20-F 1 seadrilllimited20-f2016.htm SEADRILL 20-F 2016 Document
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, 2016

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, 2016, there were 504,444,280 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   [_]
Emerging growth company  [_]
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  [_]

Indicate by check mark which basis of accounting the Registrant has used to prepare the financial statements included in this filing:
 
[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





TABLE OF CONTENTS
 
 
Page
EXPLANATORY NOTE
 
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
 
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.



EXPLANATORY NOTE

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.

As previously announced on February 22 and February 28, 2017, we concluded that, because of misstatements identified in our previously issued financial statements for the year ended December 31, 2015, we are restating our financial statements for the year ended December 31, 2015. We are also presenting the impact of the correction of the misstatements on the unaudited consolidated statements of operations, consolidated statements of comprehensive income, consolidated balance sheets and consolidated statements of cash flows for the quarters ended March 31, June 30 and September 30, 2016. As a result, our previously issued financial statements for the year ended December 31, 2015 and the related report of our independent registered public accounting firm thereon, and the previously issued unaudited financial statements in relation to each quarter in the year ended December 31, 2015 and the quarters ended March 31, June 30 and September 30, 2016, should no longer be relied upon.

The misstatements relate to the fair value accounting principles applied under generally accepted in the United States, or U.S. GAAP, to our interest rate and cross currency swap portfolio, referred to hereafter as the “Derivative valuation adjustments”. In addition to these errors, the restated financial statements also include adjustments to correct certain other immaterial errors. The effect of the Derivative valuation adjustments was a reduction in the book value of the liabilities related to derivative financial instruments.

The adjustments made have no impact on our financial covenant compliance for the current or previously reported periods. A summary of the impact to total equity as of December 31, 2015 and the quarters ended March 31, June 30 and September 30, 2016 is given below:

 (In US$ millions)
December 31,
2015

March 31,
2016

June 30,
2016

September 30,
2016

Total equity as previously reported
9,975

10,036

10,321

9,769

Derivative valuation adjustments
136

186

177

179

Other adjustments
(43
)
(10
)
(10
)
(10
)
Total equity as restated
10,068

10,212

10,488

9,938


Please refer to "Note 39 – Restatement of Previously Issued Financial Statements" of our Consolidated Financial Statements included in this annual report on Form 20-F for line item adjustments and other information as a result of the restatement.

Our management has also determined that there was a deficiency in internal control relating to the accounting for the Derivative valuation adjustments, which gave rise to this restatement and constituted a material weakness in our internal control over financial reporting. The material weakness, and our process for remediation thereof, are further described in "Item 15. Controls and Procedures" of this annual report on Form 20-F.

To further review the effects of the misstatements identified and the restatement adjustments, please see Items 3, 5, 11, 15 and 18 in this annual report on Form 20-F.

The previously filed annual report on Form 20-F and quarterly reports on Form 6-K for the periods affected by the restatement have not been amended. Accordingly, investors should no longer rely upon our previously released financial statements for these periods and any earnings releases or other communications relating to these periods. You should instead only rely upon the restated consolidated financial statements, report of our independent registered public accounting firm, and related financial information for 2015 contained in this annual report on Form 20-F or in future filings with the Commission (as applicable). All amounts in this annual report on Form 20-F affected by the restatement adjustments reflect such amounts as restated.




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 that 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:

the impact of active negotiations and contingency planning efforts with respect to a comprehensive restructuring of our debt, the outcome of which is uncertain and which we expect will involve schemes of arrangement or Chapter 11 proceedings;
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 drilling 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;



effects of remediation efforts to address the material weakness discussed in the Explanatory Note above and "Item 15. Controls and Procedures" below;
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 at 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.




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

References in this annual report to “NADL,” “Sevan Drilling” and “AOD” refer specifically to our consolidated subsidiaries North Atlantic Drilling Ltd., Sevan Drilling Limited, and Asia Offshore Drilling Limited, respectively. We also consolidate certain subsidiaries of Ship Finance International Limited, or “Ship Finance.”

References in this annual report to “Seadrill Partners,” “SeaMex” and “Archer” refer to companies in which we have direct or indirect investments in, Seadrill Partners LLC, SeaMex Limited, and Archer Limited, respectively. Our investments in Seabras Sapura Participacoes SA and Seabras Sapura Holding GmbH are together referred to as “Seabras Sapura.” We previously held investments in Sapura Energy Berhad, which was formerly known as SapuraKencana Petroleum Berhad, or “SapuraKencana.”

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 Samho Heavy Industries Co. Ltd., respectively.

References in this annual report to “Total,” “Petrobras,” “ExxonMobil,” “LLOG,” and “Statoil” refer to our key customers Total S.A., Petroleo Brasileiro S.A., Exxon Mobil Corporation, LLOG Exploration Company LLC and Statoil ASA, 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
 
Our selected statement of operations and other financial data with respect to the fiscal years ended December 31, 2016, 2015 and 2014 and our selected balance sheet data as of December 31, 2016 and 2015 have been derived from our consolidated financial statements included in Item 18 of this annual report, or the Consolidated Financial Statements, which have been prepared in accordance U.S. GAAP.
 
Our selected statement of operations and other financial data for the fiscal years ended December 31, 2013 and 2012 and our selected balance sheet data as of December 31, 2014, 2013 and 2012 have been derived from the consolidated financial statements that are not included herein.
 
The following table should be read in conjunction with “Item 5. Operating and Financial Review and Prospects” and our Consolidated Financial Statements and notes thereto, which are included herein. Furthermore, we have restated the selected financial data as of, and for the year ended, December 31, 2015 to reflect the impact of the adjustments of our consolidated financial statements as described in "Note 39 - Restatement of previously issued Financial Statements" of the notes to the Consolidated Financial Statements in this annual report. Our Consolidated 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 prepared, and we draw your attention to the statement regarding going concern as described in "Note 1 - General information".

We deconsolidated our investments in Seadrill Partners on January 2, 2014, and deconsolidated our investments in SeaMex, on March 10, 2015. Please see “Item 4. Information on the Company—A. History and Development of the Company” for further information.


1


 
Year ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
 
Restated
 
 
 
 
 
 
 
 
 
(In millions of U.S. dollars except common share and per share data)
 
 
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Total operating revenues
3,169

 
4,335

 
4,997

 
5,282

 
4,478

Net operating income
1,026

 
1,019

 
2,279

 
2,098

 
1,791

Net (loss)/income
(155
)
 
(635
)
 
4,087

 
2,786

 
1,205

(Loss)/earnings per share, basic
(0.36
)
 
(1.29
)
 
8.32

 
5.66

 
2.37

(Loss)/earnings per share, diluted
(0.36
)
 
(1.29
)
 
8.30

 
5.47

 
2.34

Dividends paid

 

 
1,415

 
1,287

 
1,925

Dividends paid per share

 

 
2.98

 
2.74

 
4.31

Dividends declared per share *

 

 
2.00

 
3.72

 
3.51


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

 
Year ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
 
Restated
 
 
 
 
 
 
 
 
 
(In millions of U.S. dollars except common share and per share data)
 
 
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
1,368

 
1,044

 
831

 
744

 
318

Drilling units
14,276

 
14,930

 
15,145

 
17,193

 
12,894

Newbuildings
1,531

 
1,479

 
2,030

 
3,419

 
1,882

Investment in associated companies
2,168

 
2,592

 
2,898

 
140

 
509

Goodwill

 

 
604

 
1,200

 
1,320

Total assets
21,666

 
23,439

 
26,297

 
26,048

 
19,321

Long-term debt (including current portion)
9,514

 
10,543

 
12,475

 
13,314

 
10,663

Common share capital
1,008

 
985

 
985

 
938

 
938

Total equity
10,063

 
10,068

 
10,390

 
8,202

 
6,024

Common shares outstanding (in millions)
504.4

 
492.8

 
492.8

 
469.0

 
469.2

Weighted average common shares outstanding (in millions)
501.0

 
492.8

 
478.0

 
469.0

 
468.5

Other Financial Data:
 
 
 
 
 

 
 

 
 

Net cash provided by operating activities
1,184

 
1,788

 
1,574

 
1,695

 
1,590

Net cash provided by/ (used in) by investing activities
328

 
(190
)
 
66

 
(2,964
)
 
(1,360
)
Net cash (used in)/provided by financing activities
(1,206
)
 
(1,370
)
 
(1,521
)
 
1,695

 
(395
)
Capital expenditures (1)
(231
)
 
(1,041
)
 
(3,168
)
 
(4,463
)
 
(1,690
)
 
(1)
Capital expenditures include additions to drilling units and equipment, additions to 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.


2




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 for 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, 2016. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations.

Risks Relating to Our Company and Industry

The success and growth of our business depends on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition.

Our business depends on the level of oil and gas exploration, development and production in offshore areas worldwide that is influenced by oil and gas prices and market expectations of potential changes in these prices.

Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including, but not limited to, the following:
worldwide production of and demand for oil and gas and geographical dislocations in supply and demand;
the cost of exploring for, developing, producing and delivering oil and gas;
expectations regarding future energy prices and production;
advances in exploration, development and production technology;
the ability of the Organization of Petroleum Exporting Countries or OPEC, to set and maintain levels of production and pricing;
the level of production in non-OPEC countries;
international sanctions on oil-producing countries, or the lifting of such sanctions;
government regulations, including restrictions on offshore transportation of oil and 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.

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

Continued periods of low demand can cause excess rig supply and intensify competition in our industry, which often results in drilling rigs, particularly older and less technologically-advanced drilling rigs, being idle for long periods of time. We cannot predict the future level of demand for drilling rigs or future conditions of the oil and gas industry with any degree of certainty. In response to the decrease in the prices of oil and gas, a number of our oil and gas company customers have announced significant decreases in budgeted expenditures for offshore drilling. Any future decrease in exploration, development or production expenditures by oil and gas companies could further reduce our revenues and materially harm our business.

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


3


The offshore drilling industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, the condition and integrity of equipment, the rig's and/or the drilling contractor's record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. Our operations may be adversely affected if our current competitors or new market entrants introduce new drilling rigs with better features, performance, prices or other characteristics compared to our drilling rigs, or expand into service areas where we operate.

Competitive pressures and other factors may result in significant price competition, particularly during industry downturns, which could have a material adverse affect on our results of operations and financial condition.

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

The oil and gas drilling industry is cyclical and is currently in a prolonged downcycle. The price of Brent crude has fallen from $115 per barrel in June 2014 to a low of $30 per barrel in January 2016. As at April 21, 2017, the price of Brent crude was approximately $52 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 2017, due to significant decreases in budgeted expenditures for offshore drilling.
  
Declines in capital spending levels, coupled with additional newbuild supply, are likely to continue to intensify price competition and put significant pressure on dayrates and utilization of our rigs.

If we are unable to secure contracts for our drilling units upon the expiration of our existing contracts, we may idle or stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. We currently have seventeen idle units, either “warm stacked,” which means the rig is kept operational and ready for redeployment, and maintains most of its crew, or “cold stacked,” which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is reassigned to an active rig or dismissed. Without new drilling contracts or additional financing being available when needed or available only on unfavorable terms, we will be unable to meet our obligations as they come due or we may be unable to enhance our existing business, complete additional drilling unit acquisitions or otherwise take advantage of business opportunities as they arise.

In the current environment our customers may also seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, resulting in lower dayrates. Our inability, or the inability of our customers to perform, under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

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

We do not know when the market for offshore drilling units may recover, or the nature or extent of any future recovery. There can be no assurance that the current demand for drilling rigs will not further decline in future periods. The continued or future decline in demand for drilling rigs would adversely affect our financial position, operating results and cash flows.

We are in ongoing comprehensive restructuring negotiations, which create significant uncertainty, which may result in impairment, losses or substantial dilution for stakeholders and which will likely involve schemes of arrangement in the United Kingdom or Bermuda or proceedings under Chapter 11 of Title 11 of the United States Code.

Over the past year we have been engaged in extensive discussions with our secured lenders and potential new money investors regarding the terms of a comprehensive restructuring. These discussions have also included an ad hoc committee of bondholders.

The key goals of our restructuring continue to be building a bridge to a recovery and achieving a sustainable capital structure. We currently believe that material additional amendments to the terms of our credit facilities will be necessary to effectuate a comprehensive restructuring.  Feedback from certain stakeholders and potential new money providers also indicates that a comprehensive and consensual agreement will likely require a substantial impairment or conversion of our bonds to equity, as well as impairment, losses or substantial dilution for other stakeholders. As a result, we currently expect that shareholders are likely to receive minimal recovery for their existing shares.

We have agreed to amendments to our secured credit facilities as one component of the broader effort to effectuate a comprehensive restructuring of our indebtedness. On April 28, 2016, we entered into agreements with our banking group to amend the financial covenants on all of our secured credit facilities. The amendments also included a milestone to implement a comprehensive restructuring, which was originally April 30, 2017. On April 4, 2017, we reached an agreement to further extend the covenant amendments and waivers to our secured credit facilities and extend the milestone to implement a comprehensive restructuring plan from April 30, 2017 to July 31, 2017. Failure to meet or extend this milestone may result in events of default under our credit facilities and other funded debt. These amendments also involved corresponding extensions of the maturities on certain secured credit facilities.

4



We expect the implementation of a comprehensive restructuring plan will likely involve schemes of arrangement in the United Kingdom or Bermuda or proceedings under Chapter 11 of Title 11 of the United States Code. We are preparing accordingly and have retained financial advisers and legal counsel. There is inherent uncertainty in the completion of this comprehensive restructuring process, and therefore we are also preparing various contingency plans in the event a consensual agreement is not reached. Commencement of schemes of arrangement or proceedings under Chapter 11 of Title 11 of the United States Code could result in defaults on the funded debt of entities in which we hold non-controlling interests, including Seadrill Partners, Archer, Seabras Sapura, and SeaMex, which could impair the value of our investments in those entities.

The outcome of these comprehensive restructuring negotiations and contingency planning efforts is uncertain and could adversely effect our business and result in impairment, losses or substantial dilution for stakeholders, and may impair our ability to continue as a going concern.

We may not have sufficient liquidity to meet our obligations as they fall due or have the ability to raise new capital or refinance existing facilities on acceptable terms.

As at December 31, 2016, we had $9.9 billion in principal amount of interest-bearing debt (including related party debt of $0.3 billion), representing approximately 576% of our total market capitalization, of which $7.3 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.

In order to continue to repay our indebtedness as it becomes due and at maturity, we need to refinance our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings. Our ability to refinance our existing facilities is dependent on reaching agreement on the terms of a restructuring plan as described in the risk above. Please also see “Item 5. Operating and Financial Review and Prospects-B. Liquidity and Capital Resources.”

The covenants in our credit facilities impose operating and financial restrictions on us, breach of which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.

Our debt agreements impose operating and financial restrictions on us. These restrictions may prohibit or otherwise limit our ability to undertake certain business activities without consent of the lending banks. These restrictions include:
executing other financing arrangements;
incurring additional indebtedness;
creating or permitting liens on our assets;
selling our drilling units or the shares of our subsidiaries;
making investments;
changing the general nature of our business;
paying dividends to our shareholders;
changing the management and/or ownership of the drilling units;
making capital expenditures; and
competing effectively to the extent our competitors are subject to less onerous restrictions.

Our lenders’ interests may be different from ours and we may not be able to obtain our lenders’ consent when beneficial for our business, which may impact our performance.


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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. During the years ended December 31, 2016 and 2015, we recognized charges of $895 million and $1,285 million relating to our certain investments due to declining dayrates and future market expectations for dayrates in the sector, respectively. During the years ended 2015 and 2014, we recognized impairment charges on goodwill of $563 million and $232 million on our floater segment and jack-up segment, respectively. In the future, we may be required to record additional impairment charges to our investments or other assets. Any further 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.

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 lenders for such noncompliance, a default could occur under the terms of those agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend or in some circumstances accelerate the outstanding loans and declare all amounts borrowed due and payable. All of our external facility 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 drilling units also 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 at December 31, 2016, we had $7.3 billion of interest-bearing debt secured by, among other things, liens on our drilling units.

If any of the aforementioned events occur, our assets may be insufficient 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 we find are favorable or acceptable. 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. Any of these events may further restrict our ability to pay dividends, repurchase our common shares, make capital expenditures or incur additional indebtedness.

Financing agreements containing operating and financial restrictions and other covenants may restrict our business and financing activities and our ability to pay for our newbuild drilling units.

Borrowings under our current credit facilities, which are subject to certain covenants, 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 at April 21, 2017 was $4.1 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.

If 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 could be prevented from realizing potential revenues from these projects. We could also lose all or a portion of yard payments that were paid by us, which as at April 21, 2017 amounted to $0.7 billion, and we could be liable for penalties and damages under such contracts.

For more information, 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.”

Certain of our affiliated or related companies may be unable to service their debt requirements and comply with the provisions contained in their loan agreements.

The failure of certain of our affiliated or related companies to service their debt requirements and comply with the provisions contained in their debt agreements may lead to an event of default under such agreements, which may have a material adverse effect on us. Such affiliated and related companies include (i) Seadrill Partners, (ii) certain subsidiaries of Seadrill Partners, (iii) our majority-owned subsidiaries, NADL, AOD and Sevan Drilling, (iv) certain subsidiaries of Ship Finance, (v) SeaMex, (vi) Seabras Sapura and (vii) Archer.

If a default occurs under the debt agreements of our affiliated or related 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. 

We have provided guarantees over certain debt facilities of our affiliates and related companies. In the event that our affiliates or related companies are unable to meet their obligations outlined above the lenders could look to us to meet such liabilities. Some examples are outlined in the following paragraphs.

Seadrill Partners has joint obligations with us under certain of our existing debt agreements and we are a guarantor under Seadrill Partners’ $420 million senior secured credit facility relating to the West Polaris. In the event Seadrill Partners defaults under its debt agreements, 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.

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We have provided guarantees over NADL’s, AOD's and Sevan Drilling's senior secured debt and certain bonds and we may not have sufficient funds to repay lenders in full if they seek to enforce the guarantees.  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 Consolidated Financial Statements as “current” may, among other things, adversely impact our compliance with the covenants contained in our existing and future debt agreements.

We also consolidate certain subsidiaries of Ship Finance into our Consolidated Financial Statements as variable interest entities or VIEs. To the extent that the VIEs default under their indebtedness and their debt becomes classified as current in their financial statements, we would in turn mark such indebtedness as current in our Consolidated Financial Statements. The characterization of the indebtedness in our Consolidated Financial Statements as current may adversely impact our compliance with the covenants contained in our existing and future debt agreements.

Similarly, we have provided support to Archer in the form of $278 million of financial guarantees for the benefit of its lenders. As part of our restructuring plans, in April 2017, we have signed and closed an agreement with Archer and its lenders to extinguish approximately $253 million in financial guarantees provided by us in exchange for a cash payment of approximately $25 million. We remain in constructive discussions with Archer and its lenders to extinguish the remaining $25 million of financial guarantees in exchange for a cash payment representing 10% of their face value. As part of Archer’s restructuring plans we have also agreed to convert $146 million in subordinated loans provided to Archer, including accrued interest and fees, into a $45 million subordinated convertible loan. The subordinated convertible loan will bear interest of 5.5%, matures in December 2021 and have a conversion right into equity of Archer Limited in 2021 based on a strike price of US$2.083 per share (subject to appropriate adjustment mechanics), which is approximately 75% above the subscription price in Archer’s private placement on February 28, 2017. As of April 21, 2017 we owned 16.3% of the outstanding common shares of Archer, as compared to 39.7% as of December 31, 2016. Our shareholding was diluted following Archer's $100 million private placement on February 28, 2017.

We also provide financial guarantees over Seabras Sapura's senior secured credit facility agreements in order to part fund the acquisition of its pipe-laying support vessels. As a condition to the lenders making the loan available to each of the borrowers, we provide several guarantees on a 50:50 basis for five of the vessels and one vessel on a joint and several basis with SapuraKencana Petroleum Berhad or 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 obligations and liabilities of the borrowers under the facility agreement which arise during the period between the expiry of a contract and extension or renewal of that contract and following a guarantee extension relating to early termination of a contract. During these periods, the guarantees can only be called if the facility is in default. The total amount guaranteed as of December 31, 2016 was $787 million.

If Archer or Seabras Sapura is unable to meet its obligations under the above references credit facilities, the lenders could look to us to meet such liabilities.

Our debt agreements also 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 their 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, and may impair our ability to continue as a going concern.

We may not be able to delay entry of newbuild drilling units into our active fleet.

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, NADL has agreed with Jurong to, among other things, delay taking delivery of the West Rigel until July 6, 2017, 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 newbuild drilling units that do not have associated drilling contracts.

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 at April 21, 2017 was $4.1 billion, of which $2.4 billion is guaranteed by us. 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 at April 21, 2017 amounted to $0.7 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.

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Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted.

In the current market some of our customers may seek to terminate their agreements with us. Examples include, but are not limited to: the termination of the West Epsilon effective September 27, 2016; the termination of the West Pegasus effective August 16, 2016; the termination of the West Hercules effective May 20, 2016; and the termination of the Sevan Driller effective March 30, 2016.

Some of our customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. The general principle is that such early termination fee shall compensate us for lost revenues less operating expenses for the remaining contract period; however, in some cases, such payments may not fully compensate us for the loss of the drilling contract.

Under certain circumstances our contracts may permit customers to terminate contracts early without the payment of any termination fees, as a result of non-performance, periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events beyond our control. In addition, national oil company customers may have special termination rights by law. During periods of challenging market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of non-performance.

In the current environment our customers may seek to 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.

Reduced day rates in our customer contracts and cancellation of drilling contracts (with or without early termination payments) may lead to reduced revenues from our operations and performance of our business and adversely affect our performance.

Our contract backlog for our fleet of drilling units may not be realized.

As of April 21, 2017, our contract backlog was approximately $3.6 billion. The contract backlog presented in this annual report and our other public disclosures is only an estimate. The actual amount of revenues earned and the actual periods during which revenues are earned will be different from the contract backlog projections due to various factors, including shipyard and maintenance projects, downtime and other events within or beyond our control. In addition, we or our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, such as the current environment, resulting in lower dayrates. In some instances, there is an option for a customer to terminate a drilling contract prematurely for convenience on payment of an early termination fee. However, this fee may not adequately compensate us for the loss of this drilling contract.

For example, 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; on May 23, 2016, we received a notice of termination from Statoil for the West Hercules drilling contract that decreased our contract backlog; on August 16, 2016, we received a notice of termination from Pemex for the West Pegasus drilling contract, resulting in a potential backlog reduction of $266 million; and on September 27, 2016, we received a notice of termination from Statoil for the West Epsilon drilling contract, resulting in a potential backlog reduction.

Our inability, or the inability of our customers, to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

We may not be able to renew or obtain new and favorable contracts for our newbuild drilling units or for our drilling units whose contracts have expired or been terminated.

During the recent period of high utilization and high dayrates, which we now 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.

As at April 21, 2017, we had eight contracts that expire in 2017, five contracts that expire in 2018 and six contracts that expire in 2019. Our ability to renew these contracts or obtain new contracts will depend on our customers and prevailing market conditions, which may vary among different geographic regions and types of drilling units.

The over-supply of drilling units will be exacerbated by the entry of newbuild rigs into the market, 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. Customers may opt to contract older rigs in order to reduce costs which could adversely affect our ability to obtain new drilling contracts due to our newer fleet. Customers may also choose not to award drilling contracts to us due to our debt restructuring activities.


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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 at April 21, 2017, we had eighteen 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 drilling contracts contain fixed terms and day-rates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including operating and maintenance costs and cost-overruns on our newbuild projects.”

If we are not able to obtain new contracts in direct continuation of existing contracts, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contract terms, our revenues and profitability could be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract and we may be unable to push this risk down to other contractors or be unable or unwilling at competitive prices to insure against this risk, which will mean the risk will have to be managed by applying other controls. This could lead to us being unable to meet our liabilities in the event of a catastrophic event on one of our rigs.

The market value of our current and newbuild drilling units we have commissioned may decrease.

The market values of drilling units 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. During 2016, the estimated fair value of our drilling units, based upon various broker valuations, has decreased by approximately 16.4%. 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;
the costs of newbuild drilling units;
the prevailing level of drilling services contract dayrates;
government or other regulations; and
technological advances.

If drilling unit values fall significantly, we may have to record an impairment adjustment in our Consolidated Financial Statements, which could adversely affect our financial results and condition. Additionally, if we sell one or more of our drilling units at a time when drilling unit prices have fallen 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 on disposal and a reduction in earnings and cause us to breach the covenants in our finance agreements. For more information 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”, and “–The covenants in our credit facilities impose operating and financial restrictions on us, breach of which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.”

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. In April 2016, however, as part of the amendments to the covenants contained in our senior secured credit facilities, the loan-to-value covenant is suspended until June 30, 2017. On April 4, 2017, we extended the amendment period until September 30, 2017.

Our business and operations involve numerous operating hazards, and in the current market we are increasingly required to take additional contractual risk in our customer contracts and we may not be able to procure insurance to adequately cover potential losses.

Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch-throughs, craterings, fires, explosions and pollution. Contract drilling and well servicing requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. We customarily provide contract indemnity to our customers for claims that could be asserted by us relating to damage to or loss of our equipment, including rigs and claims that could be asserted by us or our employees relating to personal injury or loss of life.


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Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies.

Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurances that these customers will be willing or financially able to indemnify us against all these risks. Customers may seek to cap indemnities or narrow the scope of their coverage, reducing our level of contractual protection. Please see “-Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted".

In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 decision in a case related to the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the Gulf of Mexico in April 2010, or the Deepwater Horizon Incident (to which we were not a party), the U.S. District Court for the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the U.S. Clean Water Act under a drilling contract governed by U.S. maritime law as a matter of public policy. Further, pollution and environmental risks generally are not totally insurable.

If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect our performance.

The amount recoverable under insurance may also be less than the related impact on enterprise value after a loss or not cover all potential consequences of an incident and include annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. Any such lack of reimbursement may cause us to incur substantial costs.

We could decide to retain more risk through self-insurance in the future. This self-insurance results in a higher risk of losses, which could be material, which are not covered by third-party insurance contracts. Specifically, we have at times in the past elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico due to the substantial costs associated with such coverage. Beginning on April 1, 2014, we have insured a limited part of this windstorm risk in a combined single limit annual aggregate policy. We elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a combined single limit of $100 million in the annual aggregate, which includes loss of hire. 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.

No assurance can be made that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, or that we will be able to obtain insurance against certain risks.

We 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 at April 21, 2017, our five largest customers accounted for approximately 78% of our future contracted revenues, or contract backlog. 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. Our results of operations could be materially adversely affected if any of our major customers fail to compensate us for our services or take actions outline above. Please see "-Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted".

We are subject to risks of loss resulting from non-payment or non-performance by our customers and certain other third parties. Some of these customers and other parties may be highly leveraged and subject to their own operating and regulatory risks. If any key customers or other parties default on their obligations to us, our financial results and condition could be adversely affected. Any material non-payment or non-performance by these entities, other key customers or certain other third parties could adversely affect our financial position, results of operations and cash flows.

Our drilling contracts contain fixed terms and day-rates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including operating and maintenance costs and cost-overruns on our newbuild projects.

Our operating costs are generally related to the number of units in operation and the cost level in each country or region where the units are located. A significant portion of our operating costs may be fixed over the short term.


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The average remaining contract length as at April 21, 2017, was 12 months for our floaters and 36 months 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.

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.

As at April 21, 2017, we had an outstanding newbuilding order book with various yards for an additional thirteen drilling units with corresponding contractual yard and other payment commitments totaling $4.1 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. 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.

Equipment maintenance costs fluctuate depending upon the type of activity that the unit is performing and the age and condition of the equipment. Our operating expenses and maintenance costs depend on a variety of factors, including crew costs, provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control.

In situations where our drilling units incur idle time between assignments, the opportunity to reduce the size of our crews on those drilling units is limited, as the crews will be engaged in preparing the unit for its next contract. When a unit faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to prepare drilling units for stacking and maintenance in the stacking period. Should units be idle for a longer period, we will seek to redeploy crew members who are not required to maintain the drilling unit to active rigs, to the extent possible. However, there can be no assurance that we will be successful in reducing our costs in such cases.

Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in supply of offshore drilling units and demand for contract drilling services. This could adversely affect our revenue from operations. For more information please see “-The success and growth of our business depends on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition", “-Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted" and “-Our contract backlog for our fleet of drilling units may not be realized".

Consolidation and governmental regulation of suppliers may increase the cost of obtaining supplies or restrict our ability to obtain needed supplies.

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

We may be unable to obtain, maintain, and/or renew permits necessary for our operations or experience delays in obtaining such permits including the class certifications of rigs.

The operation of our drilling units 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 secure the necessary approvals or permits in a timely manner, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment.

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Every offshore drilling unit is a registered marine vessel and must be “classed” by a classification society to fly a flag. The classification society certifies that the drilling unit is “in-class,” signifying that such drilling unit has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling unit’s country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake them on application or by official order, acting on behalf of the authorities concerned. Our drilling units are certified as being “in class” by the American Bureau of Shipping, or ABS, Det Norske Veritas and Germanisher Lloyd, or DNV GL, and the relevant national authorities in the countries in which our drilling units operate. If any drilling unit loses its flag, does not maintain its class and/or fails any periodical survey or special survey, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable. Any such inability to carry on operations or be employed could have a material adverse impact on the results of operations. Please see “Item 8. Financial Information-Legal Proceedings-Seabras Sapura joint venture” for more information.

The international nature of our operations involves additional risks including foreign government intervention in relevant markets particularly in Brazil.

We operate in various regions throughout the world. As a result of our international operations, we may be exposed to political and other uncertainties, particularly in less developed jurisdictions, 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;
uncertainty of outcome in foreign court proceedings;
the repudiation, nullification, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
political unrest;
foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
the inability to repatriate income or capital;
complications associated with repairing and replacing equipment in remote locations;
import-export quotas, wage and price controls, and the imposition of trade barriers;
U.S. and foreign sanctions or trade embargoes;
compliance with various jurisdictional regulatory or financial requirements;
compliance with and changes to taxation;
other forms of government regulation and economic conditions that are beyond our control; and
government 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;
exchange rates or exchange controls;
the repatriation of foreign earnings;
oil and gas exploration and development;
the taxation of offshore earnings and the earnings of expatriate personnel; and
the use and compensation of local employees and suppliers by foreign contractors.

Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling rigs owned by their own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what government 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.

In the years ended December 31, 2016, 2015 and 2014, 17%, 19% and 20%, respectively, of our contract revenues were derived from our Brazilian operations, particularly from our contract with 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, changes in legislation price controls, currency devaluations, capital controls and limits on imports. Further changes to monetary policy, the regulatory environment of our industry, and legislation could impact our performance.

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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) 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 had 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 on the Brazilian economy.

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 contract the unit was awarded a contract by Shell in Brazil for 60 days. The combined impact of the cancellation, reduction and new award was a decrease in contract backlog of approximately $127 million.

These and other developments in Brazil’s political conditions, economy and government policies may, directly or indirectly, adversely affect our business and results of operations.

Compliance with, and breach of, the complex laws and regulations governing international trade could be costly, expose us to liability and adversely affect our operations.

Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment in the geographic areas where we operate.

Accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. For example, on December 20, 2016, the United States President invoked a law that banned offshore oil and gas drilling in larges area of the Arctic and the Atlantic Seaboard. It is presently unclear how long this ban will remain in effect. A ban on new drilling in Canadian Arctic waters was announced simultaneously. We may be required to make significant capital expenditures or operational changes to comply with governmental laws and regulations. It is also possible that these laws and regulations may, in the future, add significantly to our operating costs or significantly limit drilling activity.

Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from the failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, the seizure of shipments, and the loss of import and export privileges.

Offshore drilling in certain areas, including arctic areas, has been curtailed and, in certain cases, prohibited because of concerns over protecting of the environment.

New laws or other governmental actions that prohibit or restrict offshore drilling or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or to the offshore drilling industry, in particular, could adversely affect our performance.

The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas could have a material adverse effect on our business, results of operations or financial condition. Future earnings may be negatively affected by compliance with any such new legislation or regulations.


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

Our operations are subject to numerous international, national, state and local laws and regulations, treaties and conventions in force in international waters and the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. These requirements include, but are not limited to the United Nation’s International Maritime Organization, or the IMO, the International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended, or MARPOL, including the designation of Emission Control Areas, or ECAs thereunder, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended, or the CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974, as from time to time amended, or SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, the IMO International Convention on Load Lines in 1966, as from time to time amended, the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004 or the BWM Convention, the U.S. Oil Pollution Act of 1990, or the OPA, requirements of the U.S. Coast Guard, or the USCG, the U.S. Environmental Protection Agency, or the EPA, the U.S. Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Maritime Transportation Security Act of 2002, 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.

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.

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.


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Failure to comply with international anti-corruption legislation, including the U.S. Foreign Corrupt Practices Act 1977 or the U.K. Bribery Act 2010, could result in fines, criminal penalties, damage to our reputation and drilling contract terminations.

We currently operate, and historically have operated, our drilling units in a number of countries throughout the world, including some with developing economies. 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 or the FCPA and the Bribery Act 2010 of the United Kingdom or the U.K. Bribery Act.

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.

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.

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 debt and common shares could be adversely affected.

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.

In 2010, the United States enacted the Comprehensive Iran Sanctions Accountability and Divestment Act, or CISADA, which expanded the scope of the former Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to non-U.S. companies such as ours, and introduced limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. On August 10, 2012, the U.S. signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the Iran Threat Reduction Act, which places further restrictions on the ability of non-U.S. companies to do business or trade with Iran and Syria. Perhaps the most significant provision in the Iran Threat Reduction Act is that prohibitions in the existing Iran sanctions applicable to U.S. persons will now apply to any foreign entity owned or controlled by a U.S. person. The other major provision in the Iran Threat Reduction Act is that issuers of securities must disclose in their annual and quarterly reports filed after February 6, 2013 if the issuer or “any affiliate” has “knowingly” engaged in certain sanctioned activities involving Iran during the timeframe covered by the report. At this time, we are not aware of any violation conducted by us or by any affiliate, which is likely to trigger a disclosure requirement.

On November 24, 2013, the P5+1 (the United States, United Kingdom, Germany, France, Russia and China) entered into an interim agreement with Iran entitled the “Joint Plan of Action,” or the JPOA. Under the JPOA it was agreed that, in exchange for Iran taking certain voluntary measures to ensure that its nuclear program is only used for peaceful purposes, the United States and the European Union would voluntarily suspend certain sanctions for a period of six months. On January 20, 2014, the United States and the European Union began implementing the temporary relief measures provided for under the JPOA.

The JPOA was subsequently extended twice. On July 14, 2015, the P5+1 and the European Union announced that they reached a landmark agreement with Iran titled the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran’s Nuclear Program, or the JCPOA, to significantly restrict Iran’s ability to develop and produce nuclear weapons for 10 years while simultaneously easing sanctions directed toward non-U.S. persons for conduct involving Iran, but taking place outside of U.S. jurisdiction and not involving U.S. persons. On January 16, 2016, or the Implementation Day, the United States joined the European Union and the U.N. in lifting a significant number of their nuclear-related sanctions on Iran following an announcement by the International Atomic Energy Agency, or the IAEA, that Iran had satisfied its respective obligations under the JCPOA.

U.S. sanctions prohibiting certain conduct that is now permitted under the JCPOA have not actually been repealed or permanently terminated at this time. Rather, the U.S. government has implemented changes to the sanctions regime by: (1) issuing waivers of certain statutory sanctions provisions; (2) committing to refrain from exercising certain discretionary sanctions authorities; (3) removing certain individuals and entities from OFAC's sanctions lists; and (4) revoking certain Executive Orders and specified sections of Executive Orders. These sanctions will not be permanently "lifted" until the earlier of “Transition Day,” set to occur on October 20, 2023, or upon a report from the IAEA stating that all nuclear material in Iran is being used for peaceful activities.


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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 an investment and co-operation agreement between our majority-owned subsidiary NADL and Rosneft Oil Company, or Rosneft, for activity in Russian Arctic and deepwater areas, as mentioned below, 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.

Certain parties with whom we have entered into contracts may be the subject of sanctions imposed by the United States, the European Union or other international bodies as a result of the annexation of Crimea by Russia in March 2014 and the subsequent conflict in eastern Ukraine, or may be affiliated with persons or entities that are the subject of such sanctions. If we determine that such sanctions require us to terminate existing contracts or if we are found to be in violation of such applicable sanctions, our results of operations may be adversely affected or we may suffer reputational harm. 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.

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

We depend on our customers’ willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and the demand for energy, including oil and gas. The world economy is currently facing a number of challenges. Concerns persist regarding the debt burden of certain European countries and their ability to meet future financial obligations and the overall stability of the euro. A renewed period of adverse development in the outlook for the financial stability of European countries, or market perceptions concerning these and related issues, could reduce the overall demand for oil and natural gas and for our services and thereby could affect our financial position, results of operations and cash available for distribution. In addition, turmoil and hostilities in the Ukraine, Korea, the Middle East, North Africa and other geographic areas and countries are adding to the overall risk picture.

Negative developments in worldwide financial and economic conditions could further cause our ability to access the capital markets to be severely restricted at a time when we would like, or need, to access such markets, which could impact our ability to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, lenders willingness to provide credit facilities to our customers, causing them to fail to meet their obligations to us.

A portion of the credit under our credit facilities is provided by European banking institutions. If economic conditions in Europe preclude or limit financing from these banking institutions, we may not be able to obtain financing from other institutions on terms that are acceptable to us, or at all, even if conditions outside Europe remain favorable for lending.

In June 2016, the U.K. voted to exit from the European Union (commonly referred to as Brexit). The impact of Brexit and the resulting U.K. and European relationship are uncertain for companies doing business both in the U.K. and the overall global economy.

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


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Our business is capital intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund our capital expenditures. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations or interpretations thereof and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.

Any reductions in drilling activity by our customers may not be uniform across different geographic regions. Locations where costs of drilling and production are relatively higher, such as Arctic or deepwater locations, may be subject to greater reductions in activity. Such reductions in high cost regions may lead to the relocation of drilling units, concentrating drilling units in regions with relatively fewer reductions in activity leading to greater competition.

If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing on terms acceptable to us or at all for the remaining installment payments we are obligated to make before the delivery of our remaining newbuildings and our other capital requirements, including principal repayments.

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 Seadrill Partners, SeaMex, Archer and Seabras Sapura.

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. Furthermore, dividends from Seadrill Partners may be reduced or cancelled going forward.

In addition, Seadrill has provided to Archer subordinated loans totaling $125 million, as well as financial guarantees for the benefit of its lenders totaling $278 million. The book value of the loans, accrued interest and fees as at the balance sheet date totaled $43 million, as we have written down the book value due to our share of Archer's net losses. As part of our restructuring plans, we have signed and closed an agreement with Archer and its lenders to extinguish approximately $253 million in financial guarantees provided by us in exchange for a cash payment of approximately $25 million. We remain in constructive discussions with Archer and its lenders to extinguish the remaining $25 million of financial guarantees in exchange for a cash payment representing 10% of their face value. As part of Archer’s restructuring plans we have also agreed to convert $146 million, including accrued interest and fees, in subordinated loans provided to Archer into a $45 million subordinated convertible loan. The subordinated convertible loan will bear interest of 5.5%, matures in December 2021 and have a conversion right into equity of Archer Limited in 2021 based on a strike price of US$2.083 per share (subject to appropriate adjustment mechanics), which is approximately 75% above the subscription price in Archer’s private placement on February 28, 2017. As of April 21, 2017 we own 16.3% of the outstanding common shares of Archer, as compared to 39.7% as of December 31, 2016. Our shareholding was diluted following Archer's $100 million private placement on February 28, 2017.

During the years ended December 31, 2016 and 2015 we recognized charges of $895 million and $1,285 million respectively relating to certain of our investments due to declining dayrates and future market expectations for dayrates in the sector. Please see Note 8 "Impairment loss on marketable securities and investments in associated companies” to our Consolidated Financial Statements included herein for further discussion.

Our ability to operate our drilling units in the U.S. Gulf of Mexico could be impaired by governmental regulation particularly in the aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout.

In the aftermath of the incident (in which we were not involved) on the Transocean “Deepwater Horizon” rig that led to the Macondo well blowout, the U.S Department of the Interior, U.S Bureau of Safety and Environmental Enforcement, or the BSEE and its predecessor put in place new and revised regulations governing safety and environmental management systems or SEMS, commonly referred to as SEMS II. During 2013, BSEE adopted a final rule modifying the SEMS requirements. The SEMS II regulations focus on operator obligations. However, they also require operators to flow SEMS obligations and commitments through their supply chain including adherence to policies, training and ensuring safe work practices.

The U.S. Occupational Safety and Health Act 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.


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In addition, the oil and gas industry has adopted new equipment and operating standards, such as the American Petroleum Institute Standard 53 relating to the design, maintenance, installation and testing of well control equipment. Likewise, in August 2015, the U.S Bureau of Ocean Energy Management or BOEM issued a Notice to Lessees (NTL 2015-NO4), regarding issues such as the general financial assurance required before drilling. In December 2015, the BSEE announced a new pilot inspection program for offshore facilities. In April 2015, it was announced that new regulations are expected to be implemented in the United States regarding offshore oil and gas drilling and the BSEE announced a new Well Control Rule in April 2016 (discussed further below). These new guidelines and standards for safety, environmental and financial assurance and any other new guidelines or standards the U.S. government or industry may issue or any other steps the U.S. government or industry may take, 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. We are not able to predict the likelihood, nature or extent of additional rulemaking or when the interim rules, or any future rules, could become final. The current and future regulatory environment in the U.S. Gulf of Mexico could impact the demand for drilling units in the U.S. Gulf of Mexico in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the U.S. Gulf of Mexico. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration and development activity in the U.S. Gulf of Mexico and, therefore, reduce demand for our services. In addition, insurance costs across the industry 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 the potential impact of new regulations that may be forthcoming, nor can we predict if implementation of additional regulations might subject us to increased costs of operating and/or a reduction in the area of operation in the U.S. Gulf of Mexico. As such, our cash flow and financial position could be adversely affected if our ultra-deepwater semi-submersible drilling rigs and ultra-deepwater drillships operating in the U.S. Gulf of Mexico were subject to the risks mentioned above.

In addition, hurricanes have from time to time caused damage to a number of drilling units and production facilities unaffiliated to us in the Gulf of Mexico. The Bureau of Ocean Energy Management, Regulation and Enforcement or 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, or GPS, and to provide the BSEE with real-time GPS location data for MODUs effective March 19, 2013 which expired January 1, 2015. These guidelines effectively imposed 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 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. 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.

Failure to obtain or retain highly skilled personnel, and to ensure they have the correct visas and permits to work in the locations in which they are required, could adversely affect our operations.

We require highly skilled personnel in the right locations to operate and provide technical services and support for our business.

Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased, and this may continue to rise. Notwithstanding the general downturn in the drilling industry, in some regions, such as 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. These factors could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for qualified personnel, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents.

Our ability to operate worldwide depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate. Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. If we are not able to obtain visas and work permits for the employees we need for operating our rigs on a timely basis, or for third-party technicians needed for maintenance or repairs, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel

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the contracts. Please see “-Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted".

Labor costs and our operating restrictions that apply could increase following collective bargaining negotiations and changes in labor laws and regulations.

Some of our employees are represented by collective bargaining agreements. The majority of these employees work in 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.

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, 2016, our total floating rate debt amounted to $7.3 billion, of which we had entered into interest rate swap agreements to fix the interest rate for a principal amount of $7.1 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 in the future, any increase in market interest rates would increase our interest rate exposure and debt service obligations, which would exacerbate the risks associated with our leveraged capital structure.

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

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

We 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, Brazilian real, Nigerian Naira, and Angolan Kwanza and there is a risk that currency fluctuations could have an adverse effect on our statements of operations and cash flows.

Brexit, or similar events in other jurisdictions, can impact global markets, excluding foreign exchange and securities markets, which may have an adverse impact on our business and operations as a result of changes in currency, exchange rates, tariffs, treaties and other regulatory matters.

A change in tax laws in any country in which we operate could result in higher tax expense.

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

A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.

Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.


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

Due to concern over the risk of climate change, a number of countries and the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions or the Paris Agreement, which resulted from the 2015 United Nations Framework Convention on Climate Change conference in Paris and entered into force on November 4, 2016. As at January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted by the IMO’s Maritime Environment Protection Committee, or the MEPC, in July 2011 relating to greenhouse gas emissions. A roadmap for a “comprehensive IMO strategy on a reduction of GHG emissions from ships” was also approved by MEPC at its 70th session in October 2016. These requirements could cause us to incur additional compliance costs.

In addition, the European Union has indicated that it intends to propose an expansion of the existing European Union Emissions Trading Scheme to include emissions of greenhouse gases from marine vessels. In April 2015, a regulation was adopted requiring that large ships (over 5,000 gross tons) calling at European Union ports from January 2018 collect and publish data on carbon dioxide emissions and other information. In the United States, the Environmental Protection Agency, or the EPA, has issued a finding that greenhouse gases endanger the public health and safety and has adopted regulations to limit greenhouse gas emissions from certain mobile sources and large stationary sources. Although the mobile source emissions regulations do not apply to greenhouse gas emissions from drilling units, such regulation of drilling units is foreseeable, and the EPA has received petitions from the California Attorney General and various environmental groups seeking such regulation. In the United States, individual states can also enact environmental regulations. For example, California has introduced caps for greenhouse gas emission and, in the end of 2016, signaled it might take additional actions regarding climate change.

Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining our assets, and might also require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. Any passage of climate control legislation or other regulatory initiatives by the IMO, the European Union, the United States or other countries in which we operate, or any treaty adopted at the international level to succeed the Kyoto Protocol, 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.

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

Acts of terrorism, piracy, and political and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. Our drilling operations could also be targeted by acts of sabotage carried out by environmental activist groups.

We rely on information technology systems and networks in our operations and administration of our business. Our drilling operations or other business operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations, or lead to an unauthorized release of information or alteration of information on our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.

In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower dayrates. Insurance premiums could also increase and coverage may be unavailable in the future. Increased insurance costs or increased costs of compliance with applicable regulations may have a material adverse effect on our results of operations.

We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.

We are currently involved in various litigation matters, and we anticipate that we will be involved in litigation matters from time to time in the future. 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.


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We may also be subject to significant legal costs in defending these actions, which we may or may not be able to recoup depending on the results of such claim.
For additional information on litigation matters that we are currently involved in, please see “Item 8. Financial Information-A. Consolidated Statements and Other Financial Information-Legal Proceedings.”

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

The majority of the intellectual property rights relating to our drilling units and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over an infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services or replacement parts, or could be required to cease using some equipment. In addition, our competitors may assert claims for infringement of intellectual property rights related to certain equipment on our drilling units and we may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of these technology disputes involving our suppliers or competitors could adversely affect our financial results and operations. We have indemnity provisions in some of our supply contracts to give us some protection from the supplier against intellectual property lawsuits. However, we cannot make any assurances that these suppliers will have sufficient financial standing to honor their indemnity obligations, or guarantee that the indemnities will fully protect us from the adverse consequences of such technology disputes. We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but we cannot provide assurance that these provisions will fully protect us from the adverse consequences of such technology disputes. For information on certain intellectual property litigation that we are currently involved in, please see “Item 8. Financial Information–A. Consolidated Statements and Other Financial Information–Legal Proceedings”.

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. Many 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. Please see “Item 6. Directors, Senior management and Employees–C. Board Practices” for more information.

We may be restricted from granting long-term contracts as a result of the Omnibus Agreement with Seadrill Partners.

We have entered into an omnibus agreement with Seadrill Partners, or 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 face risks relating to our ineffective internal control over financial reporting.

In the course of preparing the Consolidated Financial Statements for the year ended December 31, 2016 and in performing our related controls over financial reporting, we determined to restate our Consolidated Financial Statements for the year ended December 31, 2015 in this Form 20-F, as further described in the Explanatory Note above. We also determined that the design of our internal controls over accounting for interest rate and cross currency swaps was deficient. Accordingly, we have determined that this control deficiency constituted a material weakness. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. A more complete description of the recently identified errors and the resulting material weakness is included in "Item 15. Controls and Procedures" and Note 39 "Restatement of Previously Issued Financial Statements" included in this annual report on Form 20-F.

While we are taking specific steps to enhance our internal control environment and remediate this material weakness, the material weakness cannot be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that our internal controls are operating effectively. If we are unable to successfully remediate this material weakness in a timely manner, or if in the future we are unable to maintain effective internal controls and disclosure controls, investors may lose confidence in our reported financial information, which could lead to a decline in the price of our common shares, limit our ability to access the capital markets in the future, and require us to incur additional costs to improve our internal control and disclosure control systems and procedures. Further, if lenders lose confidence in the reliability of our financial statements, it could have a material adverse effect on our ability to fund our operations.

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

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


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Risks Relating to Our Common Shareholders
 
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 were restricted from paying dividends so long as the amended ratio is in effect, until January 1, 2017. As part of additional amendments to other covenants contained in our senior secured credit facilities in April 2016, as extended in April 2017, we are currently restricted from paying dividends or making distributions effectively until a restructuring of our senior secured credit facilities is agreed to, including the extension of their tenor and the amendment of financial covenants.

Please see “-We are in ongoing comprehensive restructuring negotiations, which create significant uncertainty, which may result in impairment, losses or substantial dilution for stakeholders and which will likely involve schemes of arrangement in the United Kingdom or Bermuda or proceedings under Chapter 11 of Title 11 of the United States Code.”

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, the outcome of our comprehensive restructuring, 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 our common shares, which could have an adverse effect on the realized price of our 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. For our share price history, please see “Item 9. The Offer and Listing—A. Offer and Listing Details.”

The market price of our common shares has recently declined significantly. If the average closing price of our common shares is 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, and have been trading below $1.00 since April 4, 2017. 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 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 do 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, may cause a breach under our debt agreements 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 incorporated under the laws of Bermuda, and substantially all of our assets are located outside of the United States. In addition, our directors and officers generally are or will be non-residents of the United States, and all or a substantial portion of the assets of these non-residents are located outside the United States. As a result, it may be difficult or impossible for you to effect service of process on these individuals in the United States or to enforce in the United States judgments obtained in U.S. courts against us or our directors and officers based on the civil liability provisions of applicable U.S. securities laws.

In addition, you should not assume that courts in the countries in which we are incorporated or where our assets are located (1) would enforce judgments of U.S. courts obtained in actions against us based upon the civil liability provisions of applicable U.S. securities laws or (2) would enforce, in original actions, liabilities against us based on those laws.


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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” or 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 the 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 United States 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 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, or 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 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 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 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.”

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, or 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 4,780 skilled employees. As of April 21, 2017, we had a fleet of 38 offshore drilling units consisting of 12 semi-submersible rigs, 7 drillships and 19 jack-up rigs in operation, and contracts for the construction of 13 offshore drilling units. Of the total fleet, 18 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.

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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 in the United States of 13,513,514 common shares at $9.25 per share. As of April 21, 2017, 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, or Norwegian OTC, under the symbol “NADL.” For the year ended December 31, 2016, NADL contributed $535 million (or 17%) to our revenues, and $91 million (or 9%) to our operating income. The outstanding debt of NADL as of December 31, 2016 amounted to $2,164 million (or 23%), of which $1,564 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 April 21, 2017, 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, 2016, Sevan Drilling contributed $320 million (or 10%), and $89 million (or 9%) to our revenue and operating income, respectively. The outstanding debt of Sevan Drilling as of December 31, 2016 amounted to $945 million (or 10%), all of which is guaranteed by Seadrill.

AOD, a controlled subsidiary, is a company incorporated in Bermuda that owns three high-specification jack-up drilling rigs, which are leased to a Seadrill operating subsidiary. As of April 21, 2017, we owned 66.2% of the outstanding shares in AOD. For the year ended December 31, 2016, AOD contributed $77 million (or 2%) and $37 million (or 4%) to our revenue and operating income, respectively. The outstanding debt of AOD as of December 31, 2016 amounted to $237 million (or 2%), 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:
Seadrill Partners, an associated company, is a Marshall Islands limited liability company that focuses on owning and operating offshore drilling rigs under long-term contracts with major oil companies. Seadrill Partners was a consolidated subsidiary of Seadrill, but as of January 2, 2014, we deconsolidated Seadrill Partners from our Consolidated Financial Statements. As of April 21, 2017, 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 Seadrill Partners’ credit facilities, and we also have joint and several liability under certain Seadrill Partners’ credit facilities. Please see Note 23 "Long term debt" of our Consolidated Financial Statements included herein for more information.

Archer is a global oilfield service company that specializes in drilling and well services. As of April 21, 2017 we own 16.3% of the outstanding common shares of Archer, as compared to 39.7% as of December 31, 2016. Our shareholding was diluted following Archer's $100 million private placement on February 28, 2017. In addition we provide various financial and performance guarantees on behalf of Archer. The total outstanding guarantees to Archer as of December 31, 2016 were $296 million.
On April 25, 2017, as part of our restructuring plans, we have signed and closed an agreement with Archer and its lenders to extinguish approximately $253 million in financial guarantees provided by us in exchange for a cash payment of approximately $25 million. We remain in constructive discussions with Archer and its lenders to extinguish the remaining $25 million of financial guarantees in exchange for a cash payment representing 10% of their face value. As part of Archer’s restructuring plans we have also agreed to convert $146 million outstanding in subordinated loans, fees, and interest provided to Archer into a $45 million subordinated convertible loan. The subordinated convertible loan will bear interest of 5.5%, matures in December 2021 and have a conversion right into equity of Archer Limited in 2021 based on a strike price of US$2.083 per share (subject to appropriate adjustment mechanics), which is approximately 75% above the subscription price in Archer’s private placement on February 28, 2017.

Seabras Sapura is a group of related companies that construct, own and operate pipe-laying service vessels in Brazil. As of April 21, 2017, 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, 2016 was $95 million and the total amount guaranteed as of December 31, 2016 was $787 million.

SeaMex, a joint venture, that owns and operates five jack-up drilling units located in Mexico under contract with Pemex. As of April 21, 2017, we and an investment fund controlled by Fintech Advisory Inc., or Fintech, each have a 50% ownership stake in SeaMex. SeaMex was deconsolidated from our Consolidated 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% each. As of April 21, 2017 and December 31, 2016, the facility remained undrawn.

In addition, we have entered into sale and leaseback agreements for three drilling units: the West Taurus, West Hercules and West Linus with Ship Finance, a related party. We consolidate certain related subsidiaries of Ship Finance into our Consolidated Financial Statements as variable

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interest entities or VIEs. As of April 21, 2017, through our VIEs we had gross loans outstanding to Ship Finance amounting to $415 million and net loans of $330 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. 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. Our consolidated subsidiaries, NADL, Sevan Drilling and AOD, have their own boards, with delegated authority and responsibility for the management of the respective subgroups.

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

Recent Developments

NADL Revolving credit facility
On January 31, 2017, we provided a $25 million revolving credit facility to NADL that was set to mature on March 31, 2017. On March 15, 2017, the maturity was extended until April 30, 2017. On April 25, 2017, the revolving credit facility was increased to $50 million and extended to June 30, 2017. This interim funding arrangement has been put in place while comprehensive restructuring negotiations continue at both companies.

West Mira
On March 13, 2017, we reached settlement with HSHI with regard to the West Mira, pursuant to which we received a cash payment of $170 million on March 14, 2017, representing the yard installment receivable excluding any additional accrued interest. We recorded a non-cash impairment of $44 million for the year ended December 31, 2016 to reflect the difference in the carrying value of the West Mira receivable and the settlement value.

As part of this settlement, Seatankers, a related party, has purchased the West Mira from HSHI. Seatankers is an asset holding company and is not expected to engage in offshore drilling activities in competition with Seadrill. The Company expects to execute an agreement with Seatankers for the commercial and technical management of the West Mira as well as a right of first refusal for purchase of the Unit.

Amendments to our secured credit facilities
On April 4, 2017, we extended from June 30, 2017 to September 30, 2017 the expiration of covenant amendments and waivers of our secured credit facilities, which among other things, temporarily amended the equity ratio, leverage ratio, minimum-value-clauses, and minimum liquidity requirement covenants therein. In addition, the maturity dates of the $450 million senior secured credit facility, 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 August 15, 2017, August 31, 2017 and September 14, 2017, respectively. Please see Note 23 "Long-term debt—Covenants contained within our debt facilities” for more information. The agreement also extended the milestone to implement a comprehensive restructuring plan from April 30, 2017 to July 31, 2017.

These extensions provide additional time for us to further advance the ongoing negotiations with our banks, potential new money investors, and the advisers to the ad hoc committee of bondholders regarding the terms of a comprehensive restructuring plan, which may include the infusion of new capital. While no definitive terms have been reached, based on stakeholder and new money investor feedback, as well as our existing leverage, we currently believe that a comprehensive restructuring plan will require a substantial impairment or conversion of our bonds, as well as impairment, losses or substantial dilution for other stakeholders. As a result, we expect that shareholders are likely to receive minimal recovery for their existing shares.

We expect the implementation of a comprehensive restructuring plan will likely involve schemes of arrangement in the United Kingdom or Bermuda or proceedings under Chapter 11 of the U.S. Bankruptcy Code, and we are preparing accordingly. Our business operations remain unaffected by the restructuring efforts and we expect to meet our ongoing customer and business counterparty obligations.

Contract award and extension for the West Elara and West Linus
On April 11, 2017, NADL, our majority owned subsidiary, announced the contract awards and extension for the jack-ups West Elara and West Linus respectively with ConocoPhillips Skandinavia AS, or ConocoPhillips, for work in the Greater Ekofisk Area. The contracts are for a period of 10 years and the total additional backlog for the new contract awards is estimated at $1.4 billion, excluding performance bonuses. The contracts include market indexed dayrates and the estimated backlog is subject to change based on market conditions.


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Sevan Developer
On April 27, 2017, the final delivery deferral agreement for the Sevan Developer was deferred to May 31, 2017 to finalize negotiations. If an agreement cannot be reached, the remaining installment of $26.3 million will be refunded.

Archer's refinancing and guarantees
On April 25, 2017, as part of our restructuring plans, we have signed and closed an agreement with Archer and its lenders to extinguish approximately $253 million in financial guarantees provided by us in exchange for a cash payment of approximately $25 million. We remain in constructive discussions with Archer and its lenders to extinguish the remaining $25 million of financial guarantees in exchange for a cash payment representing 10% of their face value. As part of Archer’s restructuring plans we have also agreed to convert $146 million, including accrued interest and fees, in subordinated loans provided to Archer into a $45 million subordinated convertible loan. The subordinated convertible loan will bear interest of 5.5%, matures in December 2021 and have a conversion right into equity of Archer Limited in 2021 based on a strike price of US$2.083 per share (subject to appropriate adjustment mechanics), which is approximately 75% above the subscription price in Archer’s private placement on February 28, 2017.

Significant Developments for the Period from January 1, 2014 through and including December 31, 2016

Capital expenditures
We had total capital expenditures on our drilling units and newbuildings of approximately $0.2 billion, $1.0 billion and $3.2 billion in the years 2016, 2015 and 2014, respectively. This includes maintenance expenditures of $0.1 billion, $0.1 billion and $0.3 billion in the years ended 2016, 2015 and 2014, 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.

Sale of investments
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%.

On April 27, 2016, we sold all of our investment in shares of SapuraKencana resulting in net cash proceeds of approximately $195 million.

Disposals
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 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 the 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 at 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 July 2015, Samsung agreed to postpone the delivery of the West Dorado and the West Draco until the end of the first quarter of 2017. As of April 21, 2017, the technical acceptance testing of the West Draco and the West Dorado have not yet been completed and we continue in discussions with Samsung regarding further deferrals.

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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 as per the deferral agreement originally entered in August 2015, Dalian agreed to defer delivery of one jack-up rig until the end of December 2015, five jack-up rigs to 2016 and two jack-up rigs to 2017. On December 28, 2016, the delivery dates for the West Titan, West Proteus, West Rhea and West Tethys were deferred an additional 6 months. Following this latest deferral agreement, four units are now scheduled to be delivered in 2017, and four units in 2018.

On October 17, 2016, we agreed with Cosco to exercise our third six-month option to defer the delivery of the Sevan Developer until April 15, 2017. Cosco has refunded to us $26.3 million, or 5% of the contract price, plus other associated costs during the fourth quarter of 2016. The final installment which is due at delivery has been amended to $499.7 million, representing 95% of the $526.0 million contract price.

On December 2, 2015, as further extended in June 2016, August 2016, October 2016, and January 2017, NADL entered into a standstill agreement with Jurong, effective until July 6, 2017, regarding the delivery of the West Rigel. During the period until, July 6, 2017, 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. However, based on current market conditions, management deems the most probable outcome to be that the West Rigel will be contributed to the joint asset holding company. As a result, we have concluded that the West Rigel should be classified as “Held for Sale” as of December 31, 2016 and 2015. Please see Note 36 to our Consolidated Financial Statements included herein for further information.

Acquisitions
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 was settled in January 2015.

Rosneft Framework Agreement
On May 26, 2014, we entered into an investment and co-operation agreement, or 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, or 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 share 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. We are currently in discussions with Rosneft regarding the potential extension of the Framework Agreement.

Other significant developments
In May 2016, we entered into a privately negotiated exchange agreement with certain holders of our outstanding 5.625% (subsequently increased to 6.125%) Senior Notes due 2017, or the 2017 Notes, pursuant to which we agreed to issue a total of 8,184,340 new shares of our common stock, in exchange for $55.0 million principal amount of the 2017 Notes in accordance with Section 3(a)(9) of the U.S. Securities Act of 1933, as amended, or the Securities Act. Settlement occurred on May 20, 2016.


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In June 2016, we entered into a privately negotiated exchange agreement with certain holders of the 2017 Notes, pursuant to which we agreed to issue a total of 7,500,000 new shares of our common stock, in exchange for $50.0 million principal amount of the 2017 Notes in accordance with Section 3(a)(9) of the Securities Act. Settlement occurred on June 13, 2016.

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.

Shares of our common stock have traded on the 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 April 21, 2017 our nonaffiliated public float represented 76.4% of total shares outstanding, and our principal shareholder, Hemen held 23.6%. 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. Our rigs are set forth in the fleet table in “–D. Property, Plants and Equipment”. We believe a modern fleet allows us to enjoy improved utilization and daily rates obtainable for our drilling units.

Floaters

Drillships: Drillships are self-propelled ships equipped for drilling offshore in water depths ranging from 1,000 to 12,000ft, 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-submersibles are self-propelled drilling rigs (which include cylindrical designed units) consisting of an upper working and living quarters deck connected to a lower hull consisting of columns and pontoons. Such rigs operate in a “semi-submerged” floating position, in which the lower hull is below the waterline and the upper deck protrudes above the surface. The rig is situated over a wellhead location and remains stable for drilling in the semi-submerged floating position, due in part to its wave transparency characteristics at the water line.

Semi-submersible rigs can be either moored or dynamically positioned. Moored semi-submersible rigs are positioned over the wellhead location with anchors and typically operate in water depths ranging up to 1,500ft. Dynamically positioned semi-submersible rigs are positioned over the wellhead location by a computer-controlled thruster system and typically operate in water depths ranging from 1,000 to 12,000. 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 seabed. A jack-up rig is mobilized to the drill site with a heavy lift vessel or a wet tow. At the drill site, the legs are lowered until they penetrate the sea bed and the hull is elevated to an approximate operational airgap of 50 to 100 feet depending on the expected environmental forces. After completion of the drilling operations, the hull is lowered to floating draft, 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 90 to 120 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, employing approximately 4,780 skilled employees. As at December 31, 2016, 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 four drillships, one semi-submersible rig and eight 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 7.9 years.

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.
 

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Commitment to safety and the environment

We believe that the combination of quality drilling units and experienced and skilled employees allows us to provide our customers with safe and effective operations. Quality assets and operational expertise allow us to establish, develop and maintain a position as a preferred provider of offshore drilling services for our customers.

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 is weak, new and modern units that offer superior technical capabilities, operational flexibility and reliability are preferred by customers and winning the majority of available opportunities. We believe, based on our proven operational track record and fleet composition, that we will be better placed to secure new drilling contracts than some of our competitors with older, less advanced rig fleets.

Strong and diverse customer relationships

We have strong relationships with our customers that we believe are based on our operational track record and quality of our fleet. Our customers are oil and gas exploration and production companies, including integrated oil companies, state-owned national oil companies and independent oil and gas companies. As of April 21, 2017, our five largest customers in terms of revenue were certain subsidiaries of ExxonMobil, LLOG, Petrobras, Statoil and Total.

Our Business Strategy
 
During the current challenging period for the industry and in order to maintain our position as a leading offshore driller, our strategy includes being able to deliver in the following key areas:

Best Operations

We are a leading offshore deepwater drilling company and our key objective is to deliver the best operations possible - both in terms of utilization and health, safety and environment. To do this, we leverage having one of the most modern fleets in the industry and our combination of experienced and skilled employees across the organization. Using our strong operational record, we intend to maximize opportunities for new drilling contracts and sustain a competitive cost structure, which we have been pursuing through our multi-year savings program, while minimizing chances of contract terminations.

Right rigs

Our business model includes both jack-ups and floaters and we will continue to maintain our presence in both segments. Having the right rigs in these two segments allows us to offer a range of assets to suit our customer needs, to work in various geographies and water depths, and to position ourselves for future growth in the industry.

Strongest relationships

We have established strong and long-term relationships with key players in the industry and we will seek to deepen and strengthen these relationships as part of our strategy. This involves identifying additional value-adding services for our existing customers and developing long-term partnerships. By providing the best possible service to our customers, we aim to help them unlock energy and be valued partners in their success.

Leading organization

We are proud of our Seadrill culture and we recognize that our business is built on people. As part of our strategy, we aim to recruit, retain, and develop the best people in the industry and to build an organization that adapts to business needs.

In addition to our long-term strategy, our immediate objective during the current industry downturn is to complete a comprehensive restructuring plan in order to provide a bridge to the industry recovery and realize the value of our high specification, modern fleet.

Restructuring Process

Over the past year we have been engaged in extensive discussions with our secured lenders and potential new money investors regarding the terms of a comprehensive restructuring. These discussions have also included an ad hoc committee of bondholders. While the ad hoc committee of bondholders is not presently restricted, they have indicated a willingness to become restricted again in the future if appropriate.

The objectives of our restructuring are to build a bridge to a recovery and achieve a sustainable capital structure. We have proposed to achieve this by extending bank maturities, reducing fixed amortization, amending financial covenants and raising new capital.


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Feedback from certain stakeholders and potential new money providers also indicate that a comprehensive and consensual agreement will likely require a substantial impairment or conversion of our bonds, as well as impairment, losses or substantial dilution for other stakeholders. As a result, we currently expect that shareholders are likely to receive minimal recovery for their existing shares.

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 2017. We currently have $4.1 billion of newbuild yard installments due in 2017, 2018 and 2019 that we will be working with shipyards to defer. Please see “Item 5. Operating and Financial Review—B. Liquidity and Capital Resources—Key financial covenants related to our borrowings” for further information.

As part of our restructuring process we have agreed amendments to our secured credit facilities. On April 28, 2016, we entered into agreements with our banking group to amend the financial covenants on all of our secured credit facilities. The amendments also included a milestone to implement a comprehensive restructuring, which was originally April 30, 2017. On April 4, 2017, we reached an agreement to further extend the covenant amendments and waivers to our secured credit facilities and extend the milestone to implement a comprehensive restructuring plan to July 31, 2017. These amendments also involved corresponding extensions of the maturities on certain secured credit facilities. These amendments provide a more stable platform from which to work with all parts of our capital structure to achieve a more comprehensive restructuring plan.

We expect the implementation of a comprehensive restructuring plan will likely involve schemes of arrangement in the United Kingdom or Bermuda or proceedings under Chapter 11 of Title 11 of the United States Code. We are preparing accordingly and have retained financial advisers and legal counsel.

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. Currently, the existing worldwide drilling rig fleet totaled 855 units including 119 drillships, 164 semi-submersible rigs, 539 jack-up rigs and 33 tender rigs. In addition, at such date there were 32 drillships, 102 jack-up rigs, 15 semi-submersible rigs and 8 tender rigs on order and 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.

Floaters

The worldwide fleet of semi-submersible rigs and drillships currently totals 283 units. Of the total delivered fleet, 168 units are capable of ultra-deepwater operations above 7500 feet, 40 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 8 years, 27 years for units classed for deepwater operations up to 7,500 feet and 30 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 74 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 50% capacity utilization versus 48% for deepwater and 43% for mid-water floaters. Utilization for harsh environment floaters is currently 53%. 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 to continue. We believe a total of 74 floaters have been scrapped since the end of 2013, equivalent to 21% of the total fleet, and currently there are 27 cold stacked units that are 30 years old or older, which are prime scrapping candidates. In the next 18 months 25 units that are 30 years old or older will be coming off contract with no follow-on work identified which represents additional scrapping candidates. A key rationale for scrapping is the 35 year classing expenditures that can cost upwards of $100 million. Many rig owners will choose to retire the unit rather than incur this cost without a visible recovery in demand on the horizon.

The current newbuilding orderbook stands at approximately 47 units, comprised of 32 drillships and 15 semi-submersibles. In 2017, 20 new rigs are scheduled for delivery, with an additional 18 scheduled for 2018 and 9 in 2019 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 539 units. Of the total delivered fleet, 232 units are termed as high specification or capable of operations in water depth of 350 feet and greater and 307 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 78 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 59% capacity utilization versus 51% for standard units. Harsh environment jack-ups are currently operating at 56% capacity utilization.

A total of 37 jack-ups have been scrapped since the end of 2013, equivalent to 6% of the total fleet, and currently there are 74 cold stacked units that are 30 years old or older, which are prime scrapping candidates. In the next 18 months 78 units that are 30 years old or older will be coming off contract 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 102 units. In 2017, 39 units are scheduled for delivery, with an additional 47 scheduled for 2018 and 16 in 2019 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.
 
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 and loop currents for our operations in the Gulf of Mexico, the winter season in offshore Norway, West of the Shetlands 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, 2016 our largest customers were:
Total, which accounted for approximately 18% of our revenues;
Petrobras, which accounted for approximately 17% of our revenues;
LLOG, which accounted for approximately 13% of our revenues;
ExxonMobil, which accounted for approximately 13% of our revenues; and
Statoil, which accounted for approximately 10% of our revenues.

Our contract backlog, as of April 21, 2017, totaled approximately $3.6 billion. Of the total contract backlog, $1.6 billion is attributable to our semi-submersible rigs and drillships and $2.0 billion attributable to our jack-up units. We expect approximately $2.9 billion of our contract backlog to be realized in the remainder of 2017. 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 us, 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. Please refer to “Item 3. Key Information—D. Risk Factors—Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted” and “—Our contract backlog for our fleet of drilling units may not be realized.”


31


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, 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. 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 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.

a) Physical Damage Insurance
 
We purchase hull and machinery insurance to cover for physical damage to our drilling rigs. We retain the risk, through self-insurance, for the deductibles relating to physical damage insurance on our drilling unit fleet; currently, a maximum of $5 million per occurrence.
 
b) Loss of Hire Insurance
 
We purchase insurance to cover operating deepwater drilling units, harsh environment jack-ups, and one semi tender belonging to Seadrill Partners, for loss of revenue in the event of extensive downtime caused by physical damage, where such damage is covered under our physical damage insurance. Our self-insured retentions under the loss of hire insurance are up to 60 days after the occurrence of the physical damage, plus up to 25% of the daily loss of hire after the 60 day period. Thereafter we are compensated for loss of revenue up to 180 days or 290 days depending on the rig. We retain the risk that the repair of physical damage takes longer than the total number of days in the loss of hire policy.

c) Protection and Indemnity Insurance

We purchase protection and indemnity insurance and excess liability for personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling rigs to cover claims between $200 million and $750 million depending on the type of drilling rig and area of operation, per event and in the aggregate.  We retain the risk for the deductible of up to $25,000 per occurrence relating to protection and indemnity insurance or up to $500,000 for claims made in the United States.

d) Windstorm Insurance

We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico 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, 2017 through April 30, 2018.


32


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 – Risks Relating to Our Company and Industry – Governmental laws and regulations, including environmental laws and regulations, may add to our costs, expose to us liability, 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 agreed minimum standard requirements allow a drilling unit or ship to work worldwide. However, some flag states are working outside of these international conventions and for those flag states a drilling unit or ship will not be able to work worldwide.

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, or OPA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Clean Water Act, or CWA, the U.S. Clean Air Act, or 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 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 BOPs 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, and sets criteria for safe drilling margins, 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.

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 – Risks Relating to Our Company and Industry – 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 – Risks Relating to Our Company and Industry – 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.”


33


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. In October 2016, it was reported that Brazil could lessen local content rules. Although these requirements have not had a 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.


34


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 April 21, 2017. Please see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources” for more information on our newbuilding program.

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
 
available
West Resolute
2007
 
350
 
30,000
 
Sharjah, U.A.E.
 
available
West Prospero
2007
 
400
 
30,000
 
Malaysia
 
available
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
 
September 2017
West Cressida
2009
 
375
 
30,000
 
Thailand
 
available
West Mischief
2010
 
350
 
30,000
 
Abu Dhabi
 
December 2017
West Callisto
2010
 
400
 
30,000
 
Saudi Arabia
 
November 2018
West Leda
2010
 
375
 
30,000
 
Malaysia
 
available
West Elara (2)
2011
 
450
 
40,000
 
Norway
 
October 2027
West Castor
2013
 
400
 
30,000
 
Mexico
 
December 2019
West Telesto
2013
 
400
 
30,000
 
Malaysia
 
available
West Tucana
2013
 
400
 
30,000
 
Angola
 
June 2017
AOD-1 (3)
2013
 
400
 
30,000
 
Saudi Arabia
 
June 2019
AOD-2 (3)
2013
 
400
 
30,000
 
Saudi Arabia
 
June 2019
AOD-3 (3)
2013
 
400
 
30,000
 
Saudi Arabia
 
December 2019
West Linus (2) (5)
2014
 
450
 
40,000
 
Norway
 
December 2028
West Titan (1)
2017
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Proteus (1)
2017
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Rhea (1)
2017
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Hyperion (1)
2017
 
400
 
30,000
 
Dalian Shipyard (China)
 

West Tethys (1)
2018
 
400
 
30,000
 
Dalian Shipyard (China)
 
 
West Umbriel (1)
2018
 
400
 
30,000
 
Dalian Shipyard (China)
 

West Dione (1)
2018
 
400
 
30,000
 
Dalian Shipyard (China)
 

West Mimas (1)
2018
 
400
 
30,000
 
Dalian Shipyard (China)
 

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

35


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 (1)(4)
2017
 
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
 
Liberia
 
available
West Carina
2015
 
12,000
 
40,000
 
Brazil
 
June 2018
West Draco (1)
2017
 
12,000
 
40,000
 
Samsung Heavy Industries (South Korea)
 

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

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

West Libra (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 Consolidated Financial Statements as VIEs. Please see Note 35 "Variable interest entities" of our Consolidated Financial Statements included herein for more information. The West Linus is 100% owned by Ship Finance and leased back to NADL.

Available drilling units include drilling units that may be cold or warm stacked.

The total book value of our drilling units and newbuildings as at December 31, 2016 was $14,276 million and $1,531 million respectively, including shared capital spares.

In addition, NADL has agreed with Jurong to, among other things, delay taking delivery of the West Rigel until June 2017, 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. The West Rigel is classified as an asset held of sale as at December 31, 2016.

In addition to the drilling units listed above, as at December 31, 2016, we have buildings, plant and equipment with a net book value of $41 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 $17 million in 2016.

We do not have any material intellectual property rights.

ITEM 4A.
UNRESOLVED STAFF COMMENTS

Not applicable.


36


ITEM 5.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS

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.” Furthermore, the information below has been adjusted to reflect the impact of the restatement on our Consolidated Financial Statements as described in “Note 39 – Restatement of Previously Issued Financial Statements” included in this annual report on Form 20-F. Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and are presented in U.S. dollars unless otherwise indicated. We refer you to the notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are prepared, and we draw your attention to the statement regarding going concern as described in Note 1 "General information".

Overview

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 3 operating 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 environments.

Other operations include management services to third parties and related parties. Income and expenses from these management services are classified under this segment.

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. The accounting principles for the segments are the same as for our Consolidated Financial Statements.

Our Fleet
The following table summarizes the development of our fleet of drilling units (excluding newbuildings) for the periods presented, based on the dates when the units began operations:
 
Jack-up rigs
 
Floaters
 
Total units
Unit type
 
Drillships
 
Semi-submersible rigs
 
December 31, 2014
24

 
7

 
12

 
43

additions

 
1

 

 
1

(disposals)
(5
)
 
(1
)
 

 
(6
)
December 31, 2015
19

 
7

 
12

 
38

additions

 

 

 

(disposals)

 

 

 

December 31, 2016
19

 
7

 
12

 
38


Additions of drilling units relate primarily to the completion of our newbuildings in 2015.

The disposals in 2015 related 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. There were no disposals of drilling units in 2016.

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;

37


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, including changes in counterparty credit risk;
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 our business.

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 economic 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.
 
Other revenues
Other revenues include amounts recognized as early termination fees under the drilling contracts which have been terminated prior to the contract end date, favorable and unfavorable contracts, related party revenues and external management fees. Early termination fees are recognized as and when any contingencies or uncertainties associated with our rights to receive are resolved and favorable and unfavorable drilling contracts are recognized at fair value at the date of acquisition. Related party revenues relate to management support and administrative services provided to our associates. External management fees relate to operational, administrative and support services we provide to third parties.

Please see Note 4 "Other revenues" of our Consolidated Financial Statements included herein for a detailed description of our other revenues.

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.


38


Operating Expenses
Our operating expenses consist primarily of vessel and rig operating expenses, amortization of favorable contracts, reimbursable expenses, the impairment of goodwill and drilling units, depreciation and amortization, and general and administrative expenses.
Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, 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 we operate the rigs and are expensed as incurred.
Amortization of favorable contracts relates to the amortization of favorable drilling contracts which are recorded as an intangible asset at fair value on the date of acquisition. The amounts of these assets are amortized on a straight-line basis over the estimated remaining contractual period.
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. Drilling units are recorded at historical cost less accumulated depreciation. The cost of these assets less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of our rigs, when new, is thirty years. Costs related to periodic surveys of drilling units are capitalized as part of drilling units and amortized over the anticipated period between surveys, which is generally five years. These costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic surveys are included in depreciation and amortization expense.
General and administrative expenses include the costs of our corporate and regional offices in various locations, legal and professional fees, property cost 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
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. Any related changes in fair value as a result of changes in our own and counterparty credit risk may have a significant impact on our results of operations and financial position.
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.


39


Drilling Units
The carrying amount of our drilling units is subject to various estimates, assumptions, and judgments related to capitalized costs, useful lives and residual values and impairments. At December 31, 2016 and 2015, the carrying amount of our drilling units was $14 billion and $15 billion, representing 66% and 64% of our total assets, respectively.

Drilling units and related equipment are recorded at historical cost less accumulated depreciation. 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 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. 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, 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.

During the years ended December 31, 2016, and 2015 we identified indicators that the carrying value of our drilling units may not be recoverable. Market indicators included the reduction in new contract opportunities, fall in market dayrate and contract terminations. We assessed recoverability of our drilling units by first evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilizations of the units. The estimated undiscounted future net cash flows were found to be greater than the carrying value of our drilling units, with sufficient headroom. As a result, we did not need to proceed to assess the discounted cash flows of our drilling units, and no impairment charges were recorded for the years ended December 31, 2016, and 2015.

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 our 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 we will be required to impair certain drilling units.

Impairment of Equity Method Investments and Marketable Securities
We assess our equity method investments 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.

The deteriorating market conditions in the oil and gas industry, as well as the supply and demand conditions in the industry we operate, are considered to be indicators of impairment. We have determined the length and severity of the deterioration of market conditions affecting our investments to be representative of an other than temporary impairment for the years ended December 31, 2016 and 2015. During 2016, we recognized a total impairment loss of $895 million (2015: $1,285 million).
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 that could materially affect our earnings, as described below.

40


The fair value of equity method investments (Seadrill Partners - direct ownership interest and interest in subordinated units) 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 fair value of investments accounted for using the cost method (Seadrill Partners - Seadrill member interest and IDRs) was determined using a Monte Carlo simulation method, or the Monte Carlo Model. 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. The method takes into account the cash distribution waterfall, historical volatility, estimated dividend yield and the share price of the common units as at the deconsolidation date. We employ significant judgment 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, our financial condition and results of operations could be affected in the period of any such change of estimate.
Please refer to Note 8 "Impairment loss on marketable securities and investment in associated companies" to our Consolidated Financial Statements included herein for further information on the various estimates and assumptions used for calculating the loss on impairment of equity method investments and marketable securities.
The table below summarizes the total impairments of investments made during the years ended December 31, 2016 and 2015:
(In $ millions)
Year ended December 31, 2016

 
Year ended December 31, 2015

 
 
 
(Restated)

Impairments of marketable securities
 
 
 
Seadrill Partners - Common units
153

 
574

SapuraKencana

 
178

Total impairment of marketable securities investments (reclassification from OCI)
153

 
752

 
 
 
 
Impairments of investment in associated companies
 
 
 
Seadrill Partners - Total direct ownership investments
400

 
302

Seadrill Partners - Subordinated units
180

 
125

Seadrill Partners - Seadrill Member Interest and IDRs
73

 
106

SeaMex
76

 

Sete Brasil Participacoes SA
13

 

Total impairment of investments in associated companies
742

 
533

 
 
 
 
Total impairment of investments
895

 
1,285


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 at 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 period between September 30, 2015 and September 30, 2016, Seadrill Partners’ unit price fell by approximately 62%, on both a spot price and trailing three-month average basis.

As at September 30, 2016, we 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 $153 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.


41


During the three months ended December 31, 2016, Seadrill Partners’ unit price increased from approximately $3.53 at September 30, 2016 to $4.20 at December 31, 2016. As at December 31, 2016, an unrealized gain of $17 million had been recognized in “accumulated other comprehensive income,” as a result of re-measuring the value of our investment in the common units of Seadrill Partners to the market price as at December 31, 2016.

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 at September 30, 2015 and 2016, 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 at September 30, 2015 and 2016. The fair value of these investments was derived using 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% in 2015 and 9.5% in 2016, 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.

The assumptions used in the DCF model were derived from significant unobservable inputs (representative of Level 3 inputs for Fair Value Measurement) and are based on management’s judgments and assumptions available at the time of performing the impairment test. We employ significant judgment in developing these estimates and assumptions including the following:
forecast dayrates for our drilling contracts;
utilization rates;
operating costs and overheads;
estimated annual capital expenditure, cost of rig replacement and/or enhancement programs;
estimated maintenance, inspections or other costs associated with a rig after completion/termination of the contract;
remaining useful life of each rig; and
estimated tax rates.

The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios were developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment. Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment.

We compared the carrying value of each rig to its relative recoverable value determined using undiscounted cash flow projections for each rig. For each rig with a carrying value in excess of its undiscounted cash flows, we computed its impairment based on the difference between the carrying value and fair value of the rig.

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. As at September 30, 2016, the carrying value of the subordinated units was found to exceed the fair value by $180 million, and the carrying value of the direct ownership interests was found to exceed the fair value by $400 million. We have recognized this impairment of the investments within “loss on impairment of investments” in our consolidated statement of operations for the year ended December 31, 2015 and 2016.

Seadrill Partners - Member interest - Impairment of cost method investments
We also hold the Seadrill member interest, or Seadrill Member Interest, which is a 0% non-economic interest, and which holds the rights to 100% of the incentive distribution rights, or 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.


42


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. The method takes into account the cash distribution waterfall, historical volatility, estimated dividend yield and the share price of the common units as at the deconsolidation date. We employ significant judgment 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, our financial condition and results of operations could be affected in the period of any such change of estimate.

As at September 30, 2015 and 2016, 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 and 2016. As at September 30, 2015, the carrying value of the investment was found to exceed the fair value by $106 million. As at September 30, 2016, the carrying value of the investment was found to exceed the fair value by $73 million. We have recognized this impairment within “loss on impairment of investments” in our consolidated statement of operations for the year ended December 31, 2015 and 2016.

SeaMex - Impairment of investment in associated companies
We have measured and recognized an other than temporary impairment of the investment in SeaMex as at September 30, 2016.
The fair value was derived using the DCF model. The estimated future free cash flows associated with the investment were primarily based on expectations around applicable day rates, drilling unit utilization, operating costs, capital and long-term maintenance expenditures and applicable tax rates. The cash flows were estimated over the remaining useful economic 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 11%. The DCF model derived an enterprise value of the investments, after which associated debt was subtracted to provide equity values. The carrying value of the investment was found to exceed the fair value by $76 million. We have recognized this impairment of the investments within “Loss on impairment of Investments” in the Statement of Operations.

The assumptions used in the DCF models were derived from unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the impairment test. The significant assumptions and estimate used in the model are discussed in detail under "Seadrill Partners - Subordinated units and direct ownership interests - Impairment of equity method investment" above. We employ significant judgment 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, our 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, we 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 at September 30, 2015, we recognized an impairment charge of $178 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.

An additional restated net impairment charge was recognized to bring the carrying value of the asset to the realizable value of $195 million as at December 31, 2015. The resulting net impairment was a loss of $11 million, which is recognized within "Loss on impairments of investments" in the Consolidated Statement of Operations. The total investment impairment charge for SapuraKencana recognized in the restated year ended December 31, 2015 was $178 million.

On April 27, 2016, we sold our entire shareholding in SapuraKencana for net proceeds of $195 million, net of transaction costs.


43


Financial Instruments - Derivative valuations
We recently reviewed our fair value accounting principles under ASC 820 - Fair Value Measurements relating to our interest rate and cross currency swap portfolio, and determined we had not appropriately included counterparty credit risk in our fair value measurements relating to the above derivative instruments. ASC 820 requires counterparty credit risk to be included in the determination of the fair value of our interest rate and cross currency swap portfolio, and any related changes in fair value as a result of changes in our credit risk and counterparty credit risk are recognized in the Consolidated Statements of Operations in the line item “(Loss)/gain on derivative financial instruments”. Following this review, we determined a restatement of our previously issued financial statements was required in order to correctly reflect the counterparty credit risk in our derivative valuations. The calculation of the credit risk in the swap values is subject to a number of assumptions including an assumed credit default swap rate based on our traded debt, and recovery rate which assumes the proportion of value recovered, given an event of default.

Please refer to Note 32 "Risk management and financial instruments" for further information on the derivatives valuations and Note 39 "Restatement of previously issued Financial Statements" for further information on the effects of the restatement.

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 at 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 fully impaired the book value of our goodwill in the financial period ended September 30, 2015, recognizing an impairment charge of $563 million. We first assessed the 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. 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.

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 at 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.


44


Recent Accounting Pronouncements

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

In August 2014, the Financial Accounting Standards Board, or 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 is 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. We adopted this ASU effective December 31, 2016. We have evaluated the impact of this ASU and have disclosed the relevant effects in Note 1 "General Information" of our Consolidated Financial Statements included herein.

Please see Note 2 "Accounting policies" of our Consolidated Financial Statements included herein for the full 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 FASB issued ASU 2014-09, Revenue from Contracts with Customers, which provides new authoritative guidance on the methods of revenue recognition and related disclosure requirements. This new standard supersedes all existing revenue recognition requirements, including most industry-specific guidance. The new standard requires a company to recognize revenue when it transfers goods or services to customers in an amount that reflects the consideration that the company expects to receive for those goods or services. The new standard also requires additional qualitative and quantitative disclosures. 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 at the date of adoption. Early adoption is not permitted until periods beginning after December 15, 2016.

During 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU 2016- 12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, which do not change the core principle of the Standard Update, but instead clarify the implementation guidance and provide narrow-scope improvements. In December 2016, the FASB also issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which includes additional guidance for disclosures related to remaining performance obligations. Based on the analysis to date, the Company has assessed there is significant interaction between ASC 606 and ASC 842 relating to Leases; therefore, the Company expects to adopt the updates concurrently, effective January 1, 2018. The Company continues to make significant progress on its review of the standard to determine the effect the requirements may have on its consolidated financial statements, according to its contract-specific facts and circumstances.

The Company is consulting with other drilling companies to fully determine recognition and disclosure under the new standard. At present, the Company does not expect the pattern of revenue recognition under the new guidance to materially differ from its current revenue recognition pattern and expects to transition using a modified retrospective approach whereby it will record the cumulative effect of applying the new standard to all outstanding contracts as at January 1, 2018 as an adjustment to opening retained earnings. The Company’s initial assessment may change as it continues to refine these assumptions.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update requires an entity to recognize right-of-use assets and lease liabilities on its balance sheet and disclose key information about leasing arrangements. It also offers specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and early adoption is permitted, using a modified retrospective application. The Company has started assessing the impact of this standard update on its consolidated financial statements and related disclosures and has determined that its drilling contracts contain a lease component. The adoption of this standard will result in increased disclosure of the Company’s leasing arrangements and may affect the way the Company recognizes revenues associated with the lease and revenue components, according to its contract-specific facts and circumstances. The standard update could also introduce variability to the timing of the Company’s revenue recognition compared to current accounting standards. Based on the analysis to date, the Company has assessed there is significant interaction between ASC 606 relating to revenue recognition from contracts with customers and ASC 842; therefore, the Company expects to adopt the updates concurrently, effective January 1, 2018, using the modified retrospective approach.


45


The Company is consulting with other drilling companies to fully determine recognition and disclosure under the new standard. The Company continues to make significant progress on its review of the standard to determine the effect the requirements could have on its consolidated financial statements and may change its initial assessment as it continues to refine these requirements.

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

A.
RESULTS OF OPERATIONS (Restated)


Fiscal Year Ended December 31, 2016, Compared to Fiscal Year Ended December 31, 2015
 
The following table sets forth our operating results (by segment) for 2016 and 2015 (as restated).
 
Year ended December 31, 2016
 
Year ended December 31, 2015
 
 
 
Restated
 
In US$ millions
Floaters

 
 Jack-
up rigs

 
Other

 
Total

 
Floaters

 
 Jack-
up rigs

 
Other

 
Total

Total operating revenues
2,212

 
865

 
92

 
3,169

 
2,906

 
1,293

 
136

 
4,335

(Loss)/gain on disposals

 

 

 

 
(243
)
 
179

 
1

 
(63
)
Contingent consideration realized
21

 

 

 
21

 
47

 

 

 
47

Total operating expenses (excluding impairment of long-lived assets)
(1,430
)
 
(598
)
 
(92
)
 
(2,120
)
 
(1,807
)
 
(808
)
 
(122
)
 
(2,737
)
Loss on impairment of long-lived assets
(44
)
 

 

 
(44
)
 
(563
)
 

 

 
(563
)
Operating income
759

 
267

 

 
1,026

 
340

 
664

 
15

 
1,019

Interest expense
 
 
 
 
 
 
(412
)
 
 

 
 

 
 
 
(415
)
Impairment of investments
 
 
 
 
 
 
(895
)
 
 
 
 
 
 
 
(1,285
)
Other financial items
 
 
 
 
 
 
325

 
 

 
 

 
 
 
254

Income/ (loss) before taxes
 
 
 
 
 
 
44

 
 

 
 

 
 
 
(427
)
Income taxes
 
 
 
 
 
 
(199
)
 
 

 
 

 
 
 
(208
)
Net loss
 
 
 
 
 
 
(155
)
 
 

 
 

 
 
 
(635
)


Total operating revenues
In US $millions
2016

 
2015

 
Change

Floaters
2,212

 
2,906

 
(24
)%
Jack-up rigs
865

 
1,293

 
(33
)%
Other
92

 
136

 
(32
)%
Total operating revenues
3,169

 
4,335

 
(27
)%

Total operating revenues were $3.2 billion for 2016, compared to $4.3 billion in 2015, a decrease of $1.1 billion, or 27%. Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and other revenues. The decrease in total operating revenues compared to 2015 was primarily driven by an increase in the number of idle rigs and reductions in certain operating dayrates, partly offset by improved economic utilization on the rigs that were operating.

Total operating revenues in the floaters segment were $2.2 billion in 2016 compared to $2.9 billion in 2015, a decrease of $0.7 billion, or 24%. The decrease primarily resulted from the increase in the number of idle rigs and reductions in certain operating dayrates. There were nine floaters operating at the end of 2016, compared to 14 operating at the end of 2015. In addition we disposed of the West Polaris to Seadrill Partners in June 2015. The average dayrates earned by our floaters was approximately $400,000 during 2016 compared to $441,000 during 2015. The decrease in the number of operating units and dayrates was partly offset by higher economic utilization on our floaters of 97% in 2016 compared to 91% in 2015. We also received the early termination fee for the West Hercules of $66 million, of which $58 million was recognized in 2016.

Total operating revenues in the jack-up rigs segment were $0.9 billion in 2016 compared to $1.3 billion in 2015, a decrease of $0.4 billion, or 33%. The decrease was primarily due to the increase in the number of idle rigs and reductions in certain operating dayrates. There were 12 jack-ups operating at the end of 2016 compared to 14 operating at the end of 2015. In addition the five jack-ups relating to SeaMex were deconsolidated in March 2015. The average dayrates earned by our jack-ups was approximately $159,000 during 2016 compared to $198,000 during 2015. The

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decrease in number of operating units and dayrates was partly offset by higher economic utilization on our jack-ups of 98% in 2016 compared to 97% in 2015. We also recognized the early termination fee for the West Epsilon of $11 million in 2016.

The following table summarizes our average dayrates and economic utilization percentage by rig type for the periods indicated: 
 
Year ended December 31,
 
2016
 
2015
 
Average
dayrates
($) (1)
 
Economic utilization
(%) (2)
 
Average
dayrates
($) (1)
 
Economic utilization
(%) (2)
Floaters
400,000

 
97
 
441,000

 
91
Jack-up rigs
159,000

 
98
 
198,000

 
97

(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.
(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, for the rigs that are on contract.

(Loss)/gain on disposals

In 2016 we did not record any material gains or losses on the disposal of assets. In 2015, we recorded a net loss of $239 million relating to the loss on disposals of the West Polaris, and the newbuilding West Mira which was cancelled, and the newbuilding West Rigel which is now classified as held for sale. The loss was partially offset by a gain of $181 million on the disposal of our five jack-up rigs to SeaMex.
 
Contingent consideration realized

In 2016 we recorded contingent consideration realized of $21 million (2015: $47 million) relating to the disposals of the West Polaris and West Vela.

Total operating expenses (excluding loss on impairment of long-lived assets)
In US$ millions
2016

 
2015