20-F 1 d1192257_20-f.htm d1192257_20-f.htm

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, 2010

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)


(Translation of Registrant's name into English)
(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
 


 
1

 
 
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, 2010, there were 443,125,691 shares of the Registrant's common stock, $2.00 par value, 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

[   ] 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  [   ]
Accelerated filer  [   ]
   


Non-accelerated filer   [ X ]
(Do not check if a smaller reporting company)
Smaller reporting company  [   ]

 
Indicate by check mark which basis of accounting the Registrant has used to prepare the financial statements included in this filing:
 
[ X ]  U.S. GAAP
 
[   ]  International Financial Reporting Standards as issued by the International Accounting Standards Board
 
[   ]  Other
 
If "Other" has been checked in response to the previous question, indicate by check mark which
financial statement item the Registrant has elected to follow.
 
[   ]  Item 17
 
[   ]  Item 18

If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

[   ]  Yes
[ X ]  No
   

 
2

 

 
FORWARD LOOKING STATEMENTS

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

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

The forward-looking statements in this document are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management's examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections.

In addition to these important factors and matters discussed elsewhere in this Annual Report, and in the documents incorporated by reference in this Annual Report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include factors related to the offshore drilling market, including supply and demand, utilization rates, dayrates, customer drilling programs, commodity prices, effects of new rigs on the market and effects of declines in oil and gas prices and downturn in global economy on market outlook for our various geographical operating sectors and classes of rigs, the competitive nature of the offshore drilling industry, oil and gas prices, technological developments, political events, crew wages, drydocking, repairs and maintenance, customer contracts, including contract backlog, contract commencements, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations, newbuildings, upgrades, shipyard and other capital projects, including completion, delivery and commencement of operations dates, expected downtime and lost revenue, the level of expected capital expenditures and the timing and cost of completion of capital projects, liquidity and adequacy of cash flow for our obligations, including our ability and the expected timing to access certain investments in highly liquid instruments, our results of operations and cash flow from operations, including revenues and expenses, uses of excess cash, including debt retirement and share repurchases under our share repurchase program, timing and proceeds of asset sales, tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Bermuda, Norway and the United States, legal and regulatory matters, including results and effects of legal proceedings and governmental audits and assessments, outcome and effects of internal and governmental investigations, customs and environmental matters, insurance matters, debt levels, including impacts of the financial and credit crisis, effects of accounting changes and adoption of accounting policies, investments in recruitment, retention and personnel development initiatives, pension plan and other postretirement benefit plan contributions, the timing of severance payments and benefit payments and other important factors described from time to time in the reports filed by us with the Securities and Exchange Commission, or the Commission, and the New York Stock Exchange, or NYSE. We caution readers of this Annual Report not to place undue reliance on these forward-looking statements, which speak only as of their dates.

 
3

 



TABLE OF CONTENTS

PART I

ITEM 1.
IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
5
ITEM 2.
OFFER STATISTICS AND EXPECTED TIMETABLE
5
ITEM 3.
KEY INFORMATION
5
ITEM 4.
INFORMATION ON THE COMPANY
21
ITEM 4A.
UNRESOLVED STAFF COMMENTS
32
ITEM 5.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS
32
ITEM 6.
DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
54
ITEM 7.
MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
58
ITEM 8.
FINANCIAL INFORMATION
60
ITEM 9.
THE OFFER AND LISTING
62
ITEM 10.
ADDITIONAL INFORMATION
64
ITEM 11.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
74
ITEM 12.
DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
76
     
PART II
   
     
ITEM 13.
DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
77
ITEM 14.
MATERIAL  MODIFICATIONS  TO  THE  RIGHTS  OF  SECURITY HOLDERS AND
USE OF PROCEEDS
77
ITEM 15.
CONTROLS AND PROCEDURES
77
ITEM 16.
RESERVED
78
ITEM 16A.
AUDIT COMMITTEE FINANCIAL EXPERT
78
ITEM 16B.
CODE OF ETHICS
78
ITEM 16C.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
78
ITEM 16D.
EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
79
ITEM 16E.
PURCHASES OF EQUITY  SECURITIES  BY  THE ISSUER AND AFFILIATED PURCHASERS
79
ITEM 16F.
CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT
80
ITEM 16G.
CORPORATE GOVERNANCE
80
     
PART III
   
     
ITEM 17.
FINANCIAL STATEMENTS
81
ITEM 18.
FINANCIAL STATEMENTS
81
ITEM 19.
EXHIBITS
81
     


 
4

 


PART 1.

As used in this Annual Report, unless the context otherwise requires, references to "Seadrill Limited," the "Company," "we," "us," "Group," "our" and words of similar import refer to Seadrill Limited, its subsidiaries and its other consolidated entities. Unless otherwise indicated, all references to "USD", "US$" and "$" in this report are to, and amounts are represented in, US dollar.

ITEM 1.  IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. KEY INFORMATION

A. SELECTED FINANCIAL DATA

The selected statement of operations and cash flow statement data of the Company with respect to the fiscal years ended December 31, 2010, 2009 and 2008 and the selected balance sheet data of the Company with respect to the fiscal years ended December 31, 2010 and 2009 have been derived from the Company's Consolidated Financial Statements included in Item 18 of this annual report, prepared in accordance with accounting principles generally accepted in the United States, or U.S. GAAP.

The selected statement of operations and cash flow statement data for the fiscal year ended December 31, 2007 and 2006 and the selected balance sheet data with respect to the fiscal years ended December 31, 2008, 2007 and 2006 have been derived from audited consolidated financial statements of the Company not included herein.

The following table should be read in conjunction with Item 5. "Operating and Financial Review and Prospects" and the Company's Consolidated Financial Statements and Notes thereto, which are included herein. The Company's accounts are maintained in US dollar. We refer you to the notes to our consolidated financial statements for a discussion of the basis on which our consolidated financial statements are presented.

   
Year ended December 31,
 
   
2010
 
2009
 
2008
 
2007
 
2006
 
       
(In millions of US dollar except common share and per share data)
     
Statement of Operations Data:
                     
Total operating revenues
    4,041       3,254       2,106       1,552       1,155  
Net operating income
    1,625       1,372       649       489       226  
Net income (loss) (1)
    1,172       1,353       (123 )     515       245  
Earnings per share, basic
  $ 2.73     $ 3.16     $ (0.41 )   $ 1.28     $ 0.62  
Earnings per share, diluted
  $ 2.73     $ 3.00     $ (0.41 )   $ 1.20     $ 0.61  
Dividends declared
    990       199       688       -       -  
Dividends declared per share
  $ 2.41     $ 0.50     $ 1.75       -       -  
 

 
(1) In 2008, other financial items included an impairment loss of $615 million related to our investment in Pride International Inc., or Pride, Scorpion Offshore Limited, or Scorpion, and SapuraCrest Bhd, or SapuraCrest.
 

 
 
5

 

 
 
      Year ended December 31,  
     
2010
     
2009
     
2008
     
2007
     
2006
 
           (In millions of US dollar except common
share and per share data)
       
Balance Sheet Data (at end of period):
                             
Cash and cash equivalents
    755       460       376       997       210  
Drilling units
    10,795       7,515       4,645       2,452       2,293  
Newbuildings
    1,247       1,431       3,661       3,340       2,025  
Investment in associated companies
    205       321       240       176       238  
Goodwill
    1,677       1,596       1,547       1,510       1,256  
Total assets
    17,497       13,831       12,305       9,293       6,743  
Interest bearing debt
(including current portion)
    9,156       7,396       7,437       4,601       2,815  
Share capital
    886       798       797       797       766  
Shareholders’ equity
    5,937       4,813       3,222       3,728       2,927  
Common shares outstanding, in millions
    443.1       399.0       398.4       398.5       383.1  
Weighted average common shares outstanding
    409.2       398.5       398.3       392.8       352.1  
                                         
Other Financial Data:
                                       
Net cash provided by operating activities
    1,300       1,452       401       486       174  
Net cash used in investing
activities
    (2,297 )     (924 )     (3,847 )     (1,868 )     (3,180  
Net cash provided by financing activities
    1,293       (454 )     2,826       2,168       3,162  
Capital expenditure
    (2,367 )     (1,369 )     (2,768 )     (1,738 )     (1,196  
 

B. CAPITALIZATION AND INDEBTEDNESS

Not applicable.

C. REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

D. RISK FACTORS

Our assets are primarily engaged in offshore contract drilling for the oil and gas industry in benign and harsh environments worldwide, including ultra-deepwater environments. The following summarizes some of the risks that may materially affect our business, financial condition or results of operations. Unless otherwise indicated in this Annual Report on Form 20-F for the year ended December 31, 2010, all information concerning our business and our assets is as of April 26, 2011.
 
Risks Relating to Our Industry

Our business, financial condition, results of operations and ability to pay dividends depend on the level of activity in the offshore oil and gas industry, which is significantly affected by, among other things, volatile oil and gas prices and may be materially and adversely affected by a decline in  offshore oil and gas exploration, development and production.

The offshore contract drilling industry is cyclical and volatile. Our business depends on the level of activity in oil and gas exploration, as well as the identification and development of oil and gas reserves and production in offshore areas worldwide. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development, political concerns and regulatory requirements all affect customers' levels of activity and drilling campaigns. Accordingly, oil and gas prices and market expectations of potential changes in these prices significantly affect the level of activity and demand for our drilling units and well services.



 
6

 
 
 

Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including the following:

 
worldwide production and demand for oil and gas;

 
the cost of exploring for, developing, producing and delivering oil and gas;

 
expectations regarding future energy prices;

 
advances in exploration, development and production technology;

 
the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels and pricing;

 
the level of production in non-OPEC countries;

 
government laws and regulations, including environmental protection laws and regulations;

 
local and international political, economic and weather conditions;

 
domestic and foreign tax policies;

 
the development and exploitation of alternative fuels and other alternative energy sources;

 
the policies of various governments regarding exploration and development of their oil and gas reserves;

 
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 or other geographic areas or further acts of terrorism in the United States, or elsewhere; and

 
volatility in the exchange rate of the US dollar against other currencies.

Declines in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, could negatively affect our business in the offshore drilling sector. Sustained periods of low oil prices typically result in reduced exploration and drilling because oil and gas companies' capital expenditure budgets are subject to their forecasted cash flow and are therefore sensitive to changes in energy prices. These changes in oil and gas prices can have a dramatic effect on rig demand, and periods of low demand can cause excess rig supply and intensify the competition in the industry which often results in drilling units, particularly lower specification drilling units, being idle for long periods of time. We cannot predict the future level of demand for our services or future conditions of the oil and gas industry. Any decrease in exploration, development or production expenditures by oil and gas companies could reduce our revenues and adversely affect our business and results of operations.
 
In addition to oil and gas prices, the offshore drilling industry is influenced by additional factors, including:
 
 
the availability of competing offshore drilling vessels;
 
 
the level of costs for associated offshore oilfield and construction services;
 
 
oil and gas transportation costs;
 
 
the discovery of new oil and gas reserves;
 
 
the cost of non-conventional hydrocarbons; and
 
 
regulatory restrictions on offshore drilling.
 
Any of these factors could reduce demand for our services and adversely affect our business and results of operations.
 

 
7

 

 

An over-supply of drilling units may lead to a reduction in dayrates, which are the amounts earned per day per drilling unit, which may materially impact our earnings.

In the past significant spikes in oil and gas prices have led to increased drilling activities in offshore regions with respect to both exploration and production activities. In response, offshore drilling contractors have ordered new drilling units to meet their customers' increasing demand, leading to a high number of rigs under construction. Due to the cyclicality that has characterized our industry, spikes in oil prices have often been followed by a period of sharp and sudden declines in oil prices and an oversupply of drilling units, which, in turn, results in declines in utilization and dayrates, and an increase in the number of idle drilling units without contracts.

The number of offshore drilling units (including units under construction) currently totals 923 consisting of 338 drillships and semi-submersible rigs, 551 jack-ups and 34 self-erecting tender rigs. The floater fleet includes 116 existing dynamically positioned deepwater drilling units and an additional 67 dynamically positioned deepwater units currently under construction or on order for expected deliveries between now and the end of 2014. The strong growth in deepwater units is due to oil companies' greater focus on existing and new deepwater regions for exploration and production, and the inability to upgrade or modify the existing mid-water fleet as necessary for undertaking deepwater drilling campaigns. If the floater fleet continues to grow, there may be an over-supply of such drilling units, which may lead to a reduction in dayrates and that could materially impact our earnings.

The worldwide fleet of jack-up rigs contains 551 units with an average age of approximately 20 years. Of the 551 units 102 has been built after 2005 and there are 74 jack-up rigs currently under construction. The growth in newbuilding jack-up rigs is based on demand from oil companies for more advanced and effective jack-up rigs, and reflects a general trend towards high-grading the technical capabilities of the world-wide fleet. However, the majority of the newbuilding jack-up rigs have been ordered on speculation (i.e., without fixed employment for future work in place). This could intensify price competition as scheduled delivery dates come closer, resulting in a reduction in dayrates. Lower utilization and dayrates could adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates could also have a material adverse effect on the value of our assets and could materially impact our earnings.

The world-wide fleet of self-erecting tender rigs totals 34 units including 5 rigs under construction. All tender rigs under construction, apart from the most recently ordered Seadrill rig T17, have secured contract for employment following delivery. The construction of new tender rigs reflects the general growth in demand for modern offshore drilling units as well as high-grading of the fleet. If the tender rig fleet continues to grow, there may be an over-supply of such drilling units, which may lead to a reduction in dayrates and that could materially impact our earnings.

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

If the offshore contract drilling industry suffers adverse developments in the future, the fair market value of our drilling units may decline. 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:

 
general economic and market conditions affecting the offshore contract drilling industry, including competition from other offshore contract drilling companies;

 
types, sizes and ages of drilling units;

 
supply and demand for drilling units;

 
costs of newbuildings;

 
prevailing level of drilling services contract dayrates;

 
governmental or other regulations; and

 
technological advances.

If we sell any drilling unit at a time when prices for drilling units have fallen, such a sale may result in a loss. Such a loss could materially and adversely affect our business prospects, financial condition, liquidity, results of operations and ability to pay dividends to our shareholders.
 
 
 
8

 
 
 
The offshore drilling industry is highly competitive and there is strong price competition, and as a result, we may be unable to compete successfully.
 
The offshore contract drilling industry is highly competitive with several industry participants, none of which has a dominant market share, and is characterized by high capital and maintenance requirements. Drilling contracts are traditionally awarded on a competitive bid basis. Price competition is often the primary factor in determining which qualified contractor is awarded the drilling contract, although drilling unit availability, location and suitability, the quality and technical capability of service and equipment, reputation and industry standing are key factors which are also considered. Mergers among oil and natural 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. There is no guarantee that we will be able to remain competitive in a market with a limited number of available customers.

Consolidation of suppliers may limit our ability to obtain supplies and services when we need them, at an acceptable cost, or at all.

We rely on a significant supply of consumables, spare parts and equipment to operate, maintain, repair and upgrade our fleet of drilling units. During the last decade, the number of available suppliers has been reduced, resulting in fewer alternatives for sourcing key supplies and services. In addition, certain key equipment used in our business is protected by patents and other intellectual property of our suppliers. This may limit our ability to obtain supplies and services at an acceptable cost, at the times we need them, or at all. Cost increases, delays or unavailability could negatively impact our future operations and result in additional rig downtime due to delays in the repair and maintenance of our fleet.

Our international operations involve additional risks associated with operating outside the U.S.

We operate in various regions throughout the world which may expose us to political and other uncertainties, including risks of:

 
terrorist acts, war, civil disturbances and piracy;

 
seizure, nationalization or expropriation of property or equipment;

 
repudiation, nullification, indemnification or re-regulation of contracts;

 
limitations on insurance coverage;

 
government corruption;

 
political unrest;

 
labor unrest and strikes;

 
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, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;

 
regulatory or financial requirements for compliance with foreign bureaucratic actions; and

 
changing taxation policies.

In addition, international contract drilling operations are subject to the various laws and regulations of the countries in which we operate, including laws and regulations relating to:

 
the equipping and operation of drilling units;

 
repatriation of foreign earnings;

 
oil and gas exploration and development;

 
taxation of offshore earnings and the earnings of expatriate personnel;

 
customs duties on the importation of drilling units and related equipment;

 
requirements for local registration or ownership of drilling units by nationals of the country of operations in certain countries; and

 
the use and compensation of local employees and suppliers by foreign contractors.


 
9

 
 
 
Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling units owned by such governments' own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets.

If our drilling units are located in countries that are subject to restrictions imposed by the U.S. or other governments, our reputation and the market for our common stock could be adversely affected.

In 2010, the U.S. enacted the Comprehensive Iran Sanctions Accountability and Divestment Act ("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 our Company, and introduces 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. Although we believe that we are in compliance with all applicable sanctions and embargo laws and regulations, and intend to maintain such compliance, 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 Company. Additionally, some investors may decide to divest their interest, or not to invest, in our Company 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 units, and those violations could in turn negatively affect our reputation. Investor perception of the value of our common stock may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries

We may be subject to liability under environmental laws and regulations, which could have a material adverse effect on our results of operations and financial condition.

Our operations are subject to regulations controlling the discharge of materials into the environment, requiring removal and clean-up of materials that may harm the environment or otherwise relating to the protection of the environment. For example, as an operator of mobile drilling units off the coastlines of Brazil, the United States and other countries, we may be liable for damages and costs incurred in connection with spills of oil and other chemicals and substances related to our operations, and we may also be subject to significant fines in connection with spills. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence. These laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for acts that were in compliance with all applicable laws at the time when such acts were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations or cash flows. We have generally been able to obtain a degree of contractual indemnification pursuant to which our clients agree to protect, hold harmless and indemnify us against liability for pollution, well and environmental damage; however, there is no assurance that we can obtain such indemnities in all of our future contracts or that, in the event of extensive pollution and environmental damage, our clients would always have the financial capability to fulfill their contractual obligations to us. Also, these indemnities may be held to be unenforceable in certain jurisdictions, as a result of public policy or for other reasons.

Our ability to operate our drilling units in the U.S. Gulf of Mexico could be restricted by governmental regulation.

Hurricanes Ivan, Katrina, Rita, Gustav and Ike caused damage to a number of drilling units unaffiliated to us in the Gulf of Mexico, or GOM. The Minerals Management Service of the U.S. Department of the Interior, now known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, 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 that apply through the 2013 hurricane season. These guidelines effectively impose new requirements on the offshore oil and natural gas industry in an attempt to improve the stations that house the moored units and increase the likelihood of survival of offshore drilling units during a hurricane. The guidelines also provide for enhanced information and data requirements from oil and natural gas companies that operate properties in the US GOM. BOEMRE may issue similar guidelines for future hurricane seasons and may take other steps that could increase the cost of operations or reduce the area of operations for our ultra-deepwater drilling units, thereby reducing their marketability. Implementation of new BOEMRE 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

We do not have any jack-up rigs or moored drilling units operating in the US GOM. However, we currently operate one ultra-deepwater semi-submersible drilling rig in the US GOM that is self-propelled and equipped with thrusters and other machinery, which enable the rig to move between drilling locations and remain in position while drilling without the need for anchors, and we have a similar unit en route to start operations in the Mexican part of the GOM.

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

Public health threats, such as swine flu, bird flu, Severe Acute Respiratory Syndrome and other highly communicable diseases, outbreaks of which have already occurred in various parts of the world in which we operate, could adversely impact on our operations, the operations of our customers and the global economy, including the worldwide demand for oil and gas and, ultimately, the level of demand for our services. Any of these public health threats could adversely affect our financial results.

 
10

 


We may be subject to litigation that could have an adverse effect on us.

We are currently involved in various litigation matters, none of which we expect to have a material adverse effect on us. 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 clients, 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. Any future litigation may have an adverse effect on our business, financial position, results of operations and ability to pay dividends, because of potential negative outcomes, the costs associated with prosecuting or defending such lawsuits, and the diversion of management's attention to these matters.

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

As a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. Dollars. Accordingly, we may experience currency exchange losses if we have not fully hedged our exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. We may also be unable to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. A discussion of our policy and exposure to exchange rate fluctuations is given in Item 11 "Quantitative and Qualitative Disclosures about Market Risk".

Our business and operations involve numerous operating hazards.

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, including the 2010 events related to the Deepwater Horizon, an unaffiliated drilling unit. Contract drilling and well servicing require the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages. We customarily provide contract indemnity to our customers for claims that could be asserted by us relating to damage to or loss of our equipment, including rigs and claims that could be asserted by us or our employees relating to personal injury or loss of life.

Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our clients 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 assurance that these clients will be willing or financially able to indemnify us against all these risks. We maintain insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. However, pollution and environmental risks generally are not totally insurable.

We maintain a portion of deductibles for damage to our offshore drilling equipment and third-party liabilities. With respect to hull and machinery we generally maintain a deductible per occurrence up to $5 million. However, in the event of a total loss or a constructive total loss of a drilling unit, such loss is fully covered by our insurance with no deductible. For general and marine third-party liabilities we generally maintain up to $250,000 deductible per occurrence on personal injury liability for crew claims as well as non-crew claims and per occurrence on third-party property damage.


 
11

 

If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a client, the occurrence could adversely affect our consolidated statement of financial position, results of operations or cash flows. The amount of our insurance may also be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain more risk through self-insurance in the future. This self-insurance results in a higher risk of losses, which could be material, that are not covered by third party insurance contracts. Specifically, we have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM due to the substantial costs associated with such coverage. If such windstorms cause significant damage to any rig and equipment we have in the GOM, it could have a material adverse effect on our financial position, results of operations or cash flows. Moreover, no assurance can be made that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, or obtain insurance against certain risks.

As of April 26, 2011, all of the drilling units that we owned or operated were covered by existing insurance policies.

The aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout, could negatively impact us.

In the near-term aftermath of the Deepwater Horizon Incident that led to the Macondo well blow out situation, , the U.S. government on May 30, 2010 imposed a six-month moratorium on certain drilling activities in water deeper than 500 feet in the US GOM and subsequently implemented enhanced safety requirements applicable to all drilling activity in the US GOM, including drilling activities in water shallower than 500 feet. On October 12, 2010, the U.S. government lifted the moratorium subject to compliance with enhanced safety requirements including those set forth in Notices to Lessees 2010-N05 and 2010-N06, both of which were implemented during the drilling ban. Additionally, all drilling in the US GOM will be required to comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management Systems, both of which were issued on September 30, 2010, once they become final. We continue to evaluate these new measures to ensure that our rigs and equipment are in full compliance, where applicable. 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. Nor are we able to predict when the BOEMRE will issue drilling permits to our customers. We are not able to predict the future impact of these events on our operations. Even with the drilling ban lifted, certain deepwater drilling activities remain suspended until the BOEMRE resumes its regular permitting of those activities. The current and future regulatory environment in the US GOM could impact the demand for drilling units in the US GOM in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the US GOM. It is possible that short-term potential migration of rigs from the US GOM could adversely impact dayrates levels and fleet utilization in other regions. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration and development activity in the US GOM and, therefore, reduce demand for our services. In addition, insurance costs across the industry are expected to increase as a result of the Macondo incident and, in the future, certain insurance coverage is likely to become more costly, and may become less available or not available at all. We cannot predict if the U.S. government will issue new drilling permits in a timely manner, nor can we predict the potential impact of new regulations that may be forthcoming as the investigation into the Macondo well incident continues. Nor can we predict if implementation of additional regulations might subject us to increased costs of operating and/or a reduction in the area of operation in the US GOM. As such, our cash flow and financial position could be adversely affected if our one ultra-deepwater drilling rig in the US GOM was subject to the risks mentioned above.
 
Governmental laws and regulations, including environmental laws and regulations, may add to our costs or limit our drilling activity.
 
Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment in the geographic areas where we operate. The offshore drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and, accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may, in the future, add significantly to our operating costs or significantly limit drilling activity. Our ability to compete in international contract drilling markets may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. Offshore drilling in certain areas has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

 
 
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To the extent new laws are enacted or other governmental actions are taken that prohibit or restrict offshore drilling or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or the offshore drilling industry, in particular, our business or prospects could be materially adversely affected. The operation of our drilling units will require certain governmental approvals, the number and prerequisites of which cannot be determined until we identify the jurisdictions in which we will operate on securing contracts for the drilling units. Depending on the jurisdiction, these governmental approvals may involve public hearings and costly undertakings on our part. We may not obtain such approvals or such approvals may not be obtained in a timely manner. If we fail to timely secure the necessary approvals or permits, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment. The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas could have a material adverse effect on our business, operating results or financial condition. Future earnings may be negatively affected by compliance with any such new legislation or regulations.

Climate change and greenhouse gas restrictions may adversely impact our operations and markets.

Due to concern over the risk of climate change, a number of countries and the United Nations' International Maritime Organization, or IMO, have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These regulatory measures may include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency standards, and incentives or mandates for renewable energy. In addition, although the emissions of greenhouse gases from international shipping currently are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which required adopting countries to implement national programs to reduce emissions of certain gases, a new treaty may be adopted in the future that includes restrictions on shipping emissions. 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.

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 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.
 
Technology disputes involving our suppliers could impact our operations or increase our costs.

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 infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services, replacement parts, or could be required to cease use of some equipment. We could also be required to pay royalties for the use of equipment. These consequences of technology disputes involving our suppliers could adversely affect our financial results and operations.  We have provisions in most of our supply contracts to provide indemnity from the supplier against intellectual property lawsuits.  However, we cannot be assured that our suppliers will be willing or financially able to honor their indemnity obligations, or guarantee that the indemnities will fully protect us from the adverse consequences of such technology disputes.  We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but we cannot provide assurance that these provisions will fully protect us from the adverse consequences of such technology disputes.

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

The market for our services is characterized by continual and rapid technological developments that have resulted in, and will likely continue to result in, substantial improvements in equipment functions and performance. As a result, our future success and profitability will be dependent in part upon our ability to:

 
maintain and improve our existing services and related equipment;

 
address the increasingly sophisticated needs of our customers; and

 
anticipate changes in technology and industry standards and respond to technological developments on a timely basis.

If we are not successful in acquiring new equipment or upgrading our existing equipment on a timely and cost-effective manner in response to technological developments or changes in standards in our industry, we could lose business and profits. In addition, current competitors or new market entrants may develop new technologies, services or standards that could render some of our services or equipment obsolete, which could have a material adverse effect on our operations.

Risks Relating to Our Company

The amount of our debt could limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2010, we had $9.6 billion in principal amount of debt, representing approximately 55% of our total capitalization. Our current indebtedness and future indebtedness that we may incur could affect our future operations, as 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, which may affect our flexibility in planning for, and reacting to, changes in our business and 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 our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited. 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 general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent that we are unable to repay our indebtedness as it becomes due or at maturity, we may need to refinance our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments.

If we are unable to comply with the restrictions and the financial covenants in the agreements governing our indebtedness, there could be a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.

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, there could be a default under the terms of those agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, is dependent on our future performance and may be affected by events beyond our control. If a default occurs under these agreements, lenders could terminate their commitments to lend or accelerate the outstanding loans and declare all amounts borrowed due and payable. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, we cannot guarantee that our assets will be sufficient to repay in full all of our outstanding indebtedness, and we may be unable to find alternative financing. Even if we could obtain alternative financing, that financing might not be on terms that are favorable or acceptable.


 
14

 

 
We rely on a small number of customers.

Our contract drilling business is subject to the risks associated with having a limited number of customers for our services. As of December 31, 2010, our five largest customers accounted for approximately 76% of our future contracted revenues, or order backlog. Our results of operations could be materially adversely affected if any of our major customers failed to compensate us for our services, were to terminate our contracts with or without cause, failed to renew its existing contracts or refused to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates.

Newbuilding projects and surveys are subject to risks that could cause delays or cost overruns.

As of December 31, 2010, we had an outstanding newbuilding orderbook towards various yards for an additional 10 drilling units with corresponding contractual commitments totaling $2.07 billion. Such rig 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, 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, 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. 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 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.

Some of our offshore drilling contracts may be terminated early due to certain events.

Some of our customers have the right to terminate their drilling contracts upon the payment of an early termination fee. However, such payments may not fully compensate us for the loss of the 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, longer 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. During periods of challenging market conditions, we may be subject to an increased risk of our clients seeking to repudiate their contracts, including through claims of non-performance. Our customers' ability to perform their obligations under their drilling contracts with us may also be negatively impacted by the prevailing uncertainty surrounding the development of the world economy and the credit markets. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our consolidated statement of financial position, results of operations or cash flows.

The provisions of the majority of our offshore rig contracts that are term contracts at fixed dayrates may not permit us fully to recoup our costs in the event of a rise in our expenses.

Most of the units in our fleet have long-term contracts. The average contract length as of December 31, 2010, was 30 months for our deepwater units, 23 months for our tender rigs and 12 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 contracts include escalation provisions. These provisions allow us to adjust the dayrates based on stipulated cost increases including wages, insurance and maintenance cost. However, because these escalations are normally performed on a semi-annual or annual basis, 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. Shorter term contracts normally do not contain escalations provisions.

 
15

 

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

Operating revenues may fluctuate as a function of changes in supply of offshore drilling units and demand for contract drilling services, which in turn, affect dayrates, and the economic utilization and performance of our fleet of drilling units. However, our operating costs are generally related to the number of units in operation and the cost level in each country or region where the units are located. In addition, equipment maintenance costs fluctuate depending upon the type of activity that the unit is performing and the age and condition of the equipment. In connection with new assignments, we might incur expenses relating to preparation for operations under a new contract. The expenses may vary based on the scope and length of such required preparations and the duration of the firm contractual period over which such expenditures are amortized. In situations where our drilling units incur idle time between assignments, the opportunity to reduce the size of our crews on those drilling units is limited as the crews will be engaged in preparing the unit for its next contract. When a unit faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to 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 units, 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.

We may not be able to renew or obtain new and favorable contracts for drilling units whose contracts are expiring or are terminated, which could adversely affect our revenues and profitability.

We have 12 contracts that expire in 2011, 10 contracts that expire in 2012 and five contracts that expire in 2013. Our ability to renew these contracts or obtain new contracts will depend on the prevailing market conditions. If we are not able to obtain new contracts in direct continuation, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contracts terms, our revenues and profitability could be adversely affected.
 
Our future contracted revenue for our fleet of drilling units may not be ultimately realized.

As of December 31, 2010, the future contracted revenue for our fleet of drilling units, or contract drilling backlog, was approximately $11.2 billion under firm commitments. We may not be able to perform under these contracts due to events beyond our control, and our customers may 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.

Competition within the oilfield services industry may adversely affect our ability to market our services.

The oilfield services 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. We believe that the principal competitive factors in the market areas we serve are price, product and service quality, availability of crews and equipment and technical proficiency. Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics in comparison to our products and services, or expand into service areas where we operate. Competitive pressures or other factors may also result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations and financial condition. In addition, competition among oilfield services and equipment providers is affected by each provider's reputation for safety and quality.

Any renewal of the recent worldwide 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 demand for energy, including oil and gas. Although the world economy has shown strong signs of improvement, there is still considerable instability in the world economy and challenges for certain countries including, but without limitation, Greece, Spain, Portugal, Ireland and Italy due to their mounting debt curbing. Also, the recent tragic earthquakes and tsunami in Japan have reinserted uncertainty in the global markets. In addition, continued recent hostilities in the Middle East, North Africa and other geographic areas and countries are adding to the uncertainty. A more negative outlook for the world economy could reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our results of operations and cash flows beyond what might be offset by the simultaneous impact of possibly higher oil and gas prices. We cannot assure you that our customers will sustain or increase their capital programs and budgets in response to the recent increase in crude oil prices, which were approximately $124 per barrel (Brent Oil Price) as of April 26, 2011.
 
 
16

 


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

We require highly skilled personnel to operate and provide technical services and support for our business. Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased. The drop in energy prices and utilization rate in 2008 reduced, to some extent, the need for people related to international jack-up rigs. For harsh environment and international deepwater operations, utilization rates have remained high. The number of deepwater units in operation is growing as a result of the delivery of units ordered during the period from 2005 to 2008, supplemented by new orders placed late last year and so far this year. This increase in units is expected to increase especially the demand for qualified personnel with deepwater experience, in particular in Brazil where there is additional pressure on availability of qualified personnel due to local regulations regarding numbers of local resources within crew composition. If this expansion continues and is coupled with improved demand for drilling services in general, shortages of qualified personnel could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow.

Furthermore, as a result of any increased competition for people and risk for higher turnover, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents. In response to these labor market conditions, we have increased our efforts related to recruitment, training, development and retention programs as required to meet our anticipated personnel needs.

Our labor costs and the operating restrictions that apply to us could increase as a result of collective bargaining negotiations and changes in labor laws and regulations.

Some of our employees are represented by collective bargaining agreements. The majority of these employees work in Brazil, Nigeria, Norway and the U.K. In addition, some of our contracted labor works under collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and are restricted in our ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.
 
An inability to obtain visas and work permits for our employees on a timely basis could hurt our operations and have an adverse effect on our business.

Our ability to operate worldwide depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate. Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. As a result of a change in government enforcement of the immigration policy in Angola, we have recently experienced considerable difficulty in obtaining the necessary visas and work permits for our employees to work in Angola, where we currently operate three rigs. If we are not able to obtain visas and work permits for the employees we need for operating our rigs on a timely basis, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, it could adversely affect our consolidated statement of financial position, results of operations or cash flows.


 
17

 

The failure to consummate or integrate acquisitions of other businesses and assets in a timely and cost-effective manner could have an adverse effect on our financial condition and results of operations.
 
Acquisition of assets or businesses that expand our drilling and well services operations is an important component of our business strategy. We believe that acquisition opportunities may arise from time to time, and any such acquisition could be significant. Any acquisition could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Certain acquisition and investment opportunities may not result in the consummation of a transaction.  In addition, we may not be able to obtain acceptable terms for the required financing for any such acquisition or investment that arises. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our common stock. Our future acquisitions present a number of risks, including the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets, the risk of failing to successfully and timely integrate the operations or management of any acquired businesses or assets and the risk of diverting management's attention from existing operations or other priorities. If we fail to consummate and integrate our acquisitions in a timely and cost-effective manner, our financial condition and results of operations will be adversely affected.

In order to execute our growth strategy, we may require additional capital in the future, which may not be available to us.

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 execute our growth strategy and to fund our capital expenditures. Adequate sources of capital funding may not be available when needed or may not be available on favorable terms. If we raise additional funds by issuing additional equity securities, dilution to the holdings of existing equity holders may result. If funding is insufficient at any time in the future, we may be unable to fund maintenance requirements and acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could adversely impact our financial condition and results of operations.

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 and convertible bonds, the large 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, 2010, our total net floating rate debt amounted to $6.77 billion of which we had entered into interest rate swap agreements to fix the interest rate for a principal amount of $2.95 billion.

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

We conduct our operations through various subsidiaries in countries throughout the world. Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, regulations and treaties in and between 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 erse 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.

 
18

 

While we believe that we are not currently a "passive foreign investment company", or PFIC, and do not anticipate becoming a PFIC, the United States Internal revenue Service, or IRS, could treat us as a PFIC which could have adverse United States federal income tax consequences to United States shareholders.

A foreign corporation will be treated as a PFIC, for United States federal income tax purposes if either (1) at least 75 percent of its gross income for any taxable year consists of certain types of "passive income" or (2) at least 50 percent 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 which are received from unrelated parties in connection with the active conduct of a trade or business but does not include income derived from the performance of services.

If the IRS were to find that we are or have been a PFIC for any taxable year, our United States shareholders will face adverse United States federal tax consequences.

Under the PFIC rules, unless United States shareholders make an election available under the United States Internal Revenue Code of 1986, as amended (which election could itself have adverse consequences for such shareholders, as discussed below under "Taxation – United States Federal Income Tax Considerations – Passive Foreign Investment Company Status and Significant Tax Consequences"), such shareholders would be subject to United States federal income tax at the then prevailing United States federal income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of our common shares, as if the excess distribution or gain had been recognized ratably over the shareholder's holding period of our common shares.
 
Risks Relating to Our Common Shares

Our common share price may be highly volatile.

The market price of our common shares has historically fluctuated over a wide range and may continue to fluctuate significantly in response to many factors, such as actual or anticipated fluctuations in our operating results, changes in financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. Over the last year, the stock market has experienced extreme price and volume fluctuations. Such volatility could adversely affect the market price of our common shares and impact a potential sale price if holders of our common shares decide to sell their shares.

Because we are a foreign corporation, you may not have the same rights that a shareholder in a U.S. corporation may have.

We are a Bermuda exempted company. Our Memorandum of Association and Bye-laws and the Companies Act, 1981 of Bermuda, or the Companies Act, govern our affairs. The Companies Act does not clearly establish your rights and the fiduciary responsibilities of our directors as do statutes and judicial precedent in some U.S. jurisdictions. Therefore, it may be more difficult to protect your interests as a shareholder in relation to the actions of management, directors or controlling shareholders, than it would be for shareholders of U.S. corporations to do the same. There is a statutory remedy under Section 111 of the Companies Act which provides that a shareholder may seek redress in the courts as long as such shareholder can establish that our affairs are being conducted, or have been conducted, in a manner oppressive or prejudicial to the interests of some part of the shareholders, including such shareholder.

We are incorporated in Bermuda and it may not be possible for our investors to enforce U.S. judgments against us.

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

 
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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. federal and state securities laws or (2) would enforce, in original actions, liabilities against us based on those laws.

We are subject to certain anti-takeover provisions in our constitutional documents.

Several provisions of our bye-laws may have anti-takeover effects. These provisions are intended to avoid costly takeover battles, lessen our vulnerability to a hostile change of control and enhance the ability of our board of directors 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 interest. For more detailed information, reference is made to Item 10 "Additional Information" of this Annual Report.

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

Our principal shareholder, Hemen Holding Ltd., which we refer to as Hemen, is controlled by trusts established by John Fredriksen, our President and Chairman, for the benefit of his immediate family. Hemen also has significant shareholdings in two companies affiliated with us, Frontline Ltd. (NYSE: FRO), or Frontline, and Ship Finance International Limited (NYSE: SFL), or Ship Finance. In addition, Hemen owns approximately 8.9% of our majority-owned subsidiary Seawell Limited, or Seawell. Our Vice-President and director Mr. Tor Olav Trøim is also a director of Seawell (OSE: SEAW). One of our other directors, Kate Blankenship, is also a director of Frontline, Ship Finance and Seawell and another of our directors, Kathrine Fredriksen, the daughter of  John Fredriksen, is also a director of Frontline. Mr. Fredriksen, Mr. Trøim, Mrs. Blankenship and Ms. Fredriksen owe fiduciary duties to each of Seadrill, Frontline, Ship Finance and  Seawell, and may have conflicts of interest in matters involving or affecting us and our customers. In addition, they may have conflicts of interest when faced with decisions that could have different implications for Frontline, Seawell or Ship Finance than they do for us. We cannot assure you that any of these conflicts of interest will be resolved in our favor.

Investor confidence may be adversely impacted if we are unable to comply with Section 404 of the Sarbanes-Oxley Act of 2002.

We are subject to Section 404 of the Sarbanes-Oxley Act of 2002, which requires us to include in our annual report on Form 20-F our management's report on, and assessment of, the effectiveness of our internal controls over financial reporting. In addition, our independent registered public accounting firm has attested to and reported on management's assessment of the effectiveness of our internal controls over financial reporting for the year ending December 31, 2010 and will be required to do so for the year ending December 31, 2011 and thereafter.  If we fail to maintain the adequacy of our internal controls over financial reporting, we will not be in compliance with all of the requirements imposed by Section 404. Any failure to comply with Section 404 could result in an adverse perception of the Company in the financial marketplace.

If we enter into drilling contracts with countries or government-controlled entities that are subject to restrictions imposed by the U.S. government, our reputation and the market for our common stock could be adversely affected.

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. Although these sanctions and embargoes do not prevent us from entering into drilling contracts with these countries or government-controlled entities, potential investors could view such drilling contracts negatively, which could adversely affect our reputation and the market for our common stock. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have contracts with countries identified by the U.S. government as state sponsors of terrorism. The determination by these investors not to invest in, or to divest from, our common shares may adversely affect the price at which our common shares trade. Investor perception of the value of our common stock may be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.



 
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ITEM 4.  INFORMATION ON THE COMPANY

A. HISTORY AND DEVELOPMENT OF THE COMPANY

The Company

Seadrill Limited was incorporated under the Bermuda Companies Act of 1981 of Bermuda on May 10, 2005, and our shares of common stock have been listed under the symbol "SDRL" on the Oslo Stock Exchange since November 2005 and on the New York Stock Exchange 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 jack-up rigs, tender rigs, semi-submersible rigs and drillships, which operate in shallow, mid and deepwater areas as well as benign and harsh environments. A description of our different types of drilling units is given in Item 4.B "Business Overview".  We operate through subsidiaries located throughout the world, including in Bermuda, Norway, the Cayman Islands, the British Virgin Islands, Cyprus, Nigeria, Liberia, Hungary, Singapore, Brazil, Hong Kong, Panama, the United Kingdom, Denmark, Malaysia, Brunei and the United States.  We own and operate a fleet of 40 offshore drilling units, which consist of 16 jack-up rigs, nine semi-submersible rigs, four drillships and 11 tender rigs. In April 2011, we entered into an agreement to sell one of our 16 jack-up rigs with delivery to the buyer scheduled for June or July 2011. In addition to our existing fleet, we have three semi-submersible rigs, three drillships, four tender rigs and six jack-up rigs under construction or in mobilization to first contract. Furthermore, we operate five tender rigs in association with Varia Perdana Sdn Bhd, or Varia Perdana, a Malaysian company in which we have a 49% ownership interest and which are accounted for as an investment in an associated company.

As of December 31, 2010, we owned a controlling interest in the well services company Seawell. Seawell provides services in platform drilling, facility engineering, modular rig, well intervention and oilfield technologies, and drilling and well services. Seawell currently operates on nearly 50 installations in the North Sea and has offices in Stavanger in Norway, Aberdeen and Newcastle in the United Kingdom, Houston in the United States, Esbjerg in Denmark, Rio de Janeiro in Brazil and Lagos in Nigeria and has joint ventures in Kuala Lumpur in Malaysia and Abu Dhabi in the UAE. As of December 31, 2010, we owned 52.3% of Seawell's share capital. In February 2011, Seawell completed a merger with Allis-Chalmers Energy, Inc., or Allis-Chalmers forming a global oilfields service company with operations in over 30 countries. The operating name of the combined company is to be changed to Archer, and as a result of the consummation of the merger our ownership percentage in Seawell was reduced to 36.5%. For accounting purposes the position will be deconsolidated and recognized as an investment in an associated company from the end of February, 2011, and our portion of Seawell's results will be reflected within share of results of associated companies.

We also 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 rigs and that provide us with additional exposure to market segments in which we operate or other market segments. These include:

- a 23.6% equity interest in SapuraCrest, a Malaysian oil services company, and

- a 9.4% equity interest in Pride. (NYSE: PDE), a United States offshore drilling company.

On February 7, 2011, Ensco plc ("Ensco") (NYSE: ESV) and Pride jointly announced that they have entered into a definitive merger agreement under which Ensco will combine with Pride in a cash and stock transaction valued at $41.60 per share based on Ensco's closing share price on February 4, 2011. The implied offer price represents a premium of 21% to Pride's closing share price as of the same date and a premium of 25% to the one month volume weighted average closing price of Pride. The definitive merger agreement has unanimously been approved by each company's board of directors. Under the terms of the merger agreement, Pride stockholders will receive 0.4778 newly-issued shares of Ensco plus $15.60 in cash for each share of Pride common stock. Upon closing, and reflecting the issuance of new Ensco shares, Pride stockholders collectively will own approximately 38% of Ensco's outstanding shares. The transaction is subject to approval by the shareholders of Ensco and Pride, as well as other customary closing conditions. The transaction is not subject to any financing condition Ensco and Pride will hold special shareholder meetings on May 31, 2011 to vote on the proposed merger agreement.

 
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Development of the Company

We were established in May 2005 as a Bermuda company. On May 11, 2005 we entered into a Purchase and Subscription Agreement with three affiliated companies: Greenwich Holdings Limited, or Greenwich, Seatankers Management Co Limited, or Seatankers, and Hemen.  Pursuant to agreements we acquired an offshore drilling fleet of three jack-up rigs and two floating production, storage and offloading vessels, or FPSOs, from Greenwich for an aggregate consideration of $310 million, and contracts for the construction of two new jack-up rigs from Seatankers for a total consideration of $67 million. In addition, Hemen subscribed for 84,994,000 of our shares at a subscription price of $2.03 per share and acquired all of Greenwich's and a part of Seatankers' claim for the purchase price for the assets referred to above. Greenwich, Seatankers and Hemen are controlled by trusts established by Mr. John Fredriksen, our President and Chairman, for the benefit of his immediate family. As a result of the related party nature of this transaction, the acquisition of these assets was accounted for as a transfer of assets under common control and recorded by Seadrill at the historical carrying values in the financial statements of Greenwich and Seatankers.

Subsequent to the above initial acquisitions, we have entered into further contracts for newbuildings and acquired units and other companies engaged in offshore drilling and related industries. As a result, our operations have expanded considerably and we currently have approximately 6,650 skilled employees and an active fleet of 40 units (including the one unit we agreed in early April 2011 to sell), consisting of 16 jack-up rigs, nine semi-submersible rigs, four drillships and 11 tender rigs, plus an additional 16 units under construction.

Acquisitions, Disposals and Other Transactions

Acquisitions and other transactions

In the year ended December 31, 2010, we acquired the following drilling units:

In the first quarter of 2010, the construction of our two new tender rigs, West Vencedor and T12, was completed and the units were subsequently mobilized from the Keppel FELS shipyard in Singapore and Malaysia Marine and Heavy Engineering Sdn Bnd to their first drilling locations in Angola and Thailand, respectively.

On April 14, 2010, we agreed to purchase a harsh environment jack-up rig, the West Elara, from the Jurong shipyard in Singapore. The unit is scheduled for delivery in the second quarter 2011, at which time it will be mobilized to the Norwegian Continental Shelf for commencement of a five year contract with Statoil.

On April 20, 2010, we took delivery of  a new deepwater semi-submersible rig, West Orion from the Jurong Shipyard in Singapore. The unit immediately began mobilization, and commenced operations in Brazil in July 2010.

In May 2010, we acquired a majority shareholding in Scorpion. The acquisition, which is discussed in more detail below,  increased our fleet by seven modern jack-up rigs built between 2007 and 2010.

On June 30, 2010, we took delivery of the new drillship West Gemini from the Samsumg Shipyard in South Korea. The unit began operations in Angola in August 2010.

On October 18, 2010, we entered into an agreement with the Jurong Shipyard in Singapore for the construction of two jack-up rigs, West Castor and West Tucana, with scheduled deliveries in fourth quarter 2012 and first quarter 2013. The total project price for the two rigs is estimated at $400 million.

On November 11, 2010, we entered into an agreement with the Samsung Heavy Industries, or Samsung, yard in South Korea for the construction of two ultra deepwater drillships, West Auriga and West Vela with deliveries scheduled in the first and second quarters 2013. The total estimated price for the new units is $600 million per drillship.

On November 15, 2010, we entered into an agreement with Dalian Shipbuilding Industry Offshore Co. Ltd., a Chinese shipyard, for the construction of two new jack-up rigs to be named West Telesto and West Oberon. The units are scheduled for delivery in the fourth quarter of 2012 and first quarter of 2013. Total project price for the two units is estimated at $380 million.
 
On November 30, 2010 we acquired Petrojack IV, an advanced high specification jack-up drilling unit, from Peterojack IV PTE Ltd. Singapore, an unrelated third party, for a total consideration of approximately $180 million. The unit has been renamed West Cressida.

On December 3, 2010, the new jack-up drilling rig West Juno was delivered from Keppel FELS in Singapore. The unit remained classified as a newbuild project as of December 31, 2010, and was added to our operating fleet upon the completion of testing and the commencement of its employment in the first quarter of 2011.
 
 
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The total cost shown for each of the above drilling units consists of the accumulated historic cost for the Company and includes capitalized interest and other ancillary costs.

In addition, during 2010, we acquired investments in entities involved in offshore drilling:

Starting early 2008, we purchased shares through forward contracts in Scorpion . Scorpion was incorporated in Bermuda with the purpose of operating a fleet of drilling rigs and specifically to construct, own, operate and charter rigs. Scorpion operates seven ultra premium jack-up rigs in South America, the Middle East and South East Asia. In April 2010, we increased our ownership to 40.01% at a price per Scorpion share of NOK36. At that time Scorpion had a fleet of seven premium jack-up rigs with operations in South America, Middle East and South East Asia. In late May 2010, we increased our ownership to 50.1% of the outstanding shares and, triggered by the Oslo Stock Exchange Mandatory Offer Rules summarized below, simultaneously announced a bid of NOK40.50 per share for the remaining outstanding shares that was launched on June 4, 2010. On July 19, 2010, it was announced that shareholders representing 48.7% of the total number of outstanding shares had accepted the offer, increasing our ownership to 98.8% of the outstanding shares and votes in Scorpion. On September 20, 2010, we informed the remaining Scorpion shareholders of our intention to exercise our right under Bermuda company law to acquire all remaining outstanding shares in Scorpion. The compulsory acquisition was completed on October 25, 2010 and Scorpion's shares were delisted from the Oslo Stock Exchange on November 17, 2010. As of December 31, 2010, our ownership in Scorpion is 100%.

In August 2010, our majority owned subsidiary Seawell acquired Rig Inspection Services Limited, or RIS, a private company based in Singapore and Australia. The purchase price was $9.4 million.

In August 2010, Seawell announced a merger with Allis-Chalmers in a transaction valued at approximately $890 million. As a result of consummation of the merger in the first quarter of 2011, our shareholding was reduced to 36.5% and this investment was deconsolidated and recognized  as an investment in an associated company. The Merger was completed at the end of February 2011 and is discussed further in Note 34 to our financial statements under Subsequent events.

In December 2010, Seawell acquired Gray Wireline Service, Inc., or Gray, an independent cased hole wireline company in the United States. The purchase price was $160.5 million.
 
The following is a summary of Oslo Stock Exchange Mandatory Offer Rules which precipitated our offer for the remaining Scorpion shares

 
Generally, under the rules of the Oslo Stock Exchange, a shareholder who acts in its own name or in concert with others, and who acquires shares representing more than 1/3 of the votes of an Oslo Stock Exchange listed company is obligated to make an offer for that company's remaining shares. The obligation to make a mandatory offer is triggered again if the shareholder subsequent to the initial mandatory offer acquires further shares in such company and through such acquisition becomes the owner of shares representing either 40% or more or 50% or more of the votes in that company.

 
Before January 1, 2008, the threshold of ownership required to trigger the initial mandatory offer requirement was 40%.

 
There are various procedural and substantive rules, including a best price rule that relates to the price that the offeror must pay for the shares.

 
There is also a procedure for certain Oslo Stock Exchange companies to obtain exemptions from the rules.

Disposals

During the year ended December 31, 2010, we disposed of the following assets:
 
In October 2010, we agreed to the sale of the 1984 build jack-up rig West Lasrissa to an unrelated third party for a total consideration of $55 million. The sale resulted in a net gain of $26.1 million.
 
Acquisitions, Disposals and Other Transactions since December 31, 2010:

In December 2010, we entered into a purchase agreement to acquire two ultra-deepwater semi-submersible drilling rigs, West Pegasus and West Leo, under construction at the Jurong Shipyard in Singapore. The total project price for the two rigs was estimated to approximately $1.2 billion (including project management for the remaining construction period, drilling and handling tools, spares, operations preparations and capitalized interest). The first unit was delivered from the yard in early April and is currently in transit to Mexico. Delivery of the second rig is scheduled for the fourth quarter 2011.

As of the first quarter of 2011, we are no longer consolidating the financial statements of Seawell into our consolidated statements. The de-consolidation of Seawell is discussed above in Item 4A History and development of the Company.

On February 15, 2011, our Board of Directors resolved to establish a new majority-owned subsidiary focused entirely on harsh environment operations. The new subsidiary is called North Atlantic Drilling Limited, or NADL, and a fleet of five existing harsh environment units and one newbuild contract have been transferred from Seadrill to NADL. Seadrill retained a 75% shareholding after a private placement. This transaction is described in more detail in note 34 to the financial statements under Subsequent events.
 
On February 28, 2011, we entered into an agreement for the construction of two tender rigs with the COSCO Nantong Shipyard, or COSCO, in China. The two new units, which will be named T15 and T16, are scheduled for delivery in the first quarter and third quarter 2013, respectively. This transaction is described in more detail in note 34 to the financial statements under Subsequent events.
 
 
 
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On March 21, 2011, we announced that an agreement had been entered into for the construction of a new harsh environment jack-up rig, to be named West Linus, with Jurong Shipyard in Singapore. The total project price for the new jack-up rig is estimated at $530 million and completion is scheduled for the end of the third quarter 2013. A five-year contract has been agreed, under which the new unit is scheduled to commence operations in Norway for ConocoPhillips in the fourth quarter 2013. It has been decided to offer both the construction and the drilling contract to the newly-formed subsidiary, NADL.

On April 11, 2011, we exercised an option to build a new ultra-depwater drillship at the Samsung yard in South Korea. The total project cost is estimated at $600 million and delivery of the new unit is scheduled for the third quarter 2013.

On April 12, 2011, we exercised an option to build a new tender barge at COSCO in China. The new unit, T17, is scheduled for delivery in the first quarter 2013, with a total project cost estimated at $115 million.

On April 13, 2011, we entered into an agreement to sell the newly built jack-up drilling rig West Juno to an undisclosed buyer for a total consideration of US$248.5 million.

B. BUSINESS OVERVIEW

We are an offshore drilling contractor providing global offshore drilling services to the oil and gas industry. We have a versatile fleet of drilling units that is outfitted to operate in shallow water, mid-water and deepwater areas, in benign and harsh environments. Our customers are national, international and independent oil companies. The various types of drilling units in our fleet are as follows:

Semi-submersible drilling rigs

Semi-submersible drilling rigs consist of an upper working and living quarters deck resting on vertical columns connected to lower hull pontoons. Such rigs operate in a "semi-submerged" floating position, in which the lower hull is below the waterline and the upper deck protrudes above the surface. The rig is situated over a wellhead location and remains stable for drilling in the semi-submerged floating position, due in part to its wave transparency characteristics at the water line.

There are two types of semi-submersible rigs, moored and dynamically positioned. Moored semi-submersible rigs are positioned over the wellhead location with anchors, while the dynamically positioned semi-submersible rigs are positioned over the wellhead location by a computer-controlled thruster system. Depending on country of operation, semi-submersible rigs generally operate with crews of 65 to 100 people.

Drillships

Our drillships are self-propelled ships equipped for drilling in deep waters, and are positioned over the well through a computer-controlled thruster system similar to that used on semi-submersible rigs. Drillships are suitable for drilling in remote locations because of their mobility and large load-carrying capacity. Depending on country of operation, drillships operate with crews of 65 to 100 people.

Jack-Up Rigs

Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor. A jack-up rig is towed to the drill site with its hull riding in the sea as a vessel and its legs raised. At the drill site, the legs are lowered until they penetrate the sea bed and the hull is elevated until it is above the surface of the water. After completion of the drilling operations, the hull is lowered until it rests on the water, the legs are raised and the rig can be relocated to another drill site. Jack-ups are generally suitable for water depths of 450 feet or less and operate with crews of 40 to 60 people.

Tender Rigs

Self-erecting tender rigs conduct production drilling from fixed or floating platforms. During drilling operations, the tender rig is moored next to the platform. The modularized drilling package, stored on the deck during transit, is lifted prior to commencement of operations onto the platform by the rig's integral crane. To support the operations, the tender rig contains living quarters, helicopter deck, storage for drilling supplies, power machinery for running the drilling equipment and well completion equipment. There are two types of tender rigs, barge type and semi-submersible (semi-tender) type. Tender barges and semi-tenders are equipped with similar equipment but the semi-tender's semi-submersible hull structure allows the unit to operate in rougher weather conditions. Self-erecting tender rigs allow for drilling operations to be performed from platforms without the need for permanently installed drilling packages. Self-erecting tender rigs generally operate with crews of 60 to 85 people.
 
Seawell Limited (to be renamed Archer Limited)

In addition to owning and operating offshore drilling units, during 2010, we provided well services through Seawell, a company in which we held a controlling interest of 52.3% of share capital as of December 31, 2010.  Seawell provides platform drilling, facility engineering, modular rig, well intervention and oilfield technologies. Seawell currently operates on nearly 50 installations in the North Sea and has offices in Stavanger and Bergen in Norway, Aberdeen and Newcastle in the United Kingdom, Houston in the United States, Esbjerg in Denmark, Rio de Janeiro in Brazil and Lagos in Nigeria, and has joint ventures in Kuala Lumpur in Malaysia and Abu Dhabi.

 
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In February 2011, Seawell completed a merger with Allis-Chalmers, forming a global oilfields services company with operations in over 30 countries. The operating name of the combined company is to be changed to Archer and, as a result of the consummation of the merger, with effect from the end of February 2011, our ownership percentage in Seawell was reduced to 36.5% and the position was deconsolidated and recognized as an investment in an associated company. Following the deconsolidation, our portion of Seawell's results will be reflected within results of associated companies.

Reporting Segments

Historically, we have reported our business in the following three operating segments:

 
Mobile units: We offer services encompassing drilling, completion and maintenance of offshore wells. The drilling contracts relate to semi-submersible rigs, jack-up rigs and drillships.

 
Tender Rigs: We operate self-erecting tender rigs and semi-submersible tender rigs, which are used for production drilling and well maintenance in Southeast Asia and West Africa.

 
Well Services: We provide services using platform drilling, facility engineering, modular rig, well intervention and oilfield technologies.

Information regarding our revenues, segment operating profit or loss and total assets attributable to each operating segment for the last three fiscal years is presented in Note 3 to our consolidated financial statements included in this Annual Report. Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operations for the last three fiscal years is also presented in Note 3 to our consolidated financial statements included in this Annual Report. For information about revenues, operating income, assets and other information relating to our business, our segments and the geographic areas in which we operate, see also Item 5 "Operating and Financial Review and Prospects".

In response to a significant growth in operations through acquisitions of new rigs, newbuilding orders and deconsolidation of Seawell, management has decided to review our internal structure, including the operating and reporting business segments. This review could result in a change to our reporting segments with effect from the first quarter of 2011.
 
Our Business Strategy

Our primary objective is to profitably grow our business to increase long-term distributable cash flow per share to our shareholders.

Our business strategy is to focus our company on modern state-of-the-art offshore drilling units with our main focus on deepwater operations. We believe that we have one of the most modern fleets in the industry and believe that by combining quality assets and experienced and skilled employees we will be able to provide our customers with safe and effective operations, and establish, develop and maintain a position as a preferred provider of offshore drilling services for our customers. We believe that a combination of quality assets and highly skilled employees will facilitate the procurement of term contracts and premium daily rates. We have grown our Company significantly since its incorporation in 2005 and have strong ambitions to continue our growth. We believe that the combination of term contracts and quality assets will provide us with the opportunity to obtain debt financing for such growth, and allow us to increase the return on our invested equity.

The key elements in our strategy are as follows:

 
commitment to provide customers with safe and effective operations;
 
combine state-of-the-art mobile drilling units with experienced and skilled employees;
 
growth through targeted alliances, purchase of newbuildings, mergers and acquisitions;
 
develop our strong position in deepwater and harsh environments;
 
continue to develop our rapidly growing fleet of premium jack-ups; and
 
develop our strong position in the tender rig market and pursue further growth in conventional waters as well as deepwater areas.

We believe that consolidation in the offshore drilling rig industry would improve the pricing and earnings visibility for our services. Such consolidation activities may be in the form of transactions for specific offshore drilling units or companies. We actively look for growth opportunities and intend to take part in the future consolidation of our industry if we determine that potential transactions are in the best interest of our shareholders.

Market Overview

We provide operations in oil and gas exploration and development regions throughout the world and our customers include oil super-majors and major integrated oil and gas companies, state-owned national oil companies and independent oil and gas companies. Our customers have experienced higher oil prices and significantly increased revenues over the last decade. The increase has been related to higher demand for oil and limited increase in available oil production to offset the growth in demand. Over the same period, the depletion rate for existing oil production has risen and replacement rates for oil reserves have fallen for most oil producers, highlighting the shortfall in exploration and production spending to meet future demand. In response to this development, oil producers, particularly super-majors, majors and national oil companies, have devoted more of their activities to identifying replacements for existing production in new geographical areas at increasing water depths. This has translated into an increased focus on frontier deepwater, not only in existing offshore regions such as Brazil, the US GOM, Europe and West Africa but also expanding to India, Southeast Asia, China, East Africa, the Mexican GOM, Australasia and the Mediterranean.

Mobile units

Our fleet of mobile units consists of drillships, semi-submersible rigs and jack-up rigs for global operations. The existing world wide fleet of mobile units totals 742 units including 64 drillships, 201 semi-submersible rigs and 477 jack-up rigs. In addition, there are 49 drillships, 74 jack-up rigs and 24 semi-submersible rigs under construction. Depending on rig specifications, capabilities and equipment outfitting, jack-ups rigs work in water depths up to 450ft while semi-submersible rigs and drillships can work in water depths up to 12,000ft. 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 as well as temperatures. The number of units outfitted for such operations are limited and the present number of rigs operating in harsh environment totals 38 units.
 
 
 
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The demand for these various asset classes have been positively impacted by the recently improved conditions for the oil and gas industry as mentioned above. However, over time, the demand supply condition may deviate between the various assets classes.

Jack-up rigs
The world fleet of jack-up rigs currently counts 477. Of these rigs, 378 rigs are in operational mode, 27 are warm-stacked and 72 cold-stacked. There is, in addition, 74 units under construction of which 37 have been ordered since October 2010. The existing world fleet includes 39 units equipped and outfitted for operation in harsh environment of which 7 rigs are approved for operations in Norway. Out of the rigs currently under construction, 19 will have harsh environment capabilities but only 3 will be outfitted for operations in Norway. The average age of the existing fleet is currently 24 years for the benign environment units and 16 years for the harsh environment units. The overall utilization rate for jack-up rigs are 73 percent while the utilization rate for benign environment jack-up rigs built after 2005 is 93 percent and the utilization rate for the harsh environment rigs is 87 percent. Of the existing fleet, 141 rigs are capable of drilling in water depth higher than 350ft.

Daily rate for jack-up rigs depends on country, region, water depth, capabilities technical specification, contract length and overall contract terms. For harsh environment jack-ups operating in Norway, current daily rates are approximately $300,000 whereas daily rates for similar units in the U.K. and Canada are $200,000. For benign environment jack-up rigs, daily rates are approximately $130,000 for new premium rigs and $80,000 for older jack-up rigs. Premium jack-up rigs are defined as jack-up rigs with water depth capacity greater than 350ft built after year 2000.

We believe the trend is for oil companies to gradually replace older jack-up rigs with new, more modern and efficient rigs due to wells becoming increasingly technically challenging and consequently more demanding with respect to rig equipment capabilities. Such oil companies are requiring, among others, units that can offer higher hook-loads, water depth capacities, extended cantilever-reach and increased flexibility for offline activities. We believe this trend will continue and we expect a strong market outlook for our premium jack-up rigs.

Semi-submersible rigs and drillships
The world fleet of semi-submersible rigs and drillships currently totals 265 units. In addition, there are 73 units under construction, 24 semi-submersible rigs and 49 drillships of which 31 have been ordered since October last year. 156 units were built before 1998, with an average age of 31 years and are mainly moored units. For the rigs built after 1998, almost all have been outfitted with thrusters allowing for dynamically positioning targeting operations in deeper waters. Of the world fleet, 122 units are dynamically positioned units and the remaining 143 rigs are moored units. Of the 122 dynamically positioned units, 116 units are capable of operation in deepwater waters (more than 4,500ft but less than 7,500ft) and 88 in capable of operations in ultra-deep waters (more than 7,500ft).

The demand for drillships and semi-submersible rigs has seen strong growth since 2005. The reason for this increase in demand has been related to growth in deepwater activities by oil companies. In addition to increased demand, the oil companies have also required higher operational capacities and technical specification of the units. In order to meet the new demand, new rigs had to be built and, between 2005 and 2008, some 93 new units were ordered, bringing the number of dynamically positioned drillships and semi-submersible rigs with ultra-deepwater capabilities from 27 to 120. In order to justify the significant investments, dayrates increased from approximately $290,000 in May 2005, when the first new units were ordered, to more than approximately $600,000 at the height of the market in September 2008. The financial downturn in the latter part of 2008 and subsequent drop in oil prices effectively halted the order flow for new deepwater vessels. As most of the rigs either had been contracted on long-term contracts or were under construction, there was no immediate effect on daily rates for the deepwater units. However, oil companies have held back new spending and investments in deeper water, and daily rates have slowly retreated to levels between $425,000 and $500,000. However, higher oil prices and an improved economic outlook that supports strong oil demand longer term has, together with the favorable environment for daily rates, spurred renewed interest for construction of further new deepwater vessels. Since October 2010, some 31 orders for additional deepwater units have been placed on speculation.

We believe that the long-term prospects for deepwater drilling are positive given the expected growth in oil consumption from developing nations, limited or negative growth in oil reserves, and high depletion rate of mature oil fields. We believe that these factors will continue to provide incentives for the exploration and development of deepwater fields, particularly in view of recent geologic successes in Brazil, GOM, West Africa and elsewhere, along with improving access to new promising offshore areas and new, more efficient technologies.

The number of rigs globally involved in drilling in deeper waters has been adversely impacted by the Macondo oil spill in the GOM in April 2010 as a six-month drilling permit moratorium implemented by the US Department of the Interior in May 2010 halted all deepwater operations in the United States. The drilling moratorium was lifted in October 2010: however, oil companies must submit applications in order to obtain drilling permits and resume drilling activities that demonstrate compliance with enhanced regulations The enhanced regulations required 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. The industry as such is reviewing and adapting to the new rules and requirements. Some oil companies have also elected to voluntarily implement the requirement for third-party inspections and certification on equipment operating outside the GOM. The Macondo incident has increased oil companies focus on new, modern and technically superior equipment thus reducing the oil companies' interest in using moored and older upgraded deepwater vessels..

Tender rigs

There are currently 34 self-erecting tender rigs globally including five units under construction. Out of the 34 rigs, 25 are barges and nine are semi-submersibles (semi-tender). The main markets for tender rigs are West Africa and Southeast Asia, employing 17% and 83% of tender rigs respectively. However, during 2011, a couple of units will start operation in Brazil and Trinidad and Tobago. The overall utilization rate for the world tender rig fleet is 79%, 81% for the barges and 75% for the semi-tender. This reflects that there are four stacked tender barges and two stacked semi-tenders. The daily rate for tender rigs depends on country, region, water depth, capabilities technical specification, contract length and overall contract terms. In general, daily rates are approximately $120,000 for modern tender barges and $160,000 for modern semi-tenders.

 
26

 

We are the largest operator in this segment operating a fleet of 16 units, including five units that we operate in association with Varia Perdana. In addition, we have three units under construction and one unit in transit to its first drilling assignment. We believe that the long-term outlook for tender rigs remains favorable due to their versatility and lower construction costs compared to jack-up rigs. In addition, in recent years, a combination of tender rigs and floating platforms, such as mini tension-leg platforms and spar platforms, has been used in the development of deepwater oilfields, which has increased the market for tender rigs. Interest in tender rigs has also been shown beyond the traditional West Africa and Southeast Asia markets with future opportunities expected in the GOM, South and Central America and Australia. As tender rigs primarily are used for development drilling, they normally are awarded long term contracts. We expect the market to continue to offer opportunities to build additional order backlog and earnings visibility.

Well services

Seawell is mainly involved in oil production activities in existing mature fields. The level of activity is therefore related to the development and level of the oil price. We believe that when oil prices are above $70 per barrel, oil companies will focus on maintaining their production from mature fields. Based on current market conditions, demand for drilling and well services is expected to remain high over the next few years.

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

Seasonality

In general seasonal factors do not have a significant direct effect on our business as most of our drilling units are contracted for periods of at least 12 months. However, we have operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operational utilization of the rigs and our ability to relocate rigs between drilling locations, and as such, limit contract opportunities in the short term. Such adverse weather could include the hurricane season for our operations in the GOM, the winter season in offshore Norway, 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, 2010 our five largest customers have been:

 
-
Petròleo Brasileiro S.A., or Petrobras, accounting for approximately 17% of our revenues;
 
-
Statoil ASA, or Statoil, accounting for approximately 15% of our revenues;
 
-
Total S.A. Group, or Total, accounting for approximately 10% of our revenues;
 
-
Royal Dutch Shell, or Shell, accounting for approximately 9% of our revenues; and
 
-
Exxon Mobil Corp, or Exxon, accounting for approximately 7% of our revenues.

No other customers have accounted for more than ten percent of our revenues in the three most recently reported years. In the year ended December 31, 2009, our two largest customers were Statoil and Total, who provided approximately 17% and 13% of our contract revenues, respectively. In the year ended December 31, 2008, our two largest customers were Statoil and Shell providing approximately 32% and 7% of our contract revenues, respectively. The loss of any of these significant customers could have a material adverse effect on our results of operations if they were not replaced by other customers.

Most of our drilling units are contracted to customers for periods between one and five years ahead, and our forward contracted revenue, or backlog, at December 31, 2010 totaled approximately $11.0 billion, with $7.9 billion of this amount attributable to our semi-submersible rigs and drillships. We expect approximately $3.7 billion of this backlog to be realized in 2011. Backlog for our drilling fleet is calculated as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization and demobilization, contract preparation, and customer reimbursables. The 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.

 
27

 


The following table shows the percentage of rig days committed by year as of December 31, 2010. The percentage of rig days committed is calculated as the ratio of total days committed under firm contracts to total available days in the period. Total available days for our units under construction are based on their expected delivery dates.

   
Year ending December 31,
% of rig-days committed
 
2011
 
2012
 
2013
                   
Jack-up rigs
   
71
%
   
24
%
   
17
%
Semi-submersible rigs
   
94
%
   
68
%
   
51
%
Drillships
   
100
%
   
88
%
   
20
%
Tender rigs
   
73
%
   
55
%
   
37
%

Competition

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

The demand for offshore drilling services is driven by oil and gas companies' exploration and development drilling programs. These drilling programs are affected by oil and gas companies' expectations regarding oil and gas prices, anticipated production levels, worldwide demand for oil and gas products and many other factors. The availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect our customers' drilling programs. Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by our customers for drilling services. Variations in market conditions during cycles impact us in different ways, depending primarily on the length of drilling contracts in different regions. For example, contracts in shallow waters for jack-up rig activities are shorter term, so a deterioration or improvement in market conditions for such units tends to quickly impact revenues and cash flows from those operations. On the other hand, contracts in deepwater for semi-submersible rigs and drillships tend to be longer term, so a change in market conditions tends to have a 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.

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 GOM, 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.

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 and third party liability.

 
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Our insurance claims are subject to a deductible, or non-recoverable, amount. We currently maintain a deductible per occurrence of up to $5 million related to physical damage to our rigs. However, a total loss of, or a constructive total loss of, a drilling unit is recoverable without being subject to a deductible. For general and marine third-party liabilities, we generally maintain a deductible of up to $250,000 per occurrence on personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units. Furthermore, for most of our rigs we purchase insurance to cover loss due to the drilling unit being wholly or partially deprived of income as a consequence of damage to the unit. The loss of hire insurance has a deductible period up to 60 days after the occurrence of physical damage. Thereafter, our insurance policies are limited to between 100 days and 360 days. If the repair period for any physical damage exceeds the number of days permitted under our loss of hire policy, we will be responsible for the costs in such period. We do not have loss of hire insurance on five of our jack-up units which we bought as part of the Scorpion acquisition.

We have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM due to the substantial costs associated with such coverage. This results in a higher risk of losses, which could be material, that are not covered by third party insurance contracts.

Environmental and Other Regulations in the Offshore Drilling Industry

Our offshore drilling operations include activities that are subject to numerous international, federal, state and local laws and regulations, including the International Convention for the Prevention of Pollution from Ships, or MARPOL, the International Convention on Civil Liability for Bunker Oil Pollution Damage of 1969, or CLC, or Bunker Convention, the U.S. Oil Pollution Act, or OPA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Outer Continental Shelf Lands Act, and Brazil's National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and 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 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.

For example, the IMO adopted MARPOL and Annex VI to MARPOL to regulate the discharge of harmful air emissions from ships, which include rigs and drillships. Rigs and drillships must comply with MARPOL limits on sulfur oxide and nitrogen oxide emissions, chlorofluorocarbons, and the discharge of other air pollutants, except that the MARPOL limits do not apply to emissions that are directly related to drilling, production, or processing activities.

Our drilling units are subject not only to MARPOL regulation of air emissions, but also to the Bunker Convention's strict liability for pollution damage caused by discharges of bunker fuel in ratifying states. We believe that all of our drilling units are currently compliant in all material respects with these regulations. IMO's Maritime Environment Protection Committee, or MEPC has adopted amendments to the Annex VI regulations that require a progressive reduction of sulfur oxide levels in heavy bunker fuels and create more stringent nitrogen oxide emissions standards for marine engines in the future. These amendments entered into force on July 1, 2010 and we may incur costs to comply with these revised standards.

Furthermore, any drilling units we may operate in the waters of the U.S., including  the U.S. territorial sea and the 200 nautical mile exclusive economic zone around the U.S., would have to comply with OPA and CERCLA regulations, as described above, that impose strict liability (unless the spill results solely from the act or omission of a third party, an act of God or an act of war) for all containment and clean-up costs and other damages arising from discharges of oil or other hazardous substances, other than discharges related to drilling.

In the United States in 2010, the Department of the Interior undertook a substantial reorganization of regulatory authority for offshore drilling following the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the GOM in April 2010, or the Deepwater Horizon Incident. Primary regulatory responsibility for offshore drilling was transferred from the Minerals Management Service to a new department, the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE.  In addition, a moratorium on issuance of permits for offshore drilling was in place in the United States from May 2010 through November 2010. Although the moratorium was lifted in November 2010, the number of permits issued has not returned to levels that existed prior to the Deepwater Horizon Incident, and it is not known when or whether the number of number of permits issued will be sufficient to sustain levels of deepwater drilling activity comparable to levels prior to the Deepwater Horizon Incident.  The BOEMRE periodically issues guidelines for rig fitness requirements in the GOM and may take other steps that could increase the costs of operations or reduce the area of operations for our rigs, thus reducing their marketability. Implementation of new BOEMRE guidelines or regulations may subject us to increased costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations and financial condition. Please read "Risk Factors — Our ability to operate our drilling units in the US GOM could be restricted by government regulation" in Item 3.D of this Annual Report.

 
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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. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance or limit contract drilling opportunities, including changes in response to  serious marine incident that results in significant oil pollution or otherwise causes significant adverse environmental impact, such as the Deepwater Horizon Incident, could adversely affect our financial results. While we believe that we are in substantial compliance with the current laws and regulations, there is no assurance that compliance can be maintained in the future.

In addition to the MARPOL, OPA, and CERCLA requirements described above, our international operations in the offshore drilling segment are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the importation and operation of drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, environmental protection, 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. New environmental or safety laws and regulations could be enacted, which could adversely affect our ability to operate in certain jurisdictions. Governments in some countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

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. In addition to the regulatory changes taking place in the United States, other countries have announced that they are undertaking a review of the regulation of offshore drilling industry following the Deepwater Horizon Incident. A discussion of risks relating to environmental regulations can be found in Item 3.D "Risk Factors" of this Annual Report.

C. ORGANIZATIONAL STRUCTURE

We were incorporated on May 10, 2005, under the laws of Bermuda. We are engaged, with our subsidiaries and consolidated companies, in the ownership and operation of a diversified fleet of offshore drilling units and in the provision of well services. Our operations are split into three reporting segments – mobile units (world-wide), tender rigs (mainly in south-east Asia and Africa) and well services (mainly in the North Sea).

On February 16, 2011, we reorganized our activities in the harsh environment segment by transferring those of our assets engaged therein to a new sub-holding company, NADL. NADL will have five drilling units in operation with a sixth rig, the West Elara, expected to be delivered from the Jurong Shipyard during the latter part of the second quarter 2011. NADL has 1.0 billion shares issued and outstanding, of which we own 75%.

In late February 2011, Seadrill reduced its ownership in Seawell from 52.3 percent to approximately 36.5 percent. As such, with effect from the end of February, 2011, Seawell, which represents our well service segment, will no longer be fully consolidated into Seadrill's financial statements, but will instead be classified as an investment in an associated company.
 
Overall responsibility for the management of Seadrill Limited and its subsidiaries rests with the Board of Directors, or the Board. The Board has organized the provision of management services through a subsidiary incorporated in Norway, Seadrill Management AS, or Seadrill Management. The Board has defined the scope and terms of the
services to be provided by Seadrill Management authorizing it  to run day-to-day operations. The Board must be consulted on all matters of material importance and/or of an unusual nature and, for such matters, will provide specific authorization to personnel in Seadrill Management to act on the Company's behalf.

 
30

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

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 26, 2011:
 
 
Year
Water
depth
Drilling
depth
Current location
Month of
Unit
built
(feet)
(feet)
 
contract expiry
           
Jack-up rigs
         
West Janus
1985
330
21,000
Malaysia
August 2011
West Epsilon **
1993
394
30,000
Norway
December 2014
Offshore Courageous
2007
350
30,000
Malaysia
January 2012
Offshore Defender
2007
350
30,000
Brazil
February 2012
Offshore Resolute
2007
350
30,000
Vietnam
August 2011
West Prospero (SF)
2007
400
30,000
Vietnam
December 2011
Offshore Intrepid
2008
350
30,000
Saudi Arabia / Kuwait
November 2012
Offshore Vigilant
2008
350
30,000
Venezuela
December 2011
West Ariel
2008
400
30,000
Vietnam
December 2011
West Triton
2008
375
30,000
Malaysia
August 2011
Offshore Freedom
2009
350
30,000
Saudi Arabia / Kuwait
May 2013
West Cressida
2009
375
30,000
Thailand
May 2014
Offshore Mischief
2010
350
30,000
Brazil
August 2011
West Callisto
2010
400
30,000
Indonesia
September 2011
West Juno ***
2010
400
30,000
Andaman Sea
April 2011
West Leda
2010
375
30,000
Indonesia
March 2011
West Elara (NB)
2011
492
40,000
 
October 2016
West Castor (NB)
2012
400
30,000
   
West Telesto (NB)
2012
400
30,000
   
West Oberon (NB)
2013
400
30,000
   
West Tucana (NB)
2013
400
30,000
   
West Linus (NB) **
2013
492
40,000
 
December 2018
           
Tender rigs
         
T4
1981
410
20,000
Thailand
July 2013
T8
1982
410
20,000
Singapore (warm stacked *)
 
T7
1983
410
20,000
Thailand
October 2011
West Pelaut
1994
6,500
30,000
Brunei
March 2015
West Menang
1999
6,500
30,000
Singapore (warm stacked *)
December 2012
West Alliance
2001
6,500
30,000
Malaysia
January 2015
West Setia
2005
6,500
30,000
Angola
August 2012
West Berani
2006
6,500
30,000
Indonesia
December 2011
T11
2008
6,500
30,000
Thailand
May 2013
T12
2010
6,500
30,000
Thailand
April 2014
West Vencedor
2010
6,500
30,000
Angola
July 2015
West Jaya (NB)
2011
6,500
30,000
In transit to Trinidad&Tobago
July 2013
T15 (NB)
2013
6,500
30,000
 
June 2018
T16 (NB)
2013
6,500
30,000
 
December 2018
T17 (NB)
2013
6,000
30,000
   
           
 
 
 
31

 
 
Semi-submersible rigs
         
West Alpha **
1986
2,000
23,000
Norway
June 2012
West Venture **
2000
2,600
30,000
Norway
July 2015
West Phoenix **
2008
10,000
30,000
Norway
January 2015
West Hercules (SF)
2008
10,000
35,000
China
May 2012
West Sirius
2008
10,000
35,000
Gulf of Mexico
July 2014
West Taurus (SF)
2008
10,000
35,000
Brazil
February 2015
West Eminence
2009
10,000
30,000
Brazil
July 2015
West Aquarius
2009
10,000
35,000
Indonesia
February 2013
West Orion
2010
10,000
35,000
Brazil
July 2016
West Pegasus (ex Seadragon I) (NB)
2011
10,000
35,000
In transit to Mexico
August 2016
West Leo (Seadragon II) (NB)
2011
10,000
35,000
   
West Capricorn (NB)
2011
10,000
35,000
   
           
Drillships
         
West Navigator **
2000
7,500
35,000
Norway
December 2012
West Polaris (SF)
2008
10,000
35,000
Brazil
October 2012
West Capella
2008
10,000
35,000
Nigeria
April 2014
West Gemini
2010
10,000
35,000
Angola
September 2012
West Auriga (NB)
2013
12,000
40,000
   
West Vela (NB)
2013
12,000
40,000
   
West Tellus (NB)
2013
12,000
40,000
   
 
NB – Newbuilding under construction or in mobilization to its first drilling assignment.
SF  – Unit owned by subsidiary of Ship Finance (see Note 33 to Consolidated Financial Statements).
* Warm stacked means that the unit is not operating, but is being maintained in a state of readiness for future operations.
** Owned by our subsidiary NADL in which we own 75% of the outstanding shares, See Note 34 Subsequent events.

*** Seadrill has entered into an agreement to sell the West Juno, for more detail see Note 34, Subsequent events.

In addition to the drilling units listed above, as of December 31, 2010, we have buildings, plant and equipment with a net book value of $115 million, including a modular rig under construction for Seawell, and office equipment. Our offices in Stavanger in Norway, Singapore, Houston in the United States, Rio de Janeiro in Brazil and Aberdeen in the United Kingdom are leased and aggregate office rental costs were $21.0 million in 2010, and are expected to be approximately $12.5 million in 2011.

We do not have any material intellectual property rights.

ITEM 4A. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following should be read in conjunction with Item 3.A "Selected Financial Data", Item 4 "Information on the Company" and our Consolidated Financial Statements and Notes thereto included herein.

Overview

We were established in May 2005 with an operating fleet of five units. Since then, through investment in newbuildings and the acquisition of other companies, we have expanded our operations and now have approximately 6,700 skilled employees and an operating fleet of 40 drilling units (including the one unit we agreed in April 2011 to sell). In addition, we have construction contracts for 16 new units, and we operate a further five units in association with Varia Perdana. A full fleet list is provided in Item 4.D "Information on the Company – Property, Plant and Equipment".
 
In addition to owning and operating offshore drilling units, we provide drilling and well services through our subsidiary Seawell, which will be renamed Archer. As described above, under Item 4.D "Information on the Company – Property, Plant and Equipment", as of the end of February 2011 Seawell ceased to be a majority owned subsidiary. As a result, Seawell's drilling and well services operations will be reflected in our consolidated financial statements as an investment in an associated company.

 
32

 
 
We have also made investments in other companies that are viewed as strategic investments, including Pride (9.4%), SapuraCrest (23.6%), Varia Perdana (49%).

Fleet Development

The following table summarizes the development of our active fleet of drilling units, based on the dates when the units began operations:
 
 
Mobile units segment
 
 
Unit type
FPSOs
Jack-up
rigs
Drillships
Semi-
submersible
rigs
Tender
rigs
Total
units
             
At December 31, 2005
2
3
-
-
-
5
additions in 2006
 
+2
+1
+2
+7
+12
At December 31, 2006
2
5
1
2
7
17
additions in 2007
 
+2
   
+1
+3
disposals in 2007
-2
       
-2
At December 31, 2007
-
7
1
2
8
18
additions in 2008
 
+2
+1
+2
+1
+6
disposals in 2008
 
-1
     
-1
At December 31, 2008
-
8
2
4
9
23
additions in 2009
   
+1
+4
 
+5
disposals in 2009
 
-2
     
-2
At December 31, 2009
-
6
3
8
9
26
additions in 2010
 
+10
+1
+1
+2
-14
disposals in 2010
 
-1
     
-1
At December 31, 2010
-
15
4
9
11
39

In addition to the units in the table above, our fleet list includes the following rigs under construction which are scheduled to be delivered and begin operations after December 31, 2010:

 
Delivery in 2011: two jack-up rigs (one of which we, in April 2011, agreed to sell), one tender rig and three semi-submersible rigs.

 
Delivery in 2012: two jack-up rigs.

 
Delivery in 2013: three jack-up rigs, three tender rigs and three drillships.

Factors Affecting our Results of Operations

The principal factors which have affected our results since 2005 and are expected to affect our future results of operations and financial position include:

 
the number and availability of our drilling units;

 
the daily rates obtainable of our drilling units;

 
the daily operating expenses of our drilling units;

 
utilization rates for our drilling units

 
administrative expenses;

 
interest and other financial items; and

 
tax expenses.

 
33

 
 
Revenues

Our revenues are derived primarily from the operation of our drilling units on short, medium and long-term contracts at fixed daily rates. Revenues from well services are derived from drilling on our client's fixed installations and from carrying out a wide range of engineering and down-hole services.

In general, each of our drilling units is contracted for a period of time to an oil and gas company to provide offshore drilling services at an agreed daily rate. A unit will be stacked if it has no contract in place. Daily rates can vary from approximately $50,000 per day to more than $600,000 per day, depending on the type of drilling unit and its capabilities, operating expenses, taxes and other factors. An important factor in determining the level of revenue is the technical utilization of the drilling rig. To the extent that our operations are interrupted due to equipment breakdown or operational failures, we do not generally receive dayrate compensation for the period of the interruption.

The terms and conditions of the contracts allow for compensation when factors beyond our control, including weather conditions, influence the drilling operations and, in some cases, for compensation when we perform planned maintenance activities. In many of our contracts we are entitled to cost escalation to compensate for industry specific cost increases as reflected in publicly available cost indices.

In addition to contracted daily revenue, customers may pay mobilization and demobilization fees for units before and after their drilling assignments, and may also pay reimbursement of costs incurred by the Company at their request for additional supplies, personnel and other services, not covered by the contractual daily rate.

The following table summarizes our average daily revenues and economic utilization percentage by rig type for the periods under review:
 
 
   
Year ended December 31,
 
   
2010
   
2009
   
2008
 
   
Average
daily
revenues
   
Economic utilization
   
Average
daily
revenues
   
Economic utilization
   
Average
daily
revenues
   
Economic utilization
 
   
$
     
%
   
$
     
%
   
$
     
%
 
Jack-up rigs
   
160,000
     
90
     
130,000
     
70
     
196,000
     
92
 
Semi-submersible rigs
   
486,000
     
95
     
445,000
     
92
     
345,000
     
93
 
Drillships
   
508,000
     
89
     
497,000
     
94
     
251,000
     
66
 
Tender rigs
   
95,000
     
89
     
115,000
     
93
     
95,000
     
98
 

Note: Average daily revenues are the weighted average revenues for each type of unit, based on the actual days available for each unit of that type. Economic utilization is calculated as the total days worked divided by the total days in the period.

Expenses

Our expenses consist primarily of rig operating expenses, reimbursable expenses, depreciation and amortization, administration expenses, interest and other financial expenses and tax expenses.
 
Rig operating expenses are related to the drilling units we have either in operation or stacked and include the remuneration of offshore crews and onshore rig supervision staff, as well as expenses for repairs and maintenance. Reimbursable expenses are incurred at the request of customers, and include provision of supplies, personnel and other services. Depreciation and amortization costs are based on the historical cost of our drilling units and other equipment. Administration expenses include the costs of offices in various locations, as well as the remuneration and other compensation of the directors and employees engaged in the management and administration of the Company.

 
34

 
 
Our interest expenses depend on the overall level of debt and prevailing interest rates. However, these expenses may be reduced as a consequence of capitalization of interest expenses relating to drilling units under construction. Other financial items include income from associated companies and may reflect various mark-to-market adjustments to the value of our interest rate and forward currency swap agreements and other derivative financial instruments.

Tax expenses reflect payable and deferred taxes related to our rig owning and operating activities and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the calculation of tax is based on net income or deemed income, the latter generally being a function of gross turnover.
 
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 and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that we believe to be reasonable.  Our critical accounting estimates are important to the portrayal of both our financial condition and results of operations and require us to make subjective or complex assumptions or estimates about matters that are uncertain.  Significant accounting policies are discussed in our Notes to Consolidated Financial Statements – Note 2: Accounting policies. 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 within our consolidated financial statements that require estimation.

Drilling Units

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

Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset's value for its remaining useful life, are capitalized and depreciated over the remaining life of the asset.

We determine the carrying value of these assets based on policies that incorporate our estimates, assumptions and judgments relative to the carrying value, remaining useful lives and residual values. The assumptions and judgments we use in determining the estimated useful lives of our drilling units reflect both historical experience and expectations regarding future operations, utilization and performance. The use of different estimates, assumptions and judgments in establishing estimated useful lives could result in materially different net book values of our drilling units and results of operations.

The useful lives of rigs and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We re-evaluate the remaining useful lives of our drilling units as and when 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 are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset's carrying value and fair value. In general, impairment analyses are based on expected costs, utilization and daily rates 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.


 
35

 

Income Taxes

We are a Bermuda company. Currently we are not required to pay taxes in Bermuda on ordinary income or capital gains. We have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 2016. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income, 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 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 as 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 interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amount, timing and character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are sustainable and on estimates of taxes that will ultimately be due. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as of the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances.

Contingencies

We establish reserves for estimated loss contingencies when we believe a loss is probable and the amount of the loss can be reasonably estimated. Our contingency reserves relate primarily to litigation, indemnities and potential income and other tax assessments (see also "Income Taxes" above). Revisions to contingency reserves are reflected in income in the period in which different facts or information become known, or circumstances change, that affect our previous assumptions with respect to the likelihood or amount of loss. Reserves for contingencies are based upon our assumptions and estimates regarding the probable outcome of the matter and include our costs to defend any action. In situations where we expect insurance proceeds to offset contingent liabilities, we record a receivable for all probable recoveries until the net loss is zero. We recognize contingent gains when the contingency is resolved and the gain has been realized. Should the outcome differ from our assumptions and estimates or other events result in a material adjustment to the accrued estimated contingencies, revisions to the estimated contingency amounts would be required and would be recognized in the period when the new information becomes known.

Goodwill

We allocate the cost 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. We perform a goodwill impairment test as of December 31 for each reporting segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management, based on a discounted cash flow model. When testing for impairment we use expected future cash flows using contract daily rates during the contract periods. For periods after expiry of the contract periods, daily rates are projected based on estimates regarding future market conditions, including zero escalation of daily rates. Estimated future cash flows are calculated based on remaining asset lives and are discounted using a weighted average cost of capital.


 
36

 

We have also performed sensitivity analyses using different scenarios regarding future cash flows, remaining asset lives and discount rates showing acceptable tolerance to changes in underlying assumptions in the impairment model before changes in assumptions would result in impairment. The use of different estimates and assumptions could result in materially different carrying value of goodwill and could materially affect our results of operations.

For the years ended December 31, 2010, 2009 and 2008 no impairments have resulted from our analysis.
 
Defined benefit pension plans

The Company has several defined benefit plans which provide retirement, death and termination benefits. The Company's net obligation is calculated separately for each plan by estimating the amount of the future benefit that employees have earned in return for their cumulative service. Pension and post-retirement costs and obligations are actuarially determined and are affected by assumptions including expected return on plan assets, discount rates, compensation increases and employee turnover. The use of different assumptions and estimates could result in materially different carrying value pension obligations and could materially affect our results of operations.

The aggregated projected future benefit obligation is discounted to a present value, and the aggregated fair value of any plan assets is deducted. The discount rate is the market yield at the balance sheet date on government bonds in the relevant currency and based on terms consistent with the post-employment benefit obligations. The retirement benefits are generally a function of number of years of employment and amount of employees remuneration. The plans are primarily funded through payments to insurance companies. The Company records its pension costs in the period during which the services are rendered by the employees. Actuarial gains and losses are recognized in the statement of operations when the net cumulative unrecognized actuarial gains or losses for each individual plan at the end of the previous reporting year exceed 10 percent of the higher of the present value of the defined benefit obligation and the fair value of plan assets at that date. These gains and losses are recognized over the expected remaining working lives of the employees participating in the plans. Otherwise, recognition of actuarial gains and losses is included in other comprehensive income.  Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income.

Impairment of marketable securities and equity method investees

We analyze our available-for-sale securities and equity method investees 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 fair 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 cost within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in fair value are not reflected in earnings until sale of the securities held as available for sale or of the equity method investee are sold. The evaluation of whether a decline in fair value is other-than-temporary requires a high degree of judgment and the use of different assumptions could materially affect our earnings.

Convertible debt

Our convertible bond loans are comprised of a loan component, or host contract, and an option component to convert the loan to shares, or embedded derivative. If certain criteria are met, the embedded derivative must be accounted for separately from its host contract. The value of the embedded derivative is based on the implied valuation of the loan and option components reflected in the initial pricing of the bond at issuance. Financial models that use observable and/or implied market pricing are applied to estimate these values. However, judgment is exercised in formulating the assumptions used in such valuation models.

 
37

 

Recent accounting pronouncements

In June 2009, the FASB issued amended guidance requiring companies to qualitatively assess the determination of the primary beneficiary of a variable-interest entities (or VIEs) based on whether the entity (1) has the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. It also requires additional disclosures for any enterprise that holds a variable interest in a VIE. The new accounting and disclosure requirements became effective for us from January 1, 2010. The adoption of this amended guidance did not have a material effect on our consolidated financial statements.
 
In October 2009, the FASB issued authoritative guidance that amends earlier guidance addressing the accounting for contractual arrangements in which an entity provides multiple products or services (deliverables) to a customer. The amendments address the unit of accounting for arrangements involving multiple deliverables and how arrangement consideration should be allocated to the separate units of accounting, when applicable, by establishing a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific nor third-party evidence is available. The amendments also require that arrangement consideration be allocated at the inception of an arrangement to all deliverables using the relative selling price method. We will adopt this guidance in the first quarter 2011, and adoption of this guidance is not expected to have a material effect on our consolidated financial statements.
 
In January 2010, the FASB issued authoritative guidance that changes the disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements. We adopted the guidance in the first quarter 2010, which did not have a material impact on our consolidated financial statements.
 
In January 2010 the FASB issued authoritative guidance in order to eliminate diversity in the way different enterprises reflect new shares issued as part of a distribution in their calculation of Earnings Per Share ("EPS"). The provisions of this new guidance are effective on a retrospective basis and their adoption had no impact on the Company's reported EPS.

In January 2010, the FASB issued authoritative guidance to amend the accounting and reporting requirements for decreases in ownership of a subsidiary. This guidance requires that a decrease in the ownership interest of a subsidiary that does not result in a change of control be treated as an equity transaction. The guidance also expands the disclosure requirements about the deconsolidation of a subsidiary. The Company adopted this guidance in the first quarter of 2010.

In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in the first quarter 2010. The adoption of this guidance did not have an impact on our financial statements.
 
 
In July 2010, the FASB issued authoritative guidance which requires expanded disclosures about the credit quality of an entity's financing receivables and its allowance for credit losses on a disaggregated basis. The adoption of this guidance by the Company with effect from January 1, 2010 did not have any material effect on its consolidated financial statements.
 
 
In December 2010, the FASB issued authoritative guidance which modifies the requirements of step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. The Company will adopt this guidance in the first quarter of fiscal year 2011. The Company does not believe that adoption of this guidance will have a material effect on its consolidated financial statements.

 
38

 
 
In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations to specify that if a company presents comparative financial statements, it should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current period, occurred at the beginning of the comparable prior annual reporting period only. This guidance is effective prospectively for business combinations for which the acquisition date in, on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. We will adopt this guidance prospectively beginning January 1, 2011. It is not expected to have a significant impact on the Company.

Inflation

Most of our contracts for drilling and well services include provision for rates to be adjusted annually in line with inflation. Accordingly, we do not consider inflation to be a significant risk to our profitability in the current and foreseeable economic environment, although it will have a moderate effect on operating and administration costs.

A. RESULTS OF OPERATIONS

Fiscal Year Ended December 31, 2010, compared to Fiscal Year Ended December 31, 2009.

The following table sets forth our operating results for 2010 and 2009.

   
Year ended December 31, 2010
   
Year ended December 31, 2009
 
In US$ millions
 
Mobile
units
   
Tender
rigs
   
Well
services
   
Total
   
Mobile
units
   
Tender
rigs
   
Well
services
   
Total
 
Total operating revenues
   
2,842
     
482
     
717
     
4,041
     
2,251
     
392
     
610
     
3,253
 
Gain on sale of assets
   
26
                     
26
     
71
                     
71
 
Total operating expenses
   
(1,528
)
   
(260
)
   
(654
)
   
(2,442
)
   
(1,181
)
   
(219
)
   
(552
)
   
(1,952
)
Operating income
   
1,340
     
222
     
63
     
1,625
     
1,141
     
173
     
58
     
1,372
 
Interest expense
                           
(312
)
                           
(228
)
Other financial items
                           
18
                             
329
 
Income before taxes
                           
1,331
                             
1,473
 
Income taxes
                           
(159
)
                           
(120
)
Net income
                           
1,172
                             
1,353
 

Total operating revenues

In US $millions
2010
 
2009
 
Increase
 
Mobile units
2,842
 
2,251
 
26
%
Tender rigs
482
 
392
 
23
%
Well services
717
 
610
 
18
%
Total operating revenues
4,041
 
3,253
 
24
%

Total operating revenues increased from $3.25 billion in 2009 to $4.04 billion in 2010. Total operating revenues are predominantly contract revenues with additional, relatively small amounts of reimbursables and other revenue.

Total operating revenues in the mobile unit segment increased by $0.6 billion from 2009 to 2010. The number of drilling units in the mobile units segment increased from 17 at December 31, 2009 to 29 at December 31, 2010. Seven new jack-up rigs were added to the fleet with the acquisition of Scorpion, two of the newbuild jack-up rigs, the West Callisto and the West Leda, were delivered and the jack-up rig West Cressida, formerly the Petrojack IV,  was acquired in 2010. In addition two new semi-submersible rigs, the West Orion and the West Gemini, were delivered and started operation during the period. These new units contributed to the increase in revenue. There was no significant change in the general level of daily rates during 2010.

Total operating revenues in the tender rig segment, increased by 23% from 2009 to 2010. The increase was mainly related to the two new units, the West Vencedor and the T12 being delivered and starting operations during 2010. The resulting increase was partly off-set by one unit being idle during the period. Daily rates for our tender rigs have remained fairly constant during the two year period to December 31, 2010.

 
39

 
Total operating revenues in the well services segment increased from $610 million in 2009 to $717 million in 2010. The increase relates to increased activity and the acquisition of several smaller companies during 2010.

Gain on sale of assets

In 2010, we recorded a gain of $26 million on the disposal of the jack-up rig West Larissa.

In 2009, we recorded gains of $21 million for the West Ceres and $58 million for the West Atlas, with the former being sold and the latter being declared a total loss following a fire. Also, in 2009, we recorded a $4 million gain on the sale of our interest in an oilfield in the United Kingdom and a loss of $12 million due to the PPL Shipyard Ptd Ltd exercising its purchase option on one jack-up rig under construction. All of these units were in the mobile units operating segment.

Total operating expenses
 
In US$ millions
 
2010
   
2009
   
Increase
 
Mobile units
   
1,528
     
1,181
     
29
%
Tender rigs
   
260
     
219
     
19
%
Well services
   
653
     
552
     
18
%
Total operating expenses
   
2,441
     
1,952
     
25
%
 
Total operating expenses increased from $1.95 billion in 2009 to $2.44 billion in 2010, with the increase mainly in the mobile units segment. Total operating expenses consist of rig operating expenses, depreciation, reimbursable expenses and general and administrative expenses. Total general and administrative expenses increased to $178 million in 2010 compared to $149 million in 2009. Reimbursable expenses in each segment were closely in line with reimbursable revenues.

Total operating expenses for the mobile units operating segment increased by $340 million from 2009 to 2010. Vessel and rig operating expenses increased by $205 million primarily due to the increase in the number of units during the period. Depreciation and amortization increased from $333 million in 2009 to $400 million in 2010. Of the $67 million increase, $52 million related to the newly acquired units and delivery of newbuilds during 2010, while the remaining increase of $15 million relates to the newbuilds delivered during the course of 2009.

Total operating expenses in the tender rig segment increased from $219 million in 2009 to $260 million in 2010. The increased costs were mainly a result of the delivery of two newbuilds during the year.

Total operating expenses increased in the well services segment from $552 million in 2009 to $653 million in 2010. Within this amount, operating expenses increased from $394 million in 2009 to $500 million in 2010, reflecting a similar increase in operating revenues, leaving the operating margin at approximately the same level as the prior year. Reimbursable expenses decreased from $119 million in 2009 to $103 million in 2010. Reimbursable expenses are closely linked to reimbursable revenues and amounts can fluctuate from period to period. However we normally earn a margin of approximately 5% on reimbursables within the well services segment.

The numbers above include general and administrative expenses that increased from $149 million in 2009 to $178 million in 2010. The increase is related to our growth in operations, with subsequent increase in corporate staff numbers and establishment of offices in new locations.

Interest expense

Interest expense increased from $228 million in 2009 to $312 million in 2010, as a result of an overall increase in interest bearing debt as well as less interest being capitalized. Capitalized interest relates to interest costs incurred during the construction of newbuildings  and amounted to $80 million in 2009 compared with $59 million in 2010. There has not been a significant change in the general interest rates during the year.

 
40

 
Other financial items
Other financial items reported in the Income statement includes the following items:

In US$ millions
2010
 
2009
 
Interest income
    42     78  
Share in results of associated companies
    48     92  
Impairment loss on marketable securities
    (15 )   -  
(Loss)/gain on derivative financial instruments
    (92 )   130  
Gain on re-measurement of previously held equity interest
    111     -  
Gain on bargain purchase
    56     -  
Loss on debt extinguishment
    (145 )   -  
Foreign exchange (loss)/gain
    (26 )   (25 )
Other financial items
    39     54  
Total other financial items
    18     329  
 
Interest income decreased from $78 million in 2009 to $42 million in 2010. The decrease is mainly related to lower holdings of interest bearing securities.

Share in results from associated companies decreased from $92 million to $48 million in 2010. The main reason for the reduction is related to Scorpion which was fully consolidated during the first half year of 2010, but also lower net income from SapuraCrest Petroleum and Varia Perdana contributed to the reduction.

As of December 31, 2010, we determined that the fair value of one of our investments, the marketable securities of Seahawk Drilling Inc, was below its carrying value and that there was little prospect for a recovery in value in 2011. Accordingly, in 2010, we recognized an impairment charge of $15 million.

In 2010, we recognized losses from the derivative financial instruments of $92 million compared to a gain of $130 million in 2009. The decrease is mainly related to losses of $162 million from the interest rate swap agreements compared to a gain of $26 million in the previous year. Also, gains from forward currency contracts reduced from $34 million in 2009 to $12 million in 2010, which contributed to the total decrease related to derivative financial instruments. In addition, the gain from the total return swap agreements decreased from $70 million in 2009 to $32 million in 2010 partly offset by gains from other derivative instruments totaling $26 million in 2010.

Foreign exchange loss amounted to $26 million and was of the same level as last year.

Other financial items amounted to a gaim of $39 million, which is a decrease of $15 million compared to 2009. In 2010, other financial items included a gain from remeasurement of our previously held equity interest in Scorpion of $111 million, and gain from a bargain purchase of shares in Scorpion. In addition, we recognized a loss of $145 million related to incentive offers for the early conversion and retirement of some of our convertible debt instruments.

Income taxes

Income taxes amounted to a net cost of $159 million in 2010 compared to a net cost of $120 million in 2009. Our effective tax rate was approximately 12.1% in 2010, as compared to 8.2% in 2009. The increase in tax expense in 2010 is principally due to a higher proportion of our income being generated in taxable versus non taxable jurisdictions or in taxable jurisdictions with higher tax rates. In addition our recent commencement of deepwater units operations in China, Indonesia, the Philippines and Nigeria in the prior year along with the increased rig operations in Brazil and Norway have all contributed to additional taxable income in 2010. Several of the new drilling operations are in countries which impose tax on drilling operations on the basis of deemed taxable income, leading to an increase in tax costs compared with the previous year.

 
41

 

Significant amounts of our income and costs are reported in nontaxable jurisdictions such as Bermuda. The drilling rig operations are normally carried out in taxable jurisdictions. In the tax jurisdictions where we operate, the corporate tax rate ranges from 16% to 35% for earned income and the deemed tax rates vary from 5% to 10% of revenues. Further, losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, our effective tax rate may differ significantly from period to period depending on the level of activity in and mix of each of tax jurisdictions in which our operations are conducted.

Fiscal Year Ended December 31, 2009, compared to Fiscal Year Ended December 31, 2008.

The following table sets forth our operating results for 2009 and 2008.
 


   
Year ended December 31, 2009
   
Year ended December 31, 2008
 
In US$ millions
 
Mobile units
   
Tender
rigs
   
Well services
   
Total
   
Mobile units
   
Tender
rigs
   
Well services
   
Total
 
Total operating revenues
   
2,251
     
392
     
610
     
3,253
     
1,144
     
342
     
620
     
2,106
 
Gain on sale of assets
   
71
                     
71
     
80
     
-
     
-
     
80
 
Total operating expenses
   
1,181
     
219
     
552
     
1,952
     
756
     
216
     
565
     
1,537
 
Operating income
   
1,141
     
173
     
58
     
1,372
     
468
     
126
     
55
     
649
 
Interest expense
                           
(228
)
                           
(130
)
Other financial items
                           
329
                             
(619
)
Income before taxes
                           
1,473
                             
(100
)
Income taxes
                           
(120
)
                           
(48
)
Gain on issuance of shares by subsidiary
                           
-
                             
25
 
Net income
                           
1,353
                             
(123
)
 
Total operating revenues

In US $millions
2009
 
2008
 
Increase
 
Mobile units
2,251
 
1,144
 
+97
%
Tender rigs
392
 
342
 
+15
%
Well services
610
 
620
 
-2
%
Total operating revenues
3,253
 
2,106
 
+54
%
 
Total operating revenues increased from $2.11 billion in 2008 to $3.25 billion in 2009. Total operating revenues are predominantly contract revenues with additional relatively small amounts of reimbursables and other revenues.

Total operating revenues in the mobile unit segment increased by $1.11 billion from 2008 to 2009. The number of drilling units in the mobile units segment increased from 14 at December 31, 2008 to 17 at December 31, 2009. Four new semi-submersible rigs were delivered and started operation during the period (West Phoenix, West Aquarius, West Taurus and West Eminence) along with one ultra-deepwater drillship (West Capella). The jack-up rig West Ceres was sold and the jack-up rig West Atlas was declared a total loss after a fire. Although the new units were delivered over the course of the year and some did not contribute fully to operating revenues during the year, the additional revenue generated by the new units, net of the rigs disposed of, amounted to $759 million. Average economic utilization of the fleet decreased from 92% in 2008 to 82% in 2009. The decrease is related to several of our jack-up units being stacked in the period as well as the generally lower economic utilization associated with start-up for some of our new units. Average dayrates increased from $230,000 in 2008 to $330,000 in 2009. The increase in average dayrates is related to the increase in our semi-submersible rig fleet, which achieve higher dayrates than our jack-up units.

In the tender rig operating segment, operating revenues increased by 15% from 2008 to 2009. The increase was mainly related to increased dayrates, which increased by approximately $20,000 per day to an average of $115,000 per day in 2009. The delivery of the tender rig T11, which began operations in the second quarter of 2008, also contributed to the increase. These dayrate increases were partly offset by a decline in economic utilization from 98% in 2008 to 93% in 2009.
 
Total operating revenues for well services decreased from $620 million in 2008 to $610 million in 2009. A significant portion of well services activity takes place in Norway and operating revenues in Norwegian Kroner increased from NOK2.6 billion in 2008 to NOK2.8 billion in 2009. The Norwegian content represented approximately 73 percent of total revenues and revenues are generally fairly stable.

 
42

 
Gain on sale of assets

In 2009,  we recorded gains of $21 million and $58 million for the disposal of the jack-up rigs, the West Ceres and the West Atlas respectively, the former being sold and the latter being declared a total loss following a fire. In addition, in 2009, we recorded a $4 million gain on the sale of our interest in an oilfield in the United Kingdom and a loss of $12 million due to the PPL Shipyard Pte Ltd exercising its purchase option on one jack-up rig under construction. In 2008, the jack-up rig West Titania was sold and a gain of $80 million was recorded. All of these units were in the mobile units operating segment.

Total operating expenses
 
In US$ millions
 
2009
   
2008
   
Increase
Mobile units
   
1,181
     
756
     
+56
%
Tender rigs
   
219
     
216
     
+1
%
Well services
   
552
     
565
     
-2
%
Total operating expenses
   
1,952
     
1,537
     
+27
%
 
Total operating expenses increased from $1.54 billion in 2008 to $1.95 billion in 2009, with the increase mainly in the mobile units segment. Total operating expenses consist of rig operating expenses, depreciation, reimbursable expenses and general and administrative expenses. Total general and administrative expenses increased to $149 million in 2009 compared to $126 million in of 2008. Reimbursable expenses in each segment were closely in line with reimbursable revenues.

Total operating expenses for the mobile units operating segment increased by $425 million from 2008 to 2009. Vessel and rig operating expenses increased by $257 million, mainly due to the new units which came into operation.  Depreciation and amortization increased from $173 million in 2008 to $333 million in 2009. Of the $160 million increase, $102 million was related to newbuildings delivered in 2009, while the remaining $58 million was largely related to newbuildings delivered during 2008 for which we expensed a full year of depreciation in 2009 compared to reduced periods in 2008. General and administrative expenses increased from $92 million in 2008 to $106 million in 2009. The increase is related to our expansion which has made it necessary to increase corporate staff numbers and establish new offices in different regions.

Total operating expenses in the tender rig segment increased slightly from 2008 to 2009. The increase is primarily related to the delivery of the tender rig T11 in the second quarter of 2008.

Total operating expenses decreased marginally in the well services segment from $565 million in 2008 to $552 million in 2009. Within this amount, operating expenses decreased from $425 million in 2008 to $394 million in 2009, reflecting a similar reduction in operating revenues, leaving the operating margin at approximately the same level. Reimbursable expenses increased from $104 million in 2008 to $119 million in 2009. Reimbursable expenses are closely linked to reimbursable revenues and amounts can fluctuate from period to period. However we normally earn a margin of approximately 5% on reimbursables within the well services segment.

Interest expense

Interest expense increased from $130 million in 2008 to $228 million in 2009, as a result of less interest being capitalized in 2009. Interest costs incurred during the construction of newbuildings are capitalized, and capitalized interest amounted to $151 million in 2008 compared with $80 million in 2009. The increase in interest bearing debt over the course of 2009 also contributed to the increase.

 
43

 

Other financial items
In US$ millions
2009
 
2008
 
Change *
Interest income
 
78
   
31
   
+152
%
Share in results of associated companies
 
92
   
15
   
+513
%
Gain on sale of associated companies
 
-
   
150
   
n/a
 
Impairment loss on marketable securities and investments in associated companies
 
-
   
(615
)
 
n/a
 
Gain / (loss) on derivative financial instruments
 
130
   
(353
)
 
n/a
 
Foreign exchange gain (loss)
 
(25
)
 
131
   
n/a
 
Other financial items
 
54
   
22
   
+145
%
Total other financial items
 
329
   
(619
)
 
n/a
%
 
* n/a – percentage change has not been calculated as it is not considered to be meaningful where it results from one-off or exceptional items.

Interest income increased by $47 million in 2009, primarily as a result of interest earned on the investment in the Petromena bond acquired at the end of the first quarter of 2009, which contributed interest of $44 million.

Our share in the results of associated companies increased by $77 million in 2009 due to all of our associated companies generating higher earnings.

In 2008, a gain of $150 million was recorded on the disposal of shares in Apexindo and there was an impairment loss of $615 million on our investments in Pride, Scorpion and SapuraCrest.

There was a gain on derivative financial instruments of $130 million in 2009, compared with a loss of $353 million in 2008. We have entered into interest rate swaps, forward exchange contracts and total return swap agreements, none of which are accounted for as hedges. The gain in 2009 and the loss in 2008 reflect movements in interest rates, exchange rates and our share price in these periods.

In 2009, there was a foreign exchange loss of $25 million compared to a gain of $131 million in the same period in 2008. The loss in 2009 is primarily related to the weakening of the US Dollar against the Norwegian Kroner, which adversely affects the value of our debt denominated in Norwegian Kroner.

Other financial items amounted to a gain of $54 million in 2009, and include Seahawk shares received as dividend in kind from Pride amounting to approximately $25 million and a realized gain of $16 million on the partial redemption of the Petromena NOK2.0 billion bond.

Income taxes

Income taxes amounted to a net cost of $120 million in 2009 compared to a net cost of $48 million in 2008. The Company's effective tax rate was approximately 8.2% in 2009. Due to the write down of $615 million in 2008, which was not tax deductible, the effective tax rate for 2008 is not comparable. The increase in tax expense in 2009 is principally due to a higher portion of our income being generated in taxable (versus nontaxable) jurisdictions or in taxable jurisdictions with higher tax rates.  Specifically, the Company's recent start up of deepwater units operations in Indonesia, the Philippines and Nigeria, the increased rig operations in Brazil and Norway and the commencement of full operations in China for the reporting period have all contributed to additional taxable income in 2009. Several of the new drilling operations are in countries which tax drilling operations on the basis of deemed taxable income, leading to an increase in tax costs compared with the previous year. Additionally, in 2008 there was a non-taxable gain of $150 million recorded on the disposal of shares in Apexindo.

Significant parts of the Company's income and costs are reported in nontaxable jurisdictions such as Bermuda. The drilling rig operations are normally carried out in taxable jurisdictions. In the tax jurisdictions where the Company operates, the corporate tax rate ranges from 16% to 35% (on earned income) and the deemed tax rate varies from 5% to 8% of revenues. Further, losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, our effective tax rate may differ significantly from period to period depending on the level of activity in and mix of each of the tax jurisdictions in which our operations are conducted.

 
44

 


B. LIQUIDITY AND CAPITAL RESOURCES

We operate in a capital intensive industry. Our purchase of the units acquired from Greenwich, discussed above in Item4.A – "History and Development of the Company", was financed through a combination of equity raised and debt issued. Our subsequent investment in newbuildings and our acquisition of other companies have been financed through a combination of equity issuances, bond and convertible bond offerings, and borrowings from commercial banks. Our liquidity requirements relate to servicing our debt, funding investment in drilling units, funding working capital requirements and maintaining adequate cash reserves to mitigate the effects of fluctuations in operating cash flows. Most of our contract and other revenues are received monthly in arrears, and most of our operating costs are paid on a monthly basis.

Our funding and treasury activities are conducted within corporate policies to maximize returns while maintaining appropriate liquidity for our requirements. Cash and cash equivalents are held mainly in US dollar, Norwegian Kroner, Brazilian Real, Australian Dollar, Euros, Singapore Dollar and Pound Sterling.

Our short-term liquidity requirements relate to servicing our debt and funding working capital requirements. Sources of liquidity include cash balances, restricted cash balances, short-term investments, amounts available under revolving credit facilities and contract and other revenues. We believe that contract and other revenues will generate sufficient cash flow to fund our anticipated debt service and working capital requirements for the short and medium terms.

Our long-term liquidity requirements include funding the equity portion of investments in new drilling units, and repayment of long-term debt balances including those relating to the following borrowings of the Company and its consolidated subsidiaries:

                                                                                                                                                                                  
 
 
Secured credit facilities  
   Principal outstanding at December 31, 2010
 
- $800 million secured term loan facility due 2013
 
635.5
 
- $585 million secured term loan facility due 2012
 
386.7
 
- $1.50 billion secured credit facility due 2014
 
1,026.5
 
- $100 million secured term loan facility due 2014
 
 80.3
 
- $1.50 billion senior secured credit facility due 2014
 
1,060.0
 
- $1.20 billion senior secured credit facility due 2015
 
1,133.3
 
- $700 million senior secured credit facility due 2015
 
 700.0
 
- $550 million secured multi currency credit facility due 2015
 
 189.0
 
       
Ship Finance secured credit facilities
     
       
- $170 million secured term loan facility due 2013 (VIE)
 
 101.2
 
- $700 million secured term loan facility due 2013 (VIE)
 
 546.0
 
- $1.40 billion secured term loan facility due 2013 (VIE)
 
1,099.4
 
       
Unsecured bonds
     
       
- NOK500 million unsecured bond due 2012
 
76.7
 (NOK 450.0)
- NOK800 million unsecured bond due 2011
 
123.4
 (NOK 773.5)
- $350 million unsecured bond due 2015
 
350.0
 
       
Convertible bonds
     
       
- $500 million 4.875% unsecured convertible bonds due 2014
 
5.5
 
- $1,000 million 3.625% unsecured convertible bonds due 2012
 
749.9
 
- $650 million 3.375% unsecured convertible bonds due 2017
 
531.3
 
       
CIRR loans
     
       
- NOK1.75 billion Commercial Interest Reference Rate, or CIRR credit facilities due 2016       210.9  (NOK1,237.8 million)
- NOK1.01 billion CIRR credit facilities due 2020    143.6  (NOK842.8 million)
                                                                                                                                                                                                                                                                                        
 
45

 
 
On December 31, 2010, we had remaining contractual commitments relating to ten newbuilding contracts totaling $2.07 billion, as compared to $1.68 billion on December 31, 2009.

As of December 31, 2010, we had cash and cash equivalents totaling $911 million, as compared to $602 million in 2009, including $155 million of restricted cash, as compared to $142 million in 2009. In the year ended December 31, 2010, we generated cash from operations of $1.3 billion, used $2.3 billion in investing activities and used $1.3 billion in financing activities, as compared to $1.45 billion, $0.92 billion and $0.45 billion respectively in 2009.

During the year ended December 31, 2010 we paid cash dividends of $2.41 per common share, or a total of $1.0 billion, while in 2009 we paid $0.20 billion in total cash dividends. A regular dividend of $ 0.675 per common share plus a further extraordinary dividend of $0.20 per common share, totaling $388 million was declared on February 24, 2011, and paid on March 16, 2011.

To the extent that we enter into significant further investments and/or newbuilding commitments we expect that we will require additional issuances of equity and/or new debt to meet our capital requirements. Without such significant new investments, the cash that we generate from our operations supported by existing debt capacity is expected to be sufficient to cover our existing commitments to fund newbuildings, support our projected growth including meeting our working capital needs, as well as permit us to pay dividends to our stockholders and service our debt obligations in accordance with the existing maturity profile - see Item 8.A "Consolidated Statements and Other Financial Information – Dividend Policy". A deterioration in our operating performance, inability to obtain cost efficiencies, lack of success in adding new contracts to our backlog, failure to complete our remaining newbuilding program on time and within budget, as well as numerous other factors detailed above in "Risk Factors" could limit our ability to further the growth of our business, to meet working capital requirements, and to pay dividends.

We plan to pay our debt as it becomes due, although our leverage ratio will largely be dependent upon our contract backlog, the level of our regular cash dividends and financial outlook. Any decision to refinance debt maturing in future years will take the above factors into consideration, and we believe it is likely that we will refinance a portion of our debt.

Seadrill Limited, as the parent company of its operating subsidiaries, is not a party to any drilling contracts directly and is therefore dependent on receiving cash distributions from its subsidiaries and other investments to meet its payment obligations. Cash dividend payments are regularly transferred by the various subsidiaries. Surplus cash held in subsidiaries is transferred to Seadrill Limited by intercompany loans and/or dividend payments.

Borrowings

As of December 31, 2010, we had total outstanding borrowings of $9.16 billion under our credit facilities, at an average interest rate of 2.56 %. Outstanding borrowings at December 31, 2009, totaled $7.40 billion at an average interest rate of 2.77%. In addition there is interest bearing debt to related parties that amounted to $435 million as December 31, 2010.

In August 2005, we entered into a $300 million secured loan facility with a syndicate of banks. The facility was amended and increased in 2006 to $800 million. As of December 31, 2010, the outstanding balance was $635.million, as compared to $725 million in 2009. The facility consists of two tranches with differing interest rates and repayment schedules, and each tranche bears interest at LIBOR plus a margin. The final repayment of $368 million is due in December 2013.
 
In September 2005, we raised NOK500 million through the issuance of a seven year bond, which matures in September 2012. The bond bears quarterly interest at the Norwegian Inter-Bank Offer Rate, or NIBOR, plus a margin. We later repurchased NOK50 million of the bonds. As of December 31, 2010, the outstanding balance was NOK450 million, equivalent to $77 million, as compared to NOK500 million, equivalent to $87 million, in 2009.

 
46

 
 
In December 2006, we entered into a $585 million secured term loan facility with a syndicate of banks to partly fund the acquisition of eight tender rigs, which have been pledged as security. As of December 31, 2010, the outstanding balance was $387 million, as compared to $436 million in 2009. The facility bears interest at LIBOR plus a margin and is repayable over a term of six years. At maturity a balloon payment of $300 million is due.

In February 2007, our fully consolidated VIE Rig Finance II Ltd (which is wholly-owned by Ship Finance, a related party) entered into a $170 million secured term loan facility with a syndicate of banks, in order to partly fund the acquisition of the jack-up rig West Prospero. As of December 31, 2010, the outstanding amount under the facility was $101 million, as compared to $111 million in 2009. The facility bears interest at LIBOR plus a margin and is repayable over a term of six years. The facility is secured by the assets of Rig Finance II Ltd.

In June 2007, we entered into a $1.50 billion senior secured loan facility with a syndicate of banks to partly fund the acquisition of four drilling rigs the West Alpha, the West Epsilon, the West Navigator and the West Venture, which have been pledged as security. As of December 31, 2010, the outstanding balance was $1.06 billion, as compared to $1.14 billion in 2009. The facility bears interest at LIBOR plus a margin and is repayable over a term of seven years.  A final payment of $610 million is due on maturity.

In November 2007, we issued $1.0 billion of convertible bonds at par. Interest on the bonds is fixed at 3.625% per annum, payable semi-annually in arrears. The bonds were convertible into our common shares by the holders at any time up to 10 banking days prior to November 8, 2012, and in addition, we had a right to redeem the bonds at par plus accrued interest at any time following November 29, 2010, if certain conditions were met. On December 16, 2010, we announced a conversion incentive period for the holders of up to $250 million of the bonds, and subsequently accepted early conversion of the same $250 million amount. On April 7, 2011, we exercised our right to redeem the remaining 2012 bonds. At the date of the announcement, the remaining loan was $749.4 million and the conversion price was $27.80 per share. The loan agreement provides the bondholders with a time window to convert their bonds into shares that ended on April 26, 2011. As of that date bondholders representing $721.2 million had elected to convert their bonds into shares. The remaining bonds  will be redeemed at par value plus accrued interest on the final settlement date of May 10, 2011.

In April 2008, we entered into a $100 million secured term loan facility with two banks to partly fund the acquisition of a tender rig. As of December 31, 2010, the outstanding amount on this facility was $80 million, as compared to $86 million in 2009. The facility bears interest at fixed rates and is repayable over a term of six years. A final payment of $60 million is due on maturity.

In April 2008, we entered into a CIRR term loan for NOK850 million with Eksportfinans ASA, the Norwegian export credit agency. The loan bears interest at a fixed rate of 4.56% and is repayable over a term of eight years. The outstanding balance as of December 31, 2010, was NOK600 million, equivalent to $102 million, as compared to NOK700 million, which is equivalent to $121 million, in 2009.

In June 2008, we entered into a CIRR term loan for NOK904 million with Eksportfinans ASA. The loan bears fixed interest at a fixed rate of 4.15% and is repayable over a term of eight years. The outstanding balance as of December 31, 2010, was NOK368 million, equivalent to$109 million, as compared to NOK744 million, which is equivalent to $129 million, in 2009.

In July 2008, we entered into a CIRR term loan for NOK1.01 billion with Eksportfinans ASA. The loan bears fixed interest at a fixed rate of 4.15% and is repayable over a term of twelve years. The outstanding balance as of December 31, 2010, was NOK843 million, equivalent to $144 million, as compared to NOK927 million, which is equivalent to $160 million, in 2009.

In connection with the above three CIRR fixed interest term loans totaling NOK2.08 billion, three collateral cash deposits equal to the total outstanding loan balances were established with commercial banks. The collateral cash deposits are reduced in parallel with repayments of the CIRR loans and receive fixed interest at similar rates as those paid on the CIRR loans. The collateral cash deposits are classified as "restricted cash" on the balance sheet, and the effect of these arrangements is that the CIRR loans have no effect on net interest bearing debt.


 
47

 

In July 2008, our fully consolidated VIE SFL West Polaris Limited (which is wholly-owned by Ship Finance) entered into a $700 million secured term loan facility with a syndicate of banks, in order to partly fund the acquisition of the newbuilding drillship the West Polaris. At December 31, 2010, the outstanding balance under the facility was $546 million, as compared to $619 million in 2009. The facility bears interest at LIBOR plus a margin and is repayable over a term of five years. The facility is secured by the assets of SFL West Polaris Limited.

In September 2008, our fully consolidated VIE SFL Deepwater Ltd (which is wholly-owned by Ship Finance) entered into a $1.40 billion secured term loan facility with a syndicate of banks, in order to partly fund the acquisition of the two semi-submersible rigs the West Taurus and the West Hercules. As of December 31, 2010, the outstanding balance under the facility was $1.10 billion, as compared to $1.26 billion in 2009. The facility bears interest at LIBOR plus a margin and is repayable over a term of five years. The facility is secured by the assets of SFL Deepwater Ltd.

In June 2009, we entered into a $1.50 billion secured facility with a group of various commercial lending institutions and export credit agencies. The loan is secured by first priority mortgages on two ultra-deepwater semi-submersible drilling rigs, the West Aquarius and the West Sirius, one deepwater drillship, the West Capella and one jack-up drilling rig, the West Ariel. The outstanding balance as of December 31, 2010 was $1.03 billion with $209 million still available to draw down, as compared to $659 million, with $753 million still available to draw down, in 2009. The facility bears interest at LIBOR plus a margin and is repayable over a term of five years.

In September 2009, we issued at par $500 million of senior unsecured convertible bonds, the proceeds of which were intended to be used for future growth. Interest on the bonds was fixed at 4.875%, payable semi-annually in arrears. The bonds were convertible into our common shares at any time up to ten banking days prior to September 29, 2014. The conversion price at the time of issuance was $25.18 per share, representing a 35% premium to the share price at the time. As of December 31, 2009,  for accounting purposes $105 million had been allocated to the bond equity component and $395 million to the bond liability component, due to the cash settlement option stipulated in the bond agreement. In December 2010, all of the bonds were converted to equity capital following a conversion incentive period offered by us on December 16, 2010, resulting in the issuance of an additional $31 million common shares and an additional capital contribution of $647 million.

In October 2009, we issued a NOK800 million senior unsecured two year bond. The bond bears interest at NIBOR plus a margin and the proceeds are for general corporate purposes. We later repurchased NOK76.5 million of the bonds. As of December 31, 2010, the outstanding balance was NOK723.5 million, equivalent to $123 million, as compared to NOK773.5 million, which is equivalent to $134 million, in 2009.

In June 2010, we entered into a $1.20 billion secured facility with a group of various commercial banks and export credit agencies. The loan is secured by first priority mortgages in one ultra-deepwater semi-submersible drilling rig, the West Orion, one ultra-deepwater drillship, the West Gemini, and one tender rig, the West Vencedor. The outstanding balance as of December 31, 2010, was $1.13 billion. The facility bears interest at LIBOR plus a margin and is repayable over a term of five years. At maturity a balloon payment of $567 million is due June 2015

In October 2010, we entered into a $700 million secured facility with a syndicate of banks to partly fund the acquisition of seven jack-up drilling rigs from Scorpion. The acquired rigs have been pledged as security. The outstanding balance of this facility, as of December 31, 2010, was $700 million. The facility bears interest at LIBOR plus a margin and is repayable over a term of five years. A balloon payment of $350 million is due at maturity in October 2015.

In October 2010, we issued at par $650 million of senior unsecured convertible bonds, the proceeds of which are intended to be used for general corporate purposes. Interest on the bonds is fixed at 3.375%, payable semi-annually in arrears. The bonds are convertible into our common shares at any time up to ten banking days prior to October 27, 2017. The conversion price at the time of issuance was $38,92 per share, representing a 30% premium to the share price at the time. Since then, dividend distributions have reduced the conversion price to $38.18. For accounting purposes $121 million has been allocated to the bond equity component and $531 million to the bond liability component, due to the cash settlement option stipulated in the bond agreement. Unless previously redeemed, converted or purchased and cancelled, the bonds mature in October 2017. The convertible bonds are tradable, and their market price as of April 26, 2011 was 121.3% of nominal value. If the bonds were converted into shares at the current conversion price of $37.29, a further 17,430,947 new shares would be issued.

 
48

 


In October 2010, we issued a $350 million senior unsecured five year bond. The bond bears a coupon of 6.5% and the proceeds are for general corporate purposes. As of December 31, 2010, the outstanding balance was $350 million.

In November 2010, Seawell our then 52.3% owned subsidiary, refinanced its NOK1.5 billion revolving credit facility, and entered into a $550 million multi-currency term and revolving facility agreement with a syndicate of banks, that matures in November 2015 . As of December 31, 2010, the outstanding balance of the new facility was $189 million.

In the year ended December 31, 2010, we repaid in full;
 
 
(i)
a $185 million secured term loan facility (of which $45 million was outstanding at December 31, 2009)
 
(ii)
a $100 million secured term loan facility (of which $42 million was outstanding at December 31, 2009)
 
(iii)
a $30 million unsecured bond due 2012, and
 
(iv)
a NOK 1,500 million facility (was repaid by Seawell)

Our debt agreements generally contain financial covenants as well as security provided to lenders in the form of pledged assets.

The main financial covenants contained in our bank loan agreements are as follows:

 
 
Minimum liquidity requirement, which requires us to maintain cash and cash equivalents of at least $110 million within the group.
 
 
 
Interest coverage ratio, which requires us to maintain an EBITDA to interest expense ratio of 2.5:1.
 
 
 
Current ratio, which requires us to maintain a current assets to current liabilities ratio of at least 1:1. Current assets are defined as book value less minimum liquidity, but including up to 20% of shares in listed companies of which we own 20% or more. Current liabilities are defined as book value less the current portion of long term debt.
 
 
 
Equity ratio, which requires us to maintain a total equity to total assets ratio of at least 30%. Both equity and total assets are adjusted for the difference between book and market values of drilling units.
 
 
 
Leverage ratio, which requires us to maintain a ratio of net debt to EBITDA no greater than 4.5:1. Net debt is calculated as all interest bearing debt less cash and cash equivalents excluding minimum liquidity requirements.
 

For the purposes of the above tests, EBITDA is defined as 12 months trailing earnings before interest, taxation, depreciation and amortization.

The main covenants for our outstanding bonds are as follows:

 
Equity ratio, which requires us to maintain a total equity to total assets ratio of at least 30%. Both equity and total assets are adjusted for the difference between book value and market values of drilling units.

 
Equity ratio, which requires us to maintain a ratio of adjusted equity to total liabilities of at least 40%. Adjusted shareholder's equity is book value of equity adjusted for the difference between book and market values of drilling units.

We are in compliance with all financial loan covenants as of December 31, 2010.  As of December 31, 2010, the three month United States dollar LIBOR was 0.30%, as compared to 0.25% in 2009 and three month NIBOR was 2.60 %, as compared to 2.19% in 2009.

 
49

 

Derivatives

We use financial instruments to reduce the risk associated with fluctuations in interest and foreign exchange rates. Most of these agreements do not qualify for hedge accounting and any changes in the fair values of the swap agreements are included in the Consolidated Statement of Operations under "gain/(loss) on derivative financial instruments". Two of our fully-consolidated VIEs have executed interest rate cash flow hedges in the form of interest rate swaps. Movements in the fair value of these hedging swaps are reflected in "Accumulated other comprehensive income (loss)."

As of December 31, 2010, the Company and its consolidated subsidiaries, including VIEs, had entered into interest rate swap contracts with a combined outstanding principal amount of $3.97 billion, as compared to $4.12 billion in 2009, at rates between 2.055 % per annum and 4.63 % per annum, as compared to 2.055% and 4.63% in 2009.  The overall effect of these swaps is to fix the interest rate on $3,97 billion of floating rate debt at a weighted average interest rate 3.25 % per annum, as compared to $4.12 billion at 3.26% in 2009. As of December 31, 2010, our net exposure to short term fluctuations in interest rates on our outstanding debt was $2.80 billion, as compared to $0.88 billion in 2009, based on our total net interest bearing debt of $8.48 billion less the $3.97 billion outstanding balance of fixed interest rate swaps, less the $1.72 billion in fixed interest loans.

Also as of December 31, 2010, we had entered into forward exchange contracts to sell approximately $345.5 million, as compared to $504 million in 2009, in exchange for Norwegian Kroner between January 2011 and September 2012, at exchange rates ranging from NOK5.71 to NOK6.41 per US dollar.

In June and July 2008, we entered into Total Return Swap, or TRS, agreements with a total of 4,500,000 of our own common shares as the underlying security.  The agreements were scheduled to expire in December 2008 and the reference prices were in a range of NOK141.2 to NOK157.8 per share. In November 2008, these contracts were terminated and we simultaneously entered into a new TRS agreement with 4,500,000 of our common shares as underlying security, with an agreed reference price of NOK56.70 per share and an expiration date in February 2009.

In February 2009, we entered into a new TRS agreement for the same number of shares with an expiration date in August 2009 and the new reference price was NOK61.3 per share. In August 2009, we entered into a new TRS agreement for the same number of shares with an expiration date in February 2010 and an agreed reference price of NOK98.44 per share. In February 2010, these contracts were settled and we simultaneously entered a new TRS agreement for 3,500,000 of our common shares as underlying security with an agreed reference price of NOK125.70 per share and an expiration date in February 2011. In September 2010, we partly settled the TRS agreement and reduced the number of underlying Seadrill Limited shares by 750,000 shares from 3,500,000 shares to 2,750,000 shares. In January 2011, we made another partial settlement, further reducing the number of underlying Seadrill Limited shares by 750,000 shares from 2,750,000 shares to 2,000,000 shares. In February 2011, these contracts were settled and we simultaneously entered a new TRS agreement for 2,000,000 of our common shares as underlying security with an agreed reference price of NOK202.73 per share and an expiration date in May 2011.

The settlement amount for the TRS transaction will be (A) the market value of the shares at the date of settlement plus all dividends paid by the Company between entering into and settling the contract, less (B) the reference price of the shares agreed at the inception of the contract plus the counterparty's financing costs. Settlement will be either a payment from or to the counterparty, depending on whether (A) is more or less than (B). There is no obligation for us to purchase any shares under the agreement and this arrangement has been recorded as a derivative transaction, with the fair value of the TRS recognized as an asset or liability as appropriate, and changes in fair values recognized in the consolidated statement of operations.

In addition to the above TRS transactions, we may from time to time enter into short-term TRS arrangements relating to securities in other companies. The above TRS indexed to our own common shares was our only TRS agreement as of December 31, 2010.

Equity

As of December 31, 2010, the number of common shares issued, of par value $2.00 each, was 443,308,487 and fully paid share capital amounted to $886 million. We issued no new equity in 2009 and 2008, and the number of common shares issued and fully paid share capital for that two-year period were 399,133,216 and $798 million. Respectively. In 2010, we issued new common shares on three occasions, 655,000 shares related to the exercise of stock options in March, 12,500,000 shares related to a private placement in April, which was completed as part of the Scorpion and West Elara (CJ70) acquisitions, and 31,020,271 reated to the settlement for early conversion of convertible debt in December. The total proceeds from the new shares were approximately $1,065 million including the conversion of the convertible debt.

 
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As of December 31, 2010, we were holding 182,796 of our common shares as treasury shares, as compared to 110,200 in 2009 and 717,800 in 2008, and our net outstanding share capital amounted to $886 million, as compared to $798 million in 2009 and $797 million in 2008. A share repurchase program was approved by the Board in 2007, authorizing us to buy back shares which may be either cancelled, or held as treasury shares to meet our obligations relating to our share option scheme. Under the program we purchased 750,000 shares in the year ended December 31, 2010, no shares were purchased in the year ended December 31, 2009, and 600,000 shares in the year ended December 31, 2008. As of December 31, 2010, we have not cancelled any shares and have used 2,117,200 of those shares to meet our share option scheme obligations. As of April 26, 2011, we had 898,687 treasury shares  following the purchase of a further 700,000 shares.

In May 2005 a general meeting of the Company approved authorizing the Board of Directors to establish and maintain an employee share option scheme, or the Option Scheme, in order to encourage the holding of shares in the Company by individuals including directors, officers and employees of the Company. The Board of Directors has made a number of grants pursuant to rules established to implement the Option Scheme. As of December 31, 2010, we have granted 10,250,667 options, of which 5,512,400 remain outstanding. The fair value cost of options granted is recognized in the statement of operations as an expense, with a corresponding amount credited to additional paid in capital (see Note 28 to the Consolidated Financial Statements). The additional paid-in capital arising from share options was $11 million in the year ended December 31, 2010, as compared to $16 million in 2009 and $15 million in 2008.

As of December 31, 2010, our total additional paid-in capital including contributed surpluses amounted to $3.17 billion, as compared to $2.12 billion in 2009 and $1.99 billion in 2008, of which $2.90 billion arises from shares issued at a premium, with the remaining balance attributable to the Option Scheme, purchases and sales of treasury shares and the equity component of the 3.375% convertible bond.

As of December 31, 2010, we were party to a TRS agreement with 2,750,000 of our common shares as underlying security, whereby we are exposed to movements in the price of our shares (see "Derivatives" above). In January 2011, the TRS agreement was settled and we entered into a new TRS agreement with 2,000,000 of our common shares as underlying security.

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

We do not undertake any significant expenditure on research and development, and have no significant interests in patents or licenses.

D. TREND INFORMATION

The slowdown in the world economy following the credit crisis in the latter part of 2008 had significant adverse impact on the activity levels for most of the offshore drilling industry in 2009. This trend extended into 2010 for some of the rig types and market segments, in spite of the rebound in oil prices, as oil companies retained a cautious attitude towards the longer term sustainability of the price recovery.

The rig type and market segment most  impacted by the drop in activity was jack-up rigs, especially those more suitable for benign environments. From the start of 2010, the overall market environment for jack-up rigs has improved in response to the more favorable market conditions for oil companies. During this period there has been a bifurcation in demand for jack-up rigs between newer rigs and older rigs. At present the utilization rate for jack-up rigs built after 2005 is above 90 percent while the utilization rate for rigs built before 2005 is in the mid 60 percent. The daily rates  for new premium jack-up rigs are around $130,000, depending on the country and region, with the newer rigs commanding a premium in daily rates ranging from $50,000 to $60,000 compared to older rigs.

 
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When the market tumbled in late 2008, a huge number of jack-up rigs were stacked of which the majority were older rigs. At the same time, a significant number of new rigs were under construction. Most of these had been ordered on speculation. As the jack-up rig activity has increased, oil companies have shown a preference for employing the newer premium units as they have been delivered from yards, as opposed to reactivating the older stacked rigs. This shift in demand has been due to the new rigs ability to deliver improved efficiency and increased flexibility, through higher hook-loads, extended cantilever-reach and offline activities. Since October 2010, the trend of replacing older equipment with new equipment has been intensified as firm orders for 37 new jack-up rigs have been placed by established industry players as well as new and smaller entities. Most of the newbuild orders have once again been placed on speculation with no employment contract in place. The new orders have also been incentivized through a reduction in construction cost for newbuilds compared to the peak in newbuild prices seen in 2008 and more favorable payment schedules during construction of the rigs for the drilling contractors. At the same time, the risk to the supply/demand balance caused by the possible reactivation of stacked jack-up rigs appears to be reduced as the amount of investment needed to reactivate many of these units increases over time. The number of new jack-up rigs under construction still corresponds to less than 5 percent of the existing jack-up rig fleet, which has an average age of more than 20 years. As such there seems to be a need for further high-grading of the global jack-up rig fleet and room for the new rigs under construction.

The market for tender rigs was impacted by similar deterioration in market conditions and subsequent employment challenges as for jack-up rigs. There were not many new requests by oil companies for tender rigs in 2009 and the first part of 2010 saw low tendering activity as well with a rebound in activity not taking place until late in the year. As for jack-ups, the recent trend has been that the oil companies have increasingly targeted demand in the direction of newer or modern rigs at the expense of older rigs. This has resulted in oil companies awarding solid long term contracts for new rigs to be constructed while at the same time unemployed rigs have remained stacked and available for hire. Nevertheless, the overall demand for tender rigs is developing positively and the utilization rate for global tender rig fleet that currently stands at 73% is expected to rise further. This could provide opportunities for further organic growth in this market segment.

The market for ultra-deepwater semi-submersible rigs and drillships was less affected by the credit crisis and slow down in the world economy in 2008 due to the limited availability of such rig near term and the continued long-term strategic focus by super majors and national oil companies on exploration and production activities in deeper waters. Although there were fewer fixtures in 2009 compared to 2008, daily rates remained close to $500,000 for units in such waters something that is strong by historical standards. In 2010, we saw daily rates decrease to some $450,000 as the activity level in deeper waters developed more slowly than anticipated. The Macondo incident in late April 2010 and the subsequent moratorium on offshore drilling in the US GOM further stalled such activity. The moratorium not only delayed a large number of deepwater projects in the region but also prompted oil companies to assert rights of termination in certain cases forcing relocation of deepwater drilling rigs to other regions. Although the moratorium was lifted in October 2010, delays in the approval process of drilling permits, increased regulatory requirements and perceived increase in legal risk of operating in the US GOM has hampered the activity for deepwater drilling in the United States. However, the Macondo incident has increased oil companies focus on new, modern and technically superior equipment and thus reducing their interest in using older moored and upgraded deepwater vessels with weight and capacity restrictions. This has resulted in the market absorbing new dynamically positioned deepwater rigs, originally ordered without a drilling contract in place at the time of the order, as construction is completed at yards.

There has been an increase in new countries, as well as regions, of interest for new deepwater exploration activities. These include countries in West Africa, East Africa, and Southeast Asia. New frontier markets are also emerging such as Greenland and Australia. At the same time and in response to the favorable outlook for oil prices and deepwater drilling, established players have taken advantage of the significant reduction in newbuild prices compared to the highs in 2008 and, since October 2010, orders have been placed for 31 new dynamic deepwater units, mainly on speculation. The deliveries of these units are scheduled to be delivered in 2013 and 2014 and are as such not expected a have any near term effect of significance on the market balance.

Strong growth in development drilling activities in Brazil and West Africa is expected to drive demand in the upcoming years. In the short term, more rigs moving into these regions and a return of deepwater drilling activities in the US GOM could have a positive impact on demand and daily rates. There is also likely to be a catch up effect in the US GOM related to the deepwater drilling activity that was postponed due to the moratorium and halt in issuance of drilling permits. The number of market inquiries for ultra-deepwater rigs has improved significantly over the last six and at present, daily rates for new deepwater drilling units range from $425,000 to $500,000 depending upon country, region and whether the rig is considered new out of the yard or has been in operation , the latter commanding a premium.

 
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E. OFF BALANCE SHEET ARRANGEMENTS

As described above, we are party to a TRS agreement that has our own common shares as underlying security. The fair value of this position as of December 31, 2010 and 2009, respectively, is reflected in the Consolidated Financial Statements included in Item 18 of this Annual Report.

F. CONTRACTUAL OBLIGATIONS

At December 31, 2010, we had the following contractual obligations and commitments:
 
   
Payment due by period
 
(In millions of US dollar)
 
Less than
1 year
   
1 – 3
years
   
3 – 5
years
   
After
5 years
   
Total
 
3.625% convertible bonds due 2012 (1)
   
-
     
750
     
-
     
-
     
750
 
4.875% convertible bonds due 2014 (2)
   
7
     
-
     
-
     
-
     
7
 
3.375% convertible bonds due 2017 (3)
   
-
     
-
     
-
     
650
     
650
 
Interest bearing debt
   
981
     
5,173
     
1,658
     
58
     
7,870
 
Related party interest bearing debt
   
-
     
-
     
-
     
435
     
435
 
Total debt repayments (3)
   
988
     
5,923
     
1,658
     
1,143
     
9,712
 
Total interest payments (4)
   
359