has the contractual right to recover the $170 million in pre-delivery installments, plus accrued interest, and legal costs. The recovery is however now not expected until the conclusion of an arbitration process under English law, which is expected to take up to two years.

Based both on management’s assessment of the facts and circumstances, and advice from external counsel, who have been engaged for the arbitration process, the Company believes the recovery of the installment, plus accrued interest, and legal costs, is probable, as defined by US GAAP. As such, the Company has reclassified from “Newbuildings,” a receivable of $170 million plus accrued interest of $29 million, which is presented in “Other non-current assets” on the balance sheet. The Company will continue to assess the recoverability throughout the arbitration process.

The Company will redeploy equipment, totaling $48 million, within Seadrill’s remaining fleet, and has not written off these amounts. The resulting net loss on disposal recognized was $80 million, which is included in “Loss on disposal” in the Statement of Operations.

West Rigel Transferred to Asset held for sale

On December 2, 2015, the West Rigel was classified as an Asset held for sale. As at the transfer date the West Rigel held assets at its book value of $210 million and a loss on disposal of $82 million was recognized. Please refer to Note 37 for more details.

Sale of West Polaris

On June 19, 2015, the Company sold the entities that owned and operated the West Polaris to Seadrill Operating LP, a consolidated subsidiary of Seadrill Partners LLC and 42% owned by the Company. Please refer to Note 11 for more details.


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SeaMex Limited

During the year ended December 31, 2014, the Company entered into a joint venture agreement with an investment fund controlled by Fintech Advisory Inc. (“Fintech”), for the purpose of owning and managing certain jack-up drilling units located in Mexico under contract with Pemex. The transaction was completed on March 10, 2015, when Fintech subscribed for a 50% ownership interest in the joint venture company, SeaMex Limited (“SeaMex”), which was previously 100% owned by the Company. As a result of the transaction the Company has deconsolidated certain entities as of March 10, 2015, and has recognized its remaining 50% investment in the joint venture at fair value. Please refer to Note 11 for more details.

Sale of West Auriga business

On March 21, 2014, the Company sold the entities that own and operate the West Auriga (the “Auriga business”) to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners that is 49% owned by the Company. Please refer to Note 11 for more details.

Sale of West Vela business

On November 4, 2014, the Company sold the entities that own and operate the West Vela (the “Vela business”) to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners and 49% owned by the Company. Please refer to Note 11 for more details.

Sale of majority of tender rig business

On April 30, 2013 we completed the sale of the entities which owned and operated the following tender rigs: T-4, T-7, T-11, T-12, West Alliance, West Berani, West Jaya, West Menang, West Pelaut, West Setia, and the newbuilds T-17, T-18, and West Esperanza. In addition our 49% ownership in Varia Perdana and Tioman Drilling was sold as part of this transaction, which included the following rigs: T-3, T-6, T-9, T-10, and the Teknik Berkat. This is collectively referred to as the “tender rig businesses.” Please refer to Note 11 for more details.

West Janus
In 2013 we sold the jack-up rig West Janus for net proceeds of $73 million, and recorded a gain on sale of $61 million.


Note 6 – Interest expense
 
 
Year ended December 31
 
(In US$ millions)
2015

 
2014

 
2013

Gross interest expense
475

 
548

 
540

Capitalized interest
(60
)
 
(70
)
 
(95
)
Net interest expense
415

 
478

 
445


Note 7 – Gain on realization of marketable securities

In April 2014, the Company sold a portion of its investment in SapuraKencana and received proceeds of $297 million, net of transaction costs. As a result of the sale, a gain of $131 million was recognized in the consolidated statement of operations within “Gain on realization of marketable securities,” including amounts which had been previously recognized in other comprehensive income. As a result of this transaction, as of December 31, 2015, our ownership interest in SapuraKencana’s outstanding common shares was 8.18%.


Note 8 – Impairment loss on marketable securities and investments in associated companies

Seadrill Partners - Common Units - Impairment of marketable securities
Seadrill deconsolidated Seadrill Partners in January 2014, recognizing its investments in common units at market value of $30.60. Seadrill also purchased further units in 2014 at a similar price. In October 2014, the share price began to fall below $30.60 and fell to $9.40 at September 30, 2015, as a result of deteriorating market conditions in the oil and gas industry and supply and demand conditions in the ultra-deepwater offshore drilling sector. During the period between June 30, 2015 and September 30, 2015, Seadrill Partners’ unit price fell by approximately 20%, on both a spot price and trailing three month average basis. At September 30, 2015 management determined that the investment in Seadrill Partners’ common units was other than temporarily impaired due to the length and severity of the reduction in value below historic cost. As a result the Company has impaired the investment, recognizing an impairment charge of $574 million within “Loss on impairment of investments.” This impairment charge represents a reclassification of losses previously recognized within Other Comprehensive Income. The amount reclassified out of Accumulated other comprehensive income into earnings was determined on the basis of average cost.


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Seadrill Partners - Subordinated units and direct ownership interests - Impairment of Equity Method Investment
Whilst the investments in Seadrill Partners held under the equity method are not publicly traded, the reduction in value of the publicly traded units is considered an indicator of impairment. At September 30, 2015, the Company determined the length and severity of the reduction in value of the traded units to be representative of an other than temporary impairment.

As such the Company has measured and recognized an other than temporary impairment of the subordinated units and direct ownership interests as at September 30, 2015.

The fair value of these investments was derived using an income approach which discounts future free cash flows (“DCF model”). The estimated future free cash flows associated with the investments are primarily based on expectations around applicable dayrates, drilling unit utilization, operating costs, capital and long term maintenance expenditures and applicable tax rates. The cash flows are estimated over the remaining useful economic lives of the underlying assets but no longer than 30 years in total, and discounted using an estimated market participant weighted average cost of capital of 8.5%, which was relevant to the investee. The DCF model derived an enterprise value of the investments, after which associated debt was subtracted to provide equity values. The implied valuation of Seadrill Partners derived from the DCF model was cross-checked against the market price of Seadrill Partners’ common units. The Company evaluated the difference by reviewing the implied control premium as compared to other market transactions within the industry. The Company deems the implied control premium to be reasonable in the context of the data considered.

As at September 30, 2015, the carrying value of the subordinated units was found to exceed the fair value by $125 million, and the carrying value of the direct ownership interests was found to exceed the fair value by $302 million. The company has recognized this impairment of the investments within “Loss on impairment of Investments” in the Statement of Operations.

The assumptions used in the DCF model were derived from unobservable inputs (classified as level 3) and are based on management’s judgments and assumptions available at the time of performing the impairment test.

Seadrill Partners - Member interest - Impairment of Cost method investments
The Company also holds the Seadrill member interest, which is a 0% non-economic interest, and which holds the rights to 100% of the Incentive Distribution Rights “IDRs” of Seadrill Partners. The Seadrill Member Interest and the IDRs in Seadrill Partners are accounted for as cost-method investments on the basis that they do not represent common stock interests and their fair value is not readily determinable. The fair value of the Company’s interest in the Seadrill Member and the attached IDRs at deconsolidation in January 2014, was determined using a Monte Carlo simulation method (“Monte Carlo model”). The method takes into account the cash distribution waterfall, historical volatility, estimated dividend yield and share price of the common units as of the deconsolidation date.

The reduction in value of the Seadrill Partners common units was determined to be an indicator of impairment of the Seadrill member interest. The fair value was determined using the Monte Carlo model, updated for applicable assumptions as at September 30, 2015. The carrying value of the investment was found to exceed the fair value by $106 million. The company has recognized this impairment within “Loss on impairment of Investments” in the Statement of Operations.

The assumptions used in the Monte Carlo model were derived from both observable and unobservable inputs (classified as level 3) and are based on management’s judgments and assumptions available at the time of performing the impairment test.

SapuraKencana - Impairment of marketable securities
During the period since September 30, 2014, to September 30, 2015, SapuraKencana’s share price fell by approximately 45% as a result of deteriorating market conditions in the oil and gas industry. Between June 30, 2015 and September 30, 2015, the value of the investment fell by approximately 20%, as a result of the declining share price and USD:MYR exchange rate. At September 30, 2015, management determined that the investment in SapuraKencana was other than temporarily impaired due to the length and severity of the reduction in value below historic cost. As a result the Company has impaired the investment, recognizing an impairment charge of $167 million within “Loss on impairment of investments.” This impairment charge represents a reclassification of losses previously recognized within Other Comprehensive Income. The amount reclassified out of Accumulated other comprehensive income into earnings was determined on the basis of average cost.



F-24
Table of Contents

The table below summarizes the total impairments of investments made during the year ended December 31, 2015:
(In $ millions)
Year ended December 31, 2015

Impairments of Investment in associated companies
 
Seadrill Partners - Total direct ownership investments
302

Seadrill Partners - Subordinated units
125

Seadrill Partners - Seadrill member interest and IDRs
106

Total impairment of investments in associated companies
533

 
 
Impairments of Marketable securities (refer to Note 14)
 
Seadrill Partners - Common Units
574

SapuraKencana
167

Total impairment of marketable securities investments (reclassification from OCI)
741

 
 
Total impairment of investments
1,274


During the three months ended December 31, 2015 Seadrill Partners’ unit price has fallen further from approximately $9.40 at September 30, 2015 to $3.65 at December 31, 2015. Having assessed the length and severity of the implied fall in value and the prospects for Seadrill Partners, the Company has determined that a further other than temporary impairment of the investment has not occurred.

 
Note 9 – Taxation
 
Income taxes consist of the following:

 
Year ended December 31 
(In US$ millions)
2015
 
2014
 
2013
Current tax expense:
 
 
 
 
 
Bermuda
—

 
—

 
—

Foreign
177

 
23

 
200

Deferred tax expense/(benefit):
 

 
 

 
 

Bermuda
—

 
—

 
—

Foreign
31

 
(4
)
 
(50
)
Tax related to internal sale of assets in subsidiary, amortized for group purposes
—

 
—

 
4

Total tax expense
208

 
19

 
154

Effective tax rate
(38.4
)%
 
0.5
%
 
5.2
%
 
The effective tax rate for the twelve months ended December 31, 2015 is -38.4% as compared to a rate for 2014 of 0.5%.  This means that we continue to pay tax on local operations but reported an overall loss before tax inclusive of discrete items.  The negative rate reflects no tax relief on the impairments or the derivative loss, as well as no tax chargeable on the disposal gains.  This is due to these items largely falling within the zero tax rate Bermuda companies. This is in comparison to 2014 where there was a prior year tax benefit related to the release of an uncertain tax position.

The Company, including its subsidiaries, is taxable in several jurisdictions based on its rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, the Company may pay tax within some jurisdictions even though it might have losses in others.


F-25
Table of Contents

The income taxes for the years ended December 31 2015, 2014 and 2013 differed from the amount computed by applying the Bermudan statutory income tax rate of 0% as follows:
 
Year ended December 31
(In US$ millions)
2015
 
2014
 
2013
Income taxes at statutory rate
—

 
—

 
—

Effect of transfers to new tax jurisdictions
—

 
—

 
4

Effect of change on uncertain tax positions relating to prior year 
—

 
(85
)
 
(7
)
Effect of unremitted earnings of subsidiaries
38

 
—

 
—

Effect of taxable income in various countries
170

 
104

 
157

Total tax expense
208

 
19

 
154


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 (liabilities) consist of the following:
 
Deferred Tax Assets:
(In US$ millions)
December 31,
2015

 
December 31,
2014

Pensions and stock options
9

 
19

Provisions
16

 
20

Net operating losses carried forward
265

 
291

Other
2

 
3

Gross deferred tax asset
292

 
333

Valuation allowance related to net operating losses carried forward
(211
)
 
(280
)
Net deferred tax asset
81

 
53


Deferred Tax Liability:
(In US$ millions)
December 31,
2015

 
December 31,
2014

Property, plant and equipment
98

 
60

Unremitted Earnings of Subsidiaries
38

 
—

Foreign exchange 
—

 
7

Gross deferred tax liability
136

 
67

Net deferred tax
(55
)
 
(14
)
 
Net deferred taxes are classified as follows:
(In US$ millions)
December 31,
2015

 
December 31,
2014

Deferred tax asset
81

 
53

Deferred tax liability
(136
)
 
(67
)
Net deferred tax
(55
)
 
(14
)

As of December 31, 2015, deferred tax assets related to net operating loss (“NOL”) carryforwards was $265 million, which can be used to offset future taxable income. NOL carryforwards which were generated in various jurisdictions, include $265 million that will not expire. A valuation allowance of $211 million as at December 31, 2015 (2014: $280 million; 2013: $115 million) on the NOL carryforwards results where we do not expect to generate future taxable income. The change in the valuation allowance in 2015 was due to a decrease of $69 million and zero utilization during the year compared to an increase of $165 million and zero utilization in 2014 and an increase of $41 million and zero utilization in 2013.

As of December 31, 2014, of the total deferred tax asset of $53 million, a total of $14 million related to the SeaMex business that was classified as held for sale at the balance sheet date. Please see Note 37 – Assets held for sale for more information.

The Company has reviewed its assertion of indefinite reinvestment of unremitted earnings of subsidiaries and determined that, due to the cash needs of the Company caused by the recent industry trend in the market, the Company no longer considers such earnings to be indefinitely reinvested. The Company has recognized a deferred tax liability of $38 million in 2015.

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Table of Contents


In November 2015, 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 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 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 did not have a material impact on Company’s consolidated financial statements and related disclosures.
 
Uncertain tax positions

As of December 31, 2015, we had uncertain tax positions of $9 million. The changes to our uncertain tax positions, including interest and penalties that we recognize as a component of income tax expense, were as follows:

 
Year ended December 31
 (In US$ millions)
2015
 
2014
 
2013
Balance beginning of period
9

 
147

 
154

Increases as a result of positions taken in prior periods
—

 
9

 
29

Increases as a result of positions taken during the current period
—

 
—

 
12

Decreases as a result of positions taken in prior periods
—

 
(147
)
 
(14
)
Decreases as a result of positions taken in the current period
—

 
—

 
(34
)
Balance end of period
9

 
9

 
147

 
As of December 31, 2015, if recognized, $9 million of our unrecognized tax benefits, including interest and penalties, would have a favorable impact on our effective tax rate.

Certain of our Norwegian subsidiaries were party to an ongoing dispute to a tax reassessment issued in October 2011 by the Norwegian tax authorities in regards to the transfer of certain legal entities to a different tax jurisdiction and the principles for conversion of functional currency. In April 2014 these subsidiaries entered into a settlement agreement with the Norwegian tax authorities resulting in discontinued legal proceedings in the Oslo District Court. The terms of the settlement agreement included the Company making a cash payment to the tax authorities for settlement of revised reassessments agreed between the parties. Following settlement of the uncertainties arising from these matters, we recognized a $94 million positive impact on our 2014 effective tax rate.

The parent company, Seadrill Limited, is headquartered in Bermuda where it has been granted a tax exemption until 2035.  Other jurisdictions in which the Company and its subsidiaries operate are taxable based on rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction.  Thus, the Company may pay tax within some jurisdictions even though it may have an overall loss at the consolidated level.  The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:
 
Jurisdiction
Earliest Open Year
United States
2013
Angola
2010
Australia
2011
Nigeria
2009
Norway
2013
Thailand
2005



F-27
Table of Contents

Note 10 – (Loss)/earnings per share
 
The computation of basic (loss)/earnings per share (“EPS”) is based on the weighted average number of shares outstanding during the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments.

The components of the numerator for the calculation of basic and diluted EPS are as follows:
(In US$ millions)
2015

 
2014

 
2013

 
 
 
 
 
 
Net (loss)/income attributable to the parent
(738
)
 
3,979

 
2,653

Less: Allocation to participating securities
—

 
(6
)
 
—

Net (loss)/income available to stockholders
(738
)
 
3,973

 
2,653

Effect of dilution
—

 
117

 
38

Diluted net (loss)/income available to stockholders
(738
)
 
4,090

 
2,691



The components of the denominator for the calculation of basic and diluted EPS are as follows:
(In US$ millions)
2015

 
2014

 
2013

Basic earnings per share:
 
 
 
 
 
Weighted average number of common shares outstanding
492.8

 
478.0

 
469.0

Diluted earnings per share:
 

 
 

 
 

Effect of dilutive convertible bonds
—

 
14.0

 
22.0

Effect of dilutive share options*
—

 
1.0

 
1.0

Weighted average number of common shares outstanding adjusted for the effects of dilution
492.8

 
493.0

 
492.0


* Certain stock options have been excluded from the calculation of diluted EPS because their exercise price exceeded Company’s average share price during the calculation period.

(In US$)
2015

 
2014

 
2013

 
 
 
 
 
 
Basic EPS
(1.49
)
 
8.32

 
5.66

Diluted EPS
(1.49
)
 
8.30

 
5.47


Note 11 – Disposals of businesses and deconsolidation of subsidiaries

Disposals in 2015

Disposal of the West Polaris

On June 19, 2015, the Company sold the entities that owned and operated the West Polaris (the “Polaris business”), to Seadrill Operating LP (“Seadrill Operating”), a consolidated subsidiary of Seadrill Partners LLC and 42% owned by the Company. The entities continue to be related parties subsequent to the sale.

The purchase price consisted of an initial enterprise value of $540 million, less debt assumed of $336 million. The fair value of consideration recognized on disposal was $235 million, which comprised of $204 million of cash consideration, and a working capital adjustment of $31 million, due to the net working capital of the Polaris business being greater than the required working capital prescribed in the sale and purchase agreement..

Additional contingent consideration in the form of a seller’s credit of $50 million is also potentially due from Seadrill Partners in 2021, which will carry interest at a rate of 6.5% per annum. The repayment of the seller’s credit is contingent on the future re-contracted day rate. During the 3 years period following the completion of the current customer contract, the final amount payable will be adjusted downwards to the extent the average re-contracted operating day rate (net of commissions), adjusted for utilization, over the period, is less than $450 thousand per day. If the rig is off contract during this period, the reduction is equal to $450 thousand per day.

In addition, the Company may be entitled to receive further contingent consideration from Seadrill Partners, consisting of (a) any day rates earned by Seadrill Partners in excess of $450 thousand per day, adjusted for daily utilization, tax and agency commission for the remainder of the ExxonMobil contract completing in March 2018 and (b) 50% of any day rate earned above $450 thousand per day, adjusted for daily utilization,

F-28
Table of Contents

tax and agency commission fee after the conclusion of the existing contract until 2025. In February 2016, the drilling contract with ExxonMobil was amended such that the day rate for the West Polaris was reduced from $653 thousand per day to $490 thousand per day, effective January 1, 2016.

The Company’s accounting policy is not to recognize contingent consideration before it is considered realizable and has therefore not recognized on disposal any amounts receivable relating to the elements of consideration which are contingent on future events. From the disposal date of the West Polaris on June 19, 2015 to December 31, 2015, the Company has recognized $32 million in contingent consideration, as it became realized, within “Contingent consideration realized” included within operating income.

The loss recognized at the time of disposal of the Polaris business was $77 million, after taking into account a goodwill allocation of $41 million. The loss has been presented in our consolidated statement of operations, under “(Loss)/gain on disposals” included within operating income and attributable to the floaters segment.

(In $ millions)
As at June 19, 2015

Initial enterprise value
540

Less: Debt assumed
(336
)
Initial purchase price
204

 
 
Plus: Working capital adjustment
31

Adjusted initial purchase price
235

 
 
Cash
204

Plus: Working capital receivable
31

Fair value of purchase consideration recognized on disposal
235

 
 
Less: net carrying value of assets and liabilities
(271
)
Less: allocated goodwill to subsidiaries
(41
)
Loss on disposal
(77
)
 
 
Contingent consideration realized since disposal
32

Under the terms of various agreements between Seadrill and Seadrill Partners LLC, entered into in connection with the initial public offering of Seadrill Partners LLC, Seadrill will continue to provide management, technical and administrative services to the Polaris business. See further discussion in Note 31 to the consolidated financial statements for details of these services and agreements.

The sale of the Polaris business does not qualify for reporting as a discontinued operation as the sale of the Polaris business is not considered to represent a strategic shift expected to have a major effect on the Company’s operations and financial results.

SeaMex Limited

During the year ended December 31, 2014, the Company entered into a joint venture agreement with an investment fund controlled by Fintech Advisory Inc. (“Fintech”), for the purpose of owning and managing certain jack-up drilling units located in Mexico under contract with Pemex. The West Oberon, West Intrepid, West Defender, West Courageous and West Titania jack-up drilling rigs (“the jack-up drilling rigs”) were included within the joint venture. The transaction was completed on March 10, 2015, when Fintech subscribed for a 50% ownership interest in the joint venture company, SeaMex Limited (“SeaMex”), which was previously 100% owned by the Company, and SeaMex simultaneously purchased the jack-up drilling rigs from Seadrill Limited.

As a result of the transaction the Company no longer controls the entities that own and operate these jack-up drilling units (the “Disposal Group”), and accordingly the Company has deconsolidated these entities as of March 10, 2015, and has recognized its remaining 50% investment in the joint venture at fair value. The fair value of the retained 50% equity interest in the SeaMex joint venture was determined by reference to the price paid by Fintech to obtain a 50% equity interest in the disposal group from Seadrill. Seadrill accounts for its 50% investment in the joint venture under the Equity Method.

Total consideration in respect of the Disposal Group was $1,077 million from SeaMex to Seadrill. This was comprised of net cash of $586 million, a Seller’s credit receivable of $250 million, short term related party receivable balances of $91 million and direct settlement of Seadrill’s debt facilities relating to the West Oberon amounting to $150 million. Subsequently, $162 million of related party balance was received when the West Titania was refinanced. The Seller’s credit bears interest at a rate of LIBOR plus a margin of 6.50% and matures in December 2019. See Note 31 to the consolidated financial statements for further details on the related party balances.

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Table of Contents


Seadrill utilized the cash consideration to repay outstanding debt facilities in respect of the West Courageous, West Defender, West Intrepid and West Titania. See further details in Note 23 to the consolidated financial statements.

The total recognized gain on disposal was $181 million, after taking into account a goodwill allocation of $49 million, which has been presented in our consolidated statement of operations, under “(Loss)/gain on disposals” included within operating income attributable to the jack-up segment.

The Company has not presented this disposal group as a discontinued operation in the statement of operations as it does not represent a strategic shift that has (or will have) a major effect on the Company’s operations and financial results.

 (In $ millions)
 
As at March 10, 2015

FAIR VALUE OF CONSIDERATION RECEIVED
 
 
Net cash consideration received
 
749

Seller’s credit recognized
 
250

Direct repayment of debt by the JV on behalf of Seadrill
 
150

Consideration receivable in respect of West Titania
 
162

Other related party balances payable
 
(71
)
Cash paid to acquire 50% interest in the JV
 
(163
)
Fair value of consideration received
 
1,077

 
 
 
FAIR VALUE OF RETAINED 50% INVESTMENT IN SEAMEX LIMITED
 
163

 
 
 
CARRYING VALUE OF NET ASSETS
 
 
Current assets
 
 
Cash and cash equivalents
 
40

Deferred tax assets - short term
 
8

Other current assets
 
20

Total current assets
 
68

 
 
 
Non-current assets
 
 
Drilling units
 
969

Deferred tax asset - long term
 
4

Other non-current assets
 
86

Goodwill
 
49

Total non-current assets
 
1,108

Total assets
 
1,176

 
 
 
LIABILITIES
 
 
Current liabilities
 
 
Trade accounts payable
 
(1
)
Other current liabilities
 
(56
)
Total current liabilities
 
(57
)
 
 
 
Non-current liabilities
 
 
Other non-current liabilities
 
(60
)
Total non-current liabilities
 
(60
)
Total liabilities
 
(117
)
Carrying value of net assets
 
1,059

 
 
 
GAIN ON DISPOSAL
 
181



F-30
Table of Contents

In connection with the JV agreement, SeaMex entered into a management support agreement with Seadrill Management, a wholly owned subsidiary of the Company, pursuant to which Seadrill Management provides SeaMex with certain management and administrative services. The services provided by Seadrill Management are charged at cost plus management fee of 8% of Seadrill’s costs and expenses incurred in connection with providing these services. The agreement can be terminated by SeaMex by providing 120 days written notice.

Disposals in 2014

Deconsolidation of Seadrill Partners

Under the terms of the Operating Agreement of Seadrill Partners, the board of directors of Seadrill Partners has the power to oversee and direct the operations of, and manage and determine the strategies and policies of Seadrill Partners. During the period from Seadrill Partners’ IPO in October 2012 until the time of its first effective Annual General Meeting (“AGM”) on January 2, 2014, the Company retained the sole power to appoint, remove and replace all members of Seadrill Partner’s board of directors. From the first AGM, the majority of the board members became electable by the common unitholders and accordingly, from this date the Company no longer retained the power to control the board of directors as a result of certain provisions in the Operating Agreement which limits the Company’s ability to vote its full holding of common units in an election of directors to the board of Seadrill Partners. As of January 2, 2014, Seadrill Partners is considered to be an associated company, and a related party, and not a controlled subsidiary of the Company. As such Seadrill Partners was deconsolidated by the Company.
Under the terms of various agreements between Seadrill and Seadrill Partners entered into in connection with the IPO of Seadrill Partners, Seadrill will continue to provide management, technical and administrative services to Seadrill Partners and its subsidiaries. See further discussion in Note 31 for these services and agreements.
As a result of the deconsolidation the Company has derecognized the assets and liabilities of Seadrill Partners and its subsidiaries, and has recognized its ownership interests in Seadrill Partners and its direct ownership interests in Seadrill Partners subsidiaries, Seadrill Capricorn Holdings LLC, Seadrill Operating LP, Seadrill Deepwater Drillship Ltd and its indirect ownership of Seadrill Mobile Units through another wholly owned subsidiary, at fair value at the date of deconsolidation. Additionally, the external third party debt associated with the drilling units in Seadrill Partners is not derecognized from the Company on the deconsolidation date, as the external debt was not transferred to Seadrill Partners or its subsidiaries. However, the Company had entered into back to back loan agreements at the time of the IPO and upon each sale of a drilling unit to Seadrill Partners which mirror the same terms and conditions. Therefore, the Company has recognized a related party loan receivable for similar amounts. The excess of the fair value of the investments over the carrying value of Seadrill’s share of Seadrill Partners’ net assets has been recognized as a gain in the Company’s consolidated statement of operations.
The gain recognized on deconsolidation, which all relates to the remeasurement of the Company’s retained interests in Seadrill Partners and its subsidiaries is as follows:
(In US$ millions)
As at January 2, 2014

Fair value of investment in Seadrill Partners (a)
3,724

Carrying value of the non-controlling interest in Seadrill Partners
115

Subtotal
3,839

Less:
 
Carrying value of Seadrill Partners’ net assets
1,260

Goodwill allocated to Seadrill Partners
240

Gain on deconsolidation of Seadrill Partners
2,339


(a)    Fair value of investments and continuing involvement with investees
The estimated fair value of the Company’s residual interest in Seadrill Partners comprised of the following:
(In US$ millions)
As of January 2, 2014

Common units (i)
671

Subordinated units (ii)
427

Seadrill Member Interest and Incentive Distribution Rights ("IDRs") (iii)
244

Direct ownership interests (iv)
2,382

Total
3,724


F-31
Table of Contents

(i) Common units (marketable securities)
As of the deconsolidation date, the Company held 21.5 million common units representing 48.3% of the common units in issue as a class. The Company’s holding in the voting common units of Seadrill Partners are accounted for as marketable securities on the basis that during the subordination period the common units have preferential dividend and liquidation rights, and therefore do not represent ‘in-substance common stock’ as defined by U.S. GAAP.
These securities have been recognized on January 2, 2014 at the quoted market price and are re-measured at fair value each reporting period. Any unrealized gains and losses on these securities are recognized directly in equity as a component of other comprehensive income unless an unrealized loss is considered “other-than-temporary,” in which case it is transferred to the statement of operations and realized. Dividend income from the common units is recognized in the consolidated statement of operations.

(ii) Subordinated units
As of the deconsolidation date the Company held 16.5 million units representing 100% of the subordinated units. The Company’s holding in the subordinated units of Seadrill Partners are accounted for under the equity method on the basis that the subordinated units are considered to be ‘in-substance common stock’. The subordination period will end on the satisfaction of various tests as prescribed in the Operating Agreement of Seadrill Partners, but will not end before September 30, 2017 except upon removal of the Seadrill Member. Upon the expiration of the subordination period, the subordinated units will convert into common units.
The fair value of the subordinated units on January 2, 2014, was determined based on the quoted market price of the listed common units as of the deconsolidation date, but discounted for their non-tradability and subordinated dividend and liquidation rights during the subordination period. Under the equity method the Company recognizes its share of Seadrill Partners’ earnings allocable to the subordinated units, less amortization of the basis difference (see (c) below), through the ‘share in results of associated companies’ line in the consolidated statement of operations. Dividends are recognized as a reduction in investment carrying value.

(iii) Seadrill Member Interest and IDRs
The Seadrill Member Interest (which is a 0% non-economic interest) holds the rights to 100% of the IDRs and is unable to trade these until the end of the subordination period without the approval of a majority of unaffiliated common unitholders. The Seadrill Member Interest and the IDRs in Seadrill Partners are accounted for as cost-method investments on the basis that they do not represent common stock interests and their fair value is not readily determinable. The investments are held at cost and not subsequently re-measured, however they are tested annually for impairment.
The fair value of the Company’s interest in the Seadrill Member and the attached IDRs as of January 2, 2014 was determined using a Monte Carlo simulation method. The method takes into account the cash distribution waterfall, historical volatility, dividend yield and share price of the common units as of the deconsolidation date. Distributions to the IDRs are recognized in the consolidated statement of operations.

iv) Direct Ownership interests
The Company held the following ownership interests in entities controlled by Seadrill Partners as of the date of deconsolidation:
•
70% ownership in Seadrill Operating LP
Seadrill Operating LP is a limited partnership and is controlled by its General Partner, Seadrill Operating GP LLC, which is wholly owned by Seadrill Partners.
•
49% ownership in Seadrill Capricorn Holdings LLC
Seadrill Capricorn Holdings LLC is a limited liability company. There is only one class of member interest which is deemed to represent voting common stock.
•
39% ownership of Seadrill Deepwater Drillship Ltd. and 39% (indirect) ownership of Seadrill Mobile Units (Nigeria) Ltd.
The Company held a 39% direct ownership interest in Seadrill Deepwater Drillship Ltd. and a 39% indirect ownership of Seadrill Mobile Units Ltd., through its 100% subsidiary, Seadrill UK Ltd. Both entities are limited companies and only have one class of stock, which is deemed to represent voting common stock.
All of the Company’s direct ownership interests are accounted for under the equity method as the Company is deemed to have significant influence over these entities through its voting rights and by virtue of Seadrill’s representation on the board of Seadrill Partners.
The fair values of the four ownership interests described above have been determined using a discounted cash-flow (“DCF”) methodology, using discounted cash-flow forecasts.

(b)    Gain on retained investment
The entire gain on deconsolidation relates to the re-measurement of the various retained investments described above.

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Table of Contents


(c)    Accounting for basis differences
The Company’s investments that are accounted for under the equity method (subordinated units and direct ownership interests) were recognized at fair value upon deconsolidation. Basis differences therefore exist between the fair value of the investments and the underlying carrying values of the investees’ net assets at the date of deconsolidation. A valuation exercise has been performed for each separate investment accounted for under the equity method, in order to allocate these basis differences to identifiable assets and liabilities, with any residual amount recognized as goodwill. Differences have been allocated to depreciable or amortizable assets or liabilities and will be amortized over the estimated useful economic life of the underlying assets and liabilities. This amortization is recognized in the consolidated statement of operations in the ‘share in results from associated companies’ line.
The total investments in Seadrill Partners recorded under the equity method of $2,809 million included the Company’s share of the basis difference between the total fair value and the total underlying book value of Seadrill Partners’ assets at the deconsolidation date are as follows:

(In US$ millions)
Book value
 
Fair value
 
Basis Difference
 
Seadrill's share of basis difference (1)
Drilling units
3,444

 
5,245

 
1,801

 
1,295

Drilling contracts
—

 
170

 
170

 
142

Goodwill
—

 
1,214

 
1,214

 
352

Total
3,444

 
6,629

 
3,185

 
1,789

(1) Seadrill’s share of the basis difference relates to both its investment in the subordinated units of Seadrill Partners, and its direct ownership interests in various subsidiaries of Seadrill Partners, all of which investments are accounted for under the equity method. The total basis difference has been assigned based on Seadrill’s proportional ownership interest in each investee. In the case of Seadrill’s investment in the subordinated units of Seadrill Partners, the proportional allocation to the subordinated units was based on the relative fair values of the various equity interests in Seadrill Partners.

The basis difference has been accounted for as follows:

(i) The basis difference assigned to drilling units is being depreciated over the remaining estimated useful lives of the units.

(ii) The basis difference relating to the drilling contracts is being amortized over the remaining term of the contract.

(iii) The Company will not amortize the difference assigned to goodwill, but will consider any indicators of impairment.

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Table of Contents

Disposal of the West Auriga
On March 21, 2014, the Company sold the entities that own and operate the West Auriga (the “Auriga business”) to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners that is 49% owned by the Company. The entities continue to be related parties subsequent to the sale.
The purchase price consisted of an enterprise value of $1.24 billion, less debt assumed of $443 million. The total consideration of $797 million was comprised of cash of $697 million and a discount note receivable of $100 million. The purchase price was subsequently adjusted by a working capital adjustment of $331 million arising from related party balances which remained with the disposed entities for the construction, equipping and mobilization of the West Auriga. The total recognized gain on sale of the Auriga business was $440 million, after taking into account a goodwill allocation of $33 million, which has been presented in our consolidated statement of operations, under “gain on disposals” included within operating income.

(In US$ millions)
March 21, 2014

Enterprise value
1,240

Less: Debt assumed
(443
)
Purchase price
797

 
 
Less: Working capital adjustment
(331
)
Adjusted purchase price
466

 
 
Cash
697

Discount note issued
100

Less: Working capital payable
(331
)
Fair value of purchase consideration
466

 
 
Less: net carrying value of assets and liabilities
7

Less: allocated goodwill to subsidiaries
(33
)
Gain on sale
440

Under the terms of various agreements between Seadrill and Seadrill Partners entered into in connection with the IPO of Seadrill Partners, Seadrill will continue provide management, technical and administrative services to Seadrill Partners and its subsidiaries. See further discussion in Note 31 for these services and agreements.


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Disposal of the West Vela
On November 4, 2014, the Company sold the entities that own and operate the West Vela (the “Vela business”) to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners and 49% owned by the Company. The entities continue to be related parties subsequent to the sale.
The purchase price consisted of an enterprise value of $900 million, less debt assumed of $433 million that was outstanding under the existing facility related to West Vela. The Company is also to receive deferred consideration of $44 thousand per day for the remainder of the West Vela’s current contract with BP which runs to November 2020. In addition, the Company will receive a contingent amount of up to $40 thousand per day for the remainder of the BP contract, depending on the actual amount of contract revenue received from BP. The Company’s accounting policy is not to recognize contingent consideration before it is considered realizable. The total consideration recognized on disposal of $535 million was comprised of cash of $467 million, and deferred consideration receivable of $74 million. The purchase price was also adjusted by a working capital adjustment of $6 million.
The gain recognized at the time of disposal of the Vela business was $191 million, after taking into account a goodwill allocation of $41 million. The gain has been presented in our consolidated statement of operations, under “gain on disposals” included within operating income. During the year ended December 31, 2015, the Company also recognized $15 million related to the contingent consideration realized (year ended December 31, 2014: $1 million).

(In US$ millions)
November 4, 2014

Enterprise value
900

Deferred consideration receivable
74

Less: Debt assumed
(433
)
Purchase price
541

 
 
Less: Working capital adjustment
(6
)
Adjusted purchase price
535

 
 
Cash
467

Deferred consideration receivable
74

Less: Working capital payable
(6
)
Fair value of purchase consideration
535

 
 
Less: net carrying value of assets and liabilities
(303
)
Less: allocated goodwill to subsidiaries
(41
)
Gain on sale
191

Under the terms of various agreements between Seadrill and Seadrill Partners entered into in connection with the IPO of Seadrill Partners, Seadrill will continue provide management, technical and administrative services to Seadrill Partners and its subsidiaries. See further discussion in Note 31 for these services and agreements.

Disposals in 2013

Sale of majority of tender rig business

On April 30, 2013 we completed the sale of the entities which owned and operated the following tender rigs: T-4, T-7, T-11, T-12, West Alliance, West Berani, West Jaya, West Menang, West Pelaut, West Setia, and the newbuilds T-17, T-18, and West Esperanza. In addition our 49% ownership in Varia Perdana and Tioman Drilling was sold as part of this transaction, which included the following rigs: T-3, T-6, T-9, T-10, and the Teknik Berkat. This is collectively referred to as the “tender rig businesses.”

The agreed upon price was for an enterprise value of $2.9 billion. The enterprise value price is comprised of $1.2 billion in cash, $416 million in new shares in SapuraKencana (at MYR3.18per share), $760 million related to all the debt in the tender rigs business, future estimated non recognized capital commitments of $320 million and deferred consideration of $187 million. The deferred consideration consists of non-contingent consideration of $145 million payable in three years and contingent consideration of $42 million depending on certain specified future performance conditions.


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The fair value of consideration received was $2.6 billion, which is the estimated enterprise value reduced by the future non recognized estimated capital commitments, an EBITDA contribution of approximately $75 million and an adjustment for working capital balances and other miscellaneous items and deferred consideration. The fair values recognized for the deferred consideration were $135 million and $nil for the non-contingent and contingent consideration respectively. The total recognized gain on this transaction was $1.3 billion, which has been presented in our consolidated statement of operations, under “Gain on sale of tender rig business.” The gain was calculated as follows:
(In US$ millions)
December 31, 2013

Fair value of consideration received
2,600

Carry value of assets and liabilities
1,324

Other related costs to sale
20

Total gain on sale
1,256



In conjunction with the sale agreement, the Company entered into an arrangement to continue to manage and supervise at the Company’s risk, the construction of three tender rig newbuilds; T-17, T-18, and West Esperanza. Under this arrangement the Company will incur and be reimbursed for all associated costs in accordance within an agreed upon budget to complete the construction of these rigs, except for the yard installment payments, which are paid by SapuraKencana. These rigs were delivered in 2013 and 2014. The Company will also provide operational management, administration and support services for the three tender rigs: West Jaya, West Setia, and West Esperanza which are located outside of Asia until the client contract expiry date. The Company will be reimbursed for all costs and expenses incurred and earn an agreed upon margin for these rig management services. Additionally, the Company will provide transition and separation services for certain administrative and IT functions for the tender rig business for a period of one year following the sale in which costs and expenses are reimbursed in addition to earning an agreed upon margin. While we have retained the ownership of the tender rigs T-15 and T-16, also as part of the sale agreement, SapuraKencana have been responsible for the operational management, administration and support services for the tender rig T-15 and T-16 effective from November 1, 2013 subject to similar terms for the rigs we will continue to manage as noted above.

After this transaction, the Company has ownership of 720,329,691 shares in SapuraKencana, a holding of 12.02%, representing a gross value of $1,078 million based on the closing share price of RM4.90 on December 31, 2013. This is currently held as a marketable security on the consolidated balance sheet, see Note 14 to the consolidated financial statements included herein. Additionally as a result of the sale transaction, the Company obtained board representation for SapuraKencana.

We have determined that we have significant continuing involvement in the ongoing tender rig business with SapuraKencana and therefore, we have concluded that the results of the tender rig business sold should not be presented as a discontinued operation in our consolidated statement of operations.


Note 12 – Business Acquisitions
 
Acquisitions in 2015

There were no business acquisitions in the year ended December 31, 2015.

Acquisitions in 2014

There were no business acquisitions in the year ended December 31, 2014.

Acquisitions in 2013

Acquisition of Songa Eclipse

On November 15, 2012 a subsidiary of the Company entered into an agreement with Songa Eclipse Ltd to acquire the ultra-deepwater semi-submersible drilling rig, “Songa Eclipse” for cash consideration of $590 million. The cash consideration also included the acquisition of the drilling contract with Total Offshore Angola that is fixed and ended December 2013 with three one year options to extend the contract. This acquisition is in line with our strategy of building a modern fleet through selective acquisitions and organic growth giving us an increased exposure to the ultra-deepwater market. A prepayment of $59 million was made before the end of 2012 and the physical delivery and final payment took place on January 3, 2013, which was considered to be the acquisition date. This purchase was considered to constitute a business combination for accounting purposes.

The drilling unit has been valued at fair value separately from the attached drilling contract. Drilling unit valuations are derived from the assessment of a variety of valuation techniques and inputs.  These include assessing comparable market transactions and considering implied earnings multiples, replacement values and current construction costs to arrive an estimated fair value.

The fair value of the attached 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

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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.  An estimate of prevailing market rates was obtained from independent brokers and cross checked against the Company’s own view on prevailing market rates. 

The unfavorable contract acquired is amortized over the estimated length of the contract, including extension periods, and is presented in the Statement of Operations within other revenues. Subsequent to the acquisition, the drilling rig has been renamed the West Eclipse.

The fair values of net assets acquired were as follows:
 
(In US$ millions)
 
January 3, 2013

 
 
 
Fair value of net assets acquired:
 
 
Drilling units
 
698

Unfavorable contract – Other current liabilities
 
(27
)
Unfavorable contract – Other non-current liabilities
 
(81
)
Net assets acquired
 
590

 
 
 

Fair value of consideration
 
590


In the Consolidated Statement of Operations $194 million of West Eclipse revenue and a net income of $42 million have been included since the acquisition date up until December 31, 2013.


Consolidation of Asia Offshore Drilling Ltd (AOD)

On March 25, 2013, we and the other major shareholder in AOD, Mermaid Maritime Plc, signed a shareholder resolution that changed the board of directors composition in favor of the Company. Based on this change as of March 25, 2013 we obtained control of the board of directors and also own 66.18% of the outstanding shares. As a result of obtaining control, we have consolidated the results and financial position of AOD from this date. This event is considered to constitute a business combination achieved in stages in accordance with US GAAP. This acquisition is in line with our strategy of building a modern fleet through selective acquisitions and organic growth giving us an increased exposure to the high specification jack-up market.

The drilling unit has been valued at fair value separately from the attached drilling contract. Drilling unit valuations are derived from the assessment of a variety of valuation techniques and inputs.  These include assessing comparable market transactions and considering implied earnings multiples, replacement values and current construction costs to arrive at an estimated fair value. For newbuilds we have made an estimation of the remaining contractual payments for newbuilds under construction.

The fair value of the attached 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 or decremental cash flows arising over the life of the contract compared with a contract with terms at prevailing market rates. The contract was deemed to be at prevailing market rates and as such no intangible asset or liability was recognized.

The estimated fair value of the non-controlling interest and the previously held equity investment have been determined based on the quoted share price for AOD at the time of the acquisition.

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The fair values of net assets acquired, the remeasurement of our previously held equity interest, measurement of the non-controlling interest and associated bargain purchase gain are as follows:

 
(In US$ millions)
 
March 25, 2013

 
 
 
Cash and cash equivalents
 
1

Current assets
 
1

Drilling units
 
633

Non-current assets
 
633

Construction obligation
 
(316
)
Other current liabilities
 
(8
)
Current liabilities
 
(324
)
Non-current liabilities
 
—

Net assets acquired
 
310

 
 
 
Net book value of equity investment
 
185

Fair value of previously held equity investment
 
195

Gain on re-measurement of previously held equity  investment
 
10

 
 
 

Fair value of establishment of non-controlling interest
 
100

 
 
 

Bargain purchase
 
 

Fair value of establishment of non-controlling interest
 
100

Fair value of previously held equity investment
 
195

Total
 
295

 
 
 

Net assets acquired
 
310

Gain on bargain purchase
 
15


The Company recognized a bargain purchase gain on this acquisition as a result of the market capitalization of AOD being lower than the net assets at the time of acquisition.

In the consolidated statement of operations $75 million of AOD revenue and a net income of $37 million have been included since the acquisition date up until December 31, 2013.


Consolidation of Sevan Drilling ASA

On June 26 and 27, 2013 we entered into arrangements to purchase an additional 120,065,464 shares in Sevan Drilling ASA (“Sevan”) at an average price of NOK 3.9311, for a total of $78 million. This transaction was settled on July 2, 2013. The increased interest in Sevan allows us to expand our fleet of deepwater drilling units. Following these additional share acquisitions we obtained control of 50.1% of the total outstanding shares of Sevan through direct ownership and our existing interest in forward share purchase agreements which result in a controlling financial interest under US GAAP. As a result of obtaining a controlling financial interest, we have consolidated the results and financial position of Sevan from July 2, 2013 which has been determined to be the acquisition date. The acquisition is considered to constitute a business combination achieved in stages. 

The drilling unit has been valued at fair value separately from the attached drilling contract. Drilling unit valuations are derived from the assessment of a variety of valuation techniques and inputs.  These include assessing comparable market transactions and considering implied earnings multiples, replacement values and current construction costs to arrive at an estimated fair value.

The fair value of any attached drilling contracts has been assessed separately.  The contracts were valued using an ’excess earnings’ technique where the terms of the contract are assessed relative to current market conditions. The values of the contract related intangibles were determined by means of calculating the incremental or decremental cash flows arising over the life of the contracts compared with contracts with terms at prevailing market rates.  An estimate of prevailing market rates was obtained from independent brokers and cross checked against the Company’s own view on prevailing market rates. 

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The unfavorable contracts for Sevan Driller and Sevan Brasil are amortized over the remaining contract periods resulting in approximately $20 million per quarter in total. The unfavorable contract for Sevan Louisiana will start amortizing when the contract commences with approximately $1 million per quarter for the fixed contract period.

The fair value of the non-controlling interest and the previously held equity investment have been determined based on the quoted share price for Sevan at the time of the acquisition. Additionally the Company recognized a gain of $8 million as a result of measuring at fair value its 29.9% equity interest in Sevan Drilling held before obtaining a controlling financial interest. The gain is reported as a separate line “Gain on re-measurement of previously held equity interest” in the consolidated statement of operations.

The fair value of trade and other receivables is $49 million and includes trade receivables with a fair value of $24 million. This amount is also the gross contractual amount for trade receivables. All other assets and liabilities book values have been estimated to equal fair values at the date of acquisition.

The Company recognized a bargain purchase gain of $17 million as a result of this acquisition. The gain is reported as a separate line “Gain on bargain purchase” in the consolidated statement of operations. The bargain purchase gain is a result of the market capitalization of Sevan Drilling being lower than the net assets at the time of the acquisition.

In the consolidated statement of operations $169 million of Sevan revenue and a net income of $31 million have been included since the acquisition date up until December 31, 2013.


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The fair values of net assets acquired including the remeasurement of our previously held equity interest, measurement of the non-controlling interest and associated bargain purchase gain are as follows:
 
(In US$ millions)
 
July 2,
2013

 
 
 
Cash and cash equivalents
 
54

Restricted cash
 
63

Trade and other receivables
 
49

Current assets
 
166

Drilling units
 
1,246

Newbuildings
 
1,227

Deferred income tax asset
 
76

Valuation allowance income tax asset
 
(76
)
Other non-current assets
 
1

Non-current assets
 
2,474

Total assets
 
2,640

 
 
 
Current portion of long-term debt
 
(112
)
Trade and other payables
 
(115
)
Construction obligation
 
(923
)
Unfavorable contracts
 
(79
)
Other current liabilities
 
(26
)
Current liabilities
 
(1,255
)
Long-term interest bearing debt
 
(703
)
Unfavorable contracts
 
(257
)
Other non-current liabilities
 
(16
)
Non-current liabilities
 
(976
)
Total liabilities
 
(2,231
)
Net assets acquired
 
409

 
 
 
Net book value of equity investment
 
109

Fair value of previously held equity investment
 
117

Gain on re-measurement of previously held equity investment
 
8

 
 
 

Fair value of establishment of non-controlling interest
 
197

 
 
 

Bargain purchase
 
 

Fair value of consideration transferred
 
78

Fair value of establishment of non-controlling interest
 
197

Fair value of previously held equity investment
 
117

Total
 
392

 
 
 

Net assets acquired
 
409

Gain on bargain purchase
 
17


As a result of our increased ownership interests in Sevan during the quarter, we were required to make a mandatory offer in accordance with the Oslo Stock Exchange rules for the remaining outstanding shares in Sevan for NOK 3.95. This mandatory offer period expired on August 23, 2013. As a result of the offer, we obtained an additional 47,394 shares, bringing our total interest in Sevan to 297,941,358 shares, or 50.11% of the total outstanding shares.




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Note 13 – Restricted cash
 
Restricted cash includes:
(In US$ millions)
December 31, 2015

 
December 31, 2014

CIRR deposits (1)
71

 
124

Margin calls related to share forward agreements
170

 
264

Cash pledged as collateral under credit facilities
—

 
50

Tax withholding deposits
7

 
11

Total restricted cash
248

 
449

Long-term restricted cash (related to CIRR deposits and margin calls)
198

 
181

Short-term restricted cash
50

 
268


(1) CIRR deposits are cash deposited with commercial banks, which match Commercial Interest Reference Rate (“CIRR”) loans from Eksportfinans ASA, the Norwegian export credit agency (See Note 23 to the consolidated financial statements included herein). The deposits are used to make repayments of the CIRR loans.
 

Note 14 – Marketable securities
 
The historic cost of marketable securities is marked to market, with changes in fair value recognized in “Other comprehensive income” (“OCI”).

Marketable securities held by the Company are equity securities considered to be available-for-sale securities. The following tables summarize the carrying values of the marketable securities in the balance sheet:

 
As at December 31, 2015
(In US$ millions)
Amortized
cost
 
Cumulative unrealized fair value gains/(losses)
 
Carrying
value
Sapura Kencana
206
 
22
 
228
Seadrill Partners - Common Units
247
 
(151)
 
96
Total
453
 
(129)
 
324

 
As at December 31, 2014
(In US$ millions)
Amortized
cost
 
Cumulative unrealized fair value gains/(losses)
 
Carrying
value
Sapura Kencana
373
 
(48)
 
325
Seadrill Partners - Common Units
821
 
(395)
 
426
Total
1,194
 
(443)
 
751


The following table summarizes the gross realized gains and losses from purchases and sales of marketable securities during the years presented:
 
Year ended December 31, 2015
(In US$ millions)
Gross realized gains
 
Gross realized losses
 
Gross Unrealized gains
 
Gross Unrealized losses
 
Gross proceeds from sales
 
Recognition and purchases
 
Gain/(loss) reclassified into income
Sapura Kencana
—
 
—
 
—
 
(97)
 
—
 
—
 
(167)
Seadrill Partners - Common Units
—
 
—
 
—
 
(330)
 
—
 
—
 
(574)
Total
—
 
—
 
—
 
(427)
 
—
 
—
 
(741)


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Year ended December 31, 2014
(In US$ millions)
Gross realized gains
 
Gross realized losses
 
Gross Unrealized gains
 
Gross Unrealized losses
 
Gross proceeds from sales
 
Recognition and purchases
 
Gain/(loss) reclassified into income
Petromena
6
 
—
 
—
 
—
 
10
 
—
 
—
Sapura Kencana
—
 
—
 
—
 
(456)
 
297
 
—
 
131
Seadrill Partners - Common Units
—
 
—
 
—
 
(395)
 
—
 
821
 
—
Total
6
 
—
 
—
 
(851)
 
307
 
821
 
131

 
Year ended December 31, 2013
(In US$ millions)
Gross realized gains
 
Gross realized losses
 
Gross Unrealized gains
 
Gross Unrealized losses
 
Gross proceeds from sales
 
Recognition and purchases
 
Gain/(loss) reclassified into income
Petromena
—
 
—
 
—
 
—
 
—
 
—
 
—
Sapura Kencana
—
 
—
 
333
 
—
 
—
 
416
 
—
Total
—
 
—
 
333
 
—
 
—
 
416
 
—


SapuraKencana
During 2012 we owned a 23.6% share in SapuraCrest Petroleum Bhd, which was accounted for using the equity method. On May 17, 2012 SapuraCrest Petroleum Bhd and Kencana Petroleum Bhd merged resulting in dilution of our shareholdings from 23.6% to 11.8% and therefore we recognized a gain of $169 million which is included in our consolidated statement of operations. The investment was consequently transferred from investment in associated companies to an investment accounted for at fair value as an available-for-sale security. Additionally during 2012 we further reduced our ownership share to 6.4% through a sale of shares and therefore we recognized a gain of $84 million which was included in the consolidated statement of operations.

On April 30, 2013, as part of the consideration for the sale of certain tender rigs to SapuraKencana, we received 400.8 million shares in SapuraKencana, increasing our shareholding from 6.4% to 12.0%.

On September 18, 2013, we entered into a financing arrangement whereby a proportion of our holding of SapuraKencana shares have been pledged as security for the contractual period which extends beyond the next 12 months. Accordingly, these pledged shares have been reclassified as long term marketable securities in the balance sheet. See Note 32 to the Consolidated Financial Statements included herein.

During the year ended December 31, 2014, the Company sold a portion of its investment in SapuraKencana and received proceeds of $297 million, net of transaction costs. As a result of the sale, a gain of $131 million was recognized, including amounts which had been previously recognized in other comprehensive income, which was recognized on an average cost basis. The gain is included in the consolidated statement of operations within “Gain on realization of marketable securities.” As a result of the transactions, our ownership interest in SapuraKencana’s outstanding common shares is 8.18% as at December 31, 2015.

During the year ended December 31, 2015 the Company recognized an other than temporary impairment charge of $167 million on the investment in SapuraKencana, which is recorded within “Loss on impairment of investments.” This impairment charge represents a reclassification of losses previously recognized within Other Comprehensive Income. Refer to Note Note 8 for more information.

As at December 31, 2015 accumulated unrealized gain recognized in other comprehensive income totaled $22 million had been recognized in accumulated other comprehensive income.

Seadrill Partners Common Units
Our holding of the voting common units of Seadrill Partners are accounted for as marketable securities on the basis that during the subordination period the common units have preferential dividend and liquidation rights, and therefore do not represent a ‘in-substance common stock’ interest as defined by US GAAP. These securities were recognized on January 2, 2014 at the quoted market price and are re-measured at fair value each reporting period at a total value of $671 million. For more details on the deconsolidation of Seadrill Partners see Note 11.


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In March 2014 and June 2014, the Company purchased additional common units in Seadrill Partners of 1,633,987 at $30.60 per unit and 3,183,700 at $31.41 per unit respectively, totaling $150 million. Our ownership interest in Seadrill Partners’ common units is 28.6% as of December 31, 2015 (2014: 28.6%).

Seadrill deconsolidated Seadrill Partners in January 2014, recognizing its investments in common units at market value of $30.60. Seadrill also purchased further units in 2014 at a similar price. In October 2014, the share price began to fall below $30.60 and fell to $9.40 at September 30, 2015, as a result of deteriorating market conditions in the oil and gas industry and supply and demand conditions in the ultra-deepwater offshore drilling sector. During the period between June 30, 2015 and September 30, 2015, Seadrill Partners’ unit price fell by approximately 20%, on both a spot price and trailing three month average basis. At September 30, 2015 management determined that the investment in Seadrill Partners’ common units was other than temporarily impaired due to the length and severity of the reduction in value below historic cost. As a result the Company has impaired the investment, recognizing an impairment charge of $574 million within “Loss on impairment of investments.” This impairment charge represents a reclassification of losses previously recognized within Other Comprehensive Income. The amount reclassified out of Accumulated other comprehensive income into earnings was determined on the basis of average cost.
As at December 31, 2015 an accumulated unrealized loss of $151 million has been recognized in accumulated other comprehensive income. We have evaluated the near term prospects of the Seadrill Partners in relation to the severity and duration of the decline in fair value. Seadrill Partners continues to make significant distributions to its common unitholders. Its drilling units are largely on long term contracts and so it has little exposure to short term movements in market conditions or dayrates. Based on that evaluation and our ability and intent to hold the investment for a reasonable period of time sufficient for a forecasted recovery of fair value, we do not consider the investment to be other-than-temporarily impaired at December 31, 2015.

Petromena
In February 2014 we received the final payment related to our investment in the 81.1% of the partially redeemed Petromena NOK 2,000 million bond (“Petromena”) of $10 million. The residual $6 million after the investment was reduced has been recorded as a gain in “other financial items” in the consolidated statement of operations in 2014.

Marketable securities in Seadrill Partners, with a fair value of $96 million, are in an unrealized loss position. The total cumulative unrealized holding losses as of December 31, 2015 amounted to $151 million (December 31, 2014: total accumulated losses of $443 million). The loss in 2015 represents the unrealized losses on our investment Seadrill Partners common units. These securities have been in an unrealized loss position for less than 12 months.


Note 15 – Accounts receivable
 
Accounts receivable are presented net of allowances for doubtful accounts. The allowance for doubtful accounts receivables at December 31, 2015 was $39 million (2014: $16 million; 2013: $27 million).
 
Accounts receivable is also presented net of customer receivables associated with Assets held for sale. The balance of accounts receivable classified as assets held for sale at December 31, 2015 is nil (2014: $78 million). Please refer to Note 37 – Assets held for sale.

The Company did not recognize any bad debt expense in 2015, 2014, or 2013, but has instead reduced contract revenue for the disputed amounts.

Note 16 – Other current assets
 
Other current assets include:
(In US$ millions)
December 31, 2015

 
December 31, 2014

Prepaid expenses
42

 
30

Reimbursable amounts due from customers
48

 
79

Deferred mobilization cost
55

 
7

Deferred consideration (1)
166

 
—

Taxes receivable
32

 
29

Other current assets
52

 
77

Total other current assets
395

 
222


(1)
The deferred consideration receivable relates to the disposal of the tender rig business to SapuraKencana in 2013, and the balance includes interest accrued. Refer to Note 11 for more information.


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Note 17 – Investment in associated companies
 
The Company has the following investments that are or have been recorded using the equity method for the periods presented in these financial statements:

Ownership percentage
December 31, 2015

 
December 31, 2014

 
December 31, 2013

Archer
39.9
%
 
39.9
%
 
39.9
%
Seabras Sapura Participacoes SA (”Seabras Sapura Participacoes”)
50.0
%
 
50.0
%
 
50.0
%
Seabras Sapura Holding GmbH (”Seabras Sapura Holdco”)
50.0
%
 
50.0
%
 
50.0
%
Itaunas Drilling B.V. (”Itaunas Drilling”)
30.0
%
 
30.0
%
 
30.0
%
Camburi Drilling B.V. (”Camburi Drilling”)
30.0
%
 
30.0
%
 
30.0
%
Sahy Drilling B.V. (”Sahy Drilling”)
30.0
%
 
30.0
%
 
30.0
%
Seadrill Partners (”SDLP”)
Note 1

 
Note 1

 
Note 1

SeaMex Ltd. (”SeaMex”)
50.0
%
 
—
%
 
—
%
(1)
As of the deconsolidation date of Seadrill Partners on January 2, 2014, we recognized our ownership interests in Seadrill Partners and direct ownership interests in Seadrill Partners subsidiaries, at fair value at the date of deconsolidation. Refer to Seadrill Partners paragraph below for additional information.

At the year-end the book values of the Company’s investment in associated companies are as follows:
(In US$ millions)
December 31, 2015

 
December 31, 2014

Archer
—

 
—

Seabras Sapura Participacoes
29

 
21

Seabras Sapura Holding
158

 
117

Itaunas Drilling
3

 
3

Camburi Drilling
6

 
6

Sahy Drilling
4

 
4

Seadrill Partners - Total direct ownership interests
1,767

 
2,091

Seadrill Partners - Subordinated Units
293

 
412

Seadrill Partners - Seadrill Member Interest and IDRs (1)
137

 
244

Seamex Ltd.
193

 
—

Total
2,590

 
2,898


(1)
The Seadrill Partners - Seadrill Member Interest and Incentive Distribution Rights (“IDR’s”) are accounted for as cost-method investments on the basis that they do not represent common stock interests and their fair value is not readily determinable. The investments are held at cost and not subsequently re-measured. For more details on the deconsolidation of Seadrill Partners see Note 11 for more information.

The quoted market value for the investment in Archer as at December 31, 2015 was $22 million. Quoted market prices for all our other equity investments are not available because, other than Seadrill Partners Common Units, these companies are not publicly traded. Seadrill Partners subordinated units are not tradable and hence have no quoted market price.

Archer
Archer is a company listed on the Oslo Stock Exchange and provides drilling and well services. Prior to February 2011, Archer was a consolidated subsidiary. In February 2011, we deconsolidated Archer and as a result, Archer is accounted for as an associated company.

On February 8, 2013, we were allocated 82,003,000 shares in the private placement of Archer, amounting to a value of $98 million. In addition, as consideration for acting as an underwriter to the placement, the Company received another 2,811,793 shares, amounting to a value of $3 million. The consideration for the shares was settled against the existing $55 million loan to Archer, with the remainder of the consideration funded by a $43 million loan from Archer, which was repaid on February 27, 2013.

As of December 31, 2015 we held 39.9% of the outstanding shares of Archer.

For transactions and balances with Archer, please refer to Note 31 – Related party transactions.


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Table of Contents

Seabras Sapura Participacoes and Seabras Sapura Holdco
Seabras Sapura Participacoes SA is a company incorporated in Brazil, which is currently constructing one pipe-laying vessel. It is 50% owned by TL Offshore Sdn. Bhd., a subsidiary of SapuraKencana, and 50% owned by the Company.

Seabras Sapura Holdco Ltd is a company incorporated in Bermuda, which is owns five pipe-laying vessels, of which one is under construction. It is 50% owned by TL Offshore Sdn. Bhd. and 50% owned by the Company. During 2014 Seabras Sapura Holdco Ltd was transferred into a new company Seabras Sapura Holding GmbH (a company incorporated in Austria).

For transactions and balances with Seabras Sapura Participacoes and Seabras Sapura Holdco, please refer to Note 31 – Related party transactions.

Itaunas Drilling, Camburi Drilling, and Sahy Drilling
Itaunas Drilling BV is a company incorporated in Holland, which is currently constructing a drillship. It is 70% owned by Sete International GmbH and 30% owned by the Company.

Camburi Drilling BV is a company incorporated in Holland, which is currently constructing a drillship. It is 70% owned by Sete International GmbH and 30% owned by the Company.

Sahy Drilling BV is a company incorporated in Holland, which is currently constructing a drillship. It is 70% owned by Sete International GmbH and 30% owned by the Company.

Seadrill Partners
As a result of the deconsolidation of Seadrill Partners on January 2, 2014, the Company has derecognized the assets and liabilities of Seadrill Partners and its subsidiaries, and has recognized its ownership interests in Seadrill Partners and its direct ownership interests in Seadrill Partners subsidiaries, Seadrill Capricorn Holdings LLC, Seadrill Operating LP, Seadrill Deepwater Drillship Ltd and its indirect ownership of Seadrill Mobile Units through another wholly owned subsidiary, at fair value at the date of deconsolidation. For further discussion please refer to Note 11 of the consolidated financial statements.

Seadrill’s investment in Seadrill Partners accounted for under the equity method is comprised of the following:

(a) Subordinated units - the Company’s holding in the subordinated units of Seadrill Partners are accounted for under the equity method on the basis that the subordinated units are considered to be ‘in-substance common stock’. The subordination period will end on the satisfaction of various tests as prescribed in the Operating Agreement of Seadrill Partners, but will not end before September 30, 2017 except upon removal of the Seadrill Member. Upon the expiration of the subordination period, the subordinated units will convert into common units.

(b) Direct Ownership interests - Seadrill holds ownership interests in the following entities controlled by Seadrill Partners as at December 31, 2015:
i.
42% in Seadrill Operating LP: Seadrill Operating LP is a limited partnership and is controlled by its General Partner, Seadrill Operating GP LLC, which is wholly owned by Seadrill Partners.
ii.
49% Seadrill Capricorn Holdings LLC: Seadrill Capricorn Holdings LLC is a limited liability company. There is only one class of member interest which is deemed to represent voting common stock.
iii.
39% in Seadrill Deepwater Drillship Ltd and 39% indirect interest in Seadrill Mobile Units (Nigeria) Ltd.: Both entities are limited companies and only have one class of stock, which is deemed to represent voting common stock.

All of the Company’s direct ownership interests are accounted for under the equity method as the Company is deemed to have significant influence over these entities through its voting rights and by virtue of Seadrill’s representation on the board of Seadrill Partners.

Sale of 28% limited partner interest in Seadrill Operating LP
On July 21, 2014, the Company sold a 28% limited partner interest in Seadrill Operating LP, a subsidiary of Seadrill Partners, to Seadrill Partners for cash consideration of $373 million. This resulted in a loss on sale of investment of $88 million, which has been recognized within “share in results from associated companies” in the Company’s consolidated statement of operations. The Company will continue to account for its remaining 42.0% limited partner interest in Seadrill Operating LP under the equity method.

Impairment
During the year ended December 31, 2015, the Company recognized an other than temporary impairment on the equity method investments in Seadrill Partners for a total of $533 million. Refer to Note 8 for more information.


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For transactions and balances with Seadrill Partners, please refer to Note 31 – Related party transactions.

SeaMex
During the year ended December 31, 2014, the Company entered into a joint venture agreement with an investment fund controlled by Fintech, for the purpose of owning and managing certain jack-up drilling units located in Mexico under contract with Pemex. The transaction was completed on March 10, 2015, when Fintech subscribed for a 50% ownership interest in the joint venture company, SeaMex, which was previously 50% owned by the Company, and SeaMex simultaneously purchased the jack-up drilling rigs from Seadrill Limited. As a result of the transaction the Company no longer controls the entities that own and operate these jack-up drilling units, and accordingly the Company has deconsolidated these entities as of March 10, 2015, and has recognized its remaining 50% investment in the joint venture at fair value. The fair value of the retained 50% equity interest in the SeaMex joint venture was determined by reference to the price paid by Fintech to obtain a 50% equity interest in the disposal group from Seadrill. Seadrill accounts for its 50% investment in the joint venture under the Equity Method. Refer to Note 11 for further information.

During the year ended December 31, 2015 both the JV partners have each made an additional $19 million of equity investment in SeaMex while retaining their 50% share in the JV.

For transactions and balances with SeaMex, please refer to Note 31 – Related party transactions.

Summary financial information of the equity method investees
Summarized balance sheet information of the Company’s equity method investees is as follows:
 
As of December 31, 2015
(In US$ millions)
Current assets

 
Non-current
assets

 
Current liabilities

 
Non-current liabilities

 
Non-Controlling interest

Archer
363

 
904

 
319

 
751

 
—

Seabras Sapura Participacoes
76

 
308

 
79

 
258

 
—

Seabras Sapura Holding
133

 
1,183

 
80

 
1,199

 
—

Seadrill Partners
892

 
5,949

 
847

 
3,897

 
1,133

SeaMex
218

 
1,157

 
176

 
799

 
—

Total
1,682

 
9,501

 
1,501

 
6,904

 
1,133


 
December 31, 2014
(In US$ millions)
Current assets

 
Non-current
assets

 
Current liabilities

 
Non-current liabilities

 
Non-Controlling interest

Archer
633

 
1,171

 
441

 
817

 
—

Seabras Sapura Participacoes
17

 
194

 
14

 
149

 
—

Seabras Sapura Holding
104

 
690

 
52

 
730

 
—

Seadrill Partners
762

 
5,585

 
686

 
3,617

 
1,116

SeaMex
—

 
—

 
—

 
—

 
—

Total
1,516

 
7,640

 
1,193

 
5,313

 
1,116



Summarized statement of operations information for the Company’s equity method investees is as follows:
 
Year ended December 31, 2015
(In US$ millions)
Operating revenues

 
Net operating
income

 
Net
income

 
Net income attributable to non-controlling interest

Archer
1,321

 
(13
)
 
(359
)
 
—

Seabras Sapura Participacoes
53

 
3

 
1

 
—

Seabras Sapura Holding
124

 
76

 
51

 
—

Seadrill Partners
1,742

 
844

 
488

 
231

Seamex
238

 
79

 
24

 
—

Total
3,478

 
989

 
205

 
231


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Table of Contents


 
Year ended December 31, 2014
(In US$ millions)
Operating revenues

 
Net operating
income

 
Net
income

 
Net income attributable to non-controlling interest

Archer
2,254

 
29

 
(96
)
 
—

Seabras Sapura Participacoes
29

 
(6
)
 
(6
)
 
—

Seabras Sapura Holding
39

 
24

 
13

 
—

Seadrill Partners
1,343

 
615

 
315

 
176

Seamex
—

 
—

 
—

 
—

Total
3,665

 
662

 
226

 
176


 
Year ended December 31, 2013
(In US$ millions)
Operating revenues

 
Net operating
income

 
Net
income

 
Net income attributable to non-controlling interest

Archer
2,041

 
(438
)
 
(519
)
 
—

Seabras Sapura Participacoes
—

 
(2
)
 
(1
)
 
—

Seabras Sapura Holding
—

 
—

 
(1
)
 
—

Seadrill Partners
—

 
—

 
—

 
—

Seamex
—

 
—

 
—

 
—

Total
2,041

 
(440
)
 
(521
)
 
—


At the year end the share of recorded equity in the statutory accounts of the Company’s associated companies were as follows:
(In US$ millions)
December 31, 2015

 
December 31, 2014

 
December 31, 2013

Archer
79

 
218

 
253

Seabras Sapura Participacoes
24

 
24

 
13

Seabras Sapura Holding
19

 
6

 
—

Seadrill Partners *
N/A

 
N/A

 
—

Seamex
200

 
—

 
—

Total
322

 
261

 
277

 
*
The Company accounts for its direct interests in operating subsidiaries of Seadrill Partners, and its ownership of Seadrill Partners Subordinated Units, under the equity method. The Company’s share of Seadrill Partner’s recorded equity consists of the equity attributable to non-controlling interests in Seadrill Partners, and additionally a proportionate share of equity attributable to Seadrill Partners’ unitholders.
The equity attributable to non-controlling interest in Seadrill Partners as at December 31, 2015 was $1,133 million. Seadrill’s holding in the subordinated units represents 18.0% of the limited partner interests in Seadrill Partners. Total equity attributable to Seadrill Partners unitholders as at December 31, 2015 was $964 million.



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Note 18 – Newbuildings

(In US$ millions)
December 31, 2015

 
December 31, 2014

Opening balance
2,030

 
3,419

Additions
601

 
2,433

Capitalized interest and loan related costs
60

 
70

Re-classified as Drilling Units
(725
)
 
(3,892
)
Reclassification to Assets held for sale*
(210
)
 
—

Reclassification to Non-current assets**
(199
)
 
—

Disposals**
(78
)
 
—

Closing balance
1,479

 
2,030


*
On December 2, 2015, the West Rigel was classified as an Asset held for sale. As at the transfer date the West Rigel held assets at its book value of $210.0 million. Please refer to Note 37 to the consolidated financial statements, included herein, for more details.

**
On September 14, 2015, the Company cancelled the construction contract for the West Mira with HSHI Please refer to Note 5 to the consolidated financial statements, included herein, for more details.

Note 19 – Drilling units
(In US$ millions)
December 31, 2015

 
December 31, 2014

Cost
17,606

 
19,101

Accumulated depreciation
(2,676
)
 
(2,991
)
Re-classified as assets held for sale
—

 
(965
)
Net book value
14,930

 
15,145


Depreciation and amortization expense was $761 million, $684 million and $703 million for the years ended December 31, 2015, 2014 and 2013, respectively.
 
On June 19, 2015, the Company sold the entities that owned and operated the West Polaris, to Seadrill Operating LP, a consolidated subsidiary of Seadrill Partners LLC and 42% owned by the Company. Please refer to Note 11 for more details.


During the year ended December 31, 2014, the Company entered into a joint venture agreement with an investment fund controlled by Fintech, for the purpose of owning and managing certain jack-up drilling units located in Mexico under contract with Pemex. The West Oberon, West Intrepid, West Defender, West Courageous and West Titania jack-up drilling rigs (“the jack-up drilling rigs”) were included within the joint venture. The transaction was completed on March 10, 2015, when Fintech subscribed for a 50% ownership interest in the joint venture company, SeaMex, which was previously 100% owned by the Company, and SeaMex simultaneously purchased the jack-up drilling rigs from Seadrill Limited. As a result of the transaction the Company no longer controls the entities that own and operate these jack-up drilling units, and accordingly the Company has deconsolidated these entities as of March 10, 2015. Please refer to Note 11 for more details.

Note 20 – Equipment
 
Equipment consists of office equipment, furniture and fittings.
(In US$ millions)
December 31, 2015

 
December 31, 2014

Cost
80

 
73

Accumulated depreciation
(34
)
 
(27
)
Net book value
46

 
46


Depreciation and amortization expense was $18 million, $9 million and $8 million for the years ended December 31, 2015, 2014 and 2013, respectively.


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Note 21 – Goodwill and other intangible assets and liabilities

Goodwill

The goodwill balance and changes in the carrying amount is as follows:
 

(In $ millions)
Year ended December 31,
2015

 
Year ended December 31,
2014

Opening balance
 
 
 
Goodwill
836

 
1,200

Accumulated impairment losses
(232
)
 
—

Total opening goodwill
604

 
1,200

 
 
 
 
Disposals and deconsolidations (see note 11)
(41
)
 
(315
)
Impairment of goodwill
(563
)
 
(232
)
Re-classified as assets held for sale
—

 
(49
)
 
 
 
 
Closing balance
 
 
 
Goodwill
795

 
836

Accumulated impairment losses
(795
)
 
(232
)
Total closing goodwill
—

 
604


In 2015, the $41 million derecognized through disposals and deconsolidations relates to the $41 million of goodwill relating to the West Polaris sold to Seadrill Partners, corresponding to the Floater segment
In 2014 the total derecognized was $315 million, of which $286 million related to the Floater segment and $29 million related to the Tender rig segment. The $49 million reclassified as assets held for sale at December 31, 2014 related to the Jack-up segment.
For more details on the deconsolidation of Seadrill Partners and the disposal of subsidiaries see Note 11, and details on Assets held for sale see Note 37.
For the year ended December 31, 2015
During the period between June 30, 2015 and September 30, 2015 the Company’s share price fell by 43% from $10.34 to $5.90 (based on the closing spot price), and by 34%, from $12.04 to $7.96 (based on the average trailing three month basis), partly as a result of deteriorating market conditions in the oil and gas industry and supply and demand conditions in the ultra-deepwater offshore drilling sector. As a result management determined that the Goodwill assigned to the Company’s Floaters reporting unit was likely to be impaired, and performed a quantitative impairment test as at September 30, 2015.
As at September 30, 2015 an impairment test was conducted, and it resulted in the Company recognizing an impairment loss of $563 million relating to the Floaters reporting unit which represented all of the Goodwill attributable to that reporting unit. Following the impairment the Company no longer retains any Goodwill balance. The impairment is a result of deteriorating market conditions and the Company’s outlook on expected conditions through the current down-cycle. The impairment charge was allocated between the parent and non-controlling interests based upon the non-controlling interests’ share in each drilling unit within the Floater segment. The overall charge to the reporting unit was first allocated to each drilling unit based upon the relative fair values of those drilling units. The percentage non-controlling interest in each drilling unit was then applied to the allocated charge in order to determine the portion attributable to non-controlling interests. The total impairment allocated to the non-controlling interest was $95 million.
The estimated fair value of the reporting unit was derived using an income approach, using discounted future free cash flows. The Company’s estimated future free cash flows are primarily based on its expectations around day rates, drilling unit utilization, operating costs, capital and long term maintenance expenditures and applicable tax rates. The cash flows are estimated over the remaining useful economic lives of the assets but no longer than 30 years in total, and discounted using an estimated market participant weighted average cost of capital of 10%.
The assumptions used in the Company’s estimated cash flows were derived from unobservable inputs (level 3) and are based on management’s judgments and assumptions available at the time of performing the impairment test.

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For the year ended December 31, 2014
The Company performed its annual goodwill impairment test as of December 31, 2014 for both its reporting units; Floaters and Jack-ups. The Company elected to bypass the qualitative assessment given the recent decline in market conditions in the offshore drilling industry. The annual impairment test resulted in the Company recognizing an impairment loss of $232 million relating to its Jack-up reporting unit. The impairment loss relating to the Jack-up reporting unit is primarily due to declining day rates and future market expectations for day rates in the sector. These have been trending lower as a result of the recent decline in the price of oil, which has impacted the spending plans of our customers. No impairment was recognized relating to the Floater reporting unit as the fair value estimate substantially exceeded carrying value.
The impairment charge relating to the Jack-up reporting unit was allocated between the parent and non-controlling interests based upon the non-controlling interests share in each drilling unit within the Jack-up segment. The overall charge to the reporting unit was first allocated to each drilling unit based upon the relative fair values of those drilling units. The non-controlling interest in each drilling unit was then applied to the allocated charge in order to determine the portion attributable to non-controlling interests. The total impairment allocated to the non-controlling interest was $39 million.
The estimated fair values of the Floater and Jack-up reporting units were derived using an income approach which estimated discounted future cash flows for each reporting unit. Our estimated future free cash flows are primarily based on our expectations around day rates, drilling unit utilization, operating costs, capital and long term maintenance expenditures and applicable tax rates. The cash flows are estimated over the remaining useful economic lives of the assets but no longer than 30 years in total, and discounted using an estimated market participant weighted average cost of capital of 9.5%.
The assumptions used in the Company’s estimated cash flows were derived from unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the impairment test.
As of December 31, 2015 the aggregated estimated fair value of the Company’s reporting units exceeded its market capitalization. The Company evaluated the difference by reviewing the implied control premium as compared to other market transactions within our industry and considering other benchmark data and analysis prepared by offshore drilling industry analysts. The Company deems the implied control premium to be reasonable in the context of the data considered.
For the year ended December 31, 2013
For the year ended December 31, 2013 the Company performed a qualitative assessment of its reporting units which determined that it was more likely than not that the fair value of its Floaters and Jack-up reporting units were not less than their carrying amount. As a result it was not considered necessary to perform the two step goodwill impairment test and no impairment losses were recognized.

Intangibles

Intangible assets/liabilities relate to favorable/unfavorable contracts which are recorded at fair value at the date of acquisition. 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 unfavorable contract values have been recognized and amortized over the terms of the contracts, ranging from two to five years. The gross carrying amounts and accumulated amortization 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
Unfavorable contracts - intangible liabilities
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of period
444

 
(197
)
 
247

 
444

 
(67
)
 
377

Additions
—

 
—

 
—

 
—

 
—

 
—

Amortization of unfavorable contracts
—

 
(116
)
 
(116
)
 
—

 
(130
)
 
(130
)
Balance at end of period
444

 
(313
)
 
131

 
444

 
(197
)
 
247


We amortize the favorable and unfavorable contracts as revenue or reduction to revenue over the contract term. This is recognized within other revenues in the consolidated statement of operations. 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 unfavorable contracts
65

 
43

 
23

 
—

 
—

 
131




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Table of Contents

Note 22 – Other non-current assets

Other non-current assets consist of the following:
(In US$ millions)
December 31, 2015

 
December 31, 2014

Deferred tax effect of internal transfer of assets
92

 
102

Deferred mobilization costs
32

 
47

Deferred consideration
—

 
154

Receivable from shipyard (1)
199

 
—

Other
8

 
8

Total other non-current assets
331

 
311


(1)
The Receivable from shipyard relates to the West Mira. Please see Note 5 – (Loss)/gain on disposals for more information



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Note 23 – Long-term debt
 
As of December 31, 2015 and 2014, the Company had the following debt:
(In US$ millions), unless stated otherwise
 
December 31, 2015

 
December 31, 2014

Credit facilities:
 
 
 
 
$700 facility
 
—

 
420

$2,000 facility (NADL)
 
1,200

 
1,367

$400 facility
 
240

 
280

$420 facility
 
—

 
351

$440 facility
 
224

 
258

$450 facility
 
—

 
416

$1,450 facility
 
393

 
433

$360 facility (Asia Offshore Drilling)
 
273

 
309

$300 facility
 
186

 
210

$1,750 facility (Sevan Drilling)
 
1,085

 
1,225

$150 facility
 
—

 
150

$450 Eminence facility
 
344

 
397

$1,500 facility
 
1,344

 
1,469

$1,350 facility
 
1,181

 
1,317

$950 facility
 
688

 
—

$450 facility (2015)
 
215

 
—

Total credit facilities
 
7,373

 
8,602

 
 
 
 
 
Ship Finance Loans
 
 

 
 
$375 facility (SFL Hercules)
 
256

 
284

$390 facility (SFL Deepwater)
 
221

 
303

$475 facility (SFL Linus)
 
354

 
451

Total Ship Finance Loans
 
831

 
1,038

 
 
 
 
 
Unsecured bonds
 
 
 
 
NOK1,800 million bond
 
203

 
242

$350 bond
 
—

 
342

$1,000 bond
 
948

 
1,000

$500 bond
 
479

 
479

NOK1,500 million bond (NADL)
 
161

 
190

$ 600 bond (NADL)
 
413

 
413

SEK 1,500 bond
 
177

 
190

Total unsecured bonds
 
2,381

 
2,856

 
 
 
 
 
Other credit facilities with corresponding restricted cash deposits
 
76

 
124

Total debt principal
 
10,661

 
12,620

 
 
 
 
 
Less: current portion
 
(1,526
)
 
(2,309
)
Long-term portion
 
9,135

 
10,311

 

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As discussed in Note 2, the Company has adopted ASU 2015-03, Interest - Imputation of Interest, (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs as at June 30, 2015. As a result, the consolidated balance sheet as at December 31, 2014 has been represented 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 periods presented are shown below.
 
 
Outstanding balance as at December 31, 2015
(In $ millions)

 
Principal outstanding

Less: Debt Issuance Costs

Total Debt

Current portion of long-term debt
 
1,526

(37
)
1,489

Long-term debt
 
9,135

(81
)
9,054

Total
 
10,661

(118
)
10,543


 
 
Outstanding debt as at December 31, 2014
(In $ millions)
 
Principal outstanding

Less: Debt Issuance Costs

Total Debt

Current portion of long-term debt
 
2,309

(42
)
2,267

Long-term debt
 
10,311

(103
)
10,208

Total
 
12,620

(145
)
12,475



The outstanding debt as of December 31, 2015 is repayable as follows:
(In US$ millions)
 
December 31, 2015

2016
 
1,526

2017
 
2,872

2018
 
2,432

2019
 
2,817

2020
 
1,014

2021 and thereafter
 
—

Total debt principal
 
10,661


Credit facilities

$700 million senior secured term loan
In October 2010, the Company entered into a $700 million senior secured loan facility with a syndicate of banks to partly fund the acquisition of seven jack-up drilling rigs, which were pledged as security. The net book value at December 31, 2015 of the units pledged as security is $1,074 million. The facility bore interest at LIBOR plus 2.50% per annum and was repayable over a term of five years. At maturity a balloon payment of $350 million was due in October 2015. During the year ended December 31, 2015, the facility was repaid in full. The outstanding balance as at December 31, 2015 was nil as the facility is now closed (December 31, 2014: $420 million).

$2,000 million senior secured credit facility 
In April 2011, NADL our majority owned subsidiary, entered into a $2,000 million senior secured credit facility with a syndicate of banks to partly fund the acquisition of six drilling units from Seadrill, which have been pledged as security. The net book value at December 31, 2015 of the units pledged as security is $2,179 million. The facility has a six year term and bears interest at LIBOR plus 2.00% per annum. As of December 31, 2015, the outstanding balance was $1,200 million, as compared to $1,367 million in 2014. At maturity a balloon payment of $950 million is due. As of December 31, 2015, $50 million was undrawn under this facility, which bears a commitment fee of 40% of the margin. NADL is currently restricted from using this undrawn capacity, however, due to restrictive covenants contained within the Company’s loan agreements. The facility contains a loan-to-value clause, which could require NADL, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 135% of the outstanding loan.



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Table of Contents

$400 million senior secured credit facility
In December 2011, the Company entered into a $400 million senior secured credit facility with a syndicate of banks. The jack-up rigs West Cressida, West Callisto, West Leda and West Triton have been pledged as security. The net book value at December 31, 2015 of the units pledged as security is $669 million. The facility has a five year term and bears interest of LIBOR plus 2.50% per annum. As of December 31, 2015, the outstanding balance was $240 million, as compared to $280 million in 2014. At maturity a balloon payment of $200 million is due. During the year we repaid $200 million of the revolving credit tranche, and then drew down $200 million of the revolving credit tranche by year end. We do not have any undrawn capacity on this facility as at December 31, 2015. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 150% of the outstanding loan.

$420 million senior secured credit facility
In December 2012, SFL West Polaris Limited, formerly a consolidated VIE, entered into a $420 million term loan facility with a syndicate of banks to refinance the existing $700 million secured term loan facility. The new facility had a term of five years and bore interest of LIBOR plus a margin of 3.00%. On February 28, 2014 the margin on the facility was reduced from 3.00% to 2.25%. On December 31, 2014, the Company purchased SFL West Polaris Limited from Ship Finance. Please refer to note 35 for more information.
In June 2015, the Company completed the sale of the entities that own and operate the West Polaris to Seadrill Partners. One of the entities sold was the sole borrower under this facility. See Note 11 to the consolidated financial statements, included herein, for further details. As at December 31, 2015, the outstanding balance under the facility relating to Seadrill was nil (December 31, 2014: $351 million). Seadrill Limited continues to act as a guarantor under the facility. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 125% of the outstanding loan.

$440 million secured credit facility
In December 2012, the Company entered into a $440 million secured credit facility with a syndicate of banks to fund the delivery of two tender rigs and two jack-up drilling rigs. As of December 31, 2015 we have drawn $320 million on the facility and the T-15, T-16, and West Telesto have been pledged as security, while the tranche for the West Oberon was cancelled due to other funding opportunities for this rig. The tender rigs T-15 and T-16 were sold to Seadrill Partners during 2013, and subsequently the Company entered into a back to back rig financing agreements with Seadrill Partners for the corresponding portions of the secured credit facility for $101 million and $98 million respectively. Under the terms of the secured credit facility agreements for the T-15 and T-16, certain subsidiaries of the Company and Seadrill Partners 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 party to such agreements. These obligations are continuing and extend to amounts payable by any borrower under the relevant agreement. See Note 31 for further details on related party transactions. The total net book values as at December 31, 2015 of all the units pledged as security was $453.5 million. The total net book value of the T-15 and T-16, which the Company no longer owns, was $252 million as at December 31, 2015. The facility bears interest at LIBOR plus 3.25% per annum and is repayable over a term of 5 years. The outstanding balance as at December 31, 2015 was $224 million, as compared with $258 million in 2014. At maturity a balloon payment of $173 million is due. We do not have any undrawn capacity on this facility as of December 31, 2015. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 135% of the outstanding loan.

$450 million senior secured credit facility
In December 2012, we entered into a $450 million senior secured credit facility with a syndicate of banks, and was drawn down on January 3, 2013. The West Eclipse semi-submersible rig was pledged as security, which has a net book value of $635 million as at December 31, 2015. The facility was scheduled to mature within one year and bore interest of LIBOR plus 3.00%. On December 20, 2013, we amended this facility for an additional one year, with an amended interest rate of LIBOR plus 2.00%. On December 19, 2014, we amended this facility with a new maturity date of February 3, 2015 on the same terms. In January 2015, this facility has been repaid in full and replaced with the new $950 million facility (which is detailed below). Therefore as of December 31, 2015, the outstanding balance was nil as compared to $416 million as at December 31, 2014. We do not have any undrawn capacity on this facility as of December 31, 2015.

$1,450 million senior secured credit facility
In March 2013, we entered into a $1,450 million senior secured credit facility with a syndicate of banks and export credit agencies. The West Auriga, West Vela, and West Tellus were pledged as security. The facility has a final maturity in 2025, with the exception of a commercial tranche of $203 million due for renewal in 2018, and bears an interest of LIBOR plus a margin in the range of 1.20% to 3.00%.
In March 2014, we completed the sale of the entities that own and operate the West Auriga to Seadrill Partners of which one of the entities sold, was a borrower and a guarantor under this facility, and accordingly we have derecognized the portion of this facility relating to the West Auriga. Seadrill Partners subsequently repaid the tranches relating to the West Auriga in full. In November 2014, we completed the sale of the entities that own and operate the West Vela to Seadrill Partners, of which one of the entities sold was a borrower and a guarantor under this facility, and accordingly we have derecognized the portion of this facility relating to the West Vela. See note 11 for further details of these disposals to Seadrill Partners.
Under the terms of the $1,450 million secured credit facility agreement, certain subsidiaries of Seadrill and Seadrill Partners 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

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parties under this facility as of December 31, 2015 is $776 million (compared to $856 million as at December 31, 2014) of which $393 million ($433 million as at December 31, 2014) relates to Seadrill and the West Tellus. Seadrill has not recognized any amounts that are related to amounts owed under the facility by other borrowers. Seadrill has provided an indemnity to Seadrill Partners for any payments or obligations related to this facility that are not related to the West Auriga or West Vela.
If a balloon payment of $86 million relating to the commercial tranches of the West Vela and West Tellus do not get refinanced to the satisfaction of the remaining lenders after five years, the remaining tranches also become due after five years.
As at December 31, 2015 the net book value of the West Tellus was $622 million. We do not have any undrawn capacity on this facility as of December 31, 2015. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 125% of the outstanding loan.

$360 million senior secured credit facility
In April 2013, our majority owned subsidiary AOD entered into a $360 million senior secured credit facility with a syndicate of banks. The facility is available in three equal tranches of $120 million, with each tranche relating to AOD 1, AOD 2 and AOD 3, which have been pledged as security. The loan has a five year maturity from the initial borrowing date, and bears interest of LIBOR plus 2.75%. As at December 31, 2015 the rigs have a net book value of $225 million, $216 million and $223 million respectively. We do not have any undrawn capacity on this facility as of December 31, 2015. As at December 31, 2015 the outstanding balance was $273 million as compared to $309 million as at December 31, 2014. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 120% of the outstanding loan.

$300 million senior secured credit facility
In July 2013, we entered into a $300 million senior secured credit facility with a syndicate of banks and export credit agencies. The West Tucana and West Castor were pledged as security. The facility bears interest of LIBOR plus a margin of 3.00%, and matures in 2023, however the facility may be come payable in full in 2018 if the commercial guarantee which expires after 5 years is not renewed. As at December 31, 2015 the net book values of the West Tucana and West Castor were $196 million and $204 million respectively. We do not have any undrawn capacity on this facility as of December 31, 2015. As at December 31, 2015 the outstanding balance was $186 million as compared to $210 million as at December 31, 2014. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 135% of the outstanding loan.

$150 million senior secured credit facility
In October 2013, we entered into a $150 million secured credit facility with a bank. The West Oberon and the West Prospero were pledged as security, bears interest of LIBOR plus a margin of 0.75%, with a maturity date in June 2014. The loan was subsequently amended with a new maturity date of March 31, 2015 and revised margin of 1.0%. On March 26, 2015, this facility was repaid in full as part of the SeaMex transaction. Please refer to Note 11 to the consolidated financial statements, included herein. Therefore as at December 31, 2015 and outstanding balance was nil, compared to $150 million as at December 31, 2014.

$450 million senior secured credit facility (2013)
In December 2013, we entered into a $450 million senior secured facility with a syndicate of banks. The West Eminence has been pledged as security, and bears interest of LIBOR plus a margin of 1.75% and matures in June 2016. As at December 31, 2015 the net book value of the West Eminence was $563 million. As at December 31, 2015, the outstanding balance was $344 million as compared to $397 million as at December 31, 2014. We do not have any undrawn capacity on this facility as of December 31, 2015. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 130% of the outstanding loan.

$1,350 million senior secured credit facility
In August 2014, the Company entered into a $1,350 million senior secured credit facility with a syndicate of banks. The facility consists of a term loan facility for $675 million and a revolving credit facility in an amount up to $675 million. The West Pegasus, West Gemini and West Orion were pledged as security. The total net book value at December 31, 2015 of the units pledged as security is $1,767 million. The facility bears interest at LIBOR plus a margin of 2% per annum, and is repayable in quarterly installments over a term of five years. The revolver is fully repayable at the final maturity date. The revolver facility was fully drawn and we do not have any undrawn capacity as of December 31, 2015. As at December 31, 2015, the outstanding balance was $1,181 million as compared to $1,317 million as at December 31, 2014. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 120% of the outstanding loan.


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$1,500 million senior secured credit facility (2014)
In July 2014, the Company entered into a $1,500 million senior secured credit facility with a syndicate of banks to finance the three newbuilds, the West Saturn, West Neptune and West Jupiter which are pledged as security. The net book value at December 31, 2015 of the units pledged as security is $1,899 million. The facility bears interest at LIBOR plus a margin of between 1.4% and 2.5% per annum, and is repayable over a term of 12 years. The loan includes a Commercial Interest Reference Rate (CIRR) tranche with Eksportkreditt Norge ASA, the Norwegian export credit agency, that bears fixed interest at 2.38% per annum. If the commercial tranche of $300 million, which has a balloon payment of $175 million, does not get refinanced to the satisfaction of the remaining lenders after five years, the remaining tranches also become due after five years. We do not have any undrawn capacity on this facility as of December 31, 2015. As at December 31, 2015, the outstanding balance was $1,344 million as compared to $1,469 million as at December 31, 2014. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below an average of 122% of the outstanding loan.

$1,750 million secured credit facility
In September 2013 subsidiaries of Sevan Drilling entered into a $1,750 million bank facility with a syndicate of banks and export credit agencies. The facility consists of two tranches in the amounts of $1,400 million and $350 million. On October 23, 2013 the first tranche of $1,400 million was drawn and was used to repay the existing credit facilities related to Sevan Driller and Sevan Brasil and to settle the remaining installment and other amounts for the delivery of Sevan Louisiana. The Sevan Driller, Sevan Brasil and Sevan Louisiana have been pledged as security. In December 2014 the $350 million tranche relating to the Sevan Developer was cancelled at our request as a consequence of the deferral agreement made with Cosco, and the borrowing entity relating to the Sevan Developer was released from its obligations under this facility. The facility has a maturity in September 2018 and bears interest of LIBOR plus a margin of 2.90%. As at December 31, 2015 the net book values of the Sevan Driller, Sevan Brasil and Sevan Louisiana were $575 million, $584 million and $704 million respectively. We do not have any undrawn capacity on this facility as of December 31, 2015. As at December 31, 2015, the outstanding balance was $1,085 million as compared to $1,225 million as at December 31, 2014. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 110% of the outstanding loan.

$950 million senior secured credit facility
In January 2015 the Company entered into a $950 million senior secured credit facility with a syndicate of banks and export credit agencies to fund the delivery of the West Carina and to refinance the Company’s indebtedness related to the West Eclipse. The facility comprises of a $60 million term loan, a $250 million revolving facility and a $190 million ECA facility for the West Carina; and a $225 million term loan and a $225 million revolving facility for the West Eclipse. The term loans and revolving credit facilities bear interest at LIBOR plus 2.00% and the ECA facility has a CIRR fixed interest rate of 2.12%. The Company has entered in to a floating swap agreement to counter this fixed payment, meaning the Company pays floating on this tranche. The West Carina term loan and revolving credit facility have a 5 year maturity and a 12 year profile, with a balloon payment of $187 million in year 5. The West Carina ECA facility has a 12 year maturity and a 12 year profile. The West Eclipse term loan has a 5 year maturity and a 5 year profile. The West Eclipse revolving credit facility has a maturity of 5 years and is non-amortizing, with a balloon payment of $225 million in year 5. If the commercial facilities are not refinanced satisfactorily after 5 years then the ECA facility also becomes due. During the year ended December 31, 2015 we repaid $207 million of the revolving credit facility. The total outstanding balance as at December 31, 2015 was $688 million (December 31, 2014: nil). As of December 31, 2015, $197 million was undrawn under this facility, which bears a commitment fee of 40% of the margin. The Company is currently restricted from using this undrawn capacity, however, due to restrictive covenants contained within the Company’s loan agreements. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 120% of the outstanding loan.

$450 million senior secured credit facility (2015)
In August 2015 the Company entered into a $450 million senior secured credit facility with a syndicate of banks and repaid the remaining balance of $21 million on the $700 million senior secured credit facility. The West Freedom, West Mischief, West Vigilant, West Resolute, West Prospero, and the West Ariel were pledged as security. The net book value of the rigs pledged as security as at December 31, 2015 is $888 million. The loan bears interest at a rate of LIBOR plus 2.5%. The loan has a 5 year maturity and an 8.5 years profile with a balloon payment at the end of year 5. The total outstanding balance as at December 31, 2015 was $215 million (December 31, 2014: nil). As of December 31, 2015, $215 million was undrawn under this facility, which bears a commitment fee of 40% of the margin. The Company is currently restricted from using this undrawn capacity, however, due to restrictive covenants within the Company’s loan agreements. The facility contains a loan-to-value clause, which could require the Company, to post additional collateral or prepay a portion of the outstanding borrowings should the market value of the drilling units fall below 150% of the outstanding loan.

Ship Finance International Limited (“Ship Finance”) Loans
The following loans relate to the Ship Finance International entities that we consolidate in our financial statements as Variable Interest Entities (VIEs). Refer to Note 35 for more information.


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SFL Hercules Ltd
In May 2013, SFL Hercules Ltd entered into a $375 million facility, with a syndicate of banks and financial institutions. The facility is secured by the West Hercules, which has a net book value of $571 million as of December 31, 2015. The new facility has a term of six years and bears interest of LIBOR plus a margin of 2.75%. As at December 31, 2015, the outstanding balance under the facility was $256 million, compared to $284 million as at December 31, 2014. SFL Hercules Ltd has no undrawn capacity on this facility at December 31, 2015.

SFL Deepwater Ltd
In October 2013, SFL Deepwater Ltd entered into a $390 million facility with a syndicate of banks and financial institutions. The facility is secured by the West Taurus, which has a net book value of $434 million as at December 31, 2015. The new facility has a term of five years and bears interest of LIBOR plus a margin of 2.50%. As at December 31, 2015, the outstanding balance under the facility was $221 million compared to $303 million as at December 31, 2014. SFL Deepwater Ltd has no undrawn capacity on this facility as at December 31, 2015.

SFL Linus Ltd
On October 17, 2013, SFL Linus Ltd entered into a $475 million secured term loan and revolving credit facility with a syndicate of banks to fund the acquisition of West Linus, which has been pledged as security and has a net book value of $559 million as at December 31, 2015. The facility was fully drawn on February 18, 2014, on the date of delivery of West Linus. The facility bears interest of LIBOR plus 2.75% and matures in June 2019. As at December 31, 2015, the outstanding balance under the facility was $354 million, compared to $451 million as at December 31, 2014. SFL Linus has no undrawn capacity on this facility at December 31, 2015.

Unsecured Bonds
$350 million fixed interest rate bond
In October 2010, the Company raised $350 million through the issue of a five year bond which matures in October 2015. The bond had a fixed interest rate of 6.50% per annum, which was payable semi-annually in arrears. In May 2012, we repurchased $8 million of the bonds. As at December 31, 2014, the outstanding balance was $342 million.  In October 2015, the $350 million bond was settled on maturity.

$650 million 3.375% Convertible Bonds and conversion
In October 2010, the Company issued at par $650 million of convertible bonds. Interest on the bonds was fixed at 3.375%, payable semi-annually in arrears. The bonds were convertible into the Company’s common shares at any time up to 10 banking days prior to October 27, 2017. The conversion price at the time of issuance was $38.92 per share, representing a 30% premium to the share price at the time. For accounting purposes $121 million was, at the time of issuance of the bonds, allocated to the bond equity component and $529 million to the bond liability component, due to the cash settlement option stipulated in the bond agreement. The bonds were due to mature in October 2017. The bond equity component was amortized over the maturity term, and recognized within interest expense in the consolidated statement of operations.
In July 2014, the Company launched a voluntary incentive payment offer to convert any and all of the $650 million principal amount of 3.375% convertible bonds. Holders of $649 million of principal amount of convertible bonds accepted the voluntary incentive offer and the Company then elected to exercise the “90% clean-up call” provision on the remaining $1 million outstanding.
Holders converted at the contractual conversion price of $27.69 per share and received an incentive payment of $12,102.95 per $100,000 principal amount of bond held. As a result of the transaction, the number of common shares outstanding in the Company increased by 23.8 million shares, with an increase to equity of $893 million.
As a result of the conversion the Company recorded a charge of $79 million related to the incentive paid for the induced conversion and a loss on debt extinguishment of $16 million. These amounts were recognized within net loss on debt extinguishment in the Company’s consolidated statement of operations. $278 million of the total consideration transferred on conversion was allocated to the reacquisition of the embedded conversion option and recognized as a reduction of stockholders’ equity. The total cash outflow due to the incentive payments and accrued interest was $69 million.

$1,000 million fixed interest bond
In September 2012, the Company raised $1,000 million through the issue of a 5 year bond which matures in September 2017. Interest on the bonds bears a fixed interest rate of 5.625% per annum, payable semi-annually in arrears. The interest rate increased to 6.125% in March 2014 as the Company remained unrated.
During the year ended December 31, 2015, the Company repurchased $52 million (par value) of the $1,000 million senior unsecured bond, recognizing a gain on debt extinguishment of $8 million in the Company’s consolidated statement of operations.

NOK 1,800 million floating interest rate bonds
In March 2013 the Company issued a NOK1,800 million senior unsecured bond with maturity in March 2018. The bond bears interest of NIBOR plus a margin of 3.75% per annum, payable quarterly in arrears. The bond was subsequently swapped to US$ with a fixed rate of 4.94% per annum until maturity using a cross currency interest rate swap.


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$500 million senior unsecured bond
On September 20, 2013, the Company issued a $500 million senior unsecured bond issue. The bond matures in September 2020 and bears interest of 6.125% per annum, payable semi-annually in arrears. The interest rate increased to 6.625% in March 2014 as the Company remained unrated.
In December 2014 the Company repurchased $21 million (of par value) of the $500 million senior unsecured bond, recognizing a gain on debt extinguishment of $3 million.

NOK1,500 million floating interest rate bonds
In October 2013, NADL, our majority owned subsidiary, issued a NOK1,500 million senior unsecured bond issue with maturity in October 2018, and an interest rate of NIBOR plus a margin of 4.40% per annum. The bond was subsequently swapped to US$ with a fixed rate of 6.18% per annum until maturity using a cross currency interest rate swap.
In December 2014, the Company purchased NOK82 million (of par value) of the NOK1,500 million senior unsecured bond issued by NADL, recognizing a gain on debt extinguishment of $4 million.

$600 million senior unsecured bond
In January 2014, NADL, our majority owned subsidiary, issued a $600 million senior unsecured bond issue. The bond matures in January 2019 and bears interest of 6.25% per annum. In conjunction with the issue and subsequently in the open market we bought 27.5% of the bond, which amounted to $165 million. During June 2014, we sold a portion of the bond owned by the Company for $25 million. In December 2014 the Company purchased $47 million (of par value) of the $600 million senior unsecured bond issued by NADL, recognizing a gain on debt extinguishment of $16 million. As of December 31, 2015 we held 31.1% of the bond, which amounted to $187 million.

SEK1,500 million senior unsecured bond
In March 2014, we issued a SEK1,500 million senior unsecured bond. The bond matures in March 2019 and bears interest of STIBOR plus 3.25%. The bond was subsequently swapped to US$ with a fixed rate of 5.2% per annum until maturity using a cross currency interest rate swap. 

Unsecured bond repurchases
During the year ended December 31, 2015, the Company recognized a total gains on debt extinguishment due to the repurchases of bonds of $8 million (2014: total gains on bond repurchases of $23 million), which are presented within “Net loss on debt extinguishment” in the Company’s consolidated statement of operations.

Commercial Interest Reference Rate (CIRR) Credit Facilities
In April 2008, the Company entered into a CIRR term loan for NOK850 million with Eksportfinans ASA, the Norwegian export credit agency. The loan bears fixed interest at 4.56% per annum and is repayable over a term of eight years. The outstanding balance at December 31, 2015 was $11 million (NOK100 million) compared to $27 million at December 31, 2014.
In June 2008, the Company entered into a CIRR term loan for NOK904 million with Eksportfinans ASA. The loan bears fixed interest at 4.15% per annum and is repayable over a term of eight years. The outstanding balance at December 31, 2015 was $12 million (NOK106 million) compared to $29 million at December 31, 2014.
In July 2008, the Company entered into a CIRR term loan for NOK1,011 million with Eksportfinans ASA. The loan bears fixed interest at 4.15% per annum and is repayable over a term of 12 years. The outstanding balance at December 31, 2015 was $53 million (NOK421 million) compared to $68 million at December 31, 2014.
In connection with the above three CIRR fixed interest term loans totaling $76 million (NOK627 million), fixed interest cash deposits equal to the total outstanding loan balances have been established with commercial banks. The collateral cash deposits are reduced in parallel with repayments of the CIRR loans and receive fixed interest at the same rates as those paid on the CIRR loans. The collateral cash deposits are classified as “restricted cash” in the consolidated balance sheet, and the effect of these arrangements is that the CIRR loans have no effect on net interest bearing debt.


Covenants contained in our debt facilities
Our debt agreements generally contain financial covenants as well as security provided to lenders in the form of pledged assets.

Bank Loans
In addition to security provided to lenders in the form of pledged assets, our bank loan agreements generally contain financial covenants, including:
•
Aggregated minimum liquidity requirement for the 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.

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•
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 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. This was amended in May 2015, which has been discussed further below. Net debt is calculated as all interest bearing debt less cash and cash equivalents excluding minimum liquidity requirements.
•
Debt service coverage ratio: The $1,450 million senior secured credit facility for the combined borrowers, and the $1,500 million senior secured credit facility for the individual borrowers, contain a requirement to maintain a ratio of EBITDA of the respective borrower to debt services (being all finance charges and principal) of not less than 1.15:1.

May 2015 Amendments to Senior Secured Credit Facilities
In May 2015, the Company executed an amendment to the covenants contained in all of its senior secured credit facilities. 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 senior secured credit facilities as follows:
•
.125% per annum if the leverage ratio is 4.50:1 up to and including 4.99:1;
•
.25% per annum if the leverage ratio is 5.00:1 up to and including 5.49:1;
•
.75% per annum if the leverage ratio is 5.50:1 up to and including 6.00:1

In addition, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities in May 2015, the Company is restricted from making dividend distributions, and repurchasing its own shares during the amendment period until January 1 2017.

April 2016 Amendments to Senior Secured Credit Facilities
On April 28, 2016, the Company executed amendment and waiver agreements in respect of all of its senior secured credit facilities. The Company also executed maturity extension agreements in respect of three senior secured credit facilities maturing in the near term. The key terms and conditions of these agreements are as follows:

•
Extensions:
◦
$450 million Senior Secured Credit Facility: The maturity of the $450 million senior secured credit facility, relating to the Eminence rig, has been extended from June 20, 2016 to December 31, 2016. In addition, the margin has been reset to 250 basis points.
◦
$400 million Senior Secured Credit Facility: The maturity of the $400 million senior secured credit facility, relating to jack-up rigs West Cressida, West Callisto, West Leda and West Triton, has been extended from December 8, 2016 to May 31, 2017.
◦
$2 billion Senior Secured Credit Facility: The maturity of the $2 billion senior secured credit facility of our majority-owned subsidiary NADL has been extended from April 15, 2017 to June 30, 2017.

•
Key amendments and waivers:
◦
Equity ratio: The Company 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: The Company 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: The Company’s secured bank credit facilities contain loan-to-value clauses, or minimum-value-clauses (“MVC”), which could require the Company to post additional collateral or prepay a portion of the outstanding

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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: The Company 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: The Company has agreed to consultation, information provision and certain processes in respect of further discussions with its lenders under its senior secured credit facilities.
◦
Restrictive undertakings: The Company has agreed to additional near-term restrictive undertakings applicable during this process, including (without limitation) limitations in respect of:
▪
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: The Company has agreed to refrain from borrowing any undrawn commitments under its senior secured credit facilities.
◦
Fees: The Company has agreed to pay certain fees to its lenders in consideration of these extensions and amendments.

These extensions and amendments are designed to provide the Company and the banking group with a period of stability and certainty while a more comprehensive financing package is agreed. The Company intends to further communicate these financing plans this year.


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. We are in compliance with related covenants as of December 31, 2015.

The credit facility 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 credit facility;
•
cancellation or termination of any existing charter contract or satisfactory drilling contract; and
•
a change of control.

The credit facility agreements contain customary events of default, such as failure to repay principal and interest, and other events of defaults, such as:

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•
failure to comply with the financial or insurance covenants;
•
cross-default to other indebtedness held by both Seadrill Partners and its subsidiaries and by the Company;
•
failure 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 the Company 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 the Company or any subsidiary thereof to conduct its business, which has or reasonably may be expected to have a material adverse effect.

Our secured credit facilities are 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 loan and other debt 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. In addition, the loan and other debt agreements include certain financial covenants including the requirement to maintain a certain level of free cash and failure to comply with any of the covenants in the loan agreements could result in a default under those agreements and under other agreements containing cross-default provisions. We were in compliance with all financial loan covenants as of December 31, 2015.

In addition to financial covenants, our credit facility agreements 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.

Bonds
For the Company’s outstanding Norwegian and Swedish bonds, the main financial covenant is to maintain a total equity to total assets ratio of at least 30.0%. Both equity and total assets are adjusted for the difference between book value and market values of drilling units.
For the Company’s outstanding $1,000 million, $500 million, and $600 million bonds, we are subject to certain financial and restrictive covenants contained in our indentures which restrict, among other things, our ability to pay dividends, incur indebtedness, incur liens, and make certain investments. In addition, these indentures contain other customary terms, including certain events of default, upon the occurrence of which, the bonds may be declared immediately due and payable.

In addition to the above, our bond indentures generally also contain restrictions which are customary for unsecured financings in this industry for similar unrated bonds, including limitations on indebtedness, payments, transactions with affiliates and restrictions on consolidation, merger and sale of assets.

We are in compliance with related covenants as of December 31, 2015.

Covenants contained within our consolidated Ship Finance Variable Interest Entities
The Company consolidates certain Ship Finance entities into the financial statements as variable interest entities. While we are not, directly or indirectly, obligated to repay the borrowings under this facility, a breach of one or more of the covenants contained in this credit facility may have a material adverse effect on us. Seadrill Limited is the Charter Guarantor under these facilities. The main financial covenants contained in the variable interest entities are as follows:
•
Ship Finance must maintain cash and cash equivalents of at least $25 million.
•
Ship Finance must maintain positive working capital.
•
Ship Finance must have a ratio of total liabilities to total assets of at least 0.8 to 1.0 at the end of each quarter.
•
The Company’s covenants under the bank loans listed above also apply.


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The Ship Finance subsidiaries owning West Taurus, West Hercules and West Linus are consolidated into our financial statements as a variable interest entity (“VIEs”).  To the extent that these VIEs defaults under its indebtedness and is marked current in its financial statements, we would in turn, mark such indebtedness current in our consolidated financial statements.  The characterization of the indebtedness in our financial statements as current may adversely impact our compliance with the covenants contained in our existing and future debt agreements. In the event of a default by us under one of our debt agreements, the lenders under our existing debt agreements could determine that we are in default under our other 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 our drilling rigs, even if we were to subsequently cure such default. We and Ship Finance are in compliance with related covenants as of December 31, 2015.

Covenants contained in North Atlantic Drilling Limited (“NADL”)
In February 2015, NADL received approval from its Norwegian Bondholders to amend the Bond Agreement for its NOK1.5 billion Norwegian Bond maturing in 2018. Under the terms of the agreement, Seadrill will provide a guarantee for the Bond Issue in exchange for amendments to the covenant package, principally replacing the current financial covenants with the financial covenants within Seadrill’s NOK bonds. Additionally, NADL received approval to amend its US$2 billion credit facility and US$475 million term loan and revolving credit facility. Under the terms of the agreements, Seadrill will provide a guarantee for the credit facility in exchange for amendments to the covenant package, principally replacing the existing financial covenants with financial covenants within Seadrill’s secured credit facilities. This amendment to the covenants is effective from December 31, 2014. As such there are no longer separate financial covenants contained within NADL’s credit facilities or bond agreements.

Seadrill Partners covenants
As detailed above certain subsidiaries of Seadrill Partners are borrowers and guarantors to the $440 million secured credit facility, the $1,450 million senior secured credit facility, and the $420 million senior secured credit facility. If Seadrill Partners were to default under one of its other financing agreements, it could cause an event of default under these credit facilities. Seadrill Partners’ 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 Partners are in compliance with all applicable covenants as of December 31, 2015.


Note 24 – Other current liabilities
 
Other current liabilities are comprised of the following:
 
 
(In US$ millions)
December 31, 2015

 
December 31, 2014

Taxes payable
168

 
160

Employee withheld taxes, social security and vacation payment
87

 
122

Intangible liabilities - unfavorable contracts (1)
65

 
116

Accrued interest expense
70

 
77

Liabilities relating to investment in shares (2)
—

 
167

Deferred mobilization revenue
208

 
178

Derivative financial instruments (3)
424

 
372

Accrued expenses
173

 
292

Construction obligation (4)
460

 
428

Other current liabilities
29

 
22

Total other current liabilities
1,684

 
1,934


(1) Intangible liabilities represent the estimated fair values of acquired unfavorable drilling contracts. See Notes 12 and 21 to the consolidated financial statements included herein.
(2) Liabilities relating to investment in shares primarily represents amounts owed in respect of the Company’s share forward purchase contracts for Sevan Drilling. See Note 12 to the consolidated financial statements included herein.
(3) Derivative financial instruments consist of unrealized losses on various types of derivatives.
(4) The construction obligation has been recognized upon the acquisition of Sevan Drilling. See Note 12 to the consolidated financial statements included herein.



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Note 25 – Other non-current liabilities
 
Other non-current liabilities are comprised of the following:
(In US$ millions)
December 31, 2015

 
December 31, 2014

Accrued pension liabilities
37

 
84

Deferred mobilization revenues
128

 
224

Intangible liabilities - unfavorable contracts (1)
66

 
131

Financing secured on SapuraKencana shares (Note 32)
160

 
250

Other non-current liabilities
10

 
10

Total other non-current liabilities
401

 
699

 
(1) Intangible liabilities represent the estimated fair values of acquired unfavorable drilling contracts. See Note 12 and 21 to the consolidated financial statements included herein.

Note 26 – Common shares

 
2015
 
2014
 
2013
All shares are common shares of $2.00 par value each
Shares

 
$millions

 
Shares

 
$millions

 
Shares

 
$millions

Authorized share capital
800,000,000

 
1,600

 
800,000,000

 
1,600

 
800,000,000

 
1,600

 
 
 
 
 
 
 
 
 
 
 
 
Issued and fully paid share capital
493,078,680

 
986

 
493,078,678

 
986

 
469,250,933

 
939

Treasury shares held by Company
(318,740
)
 
(1
)
 
(318,740
)
 
(1
)
 
(272,441
)
 
(1
)
Outstanding shares in issue
492,759,940

 
985

 
492,759,938

 
985

 
468,978,492

 
938

 
As of December 31, 2015, the Company’s shares were listed on the Oslo Stock Exchange and the New York Stock Exchange.
 
The Company was incorporated on May 10, 2005 and 6,000 ordinary shares of par value $2.00 each were issued. Since incorporation the number of issued shares has increased from 6,000 to 493,078,680 of par value $2.00 each as of December 31, 2015. There were no new shares issued in 2015 or 2014 other than the conversion of convertible bonds in 2014, which resulted in 23.8 million shares issued, as discussed in Note 23.

A share repurchase program was approved by the Board in 2007 giving the Company the authorization to buy back shares. Shares bought back under the authorization may be cancelled or held as treasury shares. Treasury shares may be held to meet the Company’s obligations relating to the share option plans. As at December 31, 2015 the Company held 318,740 treasury shares and net shares outstanding at December 31, 2015 was 492,759,940.
 
In November 2014 the Board authorized a share buyback program under which the Company may repurchase up to approximately 10% of shares outstanding. The Company may repurchase shares from time to time in open market transactions or private transactions in accordance with applicable securities laws. The timing and amount of any repurchases will be determined by Management of the Company based on its evaluation of market conditions, capital allocation opportunities, and other factors. The program does not require the Company to repurchase any specific number of shares and may be modified, suspended, extended or terminated by the Company at any time without prior notice. In May 2015, however, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from buying back any shares during the amendment period until January 1 2017. In addition, in April 2016, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from making dividend distributions during the amendment period until June 30, 2017.

Note 27 – Non-controlling interest
 
The Company’s consolidated statement of operations, balance sheet and statement of cash flows include the results of NADL, Asia Offshore Drilling Ltd, and Sevan Drilling ASA for the year ended, and as at December 31, 2015. As at December 31, 2015, the Company has the following ownership interests in these companies: 70.36% of NADL, 66.24% of Asia Offshore Drilling Ltd, and 50.11% of Sevan Drilling ASA. The amount of shareholders’ equity not attributable to the Company is included in non-controlling interests.

NADL

In January 2014, NADL completed its IPO in the United States of 13,513,514 common shares at $9.25 per share. The non-controlling interest recognized on the IPO was $52 million. Following NADL’s 1 for 10 reverse stock split as at December 31, 2015, there were no changes in the percentage of NADL owned by the non-controlling interest.

Seadrill Partners

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On October 24, 2012, Seadrill Partners completed its IPO of 10,062,500 common units representing limited liability company interests in Seadrill Partners at a price of $22.00 per unit, for gross proceeds of $221 million and net proceeds after issuance costs of $203 million (including 1,312,500 common units issued in connection with the exercise of the over-allotment option). Seadrill Partners is listed on the New York stock exchange under the symbol “SDLP.” Upon completion of the offering, the Company owned 14,752,525 common units and 16,543,350 subordinated units which represents 75.67% of the limited liability company interests in Seadrill Partners. Subsequent to the IPO, in October 2013, Seadrill Partners issued 3,310,622 common units to the Company, which increased the Company’s total ownership interest to 77.47%. In December 2013, Seadrill Partners issued a further 3,394,916 common units to the Company and 12,880,000 common units to the public, which had the effect of reducing the Company’s ownership total ownership to 62.35% as of December 31, 2014. The effect of these transactions was to increase the non-controlling interest by $239 million.

During the period from Seadrill Partners’ IPO in October 2012 until the time of its first effective Annual General Meeting (“AGM”) on January 2, 2014, the Company retained the sole power to appoint, remove and replace all members of Seadrill Partner’s board of directors. From the first AGM, the majority of the board members became electable by the common unitholders and accordingly, from this date the Company no longer retained the power to control the board of directors as a result of certain provisions in the Operating Agreement which limits the Company’s ability to vote its full holding of common units in an election of directors to the board of Seadrill Partners. As of January 2, 2014, Seadrill Partners is considered to be an associated company and not a controlled subsidiary of the Company, and as such Seadrill Partners was deconsolidated by the Company. The non-controlling interest derecognized was $115 million. See Note 11 of the consolidated financial statements for further details.
AOD
On March 25, 2013, we obtained control of the Board of Asia Offshore Drilling Ltd and owned 66.18% of the outstanding shares. As a result of obtaining control we have consolidated the results and financial position of Asia Offshore Drilling Ltd from this date. The fair value of the non-controlling interest established upon obtaining a controlling financial interest was $100 million. See Note 12 to the consolidated financial statements included herein for further details. Subsequent to the date of consolidation, the Company’s percentage ownership increased to 66.21%, and then increased again to 66.24%.

Sevan

On July 2, 2013 we obtained a controlling financial interest in Sevan Drilling and had ownership interests in 50.1% of the outstanding shares. As a result of obtaining control we consolidated the results and financial position of Sevan Drilling from this date. The fair value non-controlling interest established upon obtaining a controlling financial interest was $197 million. See Note 12 to the consolidated financial statements included herein for further details.

Ship Finance VIEs

In 2007 and 2008 the Company entered into sale and leaseback arrangements for drilling units with Ship Finance International Ltd, who incorporated subsidiary companies for the sole purpose of owning and leasing the drilling units. The Company has recognized these subsidiary companies as VIEs and concluded that the Company is their primary beneficiary. Accordingly, these subsidiary companies are included in the Company’s consolidated financial statements, with the Ship Finance International Ltd equity in these companies included in non-controlling interest. In 2012, the Company acquired all the shares in one of these Ship Finance International Ltd companies, Rig Finance II Ltd for $47 million. As a consequence of this, Rig Finance II Ltd is no longer treated as a VIE but a wholly owned subsidiary. In 2013 these VIEs declared dividends of $223 million to Ship Finance International Limited. In December 2014, the Company acquired all the shares of the Ship Finance International Ltd company, SFL Polaris Ltd, for a consideration of $111 million. The non-controlling interest derecognized was $7 million. As a consequence of this, SFL Polaris Ltd is no longer treated as a VIE but a wholly owned subsidiary. See Note 35 to the consolidated financial statements included herein for further details.


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Changes in non-controlling interest in 2015, 2014 and 2013 are as follows:
(In US$ millions)
 
Ship Finance International Ltd VIEs
 
North Atlantic Drilling Ltd
 
Seadrill Partners LLC
 
Asia Offshore Drilling Ltd
 
Sevan Drilling ASA
 
Seadrill Offshore Nigeria Limited and Seadrill Nigeria Operations Limited
 
Total
December 31, 2012
 
274

 
168

 
79

 
—

 
—

 


 
521

Changes in 2013
 
(220
)
 
(56
)
 
15

 
100

 
197

 


 
36

Net income attributable to non-controlling interest in 2013
 
24

 
61

 
21

 
11

 
16

 


 
133

December 31, 2013
 
78

 
173

 
115

 
111

 
213

 
—

 
690

Changes in 2014
 
(57
)
 
(4
)
 
(115
)
 
—

 
—

 
4

 
(172
)
Net income attributable to non-controlling interest in 2014
 
11

 
36

 
—

 
23

 
38

 
—

 
108

December 31, 2014
 
32

 
205

 
—

 
134

 
251

 
4

 
626

Changes in 2015
 
—

 
8

 
—

 
(14
)
 
—

 
(4
)
 
(10
)
Net income attributable to non-controlling interest in 2015
 
(17
)
 
(46
)
 
—

 
20

 
31

 
—

 
(12
)
December 31, 2015
 
15

 
167

 
—

 
140

 
282

 
—

 
604



Note 28 – Accumulated other comprehensive income

Accumulated other comprehensive income for the years December 31, 2015 and December 31, 2014:

(In US$ millions)
December 31,
2015

 
December 31,
2014

Unrealized (loss)/gain on marketable securities
(129
)
 
(443
)
Unrealized gain on foreign exchange
36

 
51

Actuarial loss relating to pension
(38
)
 
(57
)
Share in unrealized gains from associated companies
11

 
1

Accumulated other comprehensive (loss)/income
(120
)
 
(448
)
 
The unrealized loss on marketable securities relates to the accumulated losses on the investments in SapuraKencana and Seadrill Partners Common units. Refer to Note 14 - Marketable securities for further information.

The applicable amount of income taxes associated with each component of other comprehensive income is nil, other than noted below, due to the fact that the items relate to companies domiciled in non-taxable jurisdictions. However, for actuarial loss related to pension, the accumulated applicable amount of income taxes is $8 million ($22 million in 2014) as this item is related to companies domiciled in Norway where the tax rate is 25% (2014: 27%).


Note 29 – Share based compensation
 
The fair value of share based compensation is recognized as personnel compensation expense, and in the year ended December 31, 2015, $8 million (2014: $10 million, 2013: $7 million) was included in the consolidated statement of operations.
 
Share Options

Our shareholders have authorized the Board to establish and maintain Option Schemes in order to encourage our directors, officers and other employees to hold shares in the Company. The Option Scheme for US employees will expire in December 2018, whereas the Option Scheme for international employees will expire in December 2016. The Option Schemes permit the Board, at its discretion, to grant options to acquire shares in the Company to employees and directors of the Company or its subsidiaries.  The options are not transferable. The subscription price is at the discretion of the Board, provided the subscription price is never reduced below the par value of the share. The subscription price for certain options granted under the Option Schemes will be reduced by the amount of all dividends declared by the Company in the period from the date of grant until the date the option is exercised. Options granted under the Option Schemes will vest at a date determined by the board at the date of the grant.  The options granted under the plan to date vest over a period of one to five years.  There is no maximum number of shares authorized for awards of equity share options and authorized, unissued or treasury shares of the Company may be used to satisfy exercised options.
 
During 2015, 710,000 share options were granted and fair value was estimated using a Black-Scholes option pricing model. The assumptions used in estimating fair value are as follows: 1.6% risk-free interest rate, volatility of 34.8%, 0% dividend yield and an expected option term of

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three years, six months. The risk-free interest rates were estimated using the US Treasury yield curve in effect at the time of grant for instruments with a similar life. The dividend yield has been estimated at 0% as the exercise price is reduced by all dividends declared by the Company from the date of grant to the exercise date. It is also assumed that 100% of options granted will vest.

The following table summarizes share option transactions related to the Seadrill Scheme in 2015, 2014 and 2013:
 
2015
 
2014
 
2013
 
Options

 
Weighted average exercise price
$

 
Options

 
Weighted average exercise price
$

 
Options

 
Weighted average exercise price
$

Outstanding at beginning of year
2,241,116

 
35.10

 
2,838,758

 
28.53

 
3,875,891

 
29.88

Granted
710,000

 
12.04

 
—

 
—

 
270,000

 
45.66

Exercised
—

 
—

 
(461,477
)
 
20.19

 
(700,418
)
 
22.60

Forfeited
(935,945
)
 
32.81

 
(136,165
)
 
34.57

 
(606,715
)
 
32.30

Outstanding at end of year
2,015,171

 
28.53

 
2,241,116

 
35.10

 
2,838,758

 
28.53

Exercisable at end of year
882,152

 
36.14

 
1,169,584

 
27.38

 
1,080,306

 
27.38


Options granted in 2008 had been re-priced with exercise prices now being NOK90.83 ($14.09) and NOK104.64 ($16.24) per share; they were exercisable one third each year beginning 12 months after they were granted, and were expired in May 2014. These same prices and dates applied to the options granted in 2009. Options granted in April 2010 had exercise price of NOK137.40 ($23.13), were exercisable one third after 12 or 15 months and expired in March/June 2015. Options granted in November 2010 had exercise prices of NOK192.90 ($31.40) for American citizens or residents and NOK185.20 ($31.06) for non-Americans. They were exercisable one fifth each year beginning 12 months after they were granted and expired in December 2015. Options granted in November 2011 had exercise prices of NOK202.10 ($34.68) and can be exercised one fourth at a time, after the first 18, 36, 48 and 60 months from the grant date. They expire in December 2016. Options granted during 2012 had exercise prices, ranging from NOK202.10 to NOK224.53. They have the same exercise schedule as the 2011’s grant and expire between December 2016 and December 2017. Options granted in October 2013 had an exercise price of NOK273 and can be exercised one fourth at time after 13, 25, 37 and 49 months from the grant date.
 
The weighted average grant-date fair value of options granted during 2015 is $3.33 (2014: none granted, 2013: $10.23 per share).
 
As of December 31, 2015 there was $2 million in unrecognized compensation costs relating to non-vested options granted under the Options Schemes (2014: $3 million, 2013: $7 million). This amount will be recognized as expense of $1 million in 2016, $1 million in 2017 and less than a million in 2018.
 
There were 2,015,171 options outstanding at December 31, 2015 (2014: 2,241,116). Their weighted average remaining contractual life was 22 months (2014: 21 months) and their weighted average fair value was $6.06 per option (2014: $7.97 per option). The weighted average parameters used in calculating these weighted average fair values are as follows: risk-free interest rate 2.0% (2014: 2.0%), volatility 34.8% (2014: 26.1%), dividend yield 0% (2014: 0%), option holder retirement rate 0% (2014: 0%) and expected term 2 years (2014: 4 years).
 
During 2015 the total intrinsic value of options exercised was nil (2014: $9 million, 2013: $17 million) on the day of exercise. The intrinsic value of options fully vested but not exercised at December 31, 2015 was zero since the weighted average exercise price per share exceeded the market price of our shares as at that date. The average remaining term of the options was 22 months.

Restricted Stock Units

On October 1, 2013, the Board of the Company approved 373,700 awards under the Company`s Restricted Stock Units “RSU” plan. On November 7, 2013, the Board of our consolidated subsidiary, NADL, approved 278,778 awards under NADL`s RSU plan.

In December 2014, the Board of the Company approved 162,560 awards under the Company’s RSU plan.

In December 2015, the Board of the Company approved 909,970 awards under the Company’s RSU plan. Also in December 2015, the Board of our consolidated subsidiary, NADL, approved 1,478,500 awards under NADL`s RSU plan.

Under the terms of both plans, the holder of an award is entitled to receive a share in the respective company if still employed at the end of the three year vesting period. There is no requirement for the holder to pay for the share on grant date or upon vesting of the award. In addition the holder is entitled to receive an amount equal to the ordinary dividends declared and paid on the Company and NADL shares during the vesting period.

In December 2015 the shareholders of NADL in a special general meeting approved a capital reorganization including a 1-for-10 reverse stock split of the Company’s issued and outstanding common shares and reducing par value from $5.00 to $0.10. As a result of the capital restructuring the number of RSUs has been adjusted by 1,571,250 units.

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The following table summarizes RSU activity for the Company for the years ended December 31, 2015, 2014 and 2013:
Restricted Stock Units - Seadrill
2015
 
2014
 
2013
Outstanding at beginning of year
525,210

 
373,700

 
—

Granted
937,970

 
162,560

 
373,700

Forfeited
(60,200
)
 
(11,050
)
 
—

Outstanding at end of year
1,402,980

 
525,210

 
373,700



The following table summarizes RSU activity for NADL for the years ended December 31, 2015, 2014 and 2013:
Restricted Stock Units - NADL
2015
 
2014
 
2013
Outstanding at beginning of year
253,870

 
278,778

 
—

Granted
1,587,719

 
—

 
278,778

Adjustment *
(1,571,251
)
 
—

 
—

Forfeited
(95,755
)
 
(24,908
)
 
—

Outstanding at end of year
174,583

 
253,870

 
278,778


* Adjustment relates to the reverse stock split for NADL units, as discussed above

The fair value of the awards are calculated based on the market share price on grant date which for 2013 awards was $46.07 and NOK58 for the Company and NADL shares respectively. The fair value for the 2014 awards for the Company shares was $11.00. The fair value for the 2015 awards for the Company was $3.67 and NOK15.30 for NADL shares.

The fair value of the awards expected to vest is recognized as compensation cost straight-line over the vesting period. All awards are currently expected to vest. Compensation cost related to the RSU plans of $6 million has been recognized in 2015 (2014: $2 million). As of December 31, 2015 there was $6 million in unrecognized compensation costs related to non-vested awards.

Note 30 - Pension benefits

Defined Benefit Plans

The Company has several defined benefit pension plans covering substantially all Norwegian employees. All of the plans are administered by a life insurance company.
 
For onshore employees in Norway, who are participants in the defined benefit plans, the primary benefits are a retirement pension of approximately 66 percent of salary at retirement age of 67 years, together with a long-term disability pension. The retirement pension per employee is capped at an annual payment of 66 percent of the total of 12 times the Norwegian Social Security Base. All employees in this group may choose to retire at 62 years of age on a pre-retirement pension. Offshore employees in Norway have a retirement and long-term disability pension of approximately 60 percent of salary at retirement age of 67. Most offshore employees on drilling units may choose to retire at 60 years of age on a pre-retirement pension.

 
Consolidated balance sheet position
(In US$ millions)
2015

 
2014

Non-current liabilities
37

 
82

Deferred tax asset
(8
)
 
(22
)
Shareholders equity
29

 
60

 


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Annual pension cost
(In US$ millions)
2015

 
2014

 
2013

Service cost
12

 
13

 
14

Interest cost on prior years’ benefit obligation
4

 
7

 
7

Gross pension cost for the year
16

 
20

 
21

Expected return on plan assets
(3
)
 
(6
)
 
(4
)
Administration charges
1

 
1

 
—

Net pension cost for the year
14

 
15

 
17

Social security cost
2

 
2

 
2

Amortization of actuarial gains/losses
3

 
2

 
2

Impact of settlement/curtailment funded status
—

 
—

 
(2
)
Total net pension cost
19

 
19

 
19



The funded status of the defined benefit plan
(In US$ millions)
December 31, 2015

 
December 31, 2014

Projected benefit obligations at end of period
130

 
186

Plan assets at market value
(97
)
 
(114
)
Accrued pension liability exclusive social security
33

 
72

Social security related to pension obligations
4

 
10

Accrued pension liabilities
37

 
82



Change in benefit obligations
(In US$ millions)
2015

 
2014

Projected benefit obligations at beginning of period
186

 
180

Interest cost
4

 
7

Service cost
12

 
13

Benefits paid
(2
)
 
(2
)
Change in unrecognized actuarial gain
(20
)
 
23

Settlement
(20
)
 
—

Foreign currency translations
(30
)
 
(35
)
Projected benefit obligations at end of period
130

 
186

 
Change in pension plan assets
(In US$ millions)
2015

 
2014

Fair value of plan assets at beginning of year
114

 
129

Estimated return
3

 
2

Contribution by employer
12

 
17

Administration charges
(1
)
 
(1
)
Benefits paid
(2
)
 
(2
)
Change in unrecognized actuarial loss
—

 
(9
)
Settlement
(11
)
 
—

Foreign currency translations
(18
)
 
(22
)
Fair value of plan assets at end of year
97

 
114


The accumulated benefit obligation for all defined benefit pension plans was $101 million and $146 million at December 31, 2015 and 2014, respectively.


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Pension obligations are actuarially determined and are critically affected by the assumptions used, including the expected return on plan assets, discount rates, compensation increases and employee turnover rates. The Company periodically reviews the assumptions used, and adjusts them and the recorded liabilities as necessary.
 
During the year a number of employees left the Company and as a result the defined benefit scheme transferred the pension liability for these employees to the life insurance company administering the scheme. The difference between the reduction in benefit obligation and the plan assets transferred to the life insurance company has been recognized within “Other comprehensive income.” The settlement is not deemed to be significant in the context of the overall scheme and as such net unrecognized actuarial losses have not been recycled as a result of the settlement.

The expected rate of return on plan assets and the discount rate applied to projected benefits are particularly important factors in calculating the Company’s pension expense and liabilities. The Company evaluates assumptions regarding the estimated rate of return on plan assets based on historical experience and future expectations on investment returns, utilizing the asset allocation classes held by the plan’s portfolios. The discount rate is based on the covered bond rate in Norway. Changes in these and other assumptions used in the actuarial computations could impact the projected benefit obligations, pension liabilities, pension expense and other comprehensive income.

Assumptions used in calculation of pension obligations 
(In %)
2015

 
2014

 
2013

Rate of compensation increase at the end of year
2.50
%
 
2.75
%
 
3.75
%
Discount rate at the end of year
2.70
%
 
2.30
%
 
4.00
%
Prescribed pension index factor
1.20
%
 
1.20
%
 
1.40
%
Expected return on plan assets for the year
3.30
%
 
3.20
%
 
4.40
%
Employee turnover
4.00
%
 
4.00
%
 
4.00
%
Expected increases in Social Security Base
2.50
%
 
2.50
%
 
3.50
%


The weighted-average asset allocation of funds related to the Company’s defined benefit plan at December 31, was as follows:

Pension benefit plan assets 
(In %)
2015

 
2014

Equity securities
6.1
%
 
7.2
%
Debt securities
47.5
%
 
51.9
%
Real estate
14.7
%
 
14.2
%
Money market
25.2
%
 
23.5
%
Other
6.5
%
 
3.20
%
Total
100.0
%
 
100.0
%
 
The investment policies and strategies for the pension benefit plan funds do not use target allocations for the individual asset categories. The investment objectives are to maximize returns subject to specific risk management policies. The Company diversifies its allocation of plan assets by investing in both domestic and international fixed income securities and domestic and international equity securities. These investments are readily marketable and can be sold to fund benefit payment obligations as they become payable.
 
Cash flows - Contributions expected to be paid
 
The table below shows the Company’s expected annual pension plans contributions under defined benefit plans for the years 2016-2025. The expected payments are based on the assumptions used to measure the Company’s obligations at December 31, 2015 and include estimated future employee services.
 
(In US$ millions)
December 31, 2015

2016
12

2017
12

2018
12

2019
13

2020
13

2021-2025
70

Total payments expected during the next 10 years
132


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Defined Contribution and Other Plans

Company contributions to personal defined contribution pension and other plans totaled $29 million, $34 million and $8 million for the years to December 31, 2015, 2014 and 2013, respectively, and were charged to operations as they became payable.


Note 31 – Related party transactions

The significant related parties of the Company are as follows:
(i) Transactions with investees and associates, over which the Company has significant influence:
•
Seadrill Partners
•
Archer
•
SeaMex
•
Seabras Sapura

(ii) Transactions with those holding significant influence over the Company:
•
Hemen and affiliated companies

Seadrill Partners
As of January 2, 2014, the date of deconsolidation, Seadrill Partners is considered to be a related party and not a controlled subsidiary of the Company. Prior to the deconsolidation, Seadrill Partners was a consolidated subsidiary of the Company, and all inter-group transactions were eliminated in the Company’s consolidated financial statements.

The Net income /(expenses) with Seadrill Partners for the years ended December 31, 2015, 2014, and 2013 were as follows:
(In US$ millions)
 
2015

 
2014

 
2013

Management fees charged to Seadrill Partners - Other revenues (a) and (b)
 
75

 
59

 
—

Rig operating expenses charged to Seadrill Partners - Other revenues (c)
 
29

 
22

 
—

Insurance premiums charged to Seadrill Partners (d)
 
20

 
21

 
—

Rig operating costs charged by Seadrill Partners (e)
 
(13
)
 
—

 
—

Bareboat charter arrangements (f)
 
(2
)
 
(26
)
 
—

Interest expenses charged to Seadrill Partners (g)
 
16

 
40

 
—

Derivatives recharged to Seadrill Partners (h)
 
10

 
42

 
—

Net related party income from Seadrill Partners
 
135

 
158

 
—


Receivables /(payables) with Seadrill Partners and its subsidiaries as of December 31, 2015 and 2014 consisted of the following balances:
 
(In US$ millions)
 
December 31,
2015

 
December 31,
2014

Rig financing agreements and Loan Agreements (i)
 
197

 
237

$109.5 million Vendor financing loan (j)
 
110

 
110

Deferred consideration receivable (k)
 
96

 
74

Other receivables (l)
 
355

 
264

Other payables (l)
 
(179
)
 
(77
)

The following is a summary of the related party agreements with Seadrill Partners:
a) Management and administrative service 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, pursuant to which Seadrill Management provides to Seadrill Partners 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.

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

Income recognized under the above agreements (a) & (b) for the period ended December 31, 2015 was $75 million (2014: $59 million; 2013: nil).

c) Rig operating costs charged to Seadrill Partners
During 2015, Seadrill has recharged to Seadrill Partners certain rig operating costs in relation to costs incurred on behalf of the West Polaris and the West Vencedor operating in Angola. The total other revenues earned for the year ending December 31, 2015 was $29.0 million (2014: revenues of $22 million).

d) Insurance premiums
The Company negotiates insurance for drilling units on a centralized basis. The total insurance premiums related to Seadrill Partners drilling units recharged to Seadrill Partners were $20 million for the year ending December 31, 2015 (2014: $21 million).

e) Rig operating costs charged by Seadrill Partners
During 2015, Seadrill Partners has recharged to Seadrill, through its Nigerian service company, certain services, including the provision of onshore and offshore personnel, which was provided for the West Jupiter and West Saturn drilling rigs operating in Nigeria. The total rig operating expenses incurred for the period ending December 31, 2015 was $13 million (2014: nil; 2013: nil).

f) Bareboat charter arrangements
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 Seadrill Partners, 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 Seadrill Partners, had previously entered into a bareboat charter arrangement with 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 bareboat charter arrangement was replaced with 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 use the West Aquarius in order to perform its obligations under the drilling contract described above. For year ended December 31, 2015 the net effect to Seadrill of the bareboat charters was an expense of $1.6 million (2014: net expense of $25.8 million 2013: nil).

(g) Interest expenses
The total interest income charged to Seadrill Parters for the above loan arrangements, including commitment fees and other fees, was $16 million for the period ending December 31, 2015 (2014: $40 million; 2013: nil). Refer to the sections below for details on the financing arrangements.

(h) Derivative interest rate swap agreements
The Company recharges interest rate swap agreements to Seadrill Partners on a back to back basis. The total net recharged to Seadrill Partners for the year ended December 31, 2015 was $10 million, (2014: $42 million; 2013: nil).

(i) Rig Financing Agreements
In September 2012 prior to the IPO of Seadrill Partners, each of Seadrill Partners controlled subsidiaries that owns the West Capricorn, the West Vencedor, the West Aquarius, and the West Capella, or the rig owning subsidiaries, entered into intercompany loan agreements with the Company in the amount of approximately $523 million, $115 million, $305 million and $295 million respectively, corresponding to the aggregate principal amount outstanding under the external facilities allocable to the West Capricorn, the West Vencedor, the West Aquarius, and the West Capella respectively. During 2013, the rig owning companies of the T-15, T-16, West Leo and West Sirius entered into intercompany loan agreements with Company in the amount of approximately $101 million, $93 million, $486 million and $220 million respectively, corresponding to the aggregate principal amount outstanding under the facilities allocable to the T-15, T-16, West Leo and West Sirius respectively. The Company refers to these arrangements collectively as “Rig Financing Agreements.” Pursuant to these intercompany loan agreements, each rig owning subsidiary can make payments of principal and interest to Seadrill or directly to the third party lenders under each facility, corresponding to payments of principal and interest due under each Rig Financing Agreement that are allocable to each rig.

The Rig Financing Agreements related to the West Aquarius, West Capella, West Leo, West Sirius and West Capricorn were repaid during the year ended December 31, 2014 in conjunction with Seadrill Partners obtaining independent third party financing. The total outstanding principal repaid was $1.5 billion in 2014.

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West Vencedor Facility - In June 2014 the Company repaid the underlying $1,200 million senior secured loan relating to the West Vencedor, and as a result the West Vencedor Loan Agreement between the Company and Seadrill Partners was amended to carry on the existing loan on the same terms. The West Vencedor Loan Agreement between the Company and Seadrill Partners was scheduled to mature in June 2015 and all outstanding amounts thereunder would be due and payable, including a balloon payment of $70 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 $21 million due at maturity in June 2018. The total amount owed by Seadrill Partners to the Company under the remaining West Vencedor Loan agreement as of December 31, 2015, was $58 million (December 31, 2014: $78 million).

T-15 / T-16 Facility - The total amounts owed under the remaining Rig Financing Agreement relating to the T-15 and T-16, totaled $139 million as at December 31, 2015 (December 31, 2014: $159 million). Certain subsidiaries of Seadrill Partners are guarantors under the external facilities in which these rigs 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. The Company has provided an indemnification to Seadrill Partners for any payments or obligations related to these facilities for any losses incurred which do not relate to the T-15 and T-16.

West Vela facility - Under the terms of the $1,450 million secured credit facility agreement, certain subsidiaries of Seadrill and Seadrill Partners 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. Seadrill has provided an indemnity to Seadrill Partners for any payments or obligations related to this facility that are not related to the West Vela.

West Polaris facility - In June 2015, the Company completed the sale of the entities that own and operate the West Polaris to Seadrill Partners. One of the entities sold was the sole borrower under $420 million senior secured credit facility. See Note 11 for further details. Seadrill Limited continues to act as a guarantor under the facility.

(j) $109.5 million Vendor financing loan
In May, 2013, Seadrill Partners borrowed from the Company $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 at December 31, 2015 was $109.5 million (December 31, 2014: $109.5 million).

Revolving credit facility
In October 2012 Seadrill Partners entered into a $300 million revolving credit facility with the Company. 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. In March 2014 the facility was reduced to a maximum of $100 million. The outstanding balance of $125.9 million was repaid in full in March 2014. The outstanding balance as at December 31, 2015 was nil (December 31, 2014: nil).

$229.9 million discount note
On December 13, 2013, as part of the acquisition of the West Sirius, a subsidiary of Seadrill Partners issued a zero coupon discount note to the Company for $229.9 million. The note was repayable in June 2015 and upon maturity, the Company was due to receive $238.5 million. In February 2014, Seadrill Partners repaid this note in full.

$70 million discount note
In December 2013, as part of the acquisition of the West Sirius, Seadrill Partners issued a zero coupon discount note to the Company for $70 million. The note was repayable in June 2015 and upon maturity, the Company was due to receive $73 million. In February 2014, Seadrill Partners repaid this note in full.

$100 million discount note
In March 2014, as part of the acquisition of the West Auriga, Seadrill Partners issued a zero coupon discount note to the Company for $100 million. The note is repayable in September 2015 and upon maturity, the Company will receive $103.7 million. In June 2014, Seadrill Partners repaid this note in full.


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West Sirius bareboat charter financing loan
In December, 2015, an operating subsidiary of Seadrill Partners borrowed from a subsidiary of the Company $143 million 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. The loan bears interest at a rate of LIBOR plus 0.56% and matures in July 2017. The outstanding balance as at December 31, 2015 was $143 million (December 31, 2014: nil). Concurrently, the Company borrowed $143 million from a rig owning subsidiary of Seadrill Partners in order to restore its liquidity with respect to the West Sirius bareboat charter financing loan referred to above. The loan bears interest at a rate of LIBOR plus 0.56% and matures in July 2017. The outstanding balance as at December 31, 2015 was $143 million (December 31, 2014: nil). Each of the loan parties understand and agree that the loan agreements act in parallel with each other. These transactions have been classified within current and long-term portions of "Amount due from related party", "Related party payable" and "Long-term related party payable".

(k) Deferred consideration receivable
On the disposal of the West Vela and West Polaris to Seadrill Partners, the Company recognized deferred consideration receivables. Refer to the sections below for more information.

West Auriga Disposal
On March 21, 2014, the Company sold the entities that own and operate the West Auriga (the “Auriga business”) to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners that is 49% owned by the Company. The entities continue to be related parties subsequent to the sale. Refer to Note 11 - Disposals of businesses for more information.

Purchase of additional limited partner interest in Seadrill Operating LP
On July 21, 2014, the Company sold a 28% limited partner interest in Seadrill Operating LP, a subsidiary of Seadrill Partners, to Seadrill Partners for cash consideration of $373 million. This resulted in a loss on sale of investment of $88 million, which has been recognized within “share in results from associated companies” in the Company’s consolidated statement of operations. Refer to Note 17 - Investments in Associated Companies for more information.

West Vela Disposal
On November 4, 2014, the Company sold the entities that own and operate the West Vela (the “Vela business”) to Seadrill Capricorn Holdings LLC, a consolidated subsidiary of Seadrill Partners and 49% owned by the Company. The entities continue to be related parties subsequent to the sale. Refer to Note 11 - Disposals of businesses for more information.

West Polaris Disposal
On June 19, 2015, the Company sold the entities that owned and operated the West Polaris (the “Polaris business”), to Seadrill Operating LP (“Seadrill Operating”), a consolidated subsidiary of Seadrill Partners LLC and 42% owned by the Company. The entities continue to be related parties subsequent to the sale. Refer to Note 11 - Disposals of businesses for more information.

(l) Receivables and Payables
Receivables and payables with Seadrill Partners and its subsidiaries are comprised of management fees, advisory and administrative services, and other items including accrued interest. In addition, certain receivables and payables arise when the Company pays an invoice on behalf of Seadrill Partners or its subsidiaries and vice versa. Receivables and payables are generally settled quarterly in arrears. Trading balances to Seadrill Partners and its subsidiaries are unsecured and are intended to be settled in the ordinary course of business.

West Sirius Spare parts agreement
During the year ended December 31, 2015, a subsidiary of the Company entered into an agreement with Seadrill Partners to store spare parts of Seadrill Partners’ West Sirius rig while it is stacked. The Company is responsible at its own cost for the moving and storing of the spare parts during the stacking period. The Company may use the spare parts of the West Sirius during the stacking period, but must replace them as required by Seadrill Partners at its own cost.

Guarantees
Seadrill provides certain guarantees on behalf of Seadrill Partners.
Guarantees in favor of customers, which guarantee the performance of the Seadrill Partners drilling units, totaled $370 million as at December 31, 2015 (2014: $370 million).
Guarantees in favor of banks provided on behalf of Seadrill Partners totaled $698 million as at December 31, 2015 and correspond to the outstanding credit facilities relating to the West Polaris and West Vela (2014: $423 million - West Vela).
Guarantees in favor of suppliers provided on behalf of Seadrill Partners, relating to custom guarantees in Nigeria, totaled $86 million (2014: $92 million).


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Related parties to Hemen Holding Limited (“Hemen”)
Since our formation, our largest shareholder has been Hemen, which currently holds approximately 24.2% of our shares.  The Company transacts business with the following related parties, being companies in which Hemen has a significant interest:
•
Ship Finance International Limited (“Ship Finance”);
•
Metrogas Holdings Inc (“Metrogas”);
•
Frontline Management (Bermuda) Limited (“Frontline”); and
•
Seatankers Management Norway AS (“Seatankers”).

Ship Finance Transactions
The Company has entered into sale and lease back contracts for several drilling units, with subsidiaries of Ship Finance. The Company has determined that the Ship Finance subsidiaries, which own the units, are variable interest entities (VIEs), and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company’s consolidated accounts. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in the Company’s consolidated accounts (See Note 35 to the consolidated financial statements included herein).

The units that are currently leased back from Ship Finance are the West Taurus, West Hercules, and West Linus. The West Polaris was previously leased back from Ship Finance, but was repurchased in 2014, before subsequently being sold to Seadrill Partners, as described below.
 
During the years ended December 31, 2015, 2014 and 2013, the Company incurred the following lease costs on units leased from the Ship Finance subsidiaries.
(US$ millions)
2015

 
2014

 
2013

West Polaris *
—

 
55

 
70

West Hercules
55

 
75

 
77

West Taurus
57

 
111

 
112

West Linus
81

 
59

 
—

Total
193

 
300

 
259

 * The West Polaris was repurchased from Ship Finance on December 30, 2014, and subsequently sold to Seadrill Partners on June 18, 2015.

These lease costs are eliminated on consolidation.

On December 30, 2014 we entered into a share sale and purchase agreement with Ship Finance, where we acquired 100% of the equity interests in SFL West Polaris Limited, which was the owner of West Polaris. In addition the Company purchased an outstanding loan of SFL West Polaris Limited of $97 million from Ship Finance. The acquisition price for the shares of the SFL West Polaris and the loan receivable amounted to a total of $111 million. The consideration for the shares and loan was settled on January 5, 2015. See Note 35 for more details.

On June 28, 2013, our subsidiary NADL sold the entity that owns the newbuild jack-up, West Linus, to the Ship Finance subsidiary SFL Linus Ltd. The purchase consideration for this reflected the market value of the rig as of the delivery date which was $600 million. This rig was simultaneously chartered back over a period of 15 years to NADL. Upon closing, SFL Linus Ltd received a $195 million loan from Ship Finance which bears an interest of 4.5% per annum and matures in 2029. During 2014 the loan was reduced to $125 million, and is reported as long-term debt due to related parties in our balance sheet as of December 31, 2015.

On July 1, 2010 our consolidated VIEs, SFL Deepwater Ltd and SFL Polaris Ltd, paid a dividend of $290 million and $145 million respectively to Ship Finance. Ship Finance simultaneously granted loans to SFL Deepwater Ltd and SFL Polaris Ltd for the same amounts. The loans bear interest at 4.5% per annum and are reported as long-term debt due to related parties in our balance sheet as the loans mature in 2023. The loan relating to SFL Polaris Ltd was repaid when the company was repurchased from Ship Finance on December 30, 2014 as described above.

As at December 31, 2015 the VIEs had gross loans outstanding to Ship Finance amounting to $415 million and net loans of $387 million, due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis (December 31, 2014: gross loans of $415 million and net loans of $351 million). The net related party loans are disclosed as “Long-term debt due to related parties” on the balance sheet. The loans bear interest at a fixed rate of 4.5% per annum. The total interest expense of the loans for 2015 was $19 million (2014: $24 million, 2013: $20 million).

During 2013 the VIEs declared dividends totaling $223 million, which were settled against existing intercompany balances with Ship Finance.


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Metrogas transactions
In the past we have entered into agreements with Metrogas primarily to manage short-term working capital requirements. We had the following transactions with Metrogas:

On December 20, 2012, we sold the Company’s holding in a NADL unsecured bond of $500 million to Metrogas plus accrued interest of $9 million with a call option to repurchase the bond in full for a price equal to par plus unpaid accrued interest on the date of repurchase with a maturity date in June 2013. The obligation was recorded as a long term related party liability. In conjunction with this arrangement we also entered into an agreement to settle dividends payable to Metrogas in return for a short term unsecured loan of $93 million (see below). The North Atlantic bond bears a coupon of 7.75% per annum payable semi-annually in arrears. The net proceeds from these arrangements were $415 million. On May 31, 2013, the Company exercised its option to repurchase the bond from Metrogas, and as a result the bond is eliminated in the consolidated financial statements at December 31, 2015.

On December 21, 2012, we obtained a short term loan of $93 million from Metrogas. The loan bears interest of LIBOR plus a margin and was repaid in full on May 2, 2013.

On December 31, 2012, we obtained a short term loan from Metrogas of NOK140 million. The loan bears interest of NIBOR plus a margin and was repaid in full on January 2, 2013.

On February 27, 2013, we obtained a short-term loan from Metrogas of NOK300 million. The loan had an interest of NIBOR plus a margin and was repaid in full on March 12, 2013.

On March 27, 2013, we obtained a short-term loan from Metrogas of NOK700 million. The loan had an interest of NIBOR plus a margin, and was repaid in full on April 3, 2013.

On July 19, 2013, we entered into a loan agreement with Metrogas of NOK1,500 million. The loan had an interest of NIBOR plus a margin of 3.5% and was repaid in full on October 9, 2013.

On September 20, 2013, we obtained a short-term loan from Metrogas of $99 million. The loan had an interest of LIBOR plus a margin of 3.0%, and was repaid in full on September 30, 2013.

On December 10, 2013, the $1,121 million facility with Lloyds Bank TSB as agent was transferred to DNB Bank ASA as new agent and to Metrogas, as the lender. There have been no other changes to the facility. As Metrogas is a related party of the Company, the proportion of the facility related to Metrogas of $840 million was accordingly reclassified as debt due to related parties on the consolidated balance sheet as at December 31, 2014. On February 21, 2014, Seadrill Partners entered into a term loan B agreement for $1.8 billion due in February 2021 in which some of the proceeds were used to repay the portion of this facility that is related to the West Leo, which totaled $472.6 million as at December 31, 2013. The amount that was paid to Metrogas was $436 million.

On August 26, 2014, the $1,121 million facility was repaid in full, and replaced by a new $1,350 million senior secured credit facility with a syndicate of banks and DNB Bank ASA as agent. The Company recognized a $16 million gain on debt extinguishment within other financial items in the Company’s consolidated statement of operations - see Note 23 – Long-term debt.

The total interest expense of the above loans relating to Metrogas for 2015 was $0 million (2014: $1 million; 2013: $10 million).

Frontline Management transactions
Frontline provides management support and administrative services for the Company, and charged the Company fees of $4 million, $4 million and $2 million for these services in the years 2015, 2014 and 2013, respectively. These amounts are included in “general and administrative expenses.”

Seatankers Management transactions
The Company and its subsidiaries receive services from Seatankers Management Norway AS, an affiliate of Hemen. The fee was $0.6 million, nil, and nil for the years ended December 31, 2015, 2014 and 2013, respectively.


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Other related parties

Archer transactions
From time to time, we may enter into transactions with Archer our former consolidated subsidiary and current associate investment related to Archer’s working capital requirements and debt restructuring. Seadrill has provided a range of support for Archer including loans, guarantees and capital injections, in order to support the best interests of Archer and Seadrill.

We had the following transactions with Archer for the years ended December 31, 2015, 2014, and 2013:

Loan agreements
On June 27, 2012, the Company granted Archer a long term unsecured credit facility of $20 million. The principal plus interest was repaid in August 2012.

On November 12, 2012, the Company granted Archer a short term unsecured loan of $55 million. The loan bears interest of LIBOR plus a margin and was settled in February 2013.

On February 20, 2013, the Company obtained a short-term unsecured loan of $43 million from Archer. The loan had an interest of LIBOR plus a margin of 5% and was repaid on February 27, 2013.

On March 27, 2013, the Company granted Archer a short term unsecured loan of $10 million. The loan had an interest of LIBOR plus a margin of 5%, and was repaid on April 2, 2013.

On March 6, 2015, the Company purchased a $50 million subordinated loan made by Metrogas, a related party, to Archer. The aggregate consideration paid for the loan by the Company to Metrogas was $51 million which is equal to the sum of the outstanding principal amount of $50 million and $1 million accrued commitment fee and interest on the loan. The loan bears interest at 7.5% per annum and has a commitment fee of 1% on any undrawn amount. As of the date of the purchase by the Company there was no undrawn amount. Interest and any commitment fee is due upon maturity of the loan on June 30, 2018.

In the year ended December 31, 2015, the Company’s $50 million subordinated loan to Archer was written down to nil due to the Company’s share of net losses of Archer reducing the investment balance. The Company’s accounting policy, once its investment in the common stock of an investee has reached nil, is to apply the equity method to other investments in the investees securities, loans and or advances based on seniority and liquidity. The Company’s share of equity method losses or gains is determined based on the change in the Company’s claim on net assets of the investee. Archer’s net losses and other comprehensive income were therefore applied to the Company’s loan to Archer at its invested ownership of 39.89%.

The total net interest income of the above loans relating to Archer for 2015 was $3.0 million (2014: $0.0 million; 2013: $0.7 million).

Guarantees
On March 7, 2013, the Company provided a guarantee to Archer on its payment obligations on a certain financing arrangements. The maximum liability to the Company is limited to $100 million. The guarantee fee is 1.25% per annum. On July 31, 2013, the Company provided Archer with an additional guarantee of $100 million, which was provided as part of Archer’s divestiture of a division, to support Archer’s existing bank facilities. During 2014, the guarantees above were increased to a total of $250 million. The guarantee fee is 1.25% per annum.

On December 9, 2013, the Company provided Archer Topaz Limited, a wholly owned subsidiary of Archer, with a guarantee of a maximum of EUR 48.4 million (2014: EUR 48.6 million), to support Archer’s credit facilities. The guarantee fee is 1.25% per annum.

On February 5, 2014, the Company provided Archer with a guarantee of a maximum of GBP 10 million, to support Archer’s leasing obligations of a warehouse for a period of 10 years. The guarantee outstanding as at December 31, 2015 was $14 million. (2014: $40 million).

On July 14, 2014, we provided Archer Norge AS, a wholly owned subsidiary of Archer, with a guarantee of a maximum of $20 million, to support Archer’s bank guarantee facility. The guarantee fee is 1.25% per annum.

We provide Archer Well Services, a wholly owned subsidiary of Archer, with a performance guarantee of a maximum of NOK 66.0 million, or $8.0 million to support Archer’s operations in Norway with a customer.

The total guarantee fees charged to Archer for the year ended December 31, 2015 was $3.6 million (2014: $3.7 million; 2013: nil) respectively.

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These guarantee fees are included in other financial items in our consolidated statement of operations.

We do not deem it probable that we will be required to honor these guarantees, and as such, we have not recognized any related loss contingency within our consolidated financial statements as at December 31, 2015.

Archer’s refinancing and and future commitments
In December 2015, Archer announced that it has signed a fifth amendment and re-statement of its multi-currency revolving facility agreement (“MRCFA”) with its banking group which will provide Archer additional financial flexibility. The amendments include, among other things:
•
an immediate non-cash cancellation of the total commitment under the MRCFA from $750 million to $687.5 million;
•
relaxation of certain financial covenants on the bank loan; and
•
A further repayment and cancellation of the commitment under the MRCFA from $687.5 million to $625 million by April 30, 2016

In order to ensure that Archer was able to agree these amendments with its lenders, Seadrill has also agreed to inject additional capital to Archer, in an aggregate amount of up to $75 million in the event that Archer will not have sufficient funds for the above mentioned repayment and cancellation of the commitments under the facilities by April 30, 2016. By ensuring that Archer was able to reach a solution with its lenders the Company believes it has significantly reduced the probability of its guarantees over Archer’s debt being called.

We have not recognized a liability for the $75 million commitment described above, as no current obligation existed at the balance sheet date. However it is probable that we will be required to provide these funds after April 30, 2016.

Engineering Services
Archer provides certain engineering services for the Company, and charged the Company fees of $4.0 million for the year ended December 31, 2015 (2014: $4.0 million; 2013: nil) respectively. These amounts are included in vessel and rig operating expenses.


SeaMex Limited
As of March 10, 2015, the date of deconsolidation, SeaMex Limited is considered to be a related party and not a controlled subsidiary of the Company. Refer to Note 11 for more information regarding the deconsolidation. The following is a summary of the related party agreements/transactions with SeaMex:

Management and administrative service agreements
In connection with the JV agreement, SeaMex, entered into a management support agreement with Seadrill Management, a wholly owned subsidiary of the Company, pursuant to which Seadrill Management provides SeaMex certain management and administrative services. The services provided by Seadrill Management are charged at cost plus management fee of 8%. The agreement can be terminated by providing 60 days written notice. Income recognized under the management and administrative agreements for the year ended December 31, 2015 was $11 million, respectively (2014: nil; 2013: nil).

It is also agreed that Seadrill Jack Up Operations De Mexico, which is a 100% owned subsidiary of SeaMex and provides support services to the rigs acquired by the JV, will continue to provide management services to Seadrill in respect of the rigs West Pegasus and West Freedom and charge a fee of 5% plus costs incurred in connection with managing the rigs on its behalf. Seadrill Jack Up Operations De Mexico has charged the Company fees, under the above agreements for the year ended December 31, 2015 of $10 million (2014: nil; 2013: nil). These amounts are included in vessel and rig expenses.

Loans
$250 million Seller’s credit - In March 2015, the Company provided SeaMex with a $250 million as Seller’s credit as part of the settlement of the sale of assets to SeaMex. The Seller’s credit is divided into two facilities, (a) a term loan facility for an amount up to $230 million and (b) a revolving loan facility of up to $20 million. Both facilities bear interest at a rate of LIBOR plus a margin of 6.5% and mature in December 2019. Interest on the Seller’s credit is payable quarterly in arrears. The outstanding balance as at December 31, 2015 was $250 million (2014: nil).

$162 million consideration receivable - SeaMex agreed to pay to the Company an amount of $162 million being consideration receivable in respect of disposal which was payable at the time of allocation of rig contract in relation to West Titania to the Joint Venture. This amount has been paid in full during July 2015.

Seadrill has made available a fully-subordinated unsecured credit facility of $20 million which will expire at the anniversary of the first draw-down of this amount or a portion thereof. The facility is to be provided by both Seadrill and Fintech at a ratio of 50.0% each. The facility bears interest at a rate of LIBOR plus a margin of 6.5%. The facility will be repayable once SeaMex has complied with certain conditions with regards

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to its lenders and all amounts outstanding including any accrued interest are to be repaid no later than December 31, 2016. As of December 31, 2015 the facility remained undrawn. Seadrill and Fintech have also provided loan facilities (Sponsor Loans) for the two bank guarantee amounts (as detailed below), which are undrawn as at December 31, 2015.

Interest income for the year ended December 31, 2015 for these loans was $17 million (2014: nil; 2013: nil).

Capital contributions
During the year ended December 31, 2015 both the joint venture partners have each made an additional $19 million of equity investment in SeaMex while retaining their 50% share in the joint venture.

Guarantees
During the latter part of 2015, SeaMex experienced issues regarding the delayed payment of invoices by its sole customer. The customer wishes to defer payment into 2016. The customer has not disputed the invoices and is not believed to have any liquidity concerns. The amounts are therefore deemed fully recoverable. However, in order to ease the resulting cash flow impact on SeaMex, the Company, along with Fintech, its Joint Venture Partner, has agreed to provide certain support to Seamex. Simultaneously, SeaMex’s lenders have amended its bank facilities to provide some additional flexibility.

The Company and Fintech have provided a joint and several guarantee to the lenders of SeaMex’s external bank facility for a total of $30 million . The guarantee will continue to be in place until April 30, 2016. The Company and Fintech have also provided a Joint and Several guarantee for potential prepayment deficits that SeaMex might face under its loan agreements. This guarantee will remain in place for 90 days from June 30, 2016. The total guarantee for potential prepayment deficits as of December 31, 2015 is approximately $51 million. As of the balance sheet date, we have not recognized a liability as we do not consider it probable for the guarantees to be called.

Seadrill has also provided performance guarantees for the SeaMex drilling units, up to a total of $30 million as of December 31, 2015.

In respect of the guarantees and facilities described above, Seadrill has also obtained an indemnity from Fintech in order to be able to recover up to 50% of funding and costs, should Seadrill be called to make a contribution greater than its 50% share.

Receivables and Payables
Receivables and payables with SeaMex joint venture are comprised of short-term funding, management fees, advisory and administrative services, and other items including accrued interest. Receivables and payables are generally settled quarterly in arrears. Trading balances with SeaMex Joint Venture are unsecured, bear a monthly interest rate equal to 1.5%, compounded monthly and are intended to be settled in the ordinary course of business.

During the year ended December 31, 2015 Seadrill has provided additional $76 million of short term funding to SeaMex, of which, SeaMex has repaid a total of $31 million during the same period.

Receivables/(payables) with SeaMex Joint Venture as of December 31, 2015 consisted of the following:
 
(In $ millions)
 
December 31, 2015

 
December 31,
2014

Seller’s credit
 
250

 
—

Short term funding
 
45

 
—

Other receivables
 
34

 
—


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Seabras Sapura transactions
Seabras Sapura Participacoes SA and Seabras Sapura Holdco Ltd, together referred to as Seabras Sapura, are joint ventures each owned 50% by the Company, and 50% by TL Offshore, a subsidiary of SapuraKencana.

Yard guarantees
The Company provided a yard guarantee in relation to the Seabras Sapura Participacoes pipe-laying vessel of EUR 47 million, ($51 million) was provided on a 50:50 basis with the joint venture partner. During 2015 the unit was delivered and the yard obligations were fulfilled. The Company therefore no longer has any further obligations.

The Company has provided yard guarantees in relation to Seabras Sapura Holdco pipe-laying vessels totaling $125 million as at December 31, 2015 (December 31, 2014: $375 million), which have been provided on a 50:50 basis with the joint venture partner. The guarantees continue to be in place until the yard obligations have been fulfilled, which is expected to be during 2016 for the final vessel under construction.

As of the balance sheet date, we have not recognized a liability as we do not consider it probable for the guarantees to be called.

Loans
In May 2014, we entered into a loan agreement with Seabras Sapura of $10.8 million. The loan has an interest of 3.4% and is repayable by May 31, 2015. On May 28, 2015 the maturity date for this loan was extended to May 31, 2016. The outstanding balance as at December 31, 2015 was $11 million (December 31, 2014: $11 million).

In May 2014, we entered into a loan agreement with Seabras Sapura of €3.25 million. The loan has an interest of 3.4% and is repayable by May 31, 2015. On May 28, 2015 the maturity date for this loan was extended to May 31, 2016. The outstanding balance as at December 31, 2015 was $3 million (December 31, 2014: $5 million).

In January 2015, the Company provided a loan to Seabras Sapura of $18 million. The outstanding balance as at December 31, 2015 was $18 million (December 31, 2014: nil). The loan bears an interest rate of 3.4% and is repayable by February 16, 2016.

In April 2015 the Company provided a loan to Seabras Sapura of $14 million. The outstanding balance as at December 31, 2015 was $14 million (December 31, 2014: $0 million). The loan bears an interest rate of 3.99% and is repayable on demand.

The total net interest income of the above loans relating to Seabras Sapura for 2015 was $1.5 million (2014: $0.3 million; 2013: nil).

Financial guarantees
In December 2013 certain subsidiaries of the joint venture entered into a $543 million senior secured credit facility agreement in order to part fund the acquisition of the Sapura Diamante, and Sapura Topazio pipe-laying support vessels. As a condition to the lenders making the loan available to each of the borrowers, the Company provides a Sponsor Guarantee, on a 50:50 basis with the joint venture partner, in respect of the obligations of the borrowers during certain defined time periods, the release of such guarantees being subject to the satisfaction of certain defined conditions. The guarantees cover periods including (a) between delivery of the vessel from the shipyard and customer acceptance and (b) between expiry of the pipe-laying support vessels charter contracts and contract renewal. The total amount guaranteed by Seadrill as at December 31, 2015 was $242 million (December 31, 2014: $267 million).

In April 2015 certain subsidiaries of the joint venture entered into a $780 million senior secured credit facility agreement in order to part fund the acquisition of the Sapura Onix, Sapura Jade and Sapura Rubi pipe-laying support vessels. As a condition to the lenders making the loan available to each of the borrowers, the Company provides a Sponsor Guarantee, on a 50:50 basis with the joint venture partner, in respect of the obligations of the borrowers during certain defined time periods, the release of such guarantees being subject to the satisfaction of certain defined conditions. The guarantees cover periods including (a) between delivery of the vessel from the shipyard and customer acceptance and (b) between expiry of the pipe-laying support vessels charter contracts and contract renewal. The amount guaranteed by Seadrill as at December 31, 2015 was $256 million.

In addition, Seadrill provides bank guarantees in relation to the above credit facilities to cover 6 months of debt service costs and 3 months of operating expenses under retention accounts. The total amount guaranteed as at December 31, 2015 was $52 million (December 31, 2014: $26 million).

In November 2012 a subsidiary of the joint venture entered into a $179 million senior secured credit facility agreement in order to part fund the acquisition of the Sapura Esmeralda pipe-laying support vessel. As a condition to the lenders making the loan available the borrower, a wholly owned subsidiary of the Company provided a Sponsor Guarantee, on a joint and several basis with the joint venture partner, in respect of the

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obligations of the borrower. The total amount guaranteed by the subsidiaries of the joint venture partners as at December 31, 2015 was $170 million (December 31, 2014: $117 million).

As of the balance sheet date, we have not recognized a liability as we do not consider it probable for the guarantees to be called.

Other related party transactions
In the year ended December 31, 2015, the Company recognized related party revenues of $119 million (2014: $97 million, 2013: $2 million). In 2015 the revenue related to Seadrill Partners and SeaMex under the management agreements as described above. In 2014 the revenue related to Seadrill Partners under the management agreements as described above. The related party revenues in 2013 related to a previous joint venture and related party Varia Perdana and its subsidiary Crest Tender Rigs Pte Ltd (together “Varia Group”), and Asia Offshore Drilling Ltd (AOD). During 2013 we provided management support, administrative and construction management services to AOD and received bare boat fees from the Varia Group. AOD became a consolidated subsidiary of the Company during 2013 and therefore these revenues are now eliminated on consolidation, see Note 12 to the consolidated financial statements included herein. The amounts related to the Varia Group during 2013 included the period up until the sale of our tender rig business, see Note 11 to the consolidated financial statements included herein.

Note 32 – Risk management and financial instruments
 
The majority of gross earnings from the Company’s drilling units are receivable in U.S. dollars and the majority of the Company’s other transactions, assets and liabilities are denominated in U.S. dollars, the functional currency of the Company. However, the Company has operations and assets in a number of countries worldwide and incurs expenditures in other currencies, causing its results from operations to be affected by fluctuations in currency exchange rates, primarily relative to the U.S. dollar. The Company is also exposed to changes in interest rates on floating interest rate debt, and to the impact of changes in currency exchange rates on NOK and SEK denominated debt. There is thus a risk that currency and interest rate fluctuations will have a positive or negative effect on the value of the Company’s cash flows. The Company has entered into derivative agreements to mitigate the risk of fluctuations, as described below.

Interest rate risk management

The Company’s exposure 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 generally used to repay revolving credit facilities, or placed in accounts or fixed deposits with reputable financial institutions in order to maximize returns, while providing the Company with the flexibility to meet working capital and capital investments. The extent to which the Company utilizes interest rate swaps and other derivatives to manage its interest rate risk is determined by the net debt exposure.
 
Interest rate swap agreements not qualified as hedge accounting

At December 31, 2015, the Company had interest rate swap agreements with an outstanding principal of $7,088 million (December 31, 2014: $7,918 million). In addition we have an interest rate swap contract of principal $200 million, which was entered into in February 2014 with a forward start in March 2016. 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 total fair value of the interest rate swaps outstanding at December 31, 2015 amounted to a gross liability of $143 million and a net liability of $122 million due to master netting agreements with our counterparties, and an asset of $2 million (December 31, 2014: a gross liability of $191 million and net liability of $134 million, and an asset of $5 million). The fair value of the interest rate swaps are classified as other current assets and liabilities in our consolidated balance sheet as of December 31, 2015 and December 31, 2014.

The total realized and unrealized losses recognized in the consolidated statement of operations relating to interest rate swap agreements in 2015 amounted to $129 million (2014: losses of $176 million, 2013: gains of $143 million).


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The Company’s interest rate swap agreements as at December 31, 2015, were as follows:
Maturity date
 
Total outstanding principal as at December 31, 2015
 
Receive rate
 
Pay rate range
 
 
(In US$ millions)
 
 
 
 
 
 
Expiring in 2016
 
1,000
 
3 month LIBOR
 
2.14%
 
2.24%
Expiring in 2016
 
18
 
6 month LIBOR
 
3.83%
 
3.83%
Expiring in 2017
 
1,406
 
3 month LIBOR
 
0.74%
 
3.8%
Expiring in 2018
 
1,000
 
3 month LIBOR
 
2.83%
 
3.34%
Expiring in 2019
 
680
 
3 month LIBOR
 
1.11%
 
1.36%
Expiring in 2020
 
2,632
 
3 month LIBOR
 
1.36%
 
2.19%
Expiring in 2021 and thereafter
 
352
 
3 month LIBOR
 
1.38%
 
2.92%
Total
 
7,088
 
 
 
 
 
 
 
The counterparties to the above agreements are reputable financial institutions. Credit risk exists to the extent that the counterparties are unable to perform under the contracts, but this risk is considered remote as the counterparties are reputable financial institutions which have all provided loan finance to us and the interest rate swaps are related to those financing arrangements.


Cross currency interest rate swaps not qualified as hedge accounting

At December 31, 2015 the Company had outstanding cross currency interest rate swaps with principal amounts of $807 million (December 31, 2014: $807 million) with maturity dates between March 2018 and March 2019 at fixed rates ranging from 4.94% to 6.1825%. 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 total fair value of cross currency interest swaps outstanding at December 31, 2015 amounted to a liability of $291 million (December 31, 2014: a liability of $201 million). The fair value of the cross currency interest swaps are classified as other current liabilities in the consolidated balance sheet as at December 31, 2015 and within other current liabilities as at December 31, 2014.

The total realized and unrealized losses recognized in the consolidated statement of operations relating to cross currency interest rate swap agreements in 2015 amounted to $106 million (2014: losses of $171 million, 2013: losses of $10 million).


Interest rate hedge accounting
 
A Ship Finance subsidiary consolidated by the Company as a variable interest entity (VIEs) (refer to Note 35), has entered into interest rate swaps in order to mitigate the exposure to variability in cash flows for future interest payments on the loans taken out to finance the acquisition of the West Linus.  These interest rate swaps qualify for hedge accounting under US GAAP, and the instruments have been formally designated as a hedge to the underlying loan. When the hedge is effective, any changes in its fair value is included in “other comprehensive income.” The effectiveness of hedging instruments is assessed at each reporting period. The total fair value of these interest rate swaps outstanding at December 31, 2015 amounted to a liability of $2 million (December 31, 2014: a liability of $3 million), which are classified as other non-current liabilities in the consolidated balance sheet. Below is a summary of the notional amount, fixed interest rate payable and duration of the outstanding principal as of December 31, 2015.

Variable interest entity
 
Outstanding principal as at December 31, 2015
 
Receive rate
 
Pay rate
 
Length of contract
 
 
(In US$ millions)
 
 
 
 
 
 
SFL Linus Limited
(West Linus)
 
4.0
 
1 month LIBOR
 
2.01%
 
Mar 2014 - Oct 2018
SFL Linus Limited
(West Linus)
 
4.0
 
2 month LIBOR
 
2.01%
 
Mar 2014 - Nov 2018
SFL Linus Limited
(West Linus)
 
191.9
 
3 month LIBOR
 
1.77%
 
Dec 2013 - Dec 2018


In the year ended December 31, 2015 the above VIEs recorded no fair value gains/losses on interest rate swaps (December 31, 2014: no fair value gains/losses). Any such gains or losses are recorded by those VIEs as “other comprehensive income” but due to their ownership by Ship Finance these gains are allocated to “non-controlling interest” in our consolidated statement of changes in equity. The net interest paid on these swaps for the year ended December 31, 2015 was $3 million (2014: net interest of $4 million).

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Any change in fair value resulting from hedge ineffectiveness is recognized immediately in earnings. The VIEs and therefore the Company, did not recognize any gain or loss due to hedge ineffectiveness in the consolidated financial statements during the years ended December 31, 2015, 2014 and 2013 relating to derivative financial instruments.


Foreign exchange risk management

The Company and the majority 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 thus a risk that currency fluctuations could have an adverse effect on the value of our cash flows. The Company is also exposed to changes in interest rates on floating interest rate debt, and to the impact of changes in currency exchange rates on NOK and SEK denominated debt. The Company has entered into derivative agreements to mitigate the risk of exchange rate fluctuations as described below.

Foreign currency forwards not qualified as hedge accounting

The Company uses foreign currency forward contracts and other derivatives to manage exposure to foreign currency risk on certain assets, liabilities and future anticipated transactions. Such derivative contracts do not qualify for hedge accounting treatment and are recorded in the consolidated balance sheet under current receivables if the contracts have a net positive fair value, and under other current liabilities if the contracts have a net negative fair value.

At December 31, 2015, the Company had no outstanding currency forward contracts. As at December 31, 2014 the total fair value of outstanding NOK currency forward contracts amounted to a liability $24 million, which are classified as other current liabilities in the consolidated balance sheet. As at December 31, 2014 the total fair value of outstanding GBP currency forward contracts amounted to a liability of $2.6 million, and are classified as other current liabilities in the consolidated balance sheet.

The total realized and unrealized losses recognized in the consolidated statement of operations relating to foreign currency forward agreements in 2015 amounted to $9 million (2014: losses of $58 million, 2013: losses of $49 million).


Other arrangements

The Company from time to time may enter into swap agreements, forward contracts or other derivative arrangements based on assets or equity shares of the Company which provide flexible financing alternatives at a low cost.

Total Return Swap (“TRS”) Agreements
During 2015, 2014 and 2013 the Company entered into and settled various TRS agreements which are indexed to the Company’s own common shares. The settlement amount for the TRS transaction will be (A) the market value of the shares at the date of settlement plus all dividends paid by the Company between entering into and settling the contract, less (B) the reference price of the shares agreed at the inception of the contract plus the counterparty’s financing costs. Settlement will be either a payment by the counterparty to us, if (A) is greater than (B), or a payment by us to the counterparty, if (B) is greater than (A). There is no obligation for us to purchase any shares under the agreement and this arrangement has been recorded as a derivative transaction, with the fair value of the TRS recognized as an asset or liability as appropriate, and changes in fair values recognized in the consolidated statement of operations.
The fair value of the TRS agreements at December 31, 2015 was a liability of $9 million (December 31, 2014: a liability of $5 million). The fair values of the TRS agreements are classified as other current liabilities in the balance sheet as at December 31, 2015 and December 31, 2014. As of December 31, 2015 we had an outstanding agreement related to 4 million shares at NOK49.60 per share (December 31, 2014: 4.0 million shares at NOK96.02 per share). We generally settle these agreements in cash, or through further rolling of the agreements.
Subsequent to the year end, on March 3, 2016, the TRS agreement related to 4 million shares was rolled over with a new expiry date of June 3, 2016, and a new reference price of NOK 21.1611 per share.
The total realized and unrealized losses recognized in the consolidated statement of operations relating to TRS agreements in 2015 amounted to $27 million (2014: losses of $73 million, 2013: gains of $19 million).

Sevan share repurchase agreements
During 2013 the Company has entered into agreements in which the Company has sold its shares in Sevan Drilling to commercial banks and then entered into a share purchase agreement to repurchase the same amount of shares at a later date which is generally within three months from the date of entering into the sale agreement.
As at December 31, 2014 the Company had agreements for 216,065,464 Sevan Drilling ASA shares at a strike price of NOK 4.1701 and 81,828,500 Sevan Drilling ASA shares at a strike price of NOK 4.1966.

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On February 6, 2015, these forward agreements were settled and new forward agreements were entered into. The cash settlement was NOK 134 million. On May 6, 2015, the Company rolled forward the agreement and entered into a forward agreement for 216,065,464 Sevan shares expiring August 10, 2015 with a strike price of NOK 0.6247, and a second forward agreement for 81,828,500 Drilling ASA shares expiring August 6, 2015 with a strike price of NOK 0.6243.
As part of the Sevan Drilling group’s internal reorganization program effective from June 30, 2015 the parent company of the Sevan Drilling group was migrated from Sevan Drilling ASA, a Norwegian registered entity, to Sevan Drilling Limited, a Bermudan registered entity. As part of the restructuring, shareholders on the Oslo Stock Exchange listed entity were distributed shares in the Bermudan entity on a 20:1 basis. The Norwegian entity was then delisted from the Oslo Stock Exchange, and the Bermudan entity was listed in its place, maintaining the ticker “SEVDR.” Accordingly the outstanding share repurchase agreements mentioned above were settled for consideration paid of $4 million, and the Company completed the repurchase of the 297,893,964 shares in Sevan Drilling ASA at a value equal to the nominal value of the shares. Simultaneously new agreements were taken out to repurchase 14,894,699 shares in Sevan Drilling Limited with the same banks.
On November 6, 2015, the Company settled the forward agreement for 10,803,274 shares in Sevan Drilling Limited at a strike price of NOK 8.9482 and settled the forward agreement for 4,091,425 shares for a strike price of NOK 8.5539. The total amount paid on settlement was $16 million. As a result of these transactions, the Company maintained a controlling interest in the Sevan Drilling group, and as a result the Sevan Drilling group remains consolidated in the Company’s consolidated financial statements. Prior to the settlement the share repurchase agreements were accounted for as secured borrowings and therefore the Company had recognized the liabilities associated with these repurchases in other current liabilities of $167 million as of December 31, 2014. As at December 31, 2015 these agreements have been fully settled.

SapuraKencana share agreements and financing
On September 18, 2013, we entered into two derivative contract agreements with a commercial bank which enabled the Company to obtain financing against a portion of our equity investment in SapuraKencana in which the Company received $250 million upfront as prepayment for one of the agreements. The agreements have a settlement date three years from the inception date and include an interest equivalent component which is based on the prepaid amount received and LIBOR plus 1.90% per annum.
On July 8, 2015, the Company amended the financing arrangement relating to its equity investment in SapuraKencana and extended the agreement to July 2018. The total financing was reduced by $90 million to $160 million, and the corresponding restricted cash held as collateral of $93 million was settled against the liability. In addition the interest rate increased to LIBOR plus 2.6%. As at December 31, 2015, the Company had associated restricted cash of $160 million due to the significant fall in the share price of SapuraKencana
As part of these agreements, a number of shares in SapuraKencana were pledged as security, the value of which as at December 31, 2015 amounted to $228 million (December 31, 2014: $325 million), and is presented as a long term marketable security on the consolidated balance sheet (see Note 14 to the consolidated financial statements included herein). The unrealized gains and losses resulting from measuring the fair value of these contracts at December 31, 2015 are a gross asset of $135 million, and a gross liability of $135 million which have been offset in the consolidated balance sheet and consolidated income statement as these agreements meet the criteria for offsetting (December 31, 2014: gross asset of $103.0 million, and a gross liability of $103 million).
The $160 million received as a prepayment to the Company is included in other long-term liabilities as at December 31, 2015 (December 31, 2014: $250 million). The agreements also contain financial covenants which are similar to the Company’s bank loans, See Note 23 to the consolidated financial statements included herein.
On February 24, 2016, subsequent to the period end, the Company elected to exercise the optional termination notice under the prepaid forward and equity swap agreements.

Other derivative agreements
Total realized and unrealized gains and losses on other derivative instruments amounted to a loss of $3 million for 2015 (2014: a loss of $19 million, 2013: gain of $30 million).



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Fair values of financial instruments
 
The carrying value and estimated fair value of the Company’s financial instruments at 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

Assets
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
1,044

 
1,044

 
831

 
831

Restricted cash
 
248

 
248

 
449

 
449

Related party loans receivable - short term
 
371

 
371

 
69

 
69

Related party loans receivable - long term
 
464

 
464

 
311

 
311

Liabilities
 
 
 
 
 
 
 
 
Current portion of floating rate debt
 
1,493

 
1,493

 
1,928

 
1,928

Long-term portion of floating rate debt
 
6,711

 
6,711

 
7,713

 
7,713

Current portion of fixed rate CIRR loans
 
33

 
33

 
39

 
39

Long term portion of fixed rate CIRR loans
 
43

 
43

 
84

 
84

Fixed interest bonds - short term
 
—

 
—

 
323

 
342

Fixed interest bonds - long term
 
944

 
1,840

 
1,545

 
1,892

Floating interest bonds - long term
 
283

 
541

 
483

 
622

Related party fixed rate debt - long term
 
415

 
415

 
415

 
415

 
The carrying value of cash and cash equivalents and restricted cash, 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 related party loans receivable from Seadrill Partners, Archer and SeaMex are estimated to be equal to the carrying value. This debt is not freely tradable and cannot be recalled by the Company at prices other than specified in the loan note agreements. The loans were entered into at market rates. They are categorized as level 2 on the fair value measurement hierarchy. Other trading balances with related parties are not shown in the table above. The fair value of trading balances with related parties are assumed to be equal to to their carrying value.

The fair value of the current and long-term portion of floating rate debt is estimated to be equal to the carrying value since it bears variable interest rates, which are reset regularly and usually in the range between every one to six months. This debt is not freely tradable and cannot be purchased by the Company at prices other than the outstanding balance plus accrued interest. We have categorized this at level 2 on the fair value measurement hierarchy. We have based the table above on the total carrying value of principal outstanding debt, before capitalized loan fees are deducted. Refer to Note 23 - Long term debt for more information.
 
The fair value of the long-term portion of the fixed rate CIRR loans is equal to the carrying value, as they are matched with equal balances of restricted cash. We have categorized this at level 2 on the fair value measurement hierarchy.
 
The fixed interest rate bonds are freely tradable and their fair value has been set equal to the price at which they were traded at on December 31, 2015 and December 31, 2014. We have categorized this at level 1 on the fair value measurement hierarchy.

The floating interest bonds are freely tradable and their fair value has been set equal to the price at which they were traded at on December 31, 2015 and December 31, 2014. We have categorized this at level 1 on the fair value measurement hierarchy.

The fair value of the loans provided by Ship Finance to the Company’s VIE’s are estimated to be equal to the carrying value as the loans were entered into at market rates. The debt is not freely tradable and cannot be purchased by the Company at prices other than the outstanding balance. We have categorized this at level 2 on the fair value measurement hierarchy.


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Financial instruments that are measured at fair value on a recurring basis:
 
 
 
Fair value

 
Fair value measurements
at reporting date using
 
 
 
 
Quoted Prices in Active Markets for Identical Assets

 
Significant Other Observable Inputs

 
Significant Unobservable Inputs

(In US$ millions)
 
December 31, 2015

 
(Level 1)

 
(Level 2)

 
(Level 3)

Assets:
 
 
 
 
 
 
 
 
Marketable securities - current and non-current assets
 
324

 
324

 
—

 
—

Interest rate swap contracts – non-current assets
 
2

 
—

 
2

 
—

Total assets
 
326

 
324

 
2

 
—

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Interest rate swap contracts – current liabilities
 
124

 
—

 
124

 
—

Interest rate swap contracts – non-current liabilities
 
2

 
—

 
2

 
—

Cross currency interest rate swap contracts – current liabilities
 
291

 
—

 
291

 
—

Other derivative instruments – current liabilities
 
9

 
—

 
9

 
—

Total liabilities
 
426

 
—

 
426

 
—

 
 
 
Fair value

 
Fair value measurements
at reporting date using
 
 
 
 
Quoted Prices in Active Markets for Identical Assets

 
Significant Other Observable Inputs

 
Significant Unobservable Inputs

(In US$ millions)
 
December 31, 2014

 
(Level 1)

 
(Level 2)

 
(Level 3)

Assets:
 
 
 
 
 
 
 
 
Marketable securities - current and non-current assets
 
751

 
751

 
—

 
—

Interest rate swap contracts – non-current assets
 
5

 
—

 
5

 
—

Total assets
 
756

 
751

 
5

 
—

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Interest rate swap contracts – current liabilities
 
139

 
—

 
139

 
—

Interest rate swap contracts – non-current liabilities
 
3

 
—

 
3

 
—

Cross currency interest rate swap contracts – current liabilities
 
201

 
—

 
201

 
—

Foreign exchange forwards – current liabilities
 
27

 
—

 
27

 
—

Other derivative instruments – current liabilities
 
5

 
—

 
5

 
—

Total liabilities
 
375

 
—

 
375

 
—


Roll forward of fair value measurements using unobservable inputs (Level 3) relating to the Petromena Bond. Please refer to Note 14 for additional information:
 
(In US$ millions)
 
Beginning balance January 1, 2014
4

Beginning balance Realization
6

Beginning balance Proceeds on disposal
(10
)
Closing balance December 31, 2014
—

 
 
Closing balance December 31, 2015
—

 

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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.
 
Quoted market prices are used to estimate the fair value of marketable securities, which are valued at fair value on a recurring basis.
 
The fair value of total return equity swaps is calculated using the closing prices of the underlying listed shares, dividends paid since inception and the interest rate charged by the counterparty. We have categorized these transactions as level 2 on the fair value measurement hierarchy.
 
The fair values of interest rate swaps, cross currency interest rate swaps, and forward exchange contracts are calculated using well-established independent valuation techniques applied to contracted cash flows and LIBOR and NIBOR interest rates as of December 31, 2015.
 
The fair value of other derivative instruments is calculated using the closing prices of the underlying securities, dividends paid since inception and the interest charged by the counterparty.


Retained Risk
 
a) Physical Damage Insurance
 
The Company retains the risk, through self-insurance, for the deductibles relating to physical damage insurance on the Company’s drilling unit fleet, currently a maximum of $5 million per occurrence.
 
b) Loss of Hire Insurance
 
The Company purchases insurance to cover the deepwater drilling units, one semi tender and the North Atlantic fleet for loss of revenue in the event of extensive downtime caused by physical damage, where such damage is covered under the Company’s physical damage insurance. The Company’s self-insured retentions under the loss of hire insurance are up to 60 days after the occurrence of the physical damage plus a 25% quota share on the Loss of Hire daily amount. Thereafter, under the terms of the insurance, the Company is compensated for loss of revenue for a period ranging from 210 days up to 290 days. The Company retains the risk that the repair of physical damage takes longer than the total number of days in the loss of hire policy.

c) Windstorm Insurance

We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a Combined Single Limit of $100 million in the annual aggregate, which includes Loss of Hire. 


Credit risk

The Company has financial assets, including cash and cash equivalents, marketable securities, other receivables and certain amounts receivable on derivative instruments, mainly forward exchange contracts and interest rate swaps. These assets expose the Company to credit risk arising from possible default by the counterparty. The Company considers the counterparties to be creditworthy financial institutions 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. The credit exposure of interest rate swap agreements, currency option contracts and foreign currency contracts is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements. It is the Company’s policy to enter into master netting agreements with the counterparties to derivative financial instrument contracts, which give the Company the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes to the Company.



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Concentration of risk
 
The Company has financial assets, including cash and cash equivalents, marketable securities, other receivables and certain derivative instrument receivable amounts. These other assets expose the Company to credit risk arising from possible default by the counterparty. There is also a concentration of credit risk with respect to cash and cash equivalents to the extent that most of the amounts are carried with DNB ASA, Nordea Bank Finland Plc, Danske Bank A/S, and ING Bank N.V. The Company considers these risks to be remote.
 
In the years ended December 31, 2015, 2014 and 2013, the Company had the following customers with contract revenues greater than 10% in any of the years presented:

(US$ millions)
 
2015

 
2014

 
2013

Petroleo Brasileiro S.A ("Petrobras")
 
19
%
 
20
%
 
16
%
Total S.A Group ("Total")
 
16
%
 
13
%
 
14
%
Exxon Mobil Corp ("Exxon")
 
14
%
 
10
%
 
12
%
Statoil ASA ("Statoil")
 
12
%
 
13
%
 
14
%

Note 33 – Commitments and contingencies
 
Legal Proceedings

From time to time we are a party, as plaintiff or defendant, to lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the construction or operation of our drilling units, in the ordinary course of business or in connection with our 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 our financial statements as of December 31, 2015.

In December 2014, a purported shareholder class action lawsuit, Fuchs et al. v. Seadrill Limited et al., No. 14-cv-9642 (LGS)(KNF), was filed in US Federal District Court in the Southern District of New York, alleging, among other things, that Seadrill and certain of its executives made materially false and misleading statements in connection with the payment of dividends.  In January 2015, a second purported shareholder class action lawsuit, Heron v. Seadrill Limited et al., No. 15-cv-0429 (LGS)(KNF), was filed in the same court on similar grounds.  In March 2015, a third purported shareholder class action lawsuit, Glow v. Seadrill Limited et al., No. 15-cv-1770 (LGS)(KNF), was filed in the same court on similar grounds.  On March 24, 2015, the court consolidated these complaints into a single action.  On June 23, 2015 the court appointed co-lead plaintiffs and co-lead counsel and ordered the co-lead plaintiffs to file a single consolidated amended complaint by July 23, 2015.

The amended complaint was filed on July 23, 2015 alleging, among other things, that Seadrill, North Atlantic Drilling Limited and certain of their executives made materially false and misleading statements in connection with the payment of dividends, the failure to disclose the risks to the Rosneft transaction as a result of various enacted government sanctions and the inclusion in backlog of $4.1 billion attributable to the Rosneft transaction. The defendants filed their Motion to Dismiss the Complaint on October 13, 2015. The plaintiffs, in turn, filed their Opposition to the Motion to Dismiss on November 12, 2015 and the defendants’ Reply Brief was served on December 4, 2015.

Although we intend to vigorously defend this action, we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized within the financial statements.

In addition, the Company has received voluntary requests for information from the U.S. Securities and Exchange Commission concerning, among other things, statements in connection with its payment of dividends, inclusion of contracts in the Company’s backlog, and its contracts with Rosneft.

Other matters
On October 12, 2015, HSHI launched arbitration proceedings with regard to Seadrill’s cancellation of the West Mira construction contract. For further discussion please refer to “Note 5 - Gain / (Loss) on disposals.”

Sevan Drilling is a controlled subsidiary of the Company. On June 29, 2015, Sevan Drilling disclosed that it had initiated an internal investigation into activities with an agent under certain drilling contracts with Petrobras in Brazil, which were entered prior to the separation from the Sevan Marine Group. On October 16, 2015, Sevan further disclosed that Sevan Drilling ASA had been accused of breaches of Sections 276 a and 276 b of the Norwegian Criminal Code in respect of payments made in connection with the performance during 2012 to 2015 of drilling contracts originally awarded by Petrobras to Sevan Marine ASA in the period between 2005-2008. For further details please refer to the Sevan Drilling Interim Financial Report Fourth Quarter 2015 which is publicly available. We cannot predict whether any other governmental authority will seek to investigate this matter, or if a proceeding were opened, the scope or ultimate outcome of any such investigation and as a result no loss contingency has been recognized in Seadrill’s consolidated financial statements.

In February 2016, NADL was notified of certain customer claims. After an initial assessment including advice from external counsel, NADL fully refutes the validity of these claims and will take appropriate actions related to its position. The client has withheld amounts from invoice payments due in the first quarter of 2016, which total $36.2 million. No provision has been recognized in relation to these claims.

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North Atlantic Drilling, and all other offshore contractors that are members of the Norwegian Shipowners’ Association, lost a Norwegian court case in July 2015 concerning the pension rights of night shift compensation for offshore workers. The case has been appealed to the Supreme Court of Norway by the members of the Norwegian Shipowners’ Association, and the hearings are expected to be held in June 2016. Due to the uncertainty of the appeal we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized within the Company’s financial statements as at December 31, 2015.


Pledged assets
 
The book value of assets pledged under mortgages and overdraft facilities at December 31, 2015 was $14,596 million (2014: $17,772 million). In addition we have $228 million of marketable securities pledged as security for certain derivative arrangements.

Purchase Commitments
 
At December 31, 2015, the Company had contractual commitments under thirteen newbuilding contracts totaling $4,049 million (2014: $5,389 million). The contract commitments are mainly yard installments and are for the construction of one semi-submersible rigs, eight jack-up rigs and four drillships.

Note that the newbuilding commitments include $447 million related to the Sevan Developer that are presented as a contractual obligation in the balance sheet in the line item “Other short term liabilities.” Sevan Drilling and Cosco Shipyard have agreed to amend the termination rights of the construction contract and defer the delivery date for the Sevan Developer. Delivery is deferred for 12 months with mutually agreed options, exercisable at 6 month intervals, to extend the delivery date for up to a total of 36 months from October 15, 2014. The agreement will terminate at the end of each deferral period, unless the option to extend is mutually agreed by both parties. If termination should occur, Sevan is entitled to a refund of its installments less any agreed costs. Cosco will complete construction and maintain the rig at the shipyard in Qidong. Sevan will continue to market the rig as part of its fleet. Payment of the construction liability and other related costs will be deferred until delivery. On October 30, 2015 Sevan Drilling and Cosco agreed to exercise the first six-month option of the delivery deferral agreement for Sevan Developer, which extends the deferral period to April 15, 2016. The final delivery installment has been amended to $447 million, representing 85% of the $526 million contract price. As part of the agreement, Cosco has refunded 5%, or $26 million, of the contract value plus interest of $3 million back to Seadrill, which Seadrill will pay back at the time of final yard installment.

The table below shows the maturity schedule for the newbuilding contractual commitments, which reflects all recent deferral agreements with DSME, Samsung, Cosco and Dalian, and assumes we exercise the remaining deferral options for the Sevan Developer with Cosco:

(In US$ millions)
2016

 
2017

 
2018

 
2019

 
2020

 
2021 and thereafter

 
Total

Newbuildings
188

 
2,158

 
1,174

 
529

 
—

 
—

 
4,049



Guarantees
 
The Company has issued guarantees in favor of third parties as follows, which is the maximum potential future payment for each type of guarantee:

 (In US$ millions)
December 31, 2015

 
December 31, 2014

Guarantees in favor of customers 1, 2 ,3
1,530

 
1,824

Guarantees in favor of banks  1, 2, 3, 4
1,632

 
1,254

Guarantees in favor of suppliers 1, 3, 4
2,744

 
3,898

Total
5,906

 
8,404


(1)
Guarantees to Seadrill Partners - Within guarantees in favor of customers are guarantees provided on behalf of Seadrill Partners of $370 million (2014: $370 million). Guarantees in favor of banks include guarantees provided on behalf of Seadrill Partners of $698 million (2014: $423 million). Guarantees in favor of suppliers includes guarantees on behalf of Seadrill Partners of $86 million (2014: $92 million). See Note 31 to the consolidated financial statements included herein.

(2)
Guarantees to SeaMex - Within guarantees in favor of customers are guarantees provided on behalf of SeaMex of $30 million (2014: $0 million). Guarantees in favor of banks includes guarantees on behalf of SeaMex of $81 million (2014: $0 million). See Note 31 to the consolidated financial statements included herein.

(3)
Guarantees to Archer - Within guarantees provided to customers are guarantees provided on behalf of Archer of $8 million (2014: nil). Within guarantees in favor of banks are guarantees provided on behalf of Archer of $268 million and EUR 33 million ($36 million)

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(2014: $370 million and EUR 48 million ($71.9 million)). Guarantees in favor of suppliers includes guarantees on behalf of Archer of GBP 9 million ($14 million) (2014: GBP 26 million ($40 million)). See Note 31 to the consolidated financial statements included herein.

(4)
Guarantees to Seabras Sapura -Within guarantees in favor of banks are guarantees provided on behalf of Seabras Sapura Participacoes and Seabras Sapura Holdco totaling $550 million (2014: $293 million). Within guarantees in favor of suppliers are guarantees provided in relation to our joint ventures Seabras Sapura Participacoes and Seabras Sapura Holdco of EUR 0 million ($0 million) and $125 million respectively (2014: EUR 47 million ($60 million) and $375 million respectively). See Note 31 to the consolidated financial statements included herein.

As of the balance sheet date, we have not recognized any liabilities for the above guarantees, as we do not consider it probable for the guarantees to be called.

Note 34 – Operating leases

The Company has operating leases relating to premises, the most significant being its offices in London, Liverpool, Oslo, Stavanger, Singapore, Houston, Rio de Janeiro and Dubai. In the years ended December 31, 2015, 2014 and 2013 rental expenses amounted to $23 million, $24 million and $21 million, respectively. Future minimum rental payments are as follows:
 
Year
 (In US$ millions)
2016
11

2017
10

2018
8

2019
6

2020
6

2021 and thereafter
13

Total
54

 
Note 35 – Variable Interest Entities
 
As of December 31, 2015, the Company leased two semi-submersible rigs, and a jack-up rig from VIEs under capital leases. Each of the units had been sold by the Company to single purpose subsidiaries of Ship Finance Ltd and simultaneously leased back by the Company on bareboat charter contracts for a term of 15 years. The Company has several options to repurchase the units during the charter periods, and obligations to purchase the assets at the end of the 15 years lease period.
 
On June 19, 2013, SFL Deepwater Ltd sold the West Hercules to SFL Hercules Ltd. This transaction under common control has no net effects on our consolidated financial statements, and we will continue to consolidate all relevant VIEs.

On June 28, 2013, our consolidated subsidiary NADL sold the entity that own the jack-up, the West Linus, to the Ship Finance subsidiary, SFL Linus Ltd. The purchase consideration reflected a market value of the rig as of the delivery date which was $600 million. This rig was simultaneously chartered back to the Company over a period of 15 years. Upon closing of the purchase, SFL Linus Ltd received a $195 million loan from Ship Finance which bears an interest of 4.5% per annum and matures in 2029. During 2014 the loan was reduced to $125 million, and is reported as long-term debt due to related parties in our balance sheet as of December 31, 2015.

The following table gives a summary of the sale and leaseback arrangements and repurchase options, as of December 31, 2015:

Unit
 
Effective
from
 
Sale value
(In $ millions)
 
First
repurchase
option
(In $ millions)
 
Month of first
repurchase
option
 
Last
repurchase
option *
(In $ millions)
 
Month of last
repurchase
Option *
West Taurus
 
Nov 2008
 
850
 
418
 
February 2015
 
149
 
November 2023
West Hercules
 
Oct  2008
 
850
 
580
 
August 2011
 
135
 
August 2023
West Linus
 
June 2013
 
600
 
370
 
June 2018
 
170
 
June 2028

* Ship Finance has a right to require the Company to purchase the West Linus rig on the 15th anniversary for the price of $100 million if the Company doesn’t exercise the final repurchase option.
 
The Company has determined that the Ship Finance subsidiaries, which own the units, are VIEs, and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company’s consolidated financial statements. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in

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the Company’s consolidated financial statements. At December 31, 2015 and at December 31, 2014 the units are reported under drilling units in the Company’s balance sheet. The Company did not record any gains from the sale of the units, as they continued to be reported as assets at their original cost in the Company’s consolidated balance sheet at the time of each transaction. The investment in finance lease amounts are eliminated on consolidation against the corresponding finance lease liability held within Seadrill entities. The remainder of assets and liabilities of the VIEs are fully reflected within the consolidated financial statements.
 
The bareboat charter rates are set on the basis of a Base LIBOR Interest Rate for each bareboat charter contract, and thereafter are adjusted for differences between the LIBOR fixing each month and the Base LIBOR Interest Rate for each contract. A summary of the average bareboat charter rates per day for each unit is given below for the respective years.
 
 
(In US$ thousands)
 
 
 
 
2015
 
2016
 
2017
 
2018
 
2019
 
2020
West Taurus
 
186
 
165
 
158
 
158
 
144
 
143
West Hercules
 
190
 
179
 
170
 
166
 
143
 
141
West Linus
 
222
 
222
 
222
 
222
 
173
 
140


The assets and liabilities in the statutory accounts of the VIEs as at December 31, 2015 and as at December 31, 2014 are as follows:
(In US$ millions)
December 31, 2015
 
December 31, 2014
 
SFL
Deepwater
Limited

 
SFL
Hercules
Limited

 
SFL
Linus
Limited

 
SFL West
Polaris
Limited *
 
SFL
Deepwater
Ltd.

 
SFL
Hercules
Limited

 
SFL
Linus
Limited

Name of unit
West Taurus

 
West Hercules

 
West Linus

 
West
Polaris
 
West
Taurus
and West
Hercules

 
West Hercules

 
West Linus

Investment in finance lease
394

 
394

 
530

 
N/A
 
429

 
426

 
574

Amount due from related parties
4

 
5

 
—

 
N/A
 
45

 
5

 
14

Other assets
2

 
2

 
—

 
N/A
 
13

 
10

 
—

Total assets
400

 
401

 
530

 
N/A
 
487

 
441

 
588

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term interest bearing debt
23

 
28

 
51

 
N/A
 
32

 
28

 
51

Long-term interest bearing debt
198

 
229

 
302

 
N/A
 
271

 
256

 
400

Other liabilities
3

 
1

 
2

 
N/A
 
6

 
1

 
3

Short-term debt due to related parties
—

 
—

 
23

 
N/A
 
—

 
—

 
—

Long-term debt due to related parties
137

 
125

 
125

 
N/A
 
145

 
145

 
125

Total liabilities
361

 
383

 
503

 
N/A
 
454

 
430

 
579

Equity
39

 
18

 
27

 
N/A
 
33

 
11

 
9

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Book value of units in the Company's consolidated accounts
434

 
571

 
559

 
N/A
 
450

 
603

 
581


* Refer to “West Polaris acquisition” discussion below.

West Polaris acquisition

On December 30, 2014 we entered into a share sale and purchase agreement with Ship Finance, where we acquired 100% of the equity interests in SFL West Polaris Limited, which was the owner of West Polaris. In addition, the Company purchased an outstanding loan of SFL West Polaris Limited of $97 million from Ship Finance. The acquisition price for the shares and the loan amounted to $111 million. This transaction was accounted for as an equity transaction and no gain or loss was recognized. Non-controlling interest of $7 million has been derecognized, with the residual $6 million recognized as a reduction in Additional Paid in Capital. As at December 31, 2014, the consideration for the shares and loan was unpaid, and was settled on January 5, 2015. Ship Finance continued to provide a guarantee for the bank loan held by SFL West Polaris Limited, until the West Polaris was sold to Seadrill Partners in June 2015.

Historically the Company presented balances due to/from Ship Finance on a gross basis. Beginning on June 30, 2015 the Company has elected to represent this on a net basis, due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis, providing a more appropriate description of the Company’s related party net debt position. Accordingly the Company

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has represented $45 million related to SFL Deepwater Ltd, $5 million related to SFL Hercules Ltd, and $14 million related to SFL Linus Ltd as at December 31, 2014, from Amounts due from related parties (current assets) and offset against long-term debt due to related parties (non-current liabilities). Similarly, the Company has presented $8 million related to SFL Deepwater Ltd and $20 million related to SFL Hercules Ltd as at December 31, 2015 from Amounts due from related parties (Current assets) and offset against Long-term debt due to related parties (Non-current liabilities).

Note 36 - Equity offerings and drilling unit sale transactions with Seadrill Partners

The following table summarizes the issuances of common units for Seadrill Partners between their IPO in October 2012 until the deconsolidation of Seadrill Partners on January 2, 2014:

Date
Number of Common Units Issued to the Public

Number of Common Units Issued to Seadrill

Offering Price ($)

Gross proceeds from public
($'millions)

Net proceeds from public ($'millions)

Seadrill's ownership after the offering

October 24, 2012 (IPO)
10,062,500

14,752,525

22.00

221

203

75.67
%
October 18, 2013
—

3,310,622

32.29

—

—

77.47
%
December 13, 2013
12,880,000

3,394,916

29.50

380

365

62.35
%


The following table summarizes the sale of the Company’s drilling units to Seadrill Partners between its IPO until the deconsolidation of Seadrill Partners on January 2, 2014:

(In US$millions)
T-15

T-16

West Sirius

West Leo

Total

Adjusted sales price *
74

68

922

729

1,793

Less net assets transferred
5

—

(375
)
(116
)
(486
)
Excess of sales price over net assets transferred
79

68

547

613

1,307

Deemed contribution to Seadrill shareholders from non-controlling interest
19

16

105

69

209


* The Adjusted sales price above includes debt assumed and working capital adjustments.

These transactions were deemed to be reorganizations of entities under common control and accordingly no gains or losses were recognized by the Company.

On May 17, 2013, the Company sold its 100% interest in the entities that own and operate the tender rig T-15 to Seadrill Partners a total purchase price of $210 million, less approximately $101 million of debt outstanding, less $35 million of working capital adjustments. The acquisition was funded by issuance of vendor financing loan to Seadrill Partners of $110 million.

On October 18, 2013, the Company sold its 100% interest in the entity that owns the tender rig T-16, and the beneficial interest in the T-16 drilling contract (collectively, the “T-16 Business”), to Seadrill Partners for a total purchase price of $200 million, less approximately $93 million of debt outstanding, less $39 million of working capital adjustments. As part of the consideration, Seadrill Partners issued 3,310,622 common units to Seadrill as consideration for the purchase in a private placement transaction at a price of $32.29 per unit. This resulted in an increase in net assets attributable to the non-controlling interest of $19 million.

On December 13, 2013, the Company sold to Seadrill Partners: (i) 51% of its interest in each of the entities that own, operate and manage the semi-submersible drilling rig, West Sirius (the “Sirius Business”); and (ii) 30% of its interest interests in each of the entities that own and operate the semi-submersible drilling rig, West Leo (the “Leo Business”). The implied purchase prices of the Sirius Business was $1,035 million, less debt assumed of $220 million , plus working capital adjustments of $107 million. The implied purchase prices of the Leo Business was $1,250 million, less debt assumed of $486 million, less working capital adjustments of $35 million. In relation to these acquisitions, Seadrill Partners issued 12,880,000 common units to the public (including 1,680,000 common units issued to underwriters) and 3,394,916 common units to Seadrill, at a price of $29.50 per unit. The gross proceeds raised from the public was $380 million, and the net proceeds raised after issuance fees was $365 million, of which $137 million was attributable to the non-controlling interest. This resulted in an increase in net assets attributable to the non-controlling interest of $83 million.

Note 37 – Assets held for sale

As at December 31, 2015


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On December 2, 2015, the Company signed an amendment with Jurong Shipyard (“Jurong”) for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel (the “Unit”). The deferral period lasts until June 2016, following completion of which, the Company and Jurong have agreed to form a Joint Asset Holding Company for joint ownership of the Unit, to be owned 23% by the Company and 77% by Jurong, in the event no employment is secured for the Unit and no alternative transaction is completed. Until the end of the deferral period, the Company will continue to market the unit for an acceptable drilling contract, and the Unit will remain at the Jurong Shipyard in Singapore. The Company and Jurong may also consider other commercial opportunities for the Unit during this period. However, based on current market conditions, management deems the most probable outcome to be that the Unit will be contributed to the Joint Asset Holding Company.


As a result, the Company has concluded that the West Rigel drilling unit should be classified as “Held for Sale” as at December 31, 2015. A loss has been recognized in the period of $82 million, which is the difference between the net book value of the unit of $210 million, compared to the expected recoverable value of the Company’s investment in the Joint Asset Holding Company of $128 million. The loss has been recognized in “Loss on disposal” in the Statement of Operations.
(In millions of US$)
 
As at December 31, 2015

West Rigel newbuild investment, classified as held for sale
 
210

Loss on disposal
 
(82
)
Non-current assets held for sale
 
128



As at December 31, 2014

During the year ended December 31, 2014, the Company entered into a joint venture agreement with an investment fund controlled by Fintech, for the purpose of owning and managing certain jack-up drilling units located in Mexico under contract with Pemex. The West Oberon, West Intrepid, West Defender, West Courageous and West Titania jack-up drilling rigs (“the jack-up drilling rigs”) were included within the joint venture. The transaction was completed on March 10, 2015, when Fintech subscribed for a 50% ownership interest in the joint venture company, SeaMex, which was previously 100% owned by the Company, and SeaMex simultaneously purchased the jack-up drilling rigs from Seadrill Limited. As a result of the transaction the Company no longer controls the entities that own and operate these jack-up drilling units, and accordingly the Company has deconsolidated these entities as of March 10, 2015. Please refer to Note 11 for more details.

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Assets and liabilities held in the Company’s consolidated balance sheet included as held for sale are shown below:

 (In US$ millions)
 
As at December 31, 2014

ASSETS
 
 
Current assets
 
 
Cash and cash equivalents
 
27

Accounts receivables, net
 
78

Deferred tax assets
 
9

Other current assets
 
20

Total current assets
 
134

 
 
 
Non-current assets
 
 
Drilling units
 
965

Deferred tax assets LT
 
5

Goodwill
 
49

Other non-current assets
 
86

Total non-current assets
 
1,105

Total assets
 
1,239

 
 
 
LIABILITIES
 
 
Current liabilities
 
 
Trade accounts payable
 
(2
)
Other current liabilities
 
(56
)
Total current liabilities
 
(58
)
 
 
 
Non-current liabilities
 
 
Other non-current liabilities
 
(50
)
Total non-current liabilities
 
(50
)
Total liabilities
 
(108
)


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Note 38 - Supplementary cash flow information

The table below summarizes the non-cash investing and financing activities relating to the periods presented:
 
(In US$ millions)
December 31, 2015

 
December 31, 2014

 
December 31, 2013

Non-cash investing activities
 
 
 
 
 
Disposal of subsidiaries - existing bank loan repaid (1)
150

 
—

 
—

Disposal of West Auriga - consideration received as a loan note (2)
—

 
100

 
—

Disposal of West Vela - deferred consideration receivable (2)
—

 
74

 
—

Disposal of tender rig business - deferred consideration received in shares (2)
 
 
—

 
416

Disposal of tender rig business - deferred consideration in receivables (2)
 
 
—

 
145

Acquisition of Archer shares, settled against existing related party loan (3)
—

 
—

 
55

Acquisition of AOD shares, settled against existing related party loan (4)
—

 
—

 
67

Non-cash financing activities
 
 
 
 
 
Repayment of bank loan through disposal of subsidiaries (1)
(150
)
 
—

 
—

Repayment relating to share forward contracts and other derivatives (5)
(136
)
 
—

 
—

Repayment relating to SapuraKencana financing agreements (6)
(93
)
 
—

 
—

Conversion of convertible bond into shares, decrease in long term debt (7)
—

 
584

 
—

Conversion of convertible bond into shares, net increase in equity (7)
—

 
615

 
—

Purchase of SFL Polaris, net increase in related party payables and net decrease in equity (8)
—

 
13

 
—

Dividend to non-controlling interests in VIEs (9)
—

 
—

 
223


1.
Existing debt of the Company was directly settled as consideration for the disposal of certain drilling rigs to the SeaMex joint venture - see Note 5 to the consolidated financial statements included herein, for more details.
2.
Disposals of the West Auriga, West Vela, in 2014 and the disposal of the tender rig business in 2013 - refer to Note 11 to the consolidated financial statements included herein, for more details.
3.
Private placement of Archer shares in February 2013 was settled against related party loan receivable - refer to Note 17 to the consolidated financial statements included herein, for more details.
4.
Private placement of AOD shares in March 2013 was settled against elated party loan receivable - refer to Note 17 to the consolidated financial statements included herein, for more details. -
5.
During the period, Company settled Sevan share repurchase agreements using cash balances already classified as restricted.
6.
During the period, the Company settled SapuraKencana financing agreements using cash balances already classified as restricted.
7.
In July 2014, the Company launched a voluntary incentive payment offer to convert any and all of the $650 million principal amount of 3.375% convertible bonds. Holders converted at the contractual conversion price of $27.69 per share and received an incentive payment of $12,102.95 per $100,000 principal amount of bond held. As a result of the transaction, the number of common shares outstanding in the Company increased by 23.8 million shares, with an increase to equity of $893 million. $278 million of the total consideration transferred on conversion was allocated to the reacquisition of the embedded conversion option and recognized as a reduction of stockholders’ equity.
8.
Purchase of SFL Polaris from Ship Finance - refer to Note 35 - VIEs.
9.
Dividends declared by VIEs in 2013 to Ship Finance was settled against related party balances with Ship Finance - refer to Note 27 - Non-Controlling interests.

Note 39 – Subsequent Events

Agreement with DSME Shipyard
On January 15, 2016 Seadrill announced that an agreement with DSME shipyard had been reached to defer the delivery of 2 ultra-deepwater drillships, the West Aquila and West Libra, until the second quarter 2018 and first quarter of 2019 respectively. Under the terms of the original construction contracts, the units were to be delivered by the end of the second quarter of 2016 and the total final yard installment for both units of over $800 million was due at that time. This agreement significantly improves the Company’s near term liquidity position by deferring these capital commitments to 2018 and 2019 with no further payments to the yard until that time.

Sevan Developer deferral agreement with Cosco
On April 15, 2016, Sevan Drilling and Cosco agreed to exercised the second six-month deferral option for the Sevan Developer newbuilding, to extend the deferral agreement until October 15, 2016. The final delivery installment has been amended to $473.4 million, representing 90% of the $526.0 million contract price and Cosco will refund $26.3 million, or 5% of the contract price, plus other associated costs to Sevan Drilling.


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Agreement with Dalian Shipyard
On April 18, 2016, we entered into agreements with Dalian shipyard to further the defer the deliveries of all eight jack-ups under construction. Previously one unit was due at the end of 2015, five units were due in 2016, and two units were due in 2017. Following the deferral agreement, one unit is now due at the end of 2016, four units are now due in 2017, and three units are now due in 2018. This agreement significantly improves the Company’s near term liquidity position by deferring these capital commitments with no further payments to the yard until the revised delivery date.
 
Amendments to our secured credit facilities
On April 28, 2016 the Company executed an amendment to the covenants contained within its secured credit facilities, which among other things, amend the equity ratio, leverage ratio, minimum-value-clauses, and minimum liquidity requirements. The covenant amendments are in place until June 30, 2017. In addition the maturity dates of the $450 million senior secured credit facility, related to the West Eminence, the $400 million senior secured credit facility, and the $2,000 million senior secured credit facility for our consolidated subsidiary, NADL, have been amended to December 31, 2016, May 31, 2017 and June 30, 2017 respectively. Please see “Note 23. Long-term debt—Covenants contained within our debt facilities” for more information.

Sale of investment in SapuraKencana
On April 27, 2016 the Company sold all of its investment in shares of SapuraKencana resulting in net cash proceeds of approximately $195 million.

Drilling Contracts
On February 8, 2016, we secured a new drilling contract in Angola for the West Eclipse, which is expected to commence in the second quarter of 2016. The contract is for a firm period of 2 years and increases contract revenue backlog by approximately $285 million, inclusive of mobilization. As part of this agreement, the backlog for the West Polaris has been decreased by approximately $95 million, which reduces the contingent consideration that we receive from Seadrill Partners, following the sale of the West Polaris to Seadrill Partners in June 2015.

On March 23, 2016, we extended the contract for the West Tellus with Petrobras by 18 months, commencing in April 2018 to the end of October 2019. The total backlog for the contract extension is approximately $164 million. As part of the agreement to extend the West Tellus, we agreed to a dayrate reduction on the current contract effective from February 26, 2016, resulting in a $132 million reduction in our backlog.
The resulting net effect of this agreement is an increase in contract backlog of $32 million.

On March 30, 2016, Sevan Drilling and Petrobras terminated early the Sevan Driller contract and reduced the contract dayrate on the drilling contract for the Sevan Brasil. Subsequent to the effective cancellation of the Sevan Driller contract the unit was awarded a contract by Shell in Brazil for 60 days. The combined impact of the cancellation, reduction and new award is a decrease in contract backlog of approximately $127 million.





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Seadrill Partners LLC
Index to Consolidated and Combined Carve-out Financial Statements



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Management’s Report on Internal Control 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) promulgated under the Exchange Act. Internal control over financial reporting is defined in Rule 13a-15(f) or 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, 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 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 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 controls 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 Officer and Principal Financial Officer, concluded that the Company's internal controls over financial reporting are effective as of December 31, 2015.
The effectiveness of the Company's 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.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Members of Seadrill Partners LLC

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows and of changes in member’s capital present fairly, in all material respects, the financial position of Seadrill Partners LLC and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these 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 the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.

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.


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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, 2016



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SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF OPERATIONS
for the years ended December 31, 2015, 2014 and 2013
(In US$ millions, except per unit data)
 
 
 
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 party transactions.
A Statement of Other Comprehensive Income has not been presented as there are no items recognized in other comprehensive income.
See accompanying notes that are an integral part of these Consolidated and Combined Carve-out Financial Statements.


A - 4
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SEADRILL PARTNERS LLC
CONSOLIDATED BALANCE SHEETS
As at December 31, 2015 and 2014
(In US$ millions)
 
 
2015
 
2014
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
319.0

 
$
242.7

Accounts receivables, net
 
278.3

 
294.5

Amount due from related party
 
128.1

 
62.7

Other current assets
 
166.6

 
129.3

Total current assets
 
892.0

 
729.2

Non-current assets:
 
 
 
 
Drilling units
 
5,547.3

 
5,141.1

Goodwill
 
3.2

 
3.2

Deferred tax assets
 
34.2

 
18.4

Amount due from related party
 
50.0

 
—

Other non-current assets
 
314.4

 
376.2

Total non-current assets
 
5,949.1

 
5,538.9

Total assets
 
$
6,841.1

 
$
6,268.1

 
 
 
 
 
LIABILITIES AND MEMBERS’ CAPITAL
 
 
 
 
Current liabilities:
 
 
 
 
Current portion of long-term debt
 
$
93.8

 
$
68.9

Current portion of long-term related party debt
 
145.8

 
40.4

Trade accounts payable and accruals
 
24.1

 
7.9

Current portion of deferred and contingent consideration to related party
 
60.4

 
25.8

Related party payable
 
304.7

 
250.0

Other current liabilities
 
217.9

 
227.4

Total current liabilities
 
846.7

 
620.4

Non-current liabilities:
 
 
 
 
Long-term debt
 
3,440.4

 
3,156.6

Long-term related party debt
 
160.2

 
306.1

Deferred and contingent consideration to related party
 
185.4

 
111.2

Deferred tax liability
 
43.7

 
—

Long-term related party payable
 
50.0

 
—

Other non-current liabilities
 
17.3

 
29.5

Total non-current liabilities
 
3,897.0

 
3,603.4

 
 
 
 
 
Commitments and contingencies (see note 15)
 
—

 
—

Equity
 
 
 
 
Members’ Capital:
 
 
 
 
Common unitholders (issued 75,278,250 units)
 
945.5

 
913.3

Subordinated unitholders (issued 16,543,350 units)
 
18.7

 
11.7

Seadrill member interest
 
—

 
3.2

Total members’ capital
 
964.3

 
928.2

Non-controlling interest
 
1,133.1

 
1,116.1

Total equity
 
2,097.4

 
2,044.3

Total liabilities and equity
 
$
6,841.1

 
$
6,268.1

See accompanying notes that are an integral part of these Consolidated and Combined Carve-out Financial Statements.


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SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CASH FLOWS
for the years ended December 31, 2015, 2014 and 2013
(In US$ millions)
 
 
 
2015
 
2014
 
2013
Cash Flows from Operating Activities
 
 
 
 
 
 
Net income
 
$
488.4

 
$
314.6

 
$
415.4

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
237.5

 
198.7

 
141.2

Amortization of deferred loan charges
 
20.2

 
17.6

 
7.1

Amortization of favorable contracts
 
66.9

 
14.8

 
—

Gain on bargain purchase
 
(9.3
)
 
—

 
—

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

 
99.1

 
(60.2
)
Unrealized foreign exchange gain
 
(1.7
)
 
—

 
—

Payment for long term maintenance
 
(49.8
)
 
(39.1
)
 
(26.5
)
Deferred income tax (benefit) / expense
 
27.9

 
(8.6
)
 
(9.2
)
West Aquarius settlement
 
—

 
—

 
25.0

Accretion of discount on deferred consideration
 
13.3

 
—

 
—

 
 
 
 
 
 
 
Changes in operating assets and liabilities, net of effect of acquisitions
 
 
 
 
 
 
Trade accounts receivable
 
49.8

 
(46.3
)
 
(9.4
)
Prepaid expenses and accrued income
 
(1.9
)
 
—

 
—

Trade accounts payable
 
15.3

 
(10.7
)
 
48.6

Related party balances
 
(29.0
)
 
31.4

 
56.9

Other assets
 
57.9

 
9.9

 
2.0

Other liabilities
 
(45.0
)
 
41.7

 
(14.0
)
Changes in deferred revenue
 
(12.0
)
 
(14.4
)
 
(12.9
)
Other, net
 
(0.5
)
 
—

 
—

Net cash provided by operating activities
 
$
859.8

 
$
608.7

 
$
564.0

 
 
 
 
 
 
 
Cash Flows from Investing Activities
 
 
 
 
 
 
Additions to newbuildings and drilling units
 
(18.6
)
 
(31.6
)
 
(159.3
)
Acquisition of subsidiaries, net of cash acquired
 
(214.7
)
 
(1,137.7
)
 
—

Loan granted to related parties
 
(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
)



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SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CASH FLOWS
for the years ended December 31, 2015, 2014 and 2013
(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.

See accompanying notes that are an integral part of these Consolidated and Combined Carve-out Financial Statements.


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SEADRILL PARTNERS LLC
CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CHANGES IN MEMBERS’
CAPITAL
for the years ended December 31, 2015, 2014 and 2013
(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

 
$
44.6

 
$
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

 
$
18.7

 
$
—

 
$
964.3

 
$
1,133.1

 
$
2,097.4

See accompanying notes that are an integral part of these Consolidated and Combined Carve-out Financial Statements.


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SEADRILL PARTNERS LLC
NOTES TO CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

Note 1- General information
Background
On June 28, 2012, Seadrill Limited (“Seadrill”) formed Seadrill Partners LLC (the “Company”) under the laws of the Republic of the Marshall Islands.
On October 24, 2012, the Company completed its initial public offering of its 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 Company 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's 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. Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC are collectively referred to as “OPCO”. These transactions described above were reflected as a reorganization of entities under common control and, therefore, the assets and liabilities acquired from Seadrill were recorded at historical cost by the Company.
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 T-15. To finance the acquisition 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.
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 West Auriga 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 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%).


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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”). The amounts are presented in United States dollar (US dollar) rounded to the nearest hundred thousand, unless otherwise stated.
The accounting policies set out below have been applied consistently to all periods in these consolidated and combined carve-out financial statements, unless otherwise noted.

Basis of consolidation
Investments in companies in which the Company directly or indirectly holds more than 50% of the voting 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's 100% ownership of its general partner Seadrill Operating GP LLC. Ownership of the general partner is deemed to provide the Company with a controlling financial interest and, as such, the Company consolidates Seadrill Operating LP in its financial statements. The Company also owns a 51% limited partner interest in Seadrill Capricorn Holdings LLC.
All inter-company balances and transactions are eliminated. The Company allocated the initial company capital of unitholders 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 the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. The excess of the proceeds paid, if any, 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 the interests in the combining entity were actually acquired are retroactively adjusted to include the results 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.

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

Note 2 - Accounting policies
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’s revenues are derived from dayrate based drilling contracts (which may include lump sum fees for mobilization and demobilization) and other service contracts. Both dayrate base and lump sum fee revenues are recognized ratably over the contract period when services are rendered. Under some contracts, the Company is 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 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 over the original contract term, excluding any extension option periods not exercised by the Company's customers. Contingent demobilization fees are recognized as earned upon completion of the drilling contract.

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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's revenues. The Company generally records tax-assessed revenue transactions on a net basis in the consolidated and combined carve-out statement of income.

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's 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 relating to certain services, including the provision of onshore 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
Mobilization costs incurred as part of a contract are capitalized and recognized as expense over the contract term, excluding any extension periods not exercised by the Company's customers. The 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 and are expensed as incurred.

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 as costs related to onshore personnel in various locations where the Company operates the rigs and are expensed 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. 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. dollars 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.
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
The Company computes earnings per unit using the two-class method set out in US GAAP. Any undistributed earnings for the period are allocated to the various unitholders in accordance with the cash distribution provisions contained in 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 the cash distribution model.
The sum of the distributed amounts and the allocation of the undistributed earnings or deficit to each class of unitholders is divided by the weighted average number of units outstanding during the period. Diluted earnings per unit, if applicable, reflects the potential dilution that could occur if potentially dilutive instruments were exercised, resulting in the issuance of additional units that would then share in the Company's net earnings.

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Current and non-current classification
Assets and liabilities 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 establishes 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 considers 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’s 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.

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 recorded 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 value of interest-rate swap agreements, which have not been designated as hedging instruments, are recorded as a gain or loss as a separate line item within financial items in the statement of operations.

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’s 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.

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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.

Provisions
A provision is recognized in the balance sheet when the Company has 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, 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 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 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 of December 31, 2014 has been retrospectively adjusted to reflect this change in accounting principle. $7.6 million 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 material impact on its consolidated financial statements and related disclosures.


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In November 2015, 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 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 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 did not have a material impact on Company's consolidated financial statements and related disclosures.

Recently Issued Accounting Standards

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 2015 the FASB proposed to defer the effective date of the guidance by one year. Based on this proposal, public entities would need to apply the new guidance for annual and interim periods beginning after December 15, 2017, 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. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its 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.

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. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-07, Investments-Equity Method 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 use of the equity method. The guidance will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years 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.

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 accounting of the new revenue standard. The guidance will be effective for annual and interim periods beginning after December 15, 2017, 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. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The update simplifies the accounting for share based payment transactions. The guidance will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years 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.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. The update provide more clarification about identifying performance obligations and licensing. The guidance will be effective for annual and interim periods beginning after December 15, 2017, 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. Early adoption is not permitted until periods beginning after December

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15, 2016. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

Note 3 - Business acquisitions

For the year-ended December 31, 2015

West Polaris Acquisition
On June 19, 2015, the Company’s 58% owned subsidiary, Seadrill Operating LP (“Seadrill Operating”), completed the purchase (the “Polaris Acquisition”) of 100% of the ownership interests in Seadrill Polaris Ltd. (“Seadrill Polaris”) the entity that owns and operates the drillship the West Polaris (the “Polaris Business”) from Seadrill. Seadrill Operating 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 million of debt outstanding under the existing 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”).

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

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

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

Consideration
 
Cash
204.0

Contingent consideration
95.3

Seller's Credit
44.6

Plus: Working capital adjustment
30.7

Fair value of total consideration transferred
374.6

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

Current assets
52.1

Intangible asset - favorable drilling contract
124.3

Drilling unit
575.3

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

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


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 are 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, the fair value of the drilling unit recognized was $575.3 million.

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. 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 be amortized over the remaining contract period until March 2018.

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 capital 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 Polaris achieved 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 statement of operations within general and administrative expenses.

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Measurement period adjustment
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 ongoing negotiations were concluded and the customer contract for the West Polaris was adjusted to $490 thousand per day. This 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. As a result, the company has recognized a $30.3 million reduction in the Gain on Bargain Purchase since the acquisition date and a $9.3 million Net Gain on Bargain Purchase for the year ended December 31, 2015.
The gain on the bargain purchase has been recorded in the line “Gain on bargain 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 Polaris achieves 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 the West Polaris is 0% and or the contracted dayrate is re-negotiated to less than $450 thousand per day.

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 Income
488.4

 
535.7

 
314.6

 
388.9

Net income attributable to Seadrill Partners LLC members
257.2

 
284.6

 
138.2

 
181.3



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.

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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
 
Cash
696.9

Discount note issued
100.0

Working capital adjustment
(330.4
)
Fair value of total consideration transferred
466.5

 
 
Recognized amounts of identifiable assets acquired and liabilities assumed at estimated fair value
 
Cash
24.4

Current assets
44.4

Intangible asset - favorable drilling contract
76.2

Drilling unit
1,065.7

Non current assets
76.6

Long term interest bearing debt
(443.1
)
Current liabilities
(380.6
)
Total identifiable net assets
463.6

 
 
Goodwill
2.9

Total
466.5


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.

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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
Revenues
1,342.6

 
1,390.7

 
1,064.3

 
1,096.1

Net Income
314.6

 
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.

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(In US$ millions)
November 4, 2014

Consideration
 
Cash
467.0

Mobilization payable
73.7

Contingent consideration
65.7

Less: Working capital adjustment
(6.0
)
Fair value of total consideration transferred
600.4

 
 
Recognized amounts of identifiable assets acquired and liabilities assumed at estimated fair value
 
Cash
1.9

Current assets
61.4

Intangible asset - favorable drilling contract
204.7

Drilling unit
755.8

Non current assets
61.8

Long term interest bearing debt
(433.1
)
Current liabilities
(52.3
)
Total identifiable net assets
600.2

 
 
Goodwill
0.2

Total
600.4



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
Revenues
1,342.6

 
1,532.4

 
1,064.3

 
1,083.4

Net Income
314.6

 
407.6

 
415.4

 
403.8


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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 Business was acquired 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.



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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’s fleet, which is regarded as one single global segment, and is reviewed by the Chief Operating Decision Maker, which is the Company's board of directors, as an aggregated sum of assets, liabilities and activities generating distributable cash to meet minimum quarterly distributions.
A breakdown of the Company’s revenues by customer for the years ended December 31, 2015, 2014 and 2013 is as follows:
 
 
2015
 
2014
 
2013
BP
44.8
%
 
41.5
%
 
35.0
%
ExxonMobil *
32.1
%
 
26.4
%
 
14.5
%
Tullow
13.5
%
 
17.4
%
 
18.8
%
Chevron
8.5
%
 
14.7
%
 
12.1
%
Total
—
%
 
—
%
 
19.6
%
Other
1.1
%
 
—
%
 
—
%
Total
100.0
%
 
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.
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, 2014 and 2013 and fixed assets as of December 31, 2015 and 2014 by geographic area:
Revenues

(In US$ millions)
2015
 
2014
 
2013
United States
$
781.1

 
$
556.6

 
$
370.4

Nigeria
250.1

 
228.5

 
213.3

Ghana
234.7

 
233.5

 
198.6

Canada
190.9

 
126.1

 
153.5

Angola
179.4

 
92.3

 
87.9

Thailand
99.8

 
105.6

 
40.6

Other
5.6

 
—

 
—

Total
$
1,741.6

 
$
1,342.6

 
$
1,064.3


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Fixed Assets—Drilling Units (1)
 
(In US$ millions)
2015
 
2014
United States
$
2,927.4

 
$
3,024.3

Ghana
591.5

 
608.4

Angola
571.3

 
182.5

Canada
519.2

 
539.3

Nigeria
508.0

 
525.4

Thailand
251.5

 
261.2

Myanmar
178.4

 
—

Total
$
5,547.3

 
$
5,141.1


(1)
The fixed assets referred to in the table above include the eleven drilling units at December 31, 2015 and ten drilling units at December 31, 2014. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

Note 5 – Taxation
Income taxes consist of the following:
 
Year Ended December 31,
(In US$ millions)
2015
 
2014
 
2013
Current tax expense:
 
 
 
 
 
United Kingdom
—

 
—

 
—

Foreign
72.6

 
43.5

 
42.4

Total current tax expense
72.6

 
43.5

 
42.4

Deferred tax (benefit) expense:
 
 
 
 
 
United Kingdom
—

 
—

 
—

Foreign
28.0

 
(8.7
)
 
(9.2
)
Total income tax expense
100.6

 
34.8

 
33.2


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, 2014 and 2013 differs from the U.K. statutory income tax rate as follows:
 
 
2015
 
2014
 
2013
U.K. statutory income tax rate
20.3
 %
 
21.3
 %
 
23.3
 %
Non-U.K. taxes
(3.2
)%
 
(11.3
)%
 
(15.8
)%
Effective income tax rate
17.1
 %
 
10.0
 %
 
7.5
 %
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

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The net deferred tax assets consist of the following:
(In US$ millions)
2015
 
2014
Provisions
19.7

 
1.5

Net operating losses carry forward
10.7

 
14.8

Property, plant and equipment
—

 
3.0

Other
3.8

 
—

Gross deferred tax assets
34.2

 
19.3

Valuation allowance related to NOL
—

 
(0.9
)
Net deferred tax asset
34.2

 
18.4

The net deferred tax liabilities consist of the following:
(In US$ millions)
2015
 
2014
Property, plant and equipment
42.6

 
—

Other
1.1

 
—

Gross deferred tax liabilities
43.7

 
—

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 asset
34.2

 
18.4

Long-term deferred tax liability
(43.7
)
 
—

Net deferred tax (liability) / asset
(9.5
)
 
18.4

As of December 31, 2015, deferred tax assets related to net operating loss ("NOL") carryforwards was $10.7 million, which can be used to offset future taxable income. NOL carry forwards, which were generated in various jurisdictions will expire, if not utilized, in 2033 and 2034. A valuation allowance of nil exists on the NOL carryforwards results where we do not expect to generate future taxable income.

In November 2015, 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 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.

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Uncertain tax positions

As of December 31, 2015, the Company had uncertain tax positions of $9.0 million which is included in other current liabilities on our consolidated balance sheet. The changes to our liabilities related to uncertain tax positions, including interest and penalties that we recognize as a component of income tax expense, were as follows:
(In US$ 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 period
9.0

 
—

 
—

Decreases as a result of positions taken in prior periods
—

 
—

 
—

Decreases as a result of positions taken in the current period
—

 
—

 
—

Balance end of period
9.0

 
—

 
—


As of December 31, 2015, if recognized, $9.0 million of our unrecognized tax benefits, including interest and penalties, would have a favorable impact on our effective tax rate.

Note 6 – Other revenues
Related party other revenues comprise the following items:
 
 
Year Ended December 31,
(In US$ millions)
2015
 
2014
 
2013
Termination payments revenue
74.7

 
—

 
—

Related party other revenues
13.4

 
—

 
5.8

Total
88.1

 
—

 
5.8

Termination payments earned during the year ended December 31, 2015 include the termination fees after the West Sirius drilling contract was canceled before the completion date, with an effective date of April 1, 2015.
The Company's Nigerian service company earned related party revenues relating to certain services, including the provision of onshore 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 year ended December 31, 2015 and Seadrill’s West Polaris drilling rig that was operating in Nigeria during the year ended December 31, 2013.

Note 7 – Accounts receivable
Accounts receivable are presented net of allowances for doubtful accounts. There were no provisions related to allowances for doubtful accounts as at December 31, 2015. There was a provision of $5.9 million related to allowance for doubtful accounts as at December 31, 2014. There were no provisions related to allowances for doubtful accounts as at December 31, 2013.
The Company did not recognize any bad debt expense in 2015, 2014 or 2013, but has instead reduced contract revenues 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 customers
23.5

 
18.5

Mobilization revenue receivable - short-term
42.0

 
42.0

Favorable contracts to be amortized - short-term
70.5

 
40.5

Insurance receivable
12.1

 
14.9

Prepaid expenses
13.1

 
11.2

Other
5.4

 
2.2

Total other current assets
166.6

 
129.3


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


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. The gross carrying amounts and accumulated amortization 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 period
280.9

 
(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 period
357.3

 
(81.7
)
 
275.6

 
280.9

 
(14.8
)
 
266.1

*Additions to favorable contracts during the year are net of measurement period adjustments.


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 contracts
70.5

 
70.5

 
50.6

 
45.6

 
38.4

 
275.6



Note 9 – Drilling units
 
(In US$ millions)
December 31,
2015
 
December 31,
2014
Cost
6,434.2

 
5,790.5

Accumulated depreciation
(886.9
)
 
(649.4
)
Net book value
5,547.3

 
5,141.1

Depreciation and amortization expense related to the drilling units was $237.5 million, $198.7 million and $141.2 million for the years ended December 31, 2015, 2014 and 2013 respectively.

Note 10 – Other non-current assets
 
(In US$ millions)
December 31,
2015
 
December 31,
2014
Mobilization revenue receivable - long-term portion
109.2

 
150.6

Favorable contract – long-term portion
205.2

 
225.6

Total other non-current assets
314.4

 
376.2


The Mobilization revenue receivable - long-term portion consists 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. Please also refer to Note 8 - Other non-current assets.


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Note 11 – Debt

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 Facilities
2,894.7

 
2,881.0

$1,450 Senior Secured Credit Facility
382.6

 
422.9

   $420 West Polaris Facility
315.0

 
—

Sub-total external debt
3,592.3

 
3,303.9

Less current portion long term external debt
(105.3
)
 
(76.5
)
Long-term external debt
3,487.0

 
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 Agreement
139.0

 
158.8

Sub-total Rig Financing Agreements
196.5

 
237.0

 
 
 
 
 Other related party debt
 
 
 
$109.5 T-15 vendor financing facility
109.5

 
109.5

Total related party debt
306.0

 
346.5

Less current portion of related party debt
(145.8
)
 
(40.4
)
Long-term related party debt and related party loan notes
160.2

 
306.1

 
 
 
 
Total external and related party debt
3,898.3

 
3,650.4

The outstanding debt as of December 31, 2015 is repayable as follows: 
(In US$ millions)
As at December 31,
2016
251.1

2017
240.8

2018
598.8

2019
29.0

2020
29.0

2021 and thereafter
2,749.6

Total external and related party debt
3,898.3


As discussed in "Note 2 - Accounting policies", 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



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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 Senior Secured Credit Facilities
On February 21, 2014, Seadrill Operating LP, Seadrill Capricorn Holdings LLC 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 $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 this transaction were used to (a) refinance debt related to the rig facilities for the West Capella, West Aquarius, West Sirius and West Leo , (b) repay in part 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 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 to 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 million 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 from the revolving credit facility to partially finance the acquisition of the entity that owns the West Polaris.
The Amended Senior Secured Credit Facilities are guaranteed on a senior secured basis by the Borrowers and the Borrowers’ subsidiaries that own or charter the West Capella, West Aquarius, West Sirius, West Leo, West Capricorn and West Auriga. 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 the drilling units pledged as security was $3.8 billion.
Loans under the Amended Senior Secured Credit Facilities will bear interest, at the Company's option, at a rate per annum equal 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 matures in February 2021. Amortization payments in the amount of 0.25% of the original term loan amount are required to 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 term loans using proceeds from asset sales that are not otherwise utilized for permitted purposes and 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 element of the term loan facility at a weighted average fixed rate of 2.49% per annum. A variable rate option included in the swap provides that the counterparty shall pay 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 ended December 31, 2015, the Company drew down $50.0 million of the $100.0 million revolving credit facility to finance a portion of the Polaris Acquisition. Refer to Note 3 – Business acquisitions for more information.
As of December 31, 2015, the outstanding balance of the term loan was $2,894.7 million and $50.0 million of the $100 million revolving facility remains undrawn.

$1,450 million Senior Secured Credit Facility
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 the West Auriga, 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 acquisition in November 2014, the entity that owns the West Vela owed $433 million under the facility. The facility has 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

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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 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 at December 31, 2015, the total net book value of the West Vela pledged as security was $734.8 million. The outstanding balance relating to the West Vela as of December 31, 2015 was $382.6 million.

$420 million West Polaris Facility
On June 19, 2015, in connection with the completion of the Polaris Acquisition, Seadrill Polaris Ltd. as borrower, entered into an amendment and restatement of the $420.0 million 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 million revolving credit facility. The West Polaris Facility matures on January 31, 2018 and bears interest at a rate of LIBOR plus 2.25%. Commitment fees are payable quarterly in arrears on the 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.

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 over the West Polaris, and first priority perfected security interests granted by Seadrill Polaris in its earnings, earnings accounts and insurances. The net book value of the West Polaris pledged as security as at December 31, 2015 is $571.3 million.

$440 million Rig Financing Loan Agreements

Seadrill financed the construction of the 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, 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 to the T-15 and T-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.    The $440 million Rig Financing Agreement is secured by the T-15 and T-16 and one other rig owned by Seadrill. In May 2013, Seadrill entered into an amendment to the $440 million Rig Financing Agreement to allow for the transfer of the T-15 to Seadrill Partners Operating LLC and to add Seadrill Partners Operating LLC as a guarantor under the $440 million Rig Financing Agreement.  In October 2013, Seadrill entered into an amendment to the $440 million Rig Financing Agreement to allow for the transfer of the T-16 to Seadrill Partners Operating LLC. Effective from the respective dates of transfer of the T-15 and the T-16 from Seadrill to Seadrill Partners Operating LLC, the entities that own the T-15 and T-16 entered into intercompany loan agreements with Seadrill in the amount of approximately $100.5 million and 93.1 million, respectively. 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 million 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-15 and 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 party 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.

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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 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 ($78.2 million as of December 31, 2014).

$109.5 million Vendor Financing Loan Agreement
In May 2013, a subsidiary of 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, 2014 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 lenders 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:

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;

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•
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.

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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.


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$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;

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▪
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

Taxes payable
28.4

 
12.1

Employee and business withheld taxes, social security and vacation payment
15.4

 
19.5

VAT payable
4.0

 
6.1

Deferred mobilization/demobilization revenues short-term
18.0

 
15.9

Unrealized loss on derivatives
84.2

 
56.1

Accrued expenses and other current liabilities
67.9

 
117.7

Total other current liabilities
217.9

 
227.4


Note 13 – Related party transactions
The Company has entered into certain agreements 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, 2014 and 2013 were $161.8 million, $158.1 million and $122.5 million respectively.

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Net expenses (income) with Seadrill: 
(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


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 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.


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(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., 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, providing Seadrill Offshore AS with the right to use the West Aquarius. In October 2012, this bareboat charter arrangement was replaced with 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 use the West Aquarius in order to perform its obligations 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 effect was income of $2.1 million.
Seadrill T-15 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 in the charter hire rate between the two charters is retained by Seadrill UK Ltd., 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 was net income of $1.6 million (2014: net income of $25.8 million, 2013: net income 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, 2014 the Company earned no other revenues within the Company's Nigerian service company and related expenses were nil.
During the year ended December 31, 2013, the company earned revenues of $5.8 million, relating to certain services, including the provision of onshore and offshore personnel, which the Company provided to Seadrill’s West Polaris drilling rig that was operating in Nigeria during that period. Related operating expenses related to these operations in the year ended December 31, 2013 were $5.5 million.

(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 the acquisition of the West Vela in 2014 the Company recognized a long term deferred consideration balance of $61.7 million and a long term contingent consideration balance of $49.5 million. The short-term portion of the deferred consideration balance and the short-term contingent consideration balance was $25.8 million.
As of December 31, 2015 the short-term portion of these balances relating to the West Polaris and the West Vela are $30.7 million and $29.7 million respectively. As of December 31, 2015 the long-term portion of the balances relating to the West Polaris and West Vela are $90.1 million and $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.
During the year ended December 31, 2015, the Company recognized an unwind of the discount of the contingent liabilities of $13.3 million.


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(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.
•
$70.0 million discount note - On December 13, 2013, 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.
•
$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.

(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

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 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.

These transactions have been classified within current and long-term portions of "Amount due from related party", "Related party payable" and "Long-term 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.


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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.

Spare parts agreement with Seadrill
During the year ended December 31, 2015, a subsidiary of Seadrill entered into an agreement with the Company 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 during the stacking period, but must replace them as required by the Company at its own cost.

Other indemnifications and guarantees
Performance guarantees
Seadrill Limited provides performance guarantees in connection with the Company’s drilling contracts in favor of customers of the Company, amounting to a total of $370.0 million as at December 31, 2015 (December 31, 2014: $370.0 million).

Customs guarantees

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Seadrill Limited provides customs guarantees in connection with the Company’s operations, primarily in Nigeria, in favor of banks amounting to a total of $85.8 million as at December 31, 2015 (December 31, 2014: $92.4 million).

Tax indemnifications
Under the Omnibus Agreement and Sale and Purchase agreements relating to acquisitions from Seadrill subsequent to 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.

Environmental and other indemnifications
Under the Omnibus Agreement and Sale and Purchase agreements relating to acquisitions from Seadrill subsequent to 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 on October 24, 2012.

Note 14 – Risk management and financial instruments
The Company is exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. The Company may enter into a variety of derivative instruments and contracts to maintain the desired level of exposure arising from these risks.
Interest rate risk
The Company’s exposure 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, whilst 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.
Interest rate swap agreements
At December 31, 2015, the Company had interest rate swap agreements with Seadrill for an outstanding principal of $655.3 million (December 31, 2014: $690.1 million) swapping floating rate for an average fixed rate of 1.23% per annum. The combined total fair value of the interest rate outstanding as at December 31, 2015 amounted to a gross and net asset of $2.2 million (December 31, 2014: gross and net asset of $6.0 million). This is classified within related party receivables in the Company's balance sheet as of December 31, 2015 (December 31, 2014: within related party receivables). 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 (Loss)/gain on derivative financial instruments. The loss recognized for 2015 was $10.2 million (2014: loss of $41.6 million, 2013 gain of $49.9 million).
At December 31, 2015, the Company had interest rate swap agreements with external parties for a combined outstanding principal of $2,851.9 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 value 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 ).


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The Company’s interest rate swap agreements as at December 31, 2015, were as follows:
 
Outstanding principal as at December 31, 2015
 
Receive rate
Pay rate
Expiry of contract
(In US$ millions)
 
 
 
 
416.3

(1), (2)
3 month LIBOR
1.10%
July 2, 2018
100.0

(2)
3 month LIBOR
1.36%
October 29, 2019
70.4

(1), (2)
3 month LIBOR
1.11%
June 19, 2020
68.6

(1), (2)
3 month LIBOR
1.93%
December 21, 2020
2,851.9

(1)
3 month LIBOR
 2.45% to 2.52%
February 21, 2021

(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.
(2) Related party interest rate swap agreements.

The counterparties to the above interest rate swap agreements are Seadrill and various banks. The Company believes the counterparties to be creditworthy.

Foreign currency risk
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 U.S. Dollars. The Company does, however, earn revenue and incur expenses in Canadian Dollars and Nigerian Naira and there is a risk that currency fluctuations could have an adverse effect on the value of the Company's cash flows.

Concentration of 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.

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 equivalents
319.0

 
319.0

 
242.7

 
242.7

Current portion of long-term debt
88.0

 
105.3

 
68.3

 
76.5

Current portion of long-term debt to related party
145.8

 
145.8

 
40.4

 
40.4

Long-term debt
1,763.5

 
3,487.0

 
2,574.8

 
3,227.4

Long-term portion of debt to related party
160.2

 
160.2

 
306.1

 
306.1

Related party deferred and contingent consideration
245.8

 
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.


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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 assets
2.2

—

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 assets
6.0

—

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.
The fair values of interest rate swaps are calculated using well-established independent valuation techniques applied to contracted cash flows and LIBOR interest rates as of December 31, 2015 and December 31, 2014.

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Retained risk
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 Company for the associated cost for its respective drilling units. 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 OPCO 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. OPCO 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 Risk
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, 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
BP
44.8
%
 
41.5
%
 
35.0
%
ExxonMobil *
32.1
%
 
26.4
%
 
14.5
%
Tullow
13.5
%
 
17.4
%
 
18.8
%
Chevron
8.5
%
 
14.7
%
 
12.1
%
Total
—
%
 
—
%
 
19.6
%
Other
1.1
%
 
—
%
 
—
%
Total
100.0
%
 
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.



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Note 15 – Commitments and contingencies
Legal Proceedings
From time to time we are a party, as plaintiff or defendant, to lawsuits in various jurisdictions in the ordinary course of business or in connection with our 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 our financial statements as of December 31, 2015.

Pledged Assets
The book value of assets pledged under mortgage and overdraft facilities at December 31, 2015 and 2014 was $5,367.7 million, and $4,953.4 million, respectively.

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,
(in US $ millions, except per unit data)
2015
 
2014
 
2013
Net income attributable to:
 
 
 
 
 
Common unitholders
$
184.1

 
$
109.2

 
$
56.4

Subordinated unitholders
40.5

 
29.0

 
30.2

Seadrill member interest (1)
32.6

 
—

 
57.8

Net income attributable to Seadrill Partners LLC owners
$
257.2

 
$
138.2

 
$
144.4

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

 
62,374

 
26,266

Subordinated unitholders
16,543

 
16,543

 
16,543

 
 
 
 
 
 
Earnings per unit (basic and diluted):
 
 
 
 
 
Common unitholders
$
2.45

 
$
1.75

 
$
2.15

Subordinated unitholders
$
2.45

 
$
1.75

 
$
1.83

 
 
 
 
 
 
Cash distributions declared and paid in the period per unit (2)
$
1.7025

 
$
1.6025

 
$
1.2325

 
 
 
 
 
 
Subsequent event: Cash distributions declared and paid relating to the period per unit (3) :
$
0.2500

 
$
0.5675

 
$
0.4450

(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)
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

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

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 distribution made in February 2016, in respect of the fourth quarter of 2015, is below the Minimum Quarterly Distribution as set out above. 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.


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The following distributions were paid to the incentive distribution rights holders for the years ending December 31, 2015, 2014 and 2013.
 
Year ended December 31,
(in US $ millions)
2015
 
2014
 
2013
Distributions paid to incentive distribution rights holders
9.5

 
9.2

 
—


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


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

Distribution declared

On January 26, 2016, the Company declared a distribution for the fourth quarter of 2015 of $0.2500 per unit, which was paid on February 12, 2016 to unitholders of record on February 5, 2016.

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.

Amendment to the West Polaris drilling contract    
On 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 executed an amendment to the covenants contained in the $1,450 million Senior Secured Credit Facility, the West Polaris Facility and 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 Note 11 – Debt.

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.
 

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Table of Contents

 
 
SEADRILL PARTNERS LLC
(Registrant)
 
 
 
 
Date: April 28, 2016
 
 
 
 
 
 
 
 
 
By:
/s/ Mark Morris
 
 
Name:
Mark Morris
 
 
Title:
Chief Executive Officer of Seadrill Partners LLC
(Principal Executive Officer of Seadrill Partners LLC)


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