d1285852_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, 2011

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
 

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, 2011, there were 467,772,174 shares, par value $2.00 per share, of the Registrant's common stock outstanding.
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

[ X  ] Yes
[   ] No
 
 
If this report is an annual report or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

[   ] Yes
[ X ] No
 
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

[ X ] Yes
[   ] No
 
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months

[  X ] Yes
[   ] No

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  [X ]
Accelerated filer  [   ]

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

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

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

[   ]  Yes
[ X ]  No
 
 

 
 
 


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, daily rates, 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.  We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward looking statement.
 


 
 
(i)
 

 
 
 

TABLE OF CONTENTS
   
Page
PART 1
 
    
ITEM 1.
IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
1
ITEM 2.
OFFER STATISTICS AND EXPECTED TIMETABLE
1
ITEM 3
KEY INFORMATION
1
ITEM 4.
INFORMATION ON THE COMPANY
17
ITEM 4A
UNRESOLVED STAFF COMMENTS
28
ITEM 5.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS
29
ITEM 6.
DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
48
ITEM 7.
MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
53
ITEM 8
FINANCIAL INFORMATION
55
ITEM 9.
THE OFFER AND LISTING
56
ITEM 10.
ADDITIONAL INFORMATION
57
ITEM 11.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
68
ITEM 12.
DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
71
 
PART II
ITEM 13.
DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
71
ITEM 14.
MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
71
ITEM 15
CONTROLS AND PROCEDURES
72
ITEM 16.
RESERVED
72
ITEM 16A.
AUDIT COMMITTEE FINANCIAL EXPERT
73
ITEM 16B.
CODE OF ETHICS
73
ITEM 16C.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
73
ITEM 16D.
EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
73
ITEM 16E.
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
74
ITEM 16F.
CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT
74
ITEM 16G.
CORPORATE GOVERNANCE
74
ITEM 16H.
MINE SAFETY DISCLOSURE
74
     
PART III
 
    
ITEM 17.
FINANCIAL STATEMENTS
75
ITEM 18.
FINANCIAL STATEMENTS
75
ITEM 19.
EXHIBITS
75



 
 
(ii)
 


PART 1.
 
Throughout 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 "US$" and "$" in this report are to, and amounts are represented in, US dollars.
 
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, 2011, 2010 and 2009 and the selected balance sheet data of the Company with respect to the fiscal years ended December 31, 2011 and 2010 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, 2008 and 2007 and the selected balance sheet data with respect to the fiscal years ended December 31, 2009, 2008 and 2007 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 dollars. We refer you to the Notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are presented.
 
 
 
Year ended December 31,
 
 
 
2011
 
2010
 
2009
 
2008
 
2007
 
 
 
 
 
(In millions of US dollars except common share and per share data)
 
 
 
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
Total operating revenues
 
 
4,192
 
 
 
4,041
 
 
 
3,254
  
 
 
2,106
 
 
 
1,552
 
Net operating income
 
 
1,774
 
 
 
1,625
 
 
 
1,372
  
 
 
649
 
 
 
489
 
Net income (loss) (1)
 
 
1,482
 
 
 
1,172
 
 
 
1,353
  
 
 
(123
)
 
 
515
 
Earnings per share, basic
 
$
3.05
 
 
$
2.73
 
 
$
3.16
  
 
$
(0.41
)
 
$
1.28
 
Earnings per share, diluted
 
$
2.96
 
 
$
2.73
 
 
$
3.00
  
 
$
(0.41
)
 
$
1.20
 
Dividends paid (2)
 
 
1,440
 
 
 
990
 
 
 
199
  
 
 
688
 
 
 
-
 
Dividends paid per share
 
$
3.135
 
 
$
2.41
 
 
$
0.50
  
 
 
1.75
 
 
 
-
 
 
(1) In 2008, other financial items included an impairment loss of $615 million related to our investments in Pride International Inc., or Pride, Scorpion Offshore Limited, or Scorpion, and SapuraCrest Bhd, or SapuraCrest.
 
(2) For the year ended December 31, 2011, North Atlantic Drilling Limited, or NADL, a 73% owned subsidiary, paid $17 million to non-controlling interests.
 
 
 
1
 
 
 
   
Year ended December 31,
  
   
2011
    
2010
    
2009
    
2008
    
2007
  
         
(In millions of US dollars except common
share and per share data)
        
Balance Sheet Data (at end of period):
                              
Cash and cash equivalents
    
483
      
755
      
460
      
376
      
997
  
Drilling units
 
 
11,223
 
 
 
10,795
 
 
 
7,515
 
 
 
4,645
  
 
 
2,452
 
Newbuildings
 
 
2,531
 
 
 
1,247
 
 
 
1,431
 
 
 
3,661
  
 
 
3,340
 
Investment in associated companies
 
 
721
 
 
 
205
 
 
 
321
 
 
 
240
  
 
 
176
 
Goodwill
 
 
1,320
 
 
 
1,676
 
 
 
1,596
 
 
 
1,547
  
 
 
1,510
 
Total assets
 
 
18,304
 
 
 
17,497
 
 
 
13,831
 
 
 
12,305
  
 
 
9,293
 
Interest bearing debt
(including current portion)
 
 
9,993
 
 
 
9,157
 
 
 
7,396
 
 
 
7,437
  
 
 
4,601
 
Share capital
 
 
935
 
 
 
886
 
 
 
798
 
 
 
797
  
 
 
797
 
Equity
 
 
6,302
 
 
 
5,937
 
 
 
4,813
 
 
 
3,222
  
 
 
3,728
 
Common shares outstanding, in millions
 
 
467.8
 
 
 
443.1
 
 
 
399.0
 
 
 
398.4
  
 
 
398.5
 
Weighted average common shares outstanding
 
 
458.6
 
 
 
409.2
 
 
 
398.5
 
 
 
398.3
  
 
 
392.8
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
Other Financial Data:
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
Net cash provided by operating activities
 
 
1,816
 
 
 
1,300
 
 
 
1,452
 
 
 
401
  
 
 
486
 
Net cash used in investing
activities
 
 
(2,633
)
 
 
(2,297
)
 
 
(924
)
 
 
(3,847)
  
 
 
(1,868
)
Net cash provided by/(used in) financing activities
 
 
538
 
 
 
1,293
  
 
 
(453
)
 
 
(2,826)
  
 
 
2,168
 
Capital expenditure
 
 
(2,543
)
 
 
(2,368
)
 
 
(1,369
)
 
 
(2,768)
  
 
 
(1,738
)
 
 
B.
CAPITALIZATION AND INDEBTEDNESS
 
Not applicable.
 
C.
REASONS FOR THE OFFER AND USE OF PROCEEDS
 
Not applicable.
 
D.
RISK FACTORS
 
Our assets are primarily engaged in offshore contract drilling for the oil and gas industry in benign and harsh environments worldwide, including ultra-deepwater environments. The following summarizes risks that may materially affect our business, financial condition or results of operations. Unless otherwise indicated in this Annual Report on Form 20-F for the year ended December 31, 2011, all information concerning our business and our assets is as of April 24 , 2012.
 
Risks Relating to Our Industry
 
Our business in the offshore drilling sector depends on the level of activity in the offshore oil and gas industry, which is significantly affected by, among other things, volatile oil and gas prices, and may be materially and adversely affected by a decline in the offshore oil and gas industry.
 
The offshore contract drilling industry is cyclical and volatile. Our business in the offshore drilling sector depends on the level of activity in oil and gas exploration, development and production in offshore areas worldwide. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments affect customers' drilling programs. Oil and gas prices and market expectations of potential changes in these prices also significantly affect this level of activity and demand for drilling units.
 
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;
 

 
2
 

 
·
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 levels and pricing;
 
 
·
the level of production in non-OPEC countries;
 
 
·
government regulations;
 
 
·
local and international political, economic and weather conditions;
 
 
·
domestic and foreign tax policies;
 
 
·
development and exploitation of alternative fuels;
 
 
·
the policies of various governments regarding exploration and development of their oil and gas reserves; and
 
 
·
the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East or other geographic areas or further acts of terrorism in the United States, or elsewhere.
 
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 cash flow from such activities and are therefore sensitive to changes in energy prices. These changes in commodity prices can have a dramatic effect on rig demand, and periods of low demand can cause excess rig supply and intensify the competition in the industry which often results in drilling units, particularly older and lower technical 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 materially harm 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 units;
 
 
·
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.
 
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. 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.
 

 
3
 
 
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 daily rates contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurances that these 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 (except as described below with respect to drilling units and equipment in the U.S. GOM). 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 currently maintain a deductible per occurrence of $5 million for all of our fleet, except for tender barges, for which it is $1 millon. 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 $25,000 deductible per occurrence on personal injury liability for crew claims as well as non-crew claims and per occurrence on third-party property damage, except for our drilling units operating in the U.S. GOM where the deductible is $500,000 per occurrence.
 
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 U.S. 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 U.S. 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 the date of this Annual Report, all of the drilling units that we owned or operated were covered by existing insurance policies.
 
An over-supply of drilling units may lead to a reduction in daily rates and therefore may materially impact our profitability in our offshore drilling segment.
 
During the recent period of high utilization and high daily rates, industry participants have increased the supply of drilling units by ordering construction of new drilling units. Historically, this has resulted in an over-supply of drilling units and has caused a subsequent decline in utilization and daily rates when the drilling units have entered the market, sometimes for extended periods of time until the new units have been absorbed into the active fleet. According to industry sources, the worldwide fleet of ultra-deepwater drilling units consisted of 118 units, comprised of 61 semi-submersible rigs and 57 drillships as of April 24, 2012. An additional 15 semi-submersible rigs and 69 drillships are under construction or on order, which would bring the total fleet to 202 units. A relatively large number of the drilling units currently under construction have not been contracted for future work, which may intensify price competition as scheduled delivery dates occur and lead to a reduction in daily rates as the active fleet grows. Lower utilization and daily rates could adversely affect our revenues and profitability. Prolonged periods of low utilization and daily rates could also result in the recognition of impairment charges on our drilling units if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these drilling units may not be recoverable.
 
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:
 

 
4
 
 
 
·
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 daily rates;
 
 
·
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.
 
Consolidation of suppliers may increase the cost of obtaining supplies, which may have a material adverse effect on our results of operations and financial condition.
 
We rely on certain third parties to provide supplies and services necessary for our offshore drilling operations, including but not limited to drilling equipment suppliers, catering and machinery suppliers. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing key supplies. Such consolidation, combined with a high volume of drilling units under construction, may result in a shortage of supplies and services thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time. These cost increases or delays could have a material adverse effect on our results of operations and result in rig downtime, and delays in the repair and maintenance of our drilling rigs.
 
Our international operations in the offshore drilling sector involve additional risks, which could adversely affect our business.
 
We operate in various regions throughout the world. As a result of our international operations, we may be exposed to political and other uncertainties, including risks of:
 
 
·
terrorist acts, armed hostilities, war and civil disturbances;
 
 
·
acts of piracy, which have historically affected ocean-going vessels, trading in regions of the world such as the South China Sea and in the Gulf of Aden off the coast of Somalia and which have increased significantly in frequency since 2008, particularly in the Gulf of Aden and off the west coast of Africa;
 
 
·
significant governmental influence over many aspects of local economies;
 
 
·
seizure, nationalization or expropriation of property or equipment;
 
 
·
repudiation, nullification, modification or renegotiation of contracts;
 
 
·
limitations on insurance coverage, such as war risk coverage, in certain areas;
 
 
·
political unrest;
 
 
·
foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
 
 
·
the inability to repatriate income or capital;
 
 
·
complications associated with repairing and replacing equipment in remote locations;
 
 
·
import-export quotas, wage and price controls, imposition of trade barriers;
 

 
5
 

 
·
regulatory or financial requirements to comply with foreign bureaucratic actions;
 
 
·
changing taxation policies, including confiscatory taxation;
 
 
·
other forms of government regulation and economic conditions that are beyond our control; and
 
 
·
governmental corruption.
 
In addition, international contract drilling operations are subject to various laws and regulations of the countries in which we operate, including laws and regulations relating to:
 
 
·
the equipping and operation of drilling units;
 
 
·
repatriation of foreign earnings;
 
 
·
oil and gas exploration and development;
 
 
·
taxation of offshore earnings and the earnings of expatriate personnel; and
 
 
·
use and compensation of local employees and suppliers by foreign contractors.
 
Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling rigs owned by their own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets.
 
If our drilling units are located in countries that are subject to economic sanctions or other operating 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 or CISADA, which expanded the scope of the former Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to non-U.S. companies, such as 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.  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, such as Cuba, Iran, Sudan, and Syria. 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. While 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.
 
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 Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, formerly the Minerals Management Service of the U.S. Department of the Interior, effective October 1, 2011, reorganized into two new organizations, the Bureau of Ocean Energy Management, or BOEM, and the Bureau of Safety and Environmental Enforcement, or BSEE, and issued guidelines for tie-downs on drilling units and permanent equipment and facilities attached to outer continental shelf production platforms, and moored drilling unit fitness 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 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 U.S. GOM region of the Outer Continental Shelf. BOEM and BSEE may issue similar guidelines for future hurricane seasons and may take other steps that could increase the cost of operations or reduce the area of operations for our ultra-deepwater drilling units, thereby reducing their marketability. Implementation of new guidelines or regulations that may apply to ultra-deepwater drilling units may subject us to increased costs and limit the operational capabilities of our drilling units, although such risks to the extent possible should rest with our clients.
 

 
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We currently do not have any jack-up rigs or moored drilling units operating in the U.S. GOM. However, we do have two ultra-deepwater semi-submersible drilling rigs contracted for operations in the U.S. GOM that are 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 operating 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 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.
 
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 US 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.
 
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.

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.

 
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We are subject to complex laws and regulations, including environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
 
Our operations are subject to numerous laws and regulations in the form of international conventions and treaties, national, state and local laws and national and international regulations in force in the jurisdictions in which our vessels operate or are registered, which can significantly affect the ownership and operation of our drilling units. These requirements include, but are not limited to, the International Convention for the Prevention of Pollution from Ships, or MARPOL, the International Convention on Civil Liability for Oil Pollution Damage of 1969, generally referred to as CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or Bunker Convention, the U.S. Oil Pollution Act of 1990, 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. Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or operational changes and may affect the resale value or useful lifetime of our drilling units. We may also incur additional costs in order to comply with other existing and future regulatory obligations, including, but not limited to, costs relating to air emissions, including greenhouse gases, the management of ballast waters, maintenance and inspection, development and implementation of emergency procedures and insurance coverage or other financial assurance of our ability to address pollution incidents. These costs could have a material adverse effect on our business, results of operations, cash flows and financial condition. A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations. Environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under OPA, for example, owners, operators and bareboat-charterers are jointly and severally strictly liable for the discharge of oil in U.S. waters, including the 200-nautical mile exclusive economic zone around the United States. An oil spill could result in significant liability, including fines, penalties and criminal liability and remediation costs for natural resource damages under other international and U.S. federal, state and local laws, as well as third-party damages. We are required to satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents and our insurance may not be sufficient to cover all such risks. As a result, claims against us could result in a material adverse effect on our business, results of operations, cash flows and financial condition.
 
Although our drilling units are separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under OPA or other environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
 
Our drilling units could cause the release of oil or hazardous substances, especially as our drilling units age. Any releases may be large in quantity, above our permitted limits or occur in protected or sensitive areas where public interest groups or governmental authorities have special interests. Any releases of oil or hazardous substances could result in fines and other costs to us, such as costs to upgrade our drilling rigs, clean up the releases, and comply with more stringent requirements in our discharge permits. Moreover, these releases may result in our customers or governmental authorities suspending or terminating our operations in the affected area, which could have a material adverse effect on our business, results of operation and financial condition.
 
If we are able to obtain from our customers some degree of contractual indemnification against pollution and environmental damages in our contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases, and we may not be able to obtain such indemnification agreements in the future.
 
Our insurance coverage may not be available in the future, or we may not obtain certain insurance coverage. Even if insurance is available and we have obtained the coverage, it may not be adequate to cover our liabilities or our insurance underwriters may be unable to pay compensation if a significant claim should occur. Any of these scenarios could have a material adverse effect on our business, operating results and financial condition.
 
Climate change and regulation of greenhouse gases could have a negative impact on our business.
 
Due to concern over the risk of climate change, a number of countries and the United Nations' International Maritime Organization, or IMO, have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions. However, in July 2011 the IMO's Maritime Environment Protection Committee, or MEPC, adopted two new sets of mandatory requirements to address greenhouse gas emissions from ships that will enter into force in January 2013. Currently operating ships will be required to develop Ship Energy Efficiency Management Plans, and minimum energy efficiency levels per capacity mile will apply to new ships. These requirements could cause us to incur additional compliance costs. The IMO is also considering the development of market-based mechanisms to reduce greenhouse gas emissions from ships. The European Union has indicated that it intends to propose an expansion of the existing European Union emissions trading scheme to include emissions of greenhouse gases from marine vessels, including drilling units, and in January 2012, the European Commission launched a public consultation on possible measures to reduce greenhouse gas emissions from ships. In the United States, the EPA has issued a finding that greenhouse gases endanger the public health and safety and has adopted regulations to limit greenhouse gas emissions from certain mobile sources and large stationary sources. Although the mobile source emissions regulations do not apply to greenhouse gas emissions from drilling units, such regulation of drilling units is foreseeable, and the EPA has in recent years received petitions from the California Attorney General and various environmental groups seeking such regulation.

 
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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.

Additionally, adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also adversely affect demand for our services. For example, increased regulation of greenhouse gases or other concerns relating to climate change may reduce the demand for oil and gas in the future or create greater incentives for 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.

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 U.S. GOM and subsequently implemented Notices to Lessees 2010-N05 and 2010 N-06, providing enhanced safety requirements applicable to all drilling activity in the U.S. 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 the requirements set forth in Notices to Lessees 2010-N05 and 2010-N06. Additionally, all drilling in the U.S. GOM must comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management Systems, 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 BSEE 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 BSEE resumes its regular permitting of those activities. The current and future regulatory environment in the U.S. GOM could impact the demand for drilling units in the U.S. GOM in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the U.S. GOM. It is possible that short-term potential migration of rigs from the U.S. 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 U.S. 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 U.S. GOM. As such, our cash flow and financial position could be adversely affected if our two ultra-deepwater drilling rigs in the U.S. GOM were subject to the risks mentioned above.

We cannot guarantee that the use of our drilling units will not infringe the intellectual property rights of others.
 
The majority of the intellectual property rights relating to our drilling units and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over 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. In addition, our competitors may assert claims for infringement of intellectual property rights related to certain equipment on our drilling units and we may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of technology disputes involving our suppliers or competitors could adversely affect our financial results and operations. We have provisions in some of our supply contracts to provide indemnity from the supplier against intellectual property lawsuits. However, we cannot be assured that these suppliers will be willing or financially able to honor their indemnity obligations, or guarantee that the indemnities will fully protect us from the adverse consequences of such technology disputes. We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but we cannot provide assurance that these provisions will fully protect us from the adverse consequences of such technology disputes.
 

 
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We may not be able to keep pace with the continual and rapid technological developments that characterize the market for our services, and our failure to do so may result in our loss of market share.
 
The market for our services is characterized by continual and rapid technological developments that have resulted in, and will likely continue to result in, substantial improvements in equipment functions and performance. As a result, our future success and profitability will be dependent in part upon our ability to keep pace with technological developments. If we are not successful in acquiring new equipment or upgrading our existing equipment in a timely and cost-effective manner in response to technological developments or changes in standards in our industry, we could lose business and profits. 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.
 
Failure to comply with the U.S. Foreign Corrupt Practices Act could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.
 
We currently operate, and historically have operated, our drilling units in a number of countries throughout the world, including some with developing economies. Also, the existence of state or government-owned shipbuilding enterprises puts us in contact with persons who may be considered "foreign officials" under the U.S. Foreign Corrupt Practices Act of 1977, or the FCPA. We are committed to doing business in accordance with applicable anti-corruption laws and have adopted a code of business conduct and ethics which is consistent and in full compliance with the FCPA. We are subject, however, to the risk that we, our affiliated entities or our or their respective officers, directors, employees and agents may take actions determined to be in violation of such anti-corruption laws, including the FCPA. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
 
Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
 
Acts of terrorism, piracy and political and social unrest, brought about by world political events or otherwise, have caused instability in the world's financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. Our drilling operations could also be targeted by acts of piracy. In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower daily rates. Insurance premiums could increase and coverage may be unavailable in the future. U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future. Increased insurance costs or increased cost of compliance with applicable regulations may have a material adverse effect on our results of operations.
 
Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.
 
The shipment of goods, services and technology across international borders subjects our offshore drilling segment to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.
 
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
 
We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.
 
We are currently involved in various litigation matters, 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. If we are involved in any future litigation, or if our positions concerning current disputes are found to be incorrect, this 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 asserting our claims or defending such lawsuits, and the diversion of management's attention to these matters.
 

 
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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, 2011, we had $10 billion in principal amount of debt, representing approximately 65% of our total market 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, may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities, and may limit our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes. Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our newbuilding projects, will be dependent upon our future performance, which will be subject to 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.
 
We may be unable to comply with covenants in our credit facilities or any future financial obligations that impose operating and financial restrictions on us.
 
Our credit facilities impose, and future financial obligations may impose, operating and financial restrictions on us. These restrictions may prohibit or otherwise limit our ability to, among other things:
 
 
·
enter into other financing arrangements;
 
 
·
incur additional indebtedness;
 
 
·
create or permit liens on our assets;
 
 
·
sell our drilling units or the shares of our subsidiaries;
 
 
·
make investments;
 
 
·
change the general nature of our business;
 
 
·
pay dividends to our shareholders;
 
 
·
change the management and/or ownership of the drilling units;
 
 
·
make capital expenditures; and
 
 
·
compete effectively to the extent our competitors are subject to less onerous restrictions.
 
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. We pledge our drilling units as security for our indebtedness.  If our lenders were to foreclose their liens on our drilling units in the event of a default, this may impair our ability to continue our operations. As of December 31, 2011, we had $9.0 billion of indebtedness secured by, among other things, liens on our drilling units.  In addition, all of our loan agreements contain cross-default provisions, meaning that if we are in default under one of our loan agreements, amounts outstanding under our other loan agreements may also be 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.
 

 
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We rely on a small number of customers.
 
Our contract drilling business is subject to the risks associated with having a limited number of customers for our services. As of December 31, 2011, our five largest customers accounted for approximately 67% of our future contracted revenues, or 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 daily rates.
 
Newbuilding projects and surveys are subject to risks that could cause delays or cost overruns.
 
As of December 31, 2011, we had an outstanding newbuilding order book with various yards for an additional 13 drilling units with corresponding contractual yard commitments totaling $2.6 billion. Since then, we have taken delivery of one ultra-deepwater unit and ordered three new ultra-deepwater units and one tender rig, increasing our contracted yard commitments to $4.3 billion (including $0.3 billion paid in yard installments since December 31, 2011). These construction projects are subject to risks of delay or cost overruns inherent in any large construction project from numerous factors, including shortages of equipment, materials or skilled labor, unscheduled delays in the delivery of ordered materials and equipment or shipyard construction, 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 daily rates may not permit us fully to recoup our costs in the event of a rise in our expenses.
 
The majority of our drilling units have long-term contracts. The average remaining contract length as of December 31, 2011, was 28 months for our floaters, 24 months for our tender rigs and 14 months for our jack-up rigs. The majority of these contracts have daily rates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from term contracts, most of our long-term contracts include escalation provisions. These provisions allow us to adjust the daily rates 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 escalation provisions.
 

 
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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 daily rates, 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 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.
 
As of December 31, 2011, we have 12 contracts that expire in 2012, nine contracts that expire in 2013 and seven contracts that expire in 2014. 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 daily rates substantially below the existing daily rates 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, 2011, the future contracted revenue for our fleet of drilling units, or contract drilling backlog, was approximately $12.6 billion. 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 daily rates. 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.
 
An economic downturn could have a material adverse effect on our revenue, profitability and financial position.
 
We depend on our customers' willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and demand for energy, including oil and gas. The world economy is currently facing a number of challenges. This includes uncertainty to the continuing discussions in the United States regarding the federal debt ceiling. In addition, turmoil and hostilities in the Middle East, North Africa and other geographic areas and countries are adding to the overall risk picture. An extended period of adverse development in the outlook for the world economy could reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our results of operations and cash flows beyond what might be offset by the simultaneous impact of possibly higher oil and gas prices. 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 $125 per barrel (Brent Oil Price) as of April 24, 2012.
 

 
13
 

Failure to obtain or retain highly skilled personnel could adversely affect our operations.
 
We require highly skilled personnel to operate and provide technical services and support for our business. Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased. The number of rigs in operation is continuing to grow as new units ordered during the period from 2005 to 2008 are being delivered. Furthermore, additional rigs ordered from September 2010 to date are expected to increase the future demand for offshore drilling crews. In some regions such as Brazil, limited availability of qualified personnel in combination with local regulations focusing on crew composition, are expected to further increase demand for qualified offshore drilling crews, which may increase our costs. A continued expansion of the rig fleet, improved demand for drilling services in general, coupled with shortages of qualified personnel could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for 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. 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.
 
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 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 could present a number of risks, including the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets, the risk of failing to successfully and timely integrate the operations or management of any acquired businesses or assets and the risk of diverting management's attention from existing operations or other priorities. If we fail to consummate and integrate our acquisitions in a timely and cost-effective manner, our financial condition and results of operations could be adversely affected.
 
We may not be able to raise equity or debt financing sufficient to pay the cost of all of our newbuilding drilling units, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Our business is capital intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to execute our growth strategy and to fund our capital expenditures. Borrowings under our current credit facilities, which are subject to certain conditions, and available cash on hand are not sufficient to pay the remaining installments related to our contracted yard commitments of all of our newbuilding drilling units, which is currently $4.3 billion.  If we are not able to borrow additional funds, raise other capital or utilize available cash on hand, we may not be able to acquire these drilling units, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.  If for any reason we fail to make a payment when due, which may result in a default under our newbuilding contracts, or otherwise fail to take delivery of our newbuild units, we would be prevented from realizing potential revenues from these projects, we could also lose all or a portion of our yard payments that were paid by us, which as of April 24, 2012, amounted to $0.9 billion and we could be liable for penalties and damages under such contracts.
 

 
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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, 2011, our total floating rate debt amounted to $8.7 billion of which we had entered into interest rate swap agreements to fix the interest rate for a principal amount of $5.7 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 adverse to our structure; or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.
 
United States tax authorities may treat us as a "passive foreign investment company" for United States federal income tax purposes, which may have adverse tax consequences to U.S. shareholders.
 
A foreign corporation will be treated as a "passive foreign investment company," or PFIC, for U.S. federal income tax purposes if either (1) at least 75% of its gross income for any taxable year consists of certain types of "passive income" or (2) at least 50% of the average value of the corporation's assets produce or are held for the production of those types of "passive income." For purposes of these tests, "passive income" includes dividends, interest, and gains from the sale or exchange of investment property and rents and royalties other than rents and royalties which are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute "passive income." U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC and the gain, if any, they derive from the sale or other disposition of their shares in the PFIC.
 
We presently believe that we are not a PFIC and do not anticipate becoming a PFIC. This is, however, a factual determination made on an annual basis and is subject to change. Therefore, we can give you no assurance as to our PFIC status.
 
However, no assurance can be given that the U.S. Internal Revenue Service, or IRS, or a court of law will accept our position, and there is a risk that the IRS or a court of law could determine that we or one of our subsidiaries is a PFIC.  Moreover, no assurance can be given that we or one of our subsidiaries would not constitute a PFIC for any future taxable year if there were to be changes in the nature and extent of its operations.
 

 
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If the IRS were to find that we are or have been a PFIC for any taxable year, U.S. persons who receive common shares on a conversion of the bonds will face adverse U.S. tax consequences.  Under the PFIC rules, unless those shareholders make an election available under the Code (which election could itself have adverse consequences for such shareholders, as discussed below under Item 10.E "Additional Information – Taxation"), such shareholders would be liable to pay U.S. federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of the common shares, as if the excess distribution or gain had been recognized ratably over the shareholder's holding period of the common shares. In the event that our shareholders face adverse U.S. tax consequences as a result of investing in shares of our common stock, this could adversely affect our ability to raise additional capital through the equity markets.  See  Item 10.E "Additional Information – Taxation" for a more comprehensive discussion of the U.S. federal income tax consequences to U.S. shareholders if we are treated as a PFIC.
 
Investors are encouraged to consult their own tax advisors concerning the overall tax consequences of the ownership of the common shares arising in an investor's particular situation under U.S. federal, state, local or foreign law.
 
Risks Relating to Our Common Shares
 
Because we are a foreign corporation, you may not have the same rights that a shareholder in a U.S. corporation may have.
 
We are a Bermuda exempted company limited by shares. Our memorandum of association and bye-laws and the Companies Act, 1981 of Bermuda, 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.
 
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 7.8% of our minority-owned subsidiary Archer Limited (OSE:NO). Our Vice-President and director Mr. Tor Olav Trøim is also a director of Archer Limited and Golar LNG Limited (NASDAQ GS: GLNG), a company affiliated with us. One of our other directors, Kate Blankenship, is also a director of Frontline, NADL, Ship Finance, Golar LNG Limited and Archer Limited.  Another of our directors, Kathrine Fredriksen, the daughter of Mr. John Fredriksen, is also a director of Golar LNG Limited. Mr. Fredriksen, Mr. Trøim, Mrs. Blankenship and Ms. Fredriksen owe fiduciary duties to each of Seadrill, Frontline, Ship Finance, Archer Limited, and Golar LNG, as applicable, 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, Archer Limited, Ship Finance, or Golar LNG than they do for us. We cannot assure you that any of these conflicts of interest will be resolved in our favor.
 

 
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ITEM 4.                     INFORMATION ON THE COMPANY
 
A.
HISTORY AND DEVELOPMENT OF THE COMPANY
 
The Company
 
Seadrill Limited was incorporated in Bermuda under the Companies Act on May 10, 2005 as an exempted company limited by shares.  Our shares of common stock have been listed under the symbol "SDRL" on the Oslo Stock Exchange 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 for operations in shallow, mid and deepwater areas, and in benign and harsh environments.  Through a number of acquisitions of other companies and contracts for newbuildings, we have developed into one of the world's largest international offshore drilling contractors. We own and operate a fleet of 59 offshore drilling units, which consist of 13 semi-submersible rigs, nine drillships, 21 jack-up rigs and 16 tender rigs, including 16 units currently under construction, which consists of five drillships, one semi-submersible rig,  five jack-up rigs and five tender rigs. The delivery schedule for our newbuildings under construction commences during the fourth quarter 2012 and ends in the first quarter 2015, with the majority of deliveries scheduled to be completed in 2013. In addition, (i) we operate five tender rigs in association with Varia Perdana and (ii) we provide the construction supervision, project management, and commercial management to all three newbuilding jack-up rigs of AOD.
 
Our subsidiary, North Atlantic Drilling Limited, or NADL, focuses entirely on harsh environment operations.  NADL acquired from Seadrill Limited five harsh environment rigs and one construction contract for a semi-submersible. NADL currently has six drilling units in operation, one jack-up rig and one semi-submersible rig under construction. We currently own 73% of NADL's outstanding shares and the balance of the shares are held by institutional and other investors.
 
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 or deliver various oil services. These investments provide us with additional exposure to market segments in which we operate or other oil services. These include:
 
 
·
a 39.9% equity interest in the Archer Limited (OSE:ARCHER), a Bermuda oil service company;
 
 
·
a 23.6% equity interest in SapuraCrest, a Malaysian oil services company;
 
 
·
a 49% equity interest in Varia Perdana Sdn Bhd, or Varia Perdana, a Malaysian company;
 
 
·
a 33.75% equity interest in Asia Offshore Drilling Ltd. (OSE: AOD), a Bermuda offshore drilling company; and
 
 
·
a 28.5% equity interest in Sevan Drilling ASA (OSE: SEVDR), a Norwegian offshore drilling company.
 
Management of the 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.
 
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 portion of Seatankers' interest in the assets described 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.
 

 
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Since the acquisition of our initial fleet described above, we have entered into numerous contracts for newbuildings, secondhand units and other companies engaged in offshore drilling and related industries. As a result, our operations have expanded considerably and we currently have approximately 7,600 skilled employees and a fleet of 59 units consisting of 13 semi-submersible rigs, nine drillships, 21 jack-up rigs and 16 tender rigs, including 16 units currently under construction.
 
Please see Item 4D. "Information on the Company — Property, Plant and Equipment", which includes a table of all of the drilling units that we own or have contracted for delivery.
 
Acquisitions, Disposals, and Other Transactions For the Period From January 1, 2011 through and including December 31, 2011
 
 
·
In February 2011, we ordered two tender rigs from the COSCO shipyard in China.  The estimated aggregate project costs, including project management, drilling and handling tools, spares, and capitalized interest, for the two rigs is approximately $225 million. The deliveries of the rigs are scheduled for the first and second quarter 2013, respectively.  In April 2011, we exercised an option to build a third identical tender rig at the same yard for a total project cost of $115 million with a delivery in the first quarter 2013.
 
 
·
In April 2011, we exercised an option to build another 12,000ft dual derrick ultra-deepwater drillship at the Samsung Heavy Industries Co. Ltd. in South Korea, or Samsung. The estimated total project cost for the new drillship is $600 million, including project management, drilling and handling tools, spares, capitalized interest and operations preparation expenses, and delivery is scheduled for the third quarter 2013.  The drillship is identical to the two drillships we ordered from Samsung in November 2010.
 
 
·
In April 2011, we placed an order for a new harsh environment jack-up rig to be named West Linus. The rig will be built at the Jurong yard in Singapore and has a total project cost estimated at $530 million including project management, drilling and handling tools, spares, capitalized interest and operations preparation expenses. Completion of construction is scheduled at the end of the third quarter 2013 after which the rig will be mobilized to Norway in order to commence operations under a five-year contract with ConocoPhillips.
 
 
·
In June 2011, we ordered an additional semi-tender rig from Keppel FELS in Singapore. Total project price for this new rig, including project management, the drilling equipment set, spares, capitalized interest and operations preparation is estimated at $200 million and delivery is scheduled for the second quarter 2013. The rig is based on a similar design and specification as the semi-tender West Jaya, which was delivered from Keppel FELS in 2011.
 
Disposals
 
 
·
In April 2011, we entered into an agreement to sell the newly built jack-up drilling rig West Juno to an unrelated third party incorporated in the U.K. for a total consideration of $248.5 million.  Seadrill recorded a gain on sale of approximately $22 million on closing in July.
 
 
·
In May 2011, we retired the tender barge, T8 and recognized a charge of $13 million through our income statement.
 
 
·
In June 2011, we entered into an agreement to sell the 1984-built jack-up rig West Janus for a total consideration of $73 million. The agreement has been re-negotiated and the closing of the transaction is postponed and is now scheduled for completion in the fourth quarter of 2012.
 
Other transactions
 
In addition, for the period from January 1, 2011 through and until December 31, 2011, we acquired investments in entities involved in offshore drilling and oil services:
 
 
·
In February 2011, Seawell merged with Allis-Chalmers Energy Inc. As a result, our ownership interest in the combined entity, which has been renamed Archer Limited was reduced to 36.4%. Following the consummation of the merger, Archer was deconsolidated from our accounts, but recognized as an investment in an associated company.
 

 
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·
On July 1, 2011, we purchased in a private placement a 33.75% equity interest AOD (OSE: AOD) for $54 million.  In addition, we agreed to provide the construction supervision, project management, and commercial management of all of AOD's jack-up rigs.
 
 
·
On December 2, 2011, we purchased a 28.5% equity interest in Sevan Drilling ASA (OSE: SEVDR) for $65 million.
 
 
·
In August 2011 and September 2011, we increased our ownership stake in Archer Limited (OSE: ARCHER) to 39.9% by further purchases of shares for $167 million.
 
Recent Developments
 
On January 31, 2012, we completed a NOK1,250 million senior unsecured bond issue with maturity date February 13, 2014. In conjunction with the bond issues we repurchased bonds with nominal value NOK332 million of the NOK500 million unsecured bond due 2012. Following the repurchase, the remaining outstanding amount of the NOK500 million unsecured bond due 2012 was NOK169 million.
 
In February 2012, we disposed of our 3.5% holding in Ensco Plc, which we held after Ensco acquired Pride International Inc. through a combination of cash and stock last year.
 
In February 2012, we ordered two 12,000 ft dual derrick ultra-deepwater drillships to be constructed at Samsung. The drillships are of the same design as the three previous dual derrick drillships that we ordered from Samsung in the fourth quarter 2010 and first quarter 2011. The total project price per drillship is estimated to be under $600 million, which includes a turnkey contract with the yard, project management, drilling and handling tools, spares, capitalized interest and operations preparations.
 
On March 1, 2012, Hemen, a company which is ultimately controlled by trusts established for the benefit of Mr. John Fredriksen, Chairman of the Board of Seadrill, and his immediate family, announced that it had sold 24 million shares and 24 million put options at a combined purchase price of NOK236.3176 per share and per seller put option. Following the sale, Hemen's holding of shares in Seadrill Limited was reduced to 23.2%, or 109,097,583 shares. If all put options are exercised with physical delivery at expiry Hemen's position in Seadrill will increase by 24 million shares to its pre-transaction level of 133,097,583 shares, or 28%. In addition Hemen has Total Return Swap, or TRS, agreements with underlying exposure to 3.9 million shares in Seadrill.
 
On March 12, 2012, Seabras, a wholly-owned indirect subsidiary, made an initial filing of a Reference Form, or Formulário de Referência, with the Brazilian Securities and Exchange Commission, Comissão de Valores Mobiliários, or CVM, in connection with its potential future initial public offering of common shares to be listed on the Novo Mercado segment of the BM&FBOVESPA, the São Paulo Stock Exchange. The potential future offering of the common shares is subject to market and other conditions, including the approval by, and registration of the common shares with, the CVM.
 
On March 27, 2012, NADL completed a private placement, raising $300 million through the issuance of 150,000,000 new ordinary shares at $2.00 per share. The proceeds of the private placement will be used to finance the first yard installment for a newbuilding harsh environment semi-submersible rig, repay intra-company debt to Seadrill and general corporate purposes. Seadrill purchased 75,000,000 shares in the private placement. Following the private placement, our ownership interest in NADL was reduced from 77% to 73%.
 
On March 31, 2012, we obtained a short-term unsecured credit facility of $84 million from Metrogas, The amount is repayable in June 2012 and bears interest in accordance with arms-length principles.
 
On April 2, 2012, NADL entered into a contract with Jurong Shipyard in Singapore for the construction of a new harsh environment semi-submersible drilling rig to be delivered by the first quarter 2015. Total estimated project costs for the new rig, including a turnkey contract with the yard, project management, drilling and handling tools, spares, capitalized interest and operations preparations, is estimated to be approximately $650 million. The new rig will be of a Moss CS60 design, N-Class compliant and be fully winterized to meet the weather conditions in the North Atlantic areas. Maximum water depth will be 10,000 feet with a maximum drilling depth of 40,000 feet. Further, the rig will have both DP3 dynamic positioning systems and complete anchor handling capabilities. In order to meet the highest safety and operational standards, the rig will be outfitted with a six ram blow out preventer, or BOP, stack and have the flexibility for storing and handling of a second BOP.
 
On April 12, 2012, we exercised an option to build a new tender rig at the COSCO Nantong Shipyard in China. The new unit, T18, is scheduled for delivery in the fourth quarter 2013. Total project price is estimated at $135 million, including project management, drilling and handling tools, spares, and capitalized interest. T18 is similar to the three tender rigs Seadrill ordered from COSCO in 2011, with enhanced drilling capabilities allowing for higher drilling efficiency, including the advantage of a light weight drilling equipment set.
 

 
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On April 20, 2012, we issued a claim against the Norwegian Tax Authorities. The claim challenges their tax re-assessment related to change of tax jurisdiction for some of our subsidiaries and calculation of taxable gains (See Note 4 to our Consolidated Financial Statements).
 
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.
 
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.
 

 
20
 

 
·
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.
 
In response to a significant growth in operations through acquisitions of new rigs, newbuilding orders and the deconsolidation of Archer Limited (formerly Seawell Limited) in early 2011, a review our internal structure, including the operating and reporting business segments, resulted in a change to our reporting segments with effect from the first quarter of 2011.
 
As such, with effect from the first quarter of 2011, we report our business in the following operating segments:
 
 
·
Floaters: We offer services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to semi-submersible rigs and drillships for harsh and benign environments in mid-, deep- and ultra-deep waters.
 
 
·
Jack-up rigs: We offer services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to jack-up rigs for operations in harsh and benign environments.
 
 
·
Tender Rigs: We operate self-erecting tender barges 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. However, this segment is only applicable for the period up to and including February 2011 when Archer was deconsolidated.
 
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 fleet of premium jack-ups; and
 
 
·
develop our strong position in the tender rig market in conventional waters as well as deepwater areas.
 

 
21
 

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 U.S. GOM, Europe and West Africa but also expanding to India, Southeast Asia, China, East Africa, the Mexican GOM, Australasia and the Mediterranean. Significant exploration success in these areas has translated into higher demand for rigs.
 
All information below is according to industry sources.
 
The global fleet of drilling units
 
The global fleet of offshore drilling units consists of drillships, semi-submersible rigs, jack-up rigs and tender rigs. The existing world wide fleet totals 797 units including 79 drillships, 212 semi-submersible rigs, 477 jack-up rigs and 29 tender rigs. In addition, there are 71 drillships, 82 jack-up rigs, 23 semi-submersible rigs and eight tender rigs under construction. The water depth capacities for the various drilling rig types depend on rig specifications, capabilities and equipment outfitting. Jack-up rigs normally work in water depths up to 450ft while semi-submersible rigs and drillships can work in water depths up to 12,000ft and tender rigs work in water depths up to 410ft for tender barges and up to 6,000ft for semi-tenders. All offshore rigs are capable of working in benign environment but there are certain additional requirements for rigs to operate in harsh environments due to extreme marine and climatic conditions 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 42 units.
 
Jack-up rigs
 
The world fleet of jack-up rigs currently counts 477. Of these rigs, 394 rigs are in operational mode, 26 are warm-stacked and 57 are cold-stacked. In addition, there are 82 units under construction. The existing world fleet includes 52 units equipped and outfitted for operations in harsh environments of which 12 rigs are approved for operations in Norway. Out of the rigs currently under construction, 22 will have harsh environment capabilities but only 3 will be outfitted for operations in Norway. The average age of the existing fleet is currently 25 years for the benign environment units and 16 years for the harsh environment units. The overall utilization rate for jack-up rigs is 78% while the utilization rate for benign environment jack-up rigs built after 2005 is 91% and the utilization rate for the harsh environment rigs is 94%. Of the existing fleet, 147 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 in the range $340,000 to $370,000 for newer rigs whereas daily rates for harsh environment jack-ups in the U.K. and Canada are in the range $210,000 to $220,000. For benign environment jack-up rigs, daily rates are in the range $130,000 to $150,000 for new premium rigs and in the range $80,000 to $110,000 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, modern and efficient rigs due to wells becoming technically more 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 are of the opinion that this development provides for a sound market outlook for our premium jack-up rigs.
 
Semi-submersible rigs and drillships
 
The world fleet of semi-submersible rigs and drillships currently totals 291 units. In addition, there are 93 units under construction, 23 semi-submersible rigs and 71 drillships. Of the total fleet, 154 units was built before 1998. These units are mainly moored units and have an average age of some 32 years. For the existing 137 rigs built after 1998, the majority have been outfitted with thrusters allowing for dynamic positioning. 129 of the 137 units are capable of operations in deepwater waters (waters deeper than 4,500ft but less than 7,500ft) and 113 of the 137 units are capable of operations in ultra-deep waters (waters deeper than 7,500ft).
 

 
22
 

 
The demand for dynamically positioned 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 demand, a significant number of new rigs have been built since 2005 increasing the number of dynamically positioned drillships and semi-submersible rigs with ultra-deepwater capabilities from 28 to 113. In order to justify the significant investments, daily rates 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. In response to this oil price development, oil companies held back new spending and investments in deeper water, resulting in daily rates decreasing to the low $400,000s in 2010. Since then, higher oil prices and an improved economic outlook has spurred a higher activity level from oil companies that has increased the demand for ultra-deepwater units resulting in renewed interest for construction of further new ultra-deepwater units as well as pushing daily rates up. At present the levels for daily rates are in the range $520,000 to $580,000.
 
We believe that the long-term prospects for deepwater and ultra-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, East and West Africa as well as other regions, along with improving access to new promising offshore areas and new, more efficient technologies.
 
Tender rigs
 
There are currently 37 self-erecting tender rigs globally including eight units under construction. Out of the 37 rigs, 26 are barges and 11 are semi-submersibles (semi-tenders) of which there are 6 barges and 2 semi-tenders under construction. The main markets for tender rigs are West Africa and Southeast Asia, employing 14% and 83% of tender rigs respectively. However, during 2011, one unit started operations in Trinidad and Tobago in the Americas. The overall utilization rate for the world tender rig fleet is 86%, 85% for the barges and 89% for the semi-tenders. 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 up to approximately $130,000 for modern tender barges and up to $235,000 for modern semi-tenders.
 
We are the largest operator in this segment operating a fleet of 15 units, including five units that we operate in association with Varia Perdana. In addition, we have four tender barges and one semi-tender under construction. We believe that the long-term outlook for tender rigs remains favorable due to their operational 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, earnings visibility and provide organic growth opportunities.
 
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 U.S. 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, 2011 our six largest customers have been:
 

 
23
 
 
 
·
Petròleo Brasileiro S.A., or Petrobras, accounting for approximately 17% of our revenues;
 
 
·
Total S.A. Group, or Total, accounting for approximately 15% of our revenues;
 
 
·
Royal Dutch Shell, or Shell, accounting for approximately 10% of our revenues;
 
 
·
Exxon Mobil Corp, or Exxon, accounting for approximately 10% of our revenues; and
 
 
·
Statoil ASA, or Statoil, account for approximately 7% of our revenues;
 
 
·
Chevron Corporation, or Chevron, accounting for approximately 7% of our revenues.
 
In 2011, our two largest customers were Petrobras and Total, who provided approximately 17% and 15% of our contract revenues, respectively.   In the year ended December 31, 2010, our two largest customers were Petrobras and Statoil, who provided approximately 17% and 15% of our contract revenues, respectively.  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 future contracted revenue, or backlog, at December 31, 2011 totaled approximately $12.6 billion, with $8.5 billion of this amount attributable to our semi-submersible rigs and drillships.  We expect approximately $4.0 billion of our backlog to be realized in 2012. Backlog for our drilling fleet is calculated as the contract daily rate 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 daily rates than the full contractual operating daily rate.
 
The following table shows the percentage of rig days committed by year as of December 31, 2011. The percentage of rig days committed is calculated as the ratio of total days committed under 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
 
2012
 
2013
 
2014
 
 
 
 
 
 
 
 
 
 
Jack-up rigs
 
 
71
%
 
 
29
%
 
 
26
%
Semi-submersible rigs
 
 
100
%
 
 
94
%
 
 
81
%
Drillships
 
 
88
%
 
 
21
%
 
 
4
%
Tender rigs
 
 
96
%
 
 
60
%
 
 
41
%
 
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.
 

 
24
 

Offshore drilling contracts are generally awarded on a competitive bid basis. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability and sustainability, rig location, condition of equipment, operating integrity, safety performance record, crew experience, reputation, industry standing and client relations.
 
Furthermore, competition for offshore drilling rigs is generally on a global basis, as rigs are highly mobile. However, the cost associated with mobilizing rigs between regions is sometimes substantial, as entering a new region could necessitate upgrades of the unit and its equipment to specific regional requirements. In particular, for rigs to operate in harsh environments, such as offshore Norway and Canada, as opposed to benign environments, such as the U.S. 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 for some of our rigs and third party liability.
 
Our insurance claims are subject to a deductible, or non-recoverable, amount.  We currently maintain a deductible per occurrence of up to $5 million related to physical damage to our rigs.  However, a total loss of, or a constructive total loss of, a drilling unit is recoverable without being subject to a deductible.  For general and marine third-party liabilities, we generally maintain a deductible of up to $500,000 per occurrence on personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units.  Furthermore, for some of our rigs we purchase insurance to cover loss due to the drilling unit being wholly or partially deprived of income as a consequence of damage to the unit. The loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, our insurance policies are limited to 290 days. If the repair period for any physical damage exceeds the number of days permitted under our loss of hire policy, we will be responsible for the costs in such period. We do not have loss of hire insurance on our benign environment jack-up rigs and tender rigs with the exception of three semi-tender rigs.
 
We have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. 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 operations are subject to numerous laws and regulations in the form of international conventions and treaties, national, state and local laws and national and international regulations in force in the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. These requirements include, but are not limited to, the International Convention for the Prevention of Pollution from Ships, or MARPOL, the International Convention on Civil Liability for Oil Pollution Damage of 1969, generally referred to as CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or Bunker Convention, the International Convention for the Safety of Life at Sea of 1974, or SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, the International Convention for the Control and Management of Ships' Ballast Water and Sediments in February 2004, or the BWM Convention, the U.S. Oil Pollution Act of 1990, or OPA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Clean Water Act, the U.S. Clean Air Act, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, or the MTSA, European Union regulations, 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 United Nations' International Maritime Organization, or IMO, has adopted MARPOL. Annex VI to MARPOL regulates harmful air emissions from ships, which include rigs and drillships. Amendments to the Annex VI regulations which entered into force on July 1, 2010, 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. We may incur costs to comply with these revised standards. 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.
 

 
25
 

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 jurisdictional waters of ratifying states. We believe that all of our drilling units are currently compliant in all material respects with these regulations.
 
Furthermore, any drillships that we may operate in United States waters, including the U.S. territorial sea and the 200 nautical mile exclusive economic zone around the United States, would have to comply with OPA and CERCLA requirements, among others, that impose 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.
 
The U.S. BSEE periodically issues guidelines for rig fitness requirements in the Gulf of Mexico and may take other steps that could increase the cost of operations or reduce the area of operations for our units, thus reducing their marketability. Implementation of BSEE guidelines or regulations may subject us to increased costs or limit the operational capabilities of our units and could materially and adversely affect our operations and financial condition.
 
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 a serious marine incident that results in significant oil pollution or otherwise causes significant adverse environmental impact, such as the April 2010 Deepwater Horizon oil spill in the Gulf of Mexico, 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 other international conventions and laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, 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. "Risk Factors" of this Annual Report.
 
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 U.S. Department of the Interior's Minerals Management Service to a new department, the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE.  On October 1, 2011, BOEMRE was reorganized into two new organizations, the Bureau of Ocean Energy Management, or BOEM, and the Bureau of Safety and Environmental Enforcement, or BSEE.  As a result of this reorganization, BSEE is now responsible for the issuance of permits for offshore drilling activities and BOEM for all oil and gas leasing activities that were previously handled by BOEMRE.  The moratorium preventing the issuance of offshore drilling permits that was put in place in May of 2010 was subsequently lifted in October 2010, thus allowing permitting to resume.  However, the first permit was not actually issued until February of 2011, and the number of permits issued since has not yet returned to levels that existed prior to the Deepwater Horizon Incident. It is not known when or whether the number of permits issued will be sufficient to sustain levels of deepwater drilling activity comparable to levels prior to the Deepwater Horizon Incident.  The BSEE 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 BOEM or BSEE 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 U.S. GOM could be restricted by governmental regulation" in Item 3.D of this Annual Report.
 

 
26
 

 
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 – floaters (world-wide), jack-up rigs (world-wide) and tender rigs (mainly in south-east Asia and Africa).
 
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 currently has six drilling units in operation, one jack-up rig and one semi-submersible rig under construction. NADL has 1.2 billion shares issued and outstanding, of which we own 73%.
 
In late February 2011, Seadrill reduced its ownership in Archer from 52.3% to approximately 36.4%. As such, with effect from the end of February, 2011, Archer, 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. Seadrill currently has a 39.9% ownership stake in Archer.
 
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 24, 2012:
 
 
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
  
West Epsilon **
1993
394
30,000
Norway
December 2014
Offshore Courageous
2007
350
30,000
Malaysia
January 2013
Offshore Defender
2007
350
30,000
In transit to Brunei
May 2016
Offshore Resolute
2007
350
30,000
Singapore
May 2015
West Prospero
2007
400
30,000
Vietnam
December 2012
Offshore Intrepid
2008
350
30,000
Saudi Arabia / Kuwait
November 2012
Offshore Vigilant
2008
350
30,000
Trinidad & Tobago
April 2012
West Ariel
2008
400
30,000
Vietnam
December 2012
West Triton
2008
375
30,000
Malaysia Thailand JDA
May 2015
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
Colombia
September 2012
West Callisto
2010
400
30,000
Indonesia
September 2015
West Leda
2010
375
30,000
Thailand
October 2013
West Elara **
2011
492
40,000
Norway
March 2017
West Castor (NB)
2012
400
30,000
Jurong Shipyard (Singapore)
 
West Telesto (NB)
2012
400
30,000
Dalian Shipyard (China)
 
West Oberon (NB)
2013
400
30,000
Dalian Shipyard (China)
 
West Tucana (NB)
2013
400
30,000
 Jurong Shipyard (Singapore)
 
West Linus (NB) **
2013
492
40,000
 Jurong Shipyard (Singapore)
January 2019
 
 
 
 
 
 
Tender rigs
 
 
 
 
 
T4
1981
410
20,000
Thailand
June 2013
T7
1983
410
20,000
Thailand
March 2013
West Pelaut
1994
6,500
30,000
Brunei
March 2015
West Menang
1999
6,500
30,000
Malaysia
February 2013
West Alliance
2001
6,500
30,000
Malaysia
January 2015
West Setia
2005
6,500
30,000
Angola
August 2012
 
 
27
 
 
West Berani
2006
6,500
30,000
Indonesia
March 2013
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
March 2015
West Jaya
2011
6,500
30,000
Trinidad&Tobago
June 2014
T15 (NB)
2013
6,500
30,000
COSCO Shipyard (China)
March 2018
T16 (NB)
2013
6,500
30,000
COSCO Shipyard (China)
June 2018
T17 (NB)
2013
6,000
30,000
COSCO Shipyard (China)
 
West Esperanza (NB)
2013
6,500
30,000
Keppel FELS (Singapore)
December 2014
T18 (NB)
2013
6,000
30,000
COSCO Shipyard (China)
 
           
Semi-submersible rigs
 
 
 
 
 
West Alpha **
1986
2,000
23,000
Norway
November 2013
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
September 2016
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
China
June 2015
West Orion
2010
10,000
35,000
Brazil
July 2016
West Pegasus
2011
10,000
35,000
Mexico
August 2016
West Leo (NB)
2011
10,000
35,000
In transit to Ghana
April 2013
West Capricorn (NB)
2011
10,000
35,000
In transit to GOM
May 2017
West TBN**
2015
10,000
40,000
Jurong Shipyard (Singapore)
  
 
 
 
 
 
 
Drillships
 
 
 
 
 
West Navigator **
2000
7,500
35,000
Norway
June 2014
West Polaris (SF)
2008
10,000
35,000
Nigeria
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
Samsung Heavy Industries (South Korea)
 
West Vela (NB)
2013
12,000
40,000
Samsung Heavy Industries (South Korea)
 
West Tellus (NB)
2013
12,000
40,000
Samsung Heavy Industries (South Korea)
 
West Neptune (NB)
2014
12,000
40,000
Samsung Heavy Industries (South Korea)
 
West Jupiter (NB)
2014
12,000
40,000
Samsung Heavy Industries (South Korea)
 
 
 
SF           Unit owned by subsidiary of Ship Finance (see Note 33 to Consolidated Financial Statements).
NB          Newbuilding under construction or in transit to its first drilling assignment.
**           Owned by our subsidiary NADL in which we own 73% of the outstanding shares.
***         We have entered into an agreement to sell the unit and expect to complete the transaction in the fourth quarter of 2012.
 
In addition to the drilling units listed above, as of December 31, 2011, we have buildings, plant and equipment with a net book value of $25 million, including office equipment. Our offices in Stavanger in Norway, Singapore, Houston in the United States, Rio de Janeiro in Brazil, Dubai in the United Arab Emirates and Aberdeen in the United Kingdom are leased and aggregate office operating costs were $20 million in 2011.
 
We do not have any material intellectual property rights.
 
ITEM 4A.
UNRESOLVED STAFF COMMENTS
 
Not applicable.
 
28
 
 
ITEM 5.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS
 
The following should be read in conjunction with Item 3.A "Key Information – 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 7,600 skilled employees.  We own and operate a fleet of 59 offshore drilling units, which consist of 13 semi-submersible rigs, nine drillships, 21 jack-up rigs and 16 tender rigs, including 16 units currently under construction, which consists of five drillships, one semi-submersible rig, five jack-up rigs and five tender rigs. The delivery schedule for our newbuildings under construction commences during the fourth quarter 2012 and ends in the third quarter 2014, with the majority of deliveries scheduled to be completed in 2013. In addition, (i) we operate five tender rigs in association with Varia Perdana and (ii) we provide the construction supervision, project management, and commercial management to all three newbuilding jack-up rigs of AOD.  A full fleet list is provided in Item 4.D "Information on the Company – Property, Plant and Equipment".
 
Our subsidiary, NADL focuses entirely on harsh environment operations.  NADL acquired from Seadrill Limited five harsh environment rigs and one construction contract for a semi-submersible. NADL currently has six drilling units in operation, one jack-up rig and one semi-submersible rig under construction. We currently own 73% of NADL's outstanding shares and the balance of the shares are held by institutional and other investors.
 
In addition to owning and operating offshore drilling units, we have also made investments in other offshore drilling and oil service companies including Archer Limited (39.9%), SapuraCrest (23.6%), Varia Perdana (49%), Asia Offshore Drilling (AOD) (33.75%) and Sevan Drilling (28.5%).
 
Fleet Development
 
The following table summarizes the development of our active fleet of drilling units, based on the dates when the units began operations:
 


          Floaters        
Unit type
FPSOs
  
Jack-up
rigs
  
Drillships
  
Semi-
submersible
rigs
  
Tender
rigs
  
Total
units
                       
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
additions in 2011
    
+1
      
+1
  
+1
  
+3
disposals in 2011
    
-1
          
-1
  
-2
At December 31, 2011
    
15
  
4
  
10
  
11
  
40

 
29
 
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, 2011:
 
Drilling unit
Type of rig
Delivery date/Start-up date*
West Leo
Semi-submersible rig
1Q 2012
West Capricorn
Semi-submersible rig
2Q 2012
West TBN
Semi-submersible rig
1Q 2015
West Elara
Jack-up rig
1Q 2012
West Telesto
Jack-up rig
4Q 2012
West Tucana
Jack-up rig
4Q2012
West Castor
Jack-up rig
1Q 2013
West Oberon
Jack-up rig
1Q 2013
West Linus
Jack-up rig
3Q 2013
West Auriga
Drillship
1Q 2013
West Vela
Drillship
2Q 2013
West Tellus
Drillship
3Q 2013
West Neptune
Drillship
2Q 2014
West Jupiter
Drillship
3Q 2014
T-15
Tender rig
4Q 2012
T-16
Tender rig
1Q 2013
T-17
Tender rig
1Q 2013
West Esperanza
Tender rig
2Q 2013
T-18
Tender rig
4Q 2013
* Start-up date is used for rigs that have been delivered from the yard and are in transit to the first drilling assignment
 
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;
 
 
·
gains on disposals;
 
 
·
gains on deconsolidation;
 
 
·
interest and other financial items; and
 
 
·
tax expenses.
 
Revenues
 
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 daily rate compensation for the period of the interruption. Furthermore, our daily rates can be reduced in instances of interrupted or suspended service due to, among other things, repairs, upgrades, weather, maintenance, force majeure or requested suspension of services by the client and other operating factors.
 
30
 
 
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,
 
 
 
2011
 
 
2010
 
 
2009
 
 
 
Average
daily
revenues
 
 
Economic utilization
 
 
Average
daily
revenues
 
 
Economic utilization
 
 
Average
daily
revenues
 
 
Economic utilization
 
 
 
$
 
 
 
%
 
 
$
 
 
 
%
 
 
$
 
 
 
%
 
Jack-up rigs
 
 
136,000
      
90
 
 
 
160,000
 
 
 
90
 
 
 
130,000
 
 
 
70
 
Semi-submersible rigs
 
 
508,000
      
96
 
 
 
486,000
 
 
 
95
 
 
 
445,000
 
 
 
92
 
Drillships
 
 
515,000
      
94
 
 
 
508,000
 
 
 
89
 
 
 
497,000
 
 
 
94
 
Tender rigs
 
 
139,000
      
92
 
 
 
95,000
 
 
 
89
 
 
 
115,000
 
 
 
93
 

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.
 
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 Note 2 (Accounting Policies) of our notes to Consolidated Financial Statements appearing elsewhere in this Annual Report. 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 floaters, jack-up rigs, and tender rigs, when new, is 30 years.
 

 
31
 

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, daily rates 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.
 
Income Taxes
 
We are a Bermuda company. Currently we are not required to pay taxes in Bermuda on ordinary income or capital gains as we qualify as an exempt company.  We have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 2035. Certain 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 more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authority's widely understood administrative practices and precedence.  Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as of the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances.
 
 
32
 

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 and indemnities. 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. As a consequence of the change in segment structure from 2011, the amount of goodwill has been reassigned to the reporting units affected using a relative fair value allocation approach.
 
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.
 
In September 2011, the FASB issued new guidance relative to the test for goodwill impairment.  The new guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted.  We have decided to early adopt this new guidance. For the year ended December 31, 2011, we concluded it was not necessary to perform the two step goodwill impairment test, as no reporting units were at risk of failing the goodwill impairment test based on qualitative factors.
 
For the years ended December 31, 2011, 2010 and 2009 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% 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.
 
 
33
 

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.
 
Recent accounting pronouncements
 
In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-04 "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs (International Financial Reporting Standards)". In general, ASU 2011-04 clarifies the FASB's intent about the application of existing fair value measurement and disclosure requirements, and for many of these requirements the amendments are not intended to result in any change in the application of ASC Topic 820, "Fair Value Measurement". At the same time, there are some amendments that do change particular principles or requirements relating to fair value measurement and disclosure.  ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. Its adoption is not expected to have a material impact on the Company's disclosures or consolidated financial position, results of operations, and cash flows.
 
In June 2011, the FASB issued ASU 2011-05 "Presentation of Comprehensive Income" in order to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. ASU 2011-05 eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity, and requires entities to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. ASU 2011-05 is effective for fiscal years beginning after December 15, 2011, although early adoption is permitted. Its adoption is not expected to have a material impact on the Company's disclosures or consolidated financial position, results of operations, and cash flows.
 
In September 2011, the FASB issued new guidance relative to the test for goodwill impairment. The new guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. The Company has decided to adopt this new guidance early.
 
In December 2011, the FASB issued ASU 2011-11 "Disclosures about Offsetting Assets and Liabilities" in order to standardize the disclosure requirements under US GAAP and IFRS relating to both instruments and transactions eligible for offset in financial statements. ASU 2011-11 is applicable for annual reporting periods beginning on or after January 1, 2013. Its adoption is not expected to have a material impact on the Company's disclosures.
 
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
 
The Company provides drilling and related services to the offshore oil and gas industry. The split of our organization into segments has historically been based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure.
 
 
34
 

We have in 2011 and 2010 significantly expanded our fleet of drilling rigs through acquisitions of new rigs and newbuilding orders. In response to this development and the deconsolidation of Archer, management has reviewed our internal reporting structure including the operating and reporting business segments. This review has resulted in a change in our reporting segments reflecting how the Board and our directors assess performance and allocates resources. This change had effect from January 1, 2011, but the segments have also been retrospectively recasted for purposes of providing comparative data.
 
We currently operate in the following three segments:
 
Floaters: The Company offers services encompassing drilling, completion and maintenance of offshore wells. The drilling contracts relate to employment of semi-submersible rigs and drillships.
 
Jack-up rigs: The Company offers services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to Jack-up rigs for operations in harsh and benign environment.
 
Tender Rigs: The Company operates self-erecting tender rigs and semi-submersible tender rigs, which are used for production drilling and well maintenance in benign environments.
 
Segment results are evaluated on the basis of operating profit, and the information given below is based on the internal reporting structure used in the reporting to the Executive Management and the Board. The accounting principles for the segments are the same as for the Company's Consolidated Financial Statements.
 
Fiscal Year Ended December 31, 2011, compared to Fiscal Year Ended December 31, 2010.
 
The following table sets forth our operating results for 2011 and 2010.
 
   
Year ended December 31, 2011
    
Year ended December 31, 2010
  
In US$ millions
  
Floaters
    
Jack-up rigs
    
Tender Rigs
    
Well Services
    
Total
    
Floaters
    
Jack-up rigs
    
Tender Rigs
    
Well Services
    
Total
  
Total operating revenues
     2,694       776       589       133       4,192       2,264       578       482       717       4,041  
Gain on sale of assets
             22                       22               26                       26  
Total operating expenses
     (1,366 )     (578 )     (368 )     (128 )     (2,440 )     (1,124 )     (405 )     (260 )     (653 )     (2,442 )
Operating income
     1,328       220       221       5       1,774       1,140       199       222       64       1,625  
Interest expense
                                     (295 )                                     (312 )
Other financial items
                                     192                                       18  
Income before taxes
                                     1,671                                       1,331  
Income taxes
                                     (189 )                                     (159 )
Net income
                                     1,482                                       1,172  

Total operating revenues
In US $millions
  
2011
    
2010
    
Change
  
Floaters
     2,694       2,264       19 %
Jack-up rigs
     776       578       34 %
Tender Rigs
     589       482       22 %
Well services
     133       717       (81 ) %
Total operating revenues
     4,192       4,041       4 %

Total operating revenues increased from $4.0 billion in 2010 to $4.2 billion in 2011. Total operating revenues are predominantly contract revenues with additional, relatively small amounts of reimbursable and other revenues. There was an increase in all segments due to more rigs in operation than in the prior year period, offset by the deconsolidation of Archer and the well services segment in February 2011.
 
Total operating revenues in the floaters segment increased by $430 million in 2011 compared to 2010. The number of drilling units in the floaters segment increased from 13 at December 31, 2010 to 14 at December 31, 2011. There was no significant change in the general level of daily rates during this period.
 

 
35
 

Total operating revenues in the jack-up rigs segment increased by $198 million in 2011 compared to 2010. This is partly related to the jack-up rig West Juno commencing operations in the first quarter of 2011.  The same rig was sold in 2011. In addition to this the seven jack-up rigs acquired through the Scorpion acquisition in May 2010 contributed to revenues for the full year in 2011. There was no significant change in the general level of daily rates during this period.
 
Total operating revenues in the tender rig segment increased by $107 million in 2011 compared 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. In addition, the West Jaya commenced operation during the fourth quarter of 2011. Daily rates for our tender rigs have remained fairly constant during this period.
 
Total operating revenues in the well services segment decreased from $717 million in 2010 to $133 million in 2011. This is due to the fact that Archer was deconsolidated from our accounts in February 2011 and the revenue in 2011 represents only two months of operations as compared to twelve months of operations in 2010.
 
Gain on sale of assets
 
We recorded a gain of $22 million on the disposal of the jack-up rig West Juno in 2011 as compared to a gain of $26 million on the disposal of the jack-up rig West Larissa in 2010.
 
Total operating expenses
 
In US$ millions
 
2011
 
 
2010
 
 
Change
 
Floaters
 
 
1,366
  
 
 
1,124
 
 
 
22
%
Jack-up rigs
    
578
      
405
      
43
%
Tender rigs
 
 
368
  
 
 
260
 
 
 
42
%
Well services
 
 
128
  
 
 
653
 
 
 
(80)
%
Total operating expenses
 
 
2,440
  
 
 
2,442
 
 
 
0
%

Total operating expenses amounted to $2,440 million in 2011, which is unchanged from 2010. Total operating expenses consist of rig operating expenses, depreciation, reimbursable expenses and general and administrative expenses. Total general and administrative expenses increased from $178 million in 2010 to $202 million in 2011. Reimbursable expenses in each segment were closely in line with reimbursable revenues.
 
Total operating expenses for the floaters operating segment increased by $242 million in 2011 compared to 2010. This is mainly related to the increase in the number of rigs in operation.
 
Total operating expenses for the jack-up rigs operating segment increased by $173 million in 2011 compared to 2010. This is mainly related to the increase in the number of rigs in operation and also a non-recurring expense of $16 million related to termination of a third party management agreement for two jack-up rigs in the Middle East that was recognized in 2011.
 
Total operating expenses in the tender rig segment increased from $260 million in 2010 to $368 million in 2011. The increased costs were mainly a result of more rigs in operation.
 
Total operating expenses in the well services segment decreased from $653 million in 2010 to $128 million in 2011. This is due to the fact that Archer was deconsolidated from our accounts in February 2011 and the amount of $128 million represents only two months of operations as compared to twelve months of operations in 2010.
 
Interest expense
 
Interest expense decreased from $312 million in 2010 to $295 million in 2011. The main reason for this is the deconsolidation of Archer from February 2011. There has not been a significant change in the general interest rates during the period.
 
 
36
 
 
Other financial items
 
Other financial items reported in the income statement includes the following items:
 
In US$ millions
      2011        2010  
Interest income
     21       42  
Share in results of associated companies
     (420 )     48  
Impairment loss on marketable securities
     (10 )     (15 )
(Loss)/gain on derivative financial instruments
     (346 )     (92 )
Gain on re-measurement of previously held equity interest
     -       111  
Gain on bargain purchase
     -       56  
Loss on debt extinguishment
     -       (145 )
Foreign exchange (loss)/gain
     (18 )     (26 )
Gain on loss of control in subsidiary
     540       -  
Gain on realization of marketable securities
     416       -  
Other financial items
     9       39  
Total other financial items
     192       18  
 
Interest income decreased from $42 million in 2011 to $21 million in 2011. The decrease is mainly related to lower holdings of interest bearing securities in 2011.
 
Share in results from associated companies decreased from a gain of $48 million in 2010 to a loss of $420 million in 2011. This is mainly related to an impairment charge on our Archer position of $463 million recognized in the fourth quarter of 2011. However we recognized a gain of $540 million in 2011 related to the deconsolidation of Archer in the first quarter of 2011.
 
Included in the results for 2011 is a gain on realization of our holdings in Pride (which merged with and into Ensco with Ensco as the surviving corporation) recognized in the second quarter of 2011, which amounted to $416 million.
 
In 2011, we recognized losses from derivative financial instruments of $346 million compared to a loss of $92 million in 2010. The increase in loss is mainly related to losses of $314 million from the interest rate swap agreements and the forward exchange contracts in 2011 compared to a loss of $150 million in the previous year. In addition, we recognized a loss of $50 million related to our Ensco positions held through forward contracts in 2011.
 
Included for the results for 2010 is a gain of $111 million recognized relating to re-measurement of previously held equity interest and $56 million gain on bargain purchase, both related to the acquisition and consolidation of Scorpion. Please see note 25 to our Consolidated Financial Statements for the year ended December 31, 2011 included herein.
 
Foreign exchange loss amounted to $18 million and $26 million for the year ended December 31, 2011 and 2010, respectively.
 
Other financial items amounted to a gain of $9 million in 2011, which is a decrease of $30 million compared to 2010. This is mainly due to a recognized gain of $43 million due to partial redemption of the Petromena bonds in 2010.
 
Income taxes
 
Income taxes amounted to a net cost of $189 million for the year ended December 31, 2011 compared to a net cost of $159 million in the year ended December 31,2010. The tax expense in 2011 includes a $9 million provision for uncertain tax positions related to the move of legal entities to a new tax jurisdiction. In addition, we have recognized a provision for payable tax of $39 million in the balance sheet, which will be amortized over approximately 15 years.  This provision is related to the same move of legal entities to a new tax jurisdiction.  Our effective tax rate was approximately 11% in 2011 as compared to 12% in 2010. The decreased effective tax rate is principally due to a lower proportion of our income being generated in taxable versus non taxable jurisdictions or in taxable jurisdictions with lower tax rates.
 
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.
 
 
37
 
 
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
  
Floaters
    
Jack-up rigs
    
Tender Rigs
    
Well Services
    
Total
    
Floaters
    
Jack-up rigs
    
Tender Rigs
    
Well Services
    
Total
  
Total operating revenues
     2,264       578       482       717       4,041       1,864       388       392       610       3,254  
Gain on sale of assets
             26                       26               71                       71  
Total operating expenses
     (1,124 )     (405 )     (260 )     (653 )     (2,442 )     (952 )     (230 )     (219 )     (552 )     (1,953 )
Operating income
     1,140       199       222       64       1,625       912       229       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
  
Floaters
     2,264       1,864       22 %
Jack-up rigs
     578       388       49 %
Tender Rigs
     482       392       23 %
Well services
     717       610       18 %
Total operating revenues
     4,041       3,254       24 %

Total operating revenues increased from $3.3 billion in 2009 to $4.0 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 floaters segment increased by $0.4 billion from 2009 to 2010. The number of drilling units in floaters segment increased from 11 at December 31, 2009 to 13 at December 31, 2010.
 
Total operating revenues in the jack-up rigs segment increased by $190 million from 2009 to 2010.  The number of drilling units in the jack-up rigs segment increased from six at December 31, 2009 to 15 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. The jack-up rig West Larissa was sold 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.
 
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 jack-up rigs operating segment.
 
 
38
 
 
Total operating expenses
 
In US$ millions
 
2010
 
 
2009
 
 
Change
 
Floaters
 
 
1,124
 
 
 
952
 
 
 
18
%
Jack-up rigs
    
405
      
230
      
76
%
Tender rigs
 
 
260
 
 
 
219
  
 
 
19
%
Well services
 
 
653
 
 
 
552
 
 
 
18
%
Total operating expenses
 
 
2,442
 
 
 
1,953
 
 
 
25
%

Total operating expenses increased from $2.0 billion in in 2009 to $2.4 billion in 2010, with the increase mainly in the floaters and jack-up rigs segments. 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 floaters operating segment increased by $172 million from 2009 to 2010 primarily due to the increase in the number of units during the period.
 
Total operating expenses for the jack-up rigs operating segment increased by $175 million from 2009 to 2010 primarily due to the increase in the number of units during the period.
 
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.
 
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  

 
39
 

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 gain 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.
 
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.
 
B.
LIQUIDITY AND CAPITAL RESOURCES
 
We operate in a capital intensive industry.  Our investment in newbuildings and secondhand drilling units 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, funding dividend payments 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 dollars, Norwegian Kroner, Brazilian Real, Australian dollars, Euros, Singapore dollars 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 term.
 
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 borrowings of the Company and its consolidated subsidiaries discussed below.
 
On December 31, 2011, we had remaining contractual commitments relating to 13 newbuilding contracts totaling approximately $3.0 billion.
 
 
40
 

As of December 31, 2011, we had cash and cash equivalents totaling $715 million, as compared to $910 million for the same period in 2010, including $232 million of restricted cash, as compared to $155 million for the same period in 2010.  In the year ended December 31, 2011, we generated cash from operations of $1.8 billion, used $2.6 billion in investing activities and proceeds from financing activities were $0.5 billion, as compared to $1.3 billion, $2.3 billion, and $1.3 billion, respectively, in the same period in 2010.
 
For the year ended December 31, 2011 we paid cash dividends of $3.135 per common share, or a total of $1.4 billion, while for the same period in 2010 we paid $1.0 billion in total cash dividends.
 
We have entered into a significant number of construction contracts for newbuilds. Borrowings under our current credit facilities and available cash on hand are not sufficient to pay the remaining installments related to our contracted yard commitments for all of our newbuilding drilling units, which currently totals $4.3 billion (including $0.3 billion paid in yard installments since December 31, 2011).  It is our intention to fund these investments through issuance of further debt and through future cash flow from operations. If 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. We believe the cash that we generate from our operations supported by existing debt capacity, provided by our contract backlog and asset base, is expected to be sufficient to meet our existing commitments to fund newbuildings 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. "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, finance our commitments 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, 2011, we had total outstanding borrowings under our credit facilities of $10.0 billion at an average annual interest rate of 3.41%.  In addition, we had interest bearing debt of $435 million under loan agreements with related parties.
 
Set forth below is a summary of our outstanding indebtedness as of December 31, 2011.
 

Secured credit facilities
 
Principal outstanding at December 31, 2011
(In millions of US dollars)
- $800 million secured term loan facility due 2013
 
272
 
- $585 million secured term loan facility due 2012
 
337
 
- $2,000 million secured credit facility due 2017
 
1,917
 
- $100 million secured term loan facility due 2014
 
 74
 
- $1,500 million senior secured credit facility due 2014
 
1,059
 
- $1,200 million senior secured credit facility due 2015
 
1,000
 
- $700 million senior secured credit facility due 2015
 
630
 
- $550 million senior secured credit facility due 2016
 
 550
 
- $1,121 million senior secured credit facility due 2017
 
 985
 
- $170 million senior secured credit facility due 2013
 
92
 
- $400 million senior secured credit facility due 2016
  
400
  
       
Ship Finance secured credit facilities
 
 
 
- $700 million secured term loan facility due 2013 (VIE)
 
470
 
- $1,400 million secured term loan facility due 2013 (VIE)
 
939
 
 
 
41
 
 
 
 
 
 
Unsecured bonds
 
 
 
 
 
 
 
- NOK500 million unsecured bond due 2012
 
75
 (NOK 450 million)
- $350 million unsecured bond due 2015
 
350
 
 
 
 
 
Convertible bonds
 
 
 
 
 
 
 
- $1,000 million 3.625% unsecured convertible bonds due 2012
 
0
 
- $650 million 3.375% unsecured convertible bonds due 2017
 
545
 
 
 
 
 
CIRR loans
 
 
 
 
 
 
 
- NOK1,754 million Commercial Interest Reference Rate, or CIRR credit facilities due 2016
 
172
 (NOK1,032 million)
- NOK1,011 million CIRR credit facilities due 2020
 
 126
 (NOK758 million)
 
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. The facility was amended again in April, 2011 when the West Phoenix was sold to NADL. As a result, only the West Eminence was pledged as security as of December 31, 2011. The facility consists of two tranches, and bears interest at LIBOR plus 1.70% and 3.25%per annum. As of December 31, 2011, the outstanding balance was $272 million, as compared to $635 million in 2010. The final repayment of $183 million is due in 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, 2011, the outstanding balance was NOK450 million, equivalent to $75 million, as compared to NOK450 million, equivalent to $77 million, in 2010.
 
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, 2011, the outstanding balance was $337 million, as compared to $387 million in 2010. 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 variable interest entity, or VIE, Rig Finance II Ltd (previous 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. In June 2011, we acquired all the shares of Rig Finance II Limited. As of December 31, 2011, the outstanding balance was $92 million, as compared to $101 million in 2010. The facility bears interest at LIBOR plus a margin, and is repayable over a term of six years. At maturity a balloon payment of $79 million is due.
 
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. When our subsidiary, NADL, acquired these rigs in April 2011, this facility was fully repaid.
 
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 million and the conversion price was $27.80 per share. The loan agreement provided 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 million outstanding amount had elected to convert their bonds into shares. In May 2011 we exercised the embedded call option and, as a consequence, the remaining convertible bonds outstanding were settled. Bondholders representing $721 million outstanding amount had requested conversion within the conversion date stipulated in the loan agreement, while the other $28 million of bonds were redeemed at par.
 
 
42
 

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, 2011, the outstanding amount on this facility was $74 million, as compared to $80 million in 2010. 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, 2011, was NOK500 million, equivalent to $83 million, as compared to NOK600 million, which is equivalent to $102 million, in 2010.
 
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, 2011, was NOK532 million, equivalent to $89 million, as compared to NOK638 million, which is equivalent to $109 million, in 2010.
 
In July 2008, we entered into a CIRR term loan for NOK1,011 million 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, 2011, was NOK758 million, equivalent to $126 million, as compared to NOK843 million, which is equivalent to $144 million, in 2010.
 
In connection with the above three CIRR fixed interest term loans totaling NOK1.8 billion ($298 million), 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.
 
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, 2011, the outstanding balance under the facility was $470 million, as compared to $546 million in 2010. 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 $1,400 million 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, 2011, the outstanding balance under the facility was $939 million, as compared to $1,099 million in 2010. 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 $1,500 million 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 facility was fully drawn as of December 31, 2011 with a balance of $1,059 million, as compared to $1,027 million. The facility bears interest at LIBOR plus a margin and is repayable over a term of five years.
 
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 were used for general corporate purposes. We later repurchased NOK76.5 million of the bonds. The bond was repaid upon final maturity in September 2011.
 
In June 2010, we entered into a $1,200 million 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, 2011, was $1,000 million, as compared to $1,133 million in 2010. 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, 2011, was $630 million, as compared to $700 million in 2010. 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 $34.17. Per December 31, 2011, for accounting purposes $105 million has been allocated to the bond equity component and $545 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 24, 2012 was 126% of nominal value. If the bonds were converted into shares at the current conversion price of $34.17, a further 19,022,478 new shares would be issued.
 
 
43
 

In October 2010, we issued a $350 million senior unsecured five year bond. The bond bears interest at 6.5% per annum and the proceeds are for general corporate purposes. As of December 31, 2011, the outstanding balance was $350 million.
 
In January 2011, we entered into a $1,121 million secured credit facility to fund the acquisition of the two ultra-deepwater semi-submersible drilling rigs West Pegasus and West Leo. These two units were pledged as security for the facility which bears interest at LIBOR plus a margin and is repayable over a term of seven years. At maturity a balloon payment of $498 million is due.  As of December 31, 2011, the outstanding balance was $985 million, with $115 million still available to draw down.
 
In April 2011, our subsidiary NADL entered into a $2.0 billion loan facility to fund the acquisition of three semi-submersible drilling rigs, two harsh environment jack-up rigs and one drillship from Seadrill.  The facility bears interest at LIBOR plus a margin and is repayable over a term of six years with a balloon installment of $1.0 billion due at maturity.  As of December 31, 2011, the outstanding balance was $1.9 billion.
 
In December 2011, we entered into a new $550 million senior secured credit facility with a syndicate of lenders and export credit agencies. The facility bears interest at LIBOR plus a margin, has a five-year term and is repayable in quarterly installments of $14 million with a balloon payment of $275 million.  The ultra-deepwater semi-submersible rig West Capricorn is pledged as security for this facility.
 
In December 2011, we entered into a new $400 million senior secured credit facility with a syndicate of lenders. The facility bears interest at LIBOR plus a margin, has a five-year term and is repayable in quarterly installments of $10 million with a balloon payment of $200 million.  The jack-up rigs West Leda, West Cressida, West Triton and West Callisto are pledged as security for this facility.
 
In the year ended December 31, 2011, we repaid in full:
 
 
(i)
a $1.5 billion secured term loan facility (of which $1.0 billion was outstanding at December 31, 2010), and
 
 
(ii)
a NOK800 million senior unsecured two year bond (of which NOK800 million ($123 million) was outstanding at December 31, 2010.
 
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:
 
 
·
Aggregated minimum liquidity requirement for the group, requires us to maintain cash and cash equivalents of at least $155 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.
 
 
44
 
 
Our secured credit facilities are secured by:
          
 
·
guarantees from rig owning subsidiaries (guarantors),
 
 
·
a first priority share pledge over all the shares issued by each of the guarantors,
 
 
·
a first priority perfected mortgage in all collateral rigs and any deed of covenant thereto, subject to contractual agreed "quiet enjoyment" undertakings with the end-user of the collateral rigs to be entered into if this is required by the relevant end-user pursuant to the relevant contract,
 
 
·
a first priority security interest over each of the rig owners' with respect to all earnings and proceeds of insurance, and
 
 
·
a first priority security interest in the earnings accounts.
 
The Company's loan and other debt agreements also contain, as applicable, loan-to-value clauses, which could require the Company, at its option, to post additional collateral or prepay a portion of the outstanding borrowings should the value of the drilling units securing borrowings under each of such agreements decrease below required levels. In addition, the loan and other debt agreements include certain financial covenants including the requirement to maintain a certain level of free cash and failure to comply with any of the covenants in the loan agreements could result in a default under those agreements and under other agreements containing cross-default provisions.  We were in compliance with all financial loan covenants as of December 31, 2011, except for our subsidiary NADL, which recognized a temporary period of non-compliance, which was remedied during the first quarter of 2012.
 
As of December 31, 2011, the three month United States dollar LIBOR was 0.58%, as compared to 0.30% in 2010 and three month NIBOR was 2.89%, as compared to 2.60% in 2010.
 
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, 2011, we had a loss of $346 million in our Statement of Operations consisting of the following:
 
Interest-rate swap agreements and forward exchange contracts: Total realized and unrealized loss on interest-rate swap agreements, not qualified for hedge accounting, and forward exchange contracts amounted to $314 million for the year ended December 31, 2011. The loss is recognized in the statement of operations as gain/(loss) on derivative financial instruments.
 
As of December 31, 2011, the Company and its consolidated subsidiaries, including VIEs, had entered into interest rate swap contracts with a combined outstanding principal amount of $5.7 billion, as compared to $4.0 billion in 2010, at rates between 2.055 % per annum and 4.63 % per annum, as compared to 2.055% and 4.63% in 2010.  The overall effect of these swaps is to fix the interest rate on $5.7 billion of floating rate debt at a weighted average interest rate 2.84% per annum, as compared to $4.0 billion at 3.25% in 2010. As of December 31, 2011, our net exposure to short term fluctuations in interest rates on our outstanding debt was $2.7 billion, as compared to $2.9 billion in 2010, based on our total net interest bearing debt of $9.5 billion less the $5.7 billion outstanding balance of fixed interest rate swaps, less the $1.1 billion in fixed interest loans.
 
Other derivative instruments: Total realized and unrealized loss on other derivative instruments amounted to $37 million for the year ended December 31, 2011, mainly due to realized losses on our Ensco forward contracts.
 
Also as of December 31, 2011, we had entered into forward exchange contracts to sell approximately $264 million, as compared to $345.5 million in 2010, in exchange for Norwegian Kroner between January 2012 and November 2012, at exchange rates ranging from NOK5.75 to NOK6.4 per US dollar.
 
 
45
 

Total Return Swaps:  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. In May 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 NOK188.26 per share and an expiration date in September 2011. In September 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 NOK177.21 per share and an expiration date in March 2012. In March 2012, 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 NOK229.69 and expiration date in September 2012. The total realized and unrealized gain related to the TRS agreements amounted to US$5 million for the year ended December 31, 2011 and is recognized in the statement of operations as gain/(loss) on derivative financial instruments.
 
The settlement amount for the TRS transaction will be (A) the market value of the shares at the date of settlement plus all dividends paid by the Company between entering into and settling the contract, less (B) the reference price of the shares agreed at the inception of the contract plus the counterparty's financing costs. Settlement will be either a payment by the counterparty to us, if (A) is greater than (B), or a payment by us to the counterparty, if (B) is greater than (A). There is no obligation for us to purchase any shares under the agreement and this arrangement has been recorded as a derivative transaction, with the fair value of the TRS recognized as an asset or liability as appropriate, and changes in fair values recognized in the consolidated statement of operations.
 
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, 2011.
 
Equity
 
As of December 31, 2011, the number of common shares issued, of par value $2.00 each, was 469,250,933 and fully paid share capital amounted to $938 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 share issue were approximately $1,065 million including the conversion of the convertible debt. In May, 2011, we issued 25,942,446 shares related to the settlement for early conversion of convertible debt, the total proceeds from the new share issue was approximately $721 million.
 
As of December 31, 2011, we were holding 1,478,759 of our common shares as treasury shares, as compared to 182,796 in 2010 and 110,200 in 2009, and our net outstanding share capital amounted to $935 million, as compared to $886 million in 2010 and $798 million in 2009. 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 3,250,000 shares in the year ended December 31, 2011, 1,750,000 shares were purchased in the year ended December 31, 2010, and no shares in the year ended December 31, 2009.
 
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, 2011, we have granted 12,037,438 options, of which 5,420,438 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 $10 million in the year ended December 31, 2011, as compared to $11 million in 2010 and $16 million in 2009.
 
 
46
 

As of December 31, 2011, our total additional paid-in capital including contributed surpluses amounted to $4.05 billion, as compared to $3.17 billion in 2010 and $2.12 billion in 2009, 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, share issuance in NADL, the equity component convertible bonds and conversion of convertible bonds.
 
As of December 31, 2011, we were party to a TRS agreement with 2,000,000 of our common shares as underlying security, whereby we are exposed to movements in the price of our shares (see "Derivatives" above). In March 2012, 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 demand for offshore drilling services has over the last six months showed considerable strength. As a result, daily rates and contract length have continued to improve for all asset classes. The spike in rates have however been most noticeable for ultra-deepwater rigs, a market that has seen most of its near term available capacity being absorbed at record pace. In the same period our customers has continued to report significant new offshore oil and gas discoveries in mature as well as frontier areas. This success coincides with continued growth in exploration and production spending in offshore regions by oil and gas companies. In a favorable oil price environment, this underpins the long-term demand and visibility for our industry and supports further growth especially in the deepwater area.
 
Ultra-deepwater floaters (>7,500 ft water)
The global demand for ultra-deepwater drilling services has continued to increase over the last six months. This is due to the number of active floaters in the U.S. Gulf of Mexico gradually reverting to historic high activity levels and a strong demand growth in Africa as well as in Brazil. The significant exploration successes by several oil companies like for instance the recent finds in pre-salt Angola and Mozambique have led research analysts to doubling their predictions of the number of wells needed to be drilled in the coming two years compared to predictions that were made a year ago. This development has accelerated demand and led to a significant increase in contract activity bringing the contract backlog for ultra-deepwater rigs to a historic record level and driving daily rates towards historic heights. The number of rigs available for employment in 2012 has shrunk materially and market sources indicate that with a few exceptions the available capacity is already being assigned to specific customers. This leads the focus to 2013, which is also starting to look tight from a rig availability perspective due to the new demand that is coming on stream. In addition to the international deepwater demand, there has also been a push for more advanced rigs in harsh environment in response to renewed focus from oil companies on activities in such areas, which have been absorbing some of the international ultra-deepwater capacity as well as created opportunities to build new units against long-term contracts. We expect continued contracting activity and the corresponding reduction in available supply to continue to place significant upward pressure on daily rates for rigs available in 2012 and 2013.
 
Premium jack-up rigs (>350 ft water)
The overall demand for jack-ups rigs globally has improved and the global utilization rate for jack-up rigs has increased to 82% based on increased incremental demand in West Africa, Mexico and the Middle East. As a result, the number of warm stacked and cold stacked jack-up rigs has been reduced. For newer jack-up rigs, built after 2000 and with more than 350ft water depth capacity, the market balance remain sound with a high utilization rate of 96% supported by strong demand for in most regions. In light of this development, daily rates for older jack-up rigs have improved to cater for reactivation cost for such units. For newer jack-up rigs we have seen only modest increases in daily rates but significant increases in contract length as the number of term contracts that has been offered and entered into by market participants developed positively. The observed market development suggests a positive trend in terms of rig demand, utilization rates, contract length and levels for daily rates. In this environment oil companies continues to show a preference for newer equipment due to their superior technical capacities and operational flexibility.
 
Tender Rigs
We have recently seen a surge in daily rates for our tender rigs based on limited availability of premium equipment. Our customers have demonstrated a strong focus on operational efficiency something that favors newer equipment and experienced operators. We also see an increasing awareness from oil companies for the tender rig concept and its benefits in term of efficiency and operability. The contract with Amerada Hess in Equatorial Guinea for our newbuild West Esperanza is a good example of a customer that has recognized such benefits. The contract in Equatorial Guinea also increases our operational footprint in West Africa and the size of our fleet in that region.
 
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, 2011 and 2010, respectively, is reflected in the Consolidated Financial Statements included in Item 18 of this Annual Report.
 
 
47
 
 
F.
CONTRACTUAL OBLIGATIONS
 
  At December 31, 2011, we had the following contractual obligations and commitments:
 
 
 
Payment due by period
 
(In millions of US dollars)
 
Less than
1 year
 
 
1 – 3
years
 
 
3 – 5
years
 
 
After
5 years
 
 
Total
 
3.375% convertible bonds due 2017 (1)
 
 
-
 
 
 
-
 
 
 
-
 
 
 
650
 
 
 
650
 
Interest bearing debt (2)
 
 
1,419
 
 
 
3,721
 
 
 
2,679
 
 
 
1,629
 
 
 
9,448
 
Related party interest bearing debt
 
 
-
 
 
 
-
 
 
 
-
 
 
 
435
 
 
 
435
 
Total debt repayments
 
 
1,419
 
 
 
3,721
 
 
 
2,679
 
 
 
2,714
 
 
 
10,533
 
Total interest payments (3)
 
 
329
 
 
 
493
 
 
 
306
 
 
 
31
 
 
 
1,159
 
Accrued pension liabilities
 
 
10
 
 
 
17
 
 
 
14
 
 
 
2
 
 
 
43
 
Other non-current liabilities
 
 
                                
0
 
Total operating lease obligations
 
 
17
      
15
      
9
      
10
 
 
 
51
 
Total drilling unit purchases (4)
 
 
506
 
 
 
2,506
 
 
 
-
 
 
 
-
 
 
 
3,012
 
Total contractual cash obligations
 
 
2,281
 
 
 
6,752
 
 
 
3,008
 
 
 
2,757
 
 
 
14,798
 
 
(1) In October 2010, we issued $650 million of 3.375% convertible bonds with maturity 2017. Due to the hybrid nature of this financial instrument, for accounting purposes the liability is divided into $545 million of debt and $105 million of equity. The above contractual obligations assume that none of the bonds are converted into common shares and that the full $650 million is repayable in 2017. Accordingly, total debt repayments shown above exceed the interest bearing debt shown in the consolidated balance sheet by $105 million as of December 31, 2011.
 
(2) In January 2012, we issued a NOK1,250 million unsecured bond with maturity date February 13,2014. The bond bears interest at NIBOR plus 3.25%. As part of the arrangement, holders of the of the June 2005 bond, SEM 05, were offered a full prepayment in return for investing two times the amount of their current investment in the new issue. Consequently, a partial NOK341 million buyback of the SME 05 bond took place simultaneously.
 
(3) Interest payments are based on the assumption that all company and subsidiary loans are fully drawn over the period. It is further assumed that no refinancing of existing loans takes place and that there is no repayment on revolving credit facilities. Interest has been calculated using the US dollar Yield Curve published by Bloomberg, plus agreed margins for each loan facility. The effects of interest rate swaps have been included in the calculations.
 
(4) Drilling unit purchase commitments relate to five jack-up rigs, equaling a total price of $1.1 billion, four tender rigs of $0.4 billion, one semi-submersible rig of $0.1 billion and three drillships of $1.4 billion.
 
G.
SAFE HARBOR
 
See section entitled "Forward Looking Statements" in this Annual Report.
 
ITEM 6.
DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
 
A.
DIRECTORS AND SENIOR MANAGEMENT
 
The following table sets forth information regarding our directors and officers, and also certain key employees within our operating subsidiaries, who are responsible for overseeing the management of our business.
 
Name
Age
Position
John Fredriksen
67
President, Director and Chairman of the Board
Tor Olav Trøim
48
Vice President and Director
Kate Blankenship
47
Director and Audit Committee member
Carl Erik Steen
60
Director
Kathrine Fredriksen
28
Director
Georgina Sousa
61
Company Secretary
Alf C. Thorkildsen
55
Chief Executive Officer and President, Seadrill Management AS
Per Wullf
51
Chief Operating Officer and Executive Vice President, Seadrill Management AS
Esa Ikäheimonen*
48
Chief Financial Officer and Senior Vice President, Seadrill Management AS
 
 
48
 
 
Robert Hingley-Wilson
38
Chief Accounting Officer and Senior Vice President, Seadrill Management AS
Rune Magnus Lundetræ
35
Designated Chief Financial Officer and Senior Vice President, Seadrill Management AS
Svend Anton Maier
47
Senior Vice President Africa, Middle-East
Sveinung Lofthus
50
Senior Vice President Europe
Iain Hope
42
Senior Vice President Americas
Alf Ragnar Løvdal
53
Senior Vice President Asia Pacific

* In February 2012, it was announced that Esa Ikäheimonen will leave the Company during the second half of 2012 to pursue other career opportunities. The Company has decided to divide the Chief Financial Officer role in Seadrill Management AS into two positions: Chief Financial Officer (CFO) and Chief Accounting Officer (CAO). Robert Hingley-Wilson was appointed as the new CAO and SVP with immediate effect on February 2, 2012, and Rune Magnus Lundetræ was appointed as designated CFO.
 
Certain biographical information about each of our directors, executive officers and key officers is set forth below.
 
John Fredriksen has served as Chairman of the Board, President and a director of the Company since its inception in May 2005. Mr. Fredriksen has established trusts for the benefit of his immediate family which control Hemen, our largest shareholder. Mr. Fredriksen is Chairman, President, Chief Executive Officer and a director of a related party Frontline, a Bermuda company listed on the NYSE, the Oslo Stock Exchange and the London Stock Exchange. He is also a director of a related party, Golar LNG Limited, or Golar, a Bermuda company listed on the Nasdaq Global Market and the Oslo Stock Exchange whose principal shareholder is World Shipholding Limited, a company indirectly influenced by trusts established by Mr. John Fredriksen for the benefit of his immediate family. He is also a director of a related party Golden Ocean Group Limited, or Golden Ocean, a Bermuda company publicly listed on the Oslo Stock Exchange and on the Singapore stock exchange, whose principal shareholder is Hemen.
 
Tor Olav Trøim has served as Vice-President and a director of the Company since its inception in May 2005. Mr. Trøim graduated as M.Sc Naval Architect from the University of Trondheim, Norway in 1985. His careers include Equity Portfolio Manager with Storebrand ASA (1987-1990), and Chief Executive Officer for the Norwegian Oil Company DNO AS (1992-1995). Mr. Trøim has also been a director of Archer Limited since its incorporation in 2007. Mr. Trøim is also a director of Golar, and is currently a director of three Oslo Stock Exchange listed companies, Golden Ocean (also listed on the Singapore Stock Exchange), Aktiv Kapital ASA and Marine Harvest ASA. He served as a director of Frontline from November 1997 until February 2008.
 
Kate Blankenship has served as a director of the Company since its inception in May 2005. Mrs. Blankenship has also served as a director of Frontline since 2003. Mrs. Blankenship joined Frontline in 1994 and served as its Chief Accounting Officer and Secretary until October 2005. Mrs. Blankenship has been a director of Ship Finance since October 2003. Mrs. Blankenship has been a director of North Atlantic since February 2011, Independent Tankers Corporation Limited since February 2008, Golar since July 2003 and Golden Ocean since November 2004 and Archer Limited since its incorporation in 2007. She is a member of the Institute of Chartered Accountants in England and Wales.
 
Kathrine Fredriksen has served as a director of the Company since September 2008. Ms. Fredriksen has also served as a director of Golar since February 2008. She graduated from Wang Handels Gymnas in Norway and studied at the European Business School in London. Ms. Fredriksen is the daughter of Mr. John Fredriksen, our President and Chairman.
 
Carl Erik Steen was appointed to the Board in February 2011, filling the vacancy left by the retirement of former board member Kjell E Jacobsen on December 31, 2010. In 1975, Mr. Steen graduated from ETH Zurich Switzerland with a M.Sc. in Industrial and Management Engineering. He then worked as a consultant in various Norwegian companies before joining I.M. Skaugen as a Director in 1978. In 1983, Mr. Steen moved to Christiania Bank Luxembourg, and in 1987 returned to Norway to establish the international shipping desk of Christiania Bank. In 1992, Mr. Steen was appointed Executive Vice President with the responsibility of Christiania Bank's Shipping, Offshore and International activities. From January 2001 until February 2011, Mr. Steen was head of Nordea Bank's Shipping, Oil Services & International Division. Mr. Steen is also a board member of Eksportfinans (the Norwegian export credit institution for Export Financing), Wilh. Wilhelsen Holding ASA, Eitzen Chemical ASA and RS Platou ASA.
 
Georgina Sousa has served as Company Secretary of the Company since February 2006. She is currently Head of Corporate Administration for Frontline. Until January 2007, she was Vice-President-Corporate Services of Consolidated Services Limited, a Bermuda Management Company, having joined the firm in 1993 as Manager of Corporate Administration.  From 1976 to 1982 she was employed by the Bermuda law firm of Appleby, Spurling & Kempe as a Company Secretary and from 1982 to 1993 she was employed by the Bermuda law firm of Cox & Wilkinson as Senior Company Secretary.
 
Alf C. Thorkildsen has served as Chief Executive Officer and President of Seadrill Management AS since June 2008. From 2007 to 2008 Mr. Thorkildsen served as Chief Operating Officer in Seadrill. From 2002 to 2006, Mr. Thorkildsen was the Chief Financial Officer for the offshore drilling contractor Smedvig, and following the acquisition of Smedvig by Seadrill, Mr. Thorkildsen served as the Chief Financial Officer in Seadrill Management AS until 2007. Prior to joining Smedvig, Mr. Thorkildsen worked for more than 20 years at Royal Dutch Shell plc, or Shell, in various senior positions. Mr. Thorkildsen graduated from the Norwegian School of Business Administration with a degree in economics and from Arizona State University with a Masters of Business Administration.
 

 
49
 

Per Wullf has served as the Chief Operating Officer and Executive Vice President of Seadrill Management AS since February 2009. Mr. Wullf has more than 28 years of experience in the international offshore and onshore drilling industry with A.P. Moller - Maersk A/S, serving as Managing Director for Maersk Drilling Norge AS from 2006 to 2009.
 
Esa Ikäheimonen has served as the Chief Financial Officer and Senior Vice President of Seadrill Management AS since August 2010. Prior to joining the Company, Mr. Ikäheimonen served as Executive Vice President and Chief Financial Officer of Poyry Plc, a global consulting and engineering company. Before that he served with Royal Dutch Shell for almost 20 years and held several senior positions, including regional Vice President, Finance for Upstream in both Africa and Middle-East, Finance and Commercial Director in Qatar, and Downstream Finance Director for Scandinavia. Mr. Ikäheimonen holds a masters degree in Law from the University of Turku in Finland.
 
In February 2012, it was announced that Esa Ikäheimonen will leave the Company during the second half of 2012 to pursue other career opportunities.  The Company has decided to divide the Chief Financial Officer role in Seadrill Management AS into two positions: Chief Financial Officer, or CFO, and Chief Accounting Officer, or CAO, that shall report to the CEO in Seadrill Management AS, Alf C Thorkildsen as part of the executive management team.  The revised CFO role shall focus on managing Investor Relations, Treasury, Tax, and Risk and Insurance, whereas the new role of CAO shall manage all accounting and controlling work, including external reporting. Robert Hingley-Wilson was appointed as the new CAO and SVP with immediate effect on February 2, 2012, and Rune Magnus Lundetræ was appointed as designated CFO.
 
Robert Hingley-Wilson was appointed CAO, and Senior Vice President of Seadrill Management AS, in February 2012. Mr. Hingley-Wilson has served as Group Chief Accountant to a group of related companies since 2010 as an employee of Frontline Corporate Services UK Ltd.  Mr. Hingley-Wilson has an extensive background in M&A and complex accounting with both Frontline Ltd and its associated companies and in PricewaterhouseCoopers in New York City and London, where Mr. Hingley-Wilson worked from 1996 until joining Frontline in 2010. Mr. Hingley-Wilson has a law degree and trained as a Solicitor in the United Kingdom, and has been a member of the Institute of Chartered Accountants in England and Wales since 1998.
 
Rune Magnus Lundetræ was appointed designated Chief Financial Officer and Senior Vice President in February 2012. He will take over as CFO when Mr Esa Ikaheimonen retires from the position later this year. Before his current position Mr. Lundetræ was Finance Director for Seadrill Americas and Commercial Director for Seadrill Europe (now North Atlantic Drilling Limited). He also served as CFO for Scorpion Offshore Ltd after Seadrill acquired a majority stake in the company in July 2010 and up to delisting the company in November 2010. Prior to joining Seadrill Mr. Lundetræ worked as an auditor for KPMG and PricewaterhouseCoopers in Stavanger, Norway from 2001 until 2007. Mr. Lundetræ graduated as MSc in Management from the London School of Economics in 2001 and as MSc in Accounting and Auditing from the Norwegian School of Business Administration (NHH) in 2004. He registered as a Certified Public Accountant (CPA) in Norway in 2005.
 
Svend Anton Maier has served as Senior Vice President, Africa and Middle-East since January 2011. Mr. Maier joined the Company in February 2007 as Vice President, Deepwater Eastern Hemisphere. Mr. Maier has more than 20 years of experience in the offshore drilling industry. Prior to joining us, Mr. Maier held several senior positions in Transocean Ltd., including operations manager in Egypt, Equatorial Guinea and Gabon. Mr. Maier graduated from the Maritime Institute of Tønsberg with a degree in marine engineering.
 
Sveinung Lofthus has served as the Senior Vice President, Europe since 2005. Mr. Lofthus has more than 20 years experience in the international offshore and onshore drilling industry, including project and rig management positions in Smedvig. Mr. Lofthus graduated from the University of Stavanger with a degree in petroleum engineering.
 
Alf Ragnar Løvdal was appointed Senior Vice President Asia Pacific in January 2011. From April 2009, Mr. Løvdal held the position of Senior Vice President, Tender Rigs in April 2009. He was previously CEO in Seawell Management AS. Mr. Løvdal has 30 years of experience in the oil and gas industry, including two years as Chief Executive Officer in Seawell management AS, 20 years responsibility for the well services business in the drilling contractor Smedvig and five years of offshore field experience with Schlumberger. He has a degree in mechanical engineering from Horten Engineering Academy in Norway.
 
Iain Hope joined Seadrill in 2009 and has served as Senior Vice President Americas since January 2011. Mr. Hope has 20 years of experience in the drilling industry, most recently as director of operations excellence for Seadrill Americas. Prior to joining Seadrill, Mr. Hope held several senior positions at Transocean including division manager South America, director of deepwater marketing, operation manager North America and rig manager in Brazil, West Africa and North Sea. He has a bachelor degree in Electrical and Electronic Engineering from Robert Gordon's, Aberdeen and completed postgraduate studies in Drilling Engineering prior to entering the industry.
 
50
 
 
B.
COMPENSATION
 
During the year ended December 31, 2011, we paid our directors and executive officers aggregate compensation of $20.0 million, including compensation in the form of options exercised. In addition we have incurred compensation expense in the aggregate amount of $0.1 million for their pension and retirement benefits. These amounts include compensation of $2.2 million paid to the Chief Executive Officer, excluding compensation related to exercised options, and $0.05 million expensed for the Chief Executive Officer's pension and retirement benefits.
 
In the event the Chief Executive Officer resigns at the request of the Board of Directors, he will receive compensation equal to his salary for two years.
 
In addition to cash compensation, during 2011 we also recognized an expense of $2.9 million relating to stock options granted in 2009, 2010 and 2011 to certain of our directors and employees. The options vest over a three to five year period, with the first tranche vesting in May 2012, and they expire between May 2014 and April 2017. The exercise price of the options at December 31, 2011, was in the range NOK56.0 to NOK202.1 (equivalent to $9.3 to $33.7) per share, and will for most options be reduced by the amount of any future dividends declared with respect to the common shares.
 
C.
BOARD PRACTICES
 
Our Board of Directors is elected annually by a vote of a majority of the common shares represented at the meeting at which one or more holders of one-third of our outstanding common shares constitutes a quorum. In addition, the maximum and minimum number of directors is determined by our shareholders at the annual general meeting, but no less than two directors shall serve at any given time. Each director shall hold office until the next annual general meeting following his or her election or until his or her successor is elected.
 
Our Board of Directors currently consists of five directors. Three of our directors, John Fredriksen, Kathrine Fredriksen and Tor Olav Trøim may be deemed affiliated with our largest shareholder, Hemen. Two of our directors, Kate Blankenship and Carl Steen, are independent pursuant to Rule 10A-3 of the Securities and Exchange Commission.
 
We currently have an audit committee, which is responsible for overseeing the quality and integrity of our financial statements and its accounting, auditing and financial reporting practices, our compliance with legal and regulatory requirements, the independent auditor's qualifications, independence and performance and our internal audit function. Our audit committee consists of Mrs. Blankenship.
 
In 2011, we formed a compensation committee responsible for establishing and reviewing the executive officers' and senior managements' compensation and benefits. Our committee consists of Mr. Trøim and Mrs. Blankenship.
 
In lieu of a nomination committee, our Board of Directors is responsible for identifying and recommending potential candidates to become board members and recommending directors for appointment to board committees.
 
There are no service contracts between us and any of our directors providing for benefits upon termination of their employment or service.
 
As a foreign private issuer we are exempt from certain requirements of the New York Stock Exchange that are applicable to U.S. listed companies. For a listing and further discussion of how our corporate governance practices differ from those required of U.S. companies listed on the New York Stock Exchange, please see Item 16G or visit the corporate governance section of our website at www.seadrill.com.
 
D.
EMPLOYEES
 
As at April 24, 2012, we have approximately 7,600 employees.
 
Some of our employees and our contracted labor, most of whom work in Brazil, Nigeria, Norway and the U.K., are represented by collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and have restricted ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.
 
 
51
 
 
We consider our relationships with the various unions as stable, productive and professional. At present, there are no ongoing negotiations or outstanding issues.
 
Total employees (including contracted-in staff )
 
December 31,
2009
 
 
December 31,
2010
 
 
December 31,
2011
 
 
March 31,
2012
 
Operating segments:
 
  
 
 
 
 
 
 
 
 
 
 
Floaters
 
  
2,650
 
 
 
3,000
 
 
 
3,170
      
3,250
 
Jack-up rigs
 
  
450
 
 
 
1,500
 
 
 
1,900
      
1,900
 
Tender rigs
 
  
1,800
 
 
 
2,100
  
 
 
2,300
      
2,300
 
Corporate
 
  
100
 
 
 
100
 
 
 
130
      
150
 
Total employees
 
  
5,000
 
 
 
6,700
 
 
 
7,500
      
7,600
 
 
 
 
 
 
 
 
 
 
 
 
          
 
Geographical location:
 
 
 
 
 
 
 
 
 
 
          
 
Norway
 
 
1,000
  
 
 
1,100
 
 
 
1,100
      
1,100
 
Rest of Europe
 
 
0
  
 
 
0
 
 
 
100
      
200
 
USA
 
 
400
  
 
 
500
 
 
 
600
      
600
 
South America
 
 
900
  
 
 
1,100
 
 
 
1,100
      
1,100
 
Asia and Australia
 
 
2,500
  
 
 
3,100
 
 
 
3,200
      
3,200
 
Africa
 
 
200
  
 
 
900
 
 
 
1,400
      
1,400
 
Total employees
 
 
5,000
      
6,700
 
 
 
7,500
      
7,600
 
 
The number of employees has increased over the three years to December 31, 2011 as a result of the increase in our operating fleet of drilling units and business acquisitions.
 
E.
SHARE OWNERSHIP
 
The table below shows the number of common shares beneficially owned and the percentage owned of our outstanding common shares for our directors, officers and key employees as of April 24, 2012, and the percentage held of the total common shares in issue. Also shown are their interests in share options awarded to them under the Option Scheme which was approved by the Company in May 2005. The subscription price for options granted under the scheme will normally be reduced by the amount of all dividends declared by the Company in the period from the date of grant until the date the option is exercised.
 
Director or Key Employee
  
Beneficial Interest in
Common Shares of
$2.00 each
  
Interest in Options
  
 
 
Number of shares
 
 
%
 
Total
number of
options
 
 
Number of
options
vested
 
 
Exercise price
 
 
Expiry date
 
John Fredriksen (2)
 
 
(2
)
 
(2
)
 
-
 
 
-
 
 
 -
 
 
 -
 
Tor Olav Trøim (3)
 
 
635,000
 
 
(1
)
 
-
 
 
-
 
 
 -
 
 
 -
 
Kate Blankenship
 
 
41,000
 
 
(1
)
 
20,000
 
 
13,333
 
 
NOK51.5
 
 
May 2014
 
Kathrine Fredriksen
 
 
-
 
 
(1
)
 
-
 
 
-
 
 
 -
 
 
 -
 
Carl Erik Steen
    
-
    
(1
)
  
-
    
-
    
-
    
-
  
Georgina Sousa
 
 
-
 
 
(1
)
 
-
 
 
-
 
 
 -
 
 
 -
 
Alf C. Thorkildsen
 
 
20,000
 
 
(1
)
 
325,000 100,000 100,000
 
 
216,666
20,000
-
 
 
NOK51.5
NOK159.5
NOK193.2
 
 
May 2014
December 2015
December 2016
 
Esa Ikäheimonen
 
 
 
 
 
(1
)
 
100,000
60,000 60,000
 
 
50,000
12,000
 -
 
 
NOK104.1
NOK159.5
NOK193.2
 
 
May 2015
December 2015
December 2016
 
Per Wullf
 
 
-
 
 
(1
)
 
50,000
60,000 60,000
 
 
-
12,000
-
 
 
NOK51.5
NOK159.5
NOK193.2
 
 
May 2014
December 2015
December 2016
 
Iain Hope
 
 
-
 
 
(1
)
 
13,400
40,000 60,000
 
 
6,700
8,000
-
 
 
NOK104.6
NOK192.9
NOK202.1
 
 
May 2014
December 2015
December 2016
 
 
 
52
 
 
Sveinung Lofthus
 
 
2,000
 
 
(1
)
 
40,000
40,000 60,000
 
 
20,000
8,000
-
 
 
NOK51.5
NOK159.5
NOK176.4
 
 
May 2014
December 2015
December 2015
 
Rune Magnus Lundetræ
          
(1
)
  
3,400
20,000
15,000
15,000
40,000
    
-
10,000
3,000
-
-
    
NOK51.5
NOK104.1
NOK159.5
NOK193.2
NOK219.1
    
May 2014
May 2015
December 2015
December 2016
April 2017
  
Alf Ragnar Løvdal
 
 
-
 
 
(1
)
 
14,000
40,000 60,000
 
 
-
8,000
-
 
 
NOK51.5
NOK159.5
NOK193.2
 
 
May 2014
December 2015
December 2016
 
Svend Anton Maier
 
 
-
 
 
(1
)
 
60,000
40,000 60,000
 
 
40,000
8,000
-
 
 
NOK51.5
NOK159.5
NOK193.2
 
 
May 2014
December 2015
December 2016
  
Robert Hingley-Wilson
    
-
    
(1
)
  
40,000
    
-
    
NOK219.1
    
April 2017
 
 
(1) less than 1%.
 
(2) Hemen Holding Limited, a Cyprus holding company, and other related companies which are collectively referred to herein as Hemen, the shares of which are held in trusts established by Mr. John Fredriksen for the benefit of his immediate family. Mr. Fredriksen disclaims beneficial ownership of the 109,097,583 shares of our common stock held by Hemen, except to the extent of his voting and dispositive interest in such shares of common stock. Mr. Fredriksen has no pecuniary interest in the shares held by Hemen. In addition, to the holdings of shares and options contained in the table above, as of April 26, 2011, Hemen is party to separate TRS agreements relating to 3,900,000 of our common shares.
 
(3) In addition to the holdings of shares and options contained in the table above, as of April 26, 2011, Drew Investment Ltd., a company controlled by Tor Olav Trøim, is party to separate TRS agreements relating to 400,000 of our common shares.
 
ITEM 7.
MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
 
A.
MAJOR SHAREHOLDERS
 
The following table presents certain information as at April 24, 2012, regarding the ownership of our common shares with respect to each shareholder whom we know to beneficially own more than 5% of our outstanding common shares:
 
 
 
Common Shares Held
 
Shareholder
 
Number
 
 
%
 
Hemen (1)
 
 
109,097,583
 
 
 
23.2
%
Folketrygdfondet (2)
 
 
23,736,823
 
 
 
5.1
%

(1) As discussed above, the shares of Hemen are held in trusts established by Mr. John Fredriksen for the benefit of his immediate family.
 
On March 1, 2012, Hemen announced that it had sold 24 million shares and 24 million put options at a combined purchase price of NOK236.3176 per share and per seller put option. Following the sale, Hemen's holding of shares in Seadrill Limited was reduced to 23.2%, or 109,097,583 shares. If all put options are exercised with physical delivery at expiry Hemen's position in Seadrill will increase by 24 million shares to its pre-transaction level of 133,097,583 shares, or 28%. In addition Hemen has TRS agreements with underlying exposure to 3.9 million shares in Seadrill.
 
(2) Folketrygdfondet manages the Government Pension Fund of Norway on behalf of the Norwegian Ministry of Finance.
 
As of April 24, 2012 the Company had a single shareholder of record in the United States, in whose name all shareholdings in the United States are recorded. We had a total of 469,250,933 common shares outstanding of which 1,281,359 were held as treasury shares, as of April 24, 2012.
 
Our major shareholders have the same voting rights as our other shareholders. No corporation or foreign government owns more than 50% of our outstanding common shares. We are not aware of any arrangements, the operation of which may at a subsequent date result in a change in control of Seadrill.
 
B.
RELATED PARTY TRANSACTIONS
 
We were formed on May 10, 2005, and our shares commenced trading on the Oslo Stock Exchange in November 2005.  Our shares commenced trading on the New York Stock Exchange in April 2010.  Since our formation, our largest shareholder has been Hemen, which currently holds approximately 23% of our shares.  Under the mandatory offer rules of the Oslo Stock Exchange, if Hemen were to acquire more than 1/3 of our shares, it could trigger the mandatory offer rules.  Hemen has not advised us of any intention to do so.
 

 
53
 

We transact business with the following related parties, being companies in which Hemen and companies associated with Hemen have a significant interest:
 
 
·
Ship Finance International Limited, or Ship Finance
 
 
·
Asia Offshore Drilling Limited, or AOD
 
 
·
Scorpion Offshore Ltd, or Scorpion
 
 
·
Metrogas Holdings Inc, or Metrogas
 
 
·
Frontline Management (Bermuda) Limited, or Frontline
 
The Company has entered into sale and lease back contracts for several drilling units with Ship Finance, a company in which our principal shareholders Hemen and companies associated with Hemen have a significant interest. Hemen is controlled by trusts established by the Company's President and Chairman Mr. John Fredriksen for the benefit of his immediate family. The Company has determined that the Ship Finance subsidiaries, which own the units, are variable interest entities, or VIEs, and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company's consolidated accounts. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in the Company's consolidated accounts.
 
On March 31, 2012, we obtained a short-term unsecured credit facility of $84 million from Metrogas, The amount is repayable in June 2012 and bears interest in accordance with arms-length principles.
 
In the year ended December 31, 2011, the Company incurred the following lease costs on units leased back from Ship Finance subsidiaries.
 
Rig
 
In millions of
US dollars
 
West Prospero
 
 
7
 
West Polaris
 
 
126
 
West Hercules
 
 
120
 
West Taurus
 
 
112
 
Total
 
 
365
 

These lease costs are eliminated at consolidation.
 
On June 24, 2011, we entered into a share sale and purchase agreement with Ship Finance, where we acquired all the shares of Rig Finance II Limited, which was the owner of West Prospero. The acquisition price for the shares amounted to $47 million. This transaction is accounted for as an equity transaction and no gain or loss is recognized.
 
In July 2011, we participated in a private placement in AOD and were allocated shares for $54 million, which corresponds to a 33.75% ownership stake. AOD was established by Mermaid Maritime Public Company Limited in late 2010 when two MOD-V B Class jack-up rigs where ordered at Keppel FELS in Singapore. AOD had additional option agreements for construction of two similar units. Furthermore, it was agreed that we would be responsible for the construction supervision, project management and commercial management of all of AODs jack-up rigs. The total amount of management fees amounted to $2 million for the year ended December 31, 2011.
 
In December 2010, we agreed to amend the original sale and leaseback agreement with Rig Finance II Ltd. granting them a put option exercisable at the end of the lease period at which point in time the jack-up rig West Prospero could be sold to Seadrill at a fixed price of $40 million.
 
On July 1, 2010 our fully consolidated VIEs, SFL Deepwater Ltd and SFL Polaris Ltd, paid a dividend of $290 million and $145 million respectively to Ship Finance. Ship Finance simultaneously granted loans to SFL Deepwater Ltd and SFL Polaris Ltd for the same amounts. The loans bear interest at 4.5% per annum and comprise the balance of $435 million, reported as long-term debt due to related parties in our balance sheet as of December 31, 2011.
 

 
54
 

As of December 31, 2009, the Company had a receivable from Ship Finance of $90 million related to an unsecured credit facility. The loan was repaid on March 30, 2010. Interest payable by Ship Finance, agreed on an arms-length basis, was paid monthly. Interest of $0, $3 and $9 million was received from Ship Finance in the years ended December 31, 2011, 2010 and 2009 respectively.
 
In April 2009, the Company obtained an unsecured credit facility loan of $60 million from Metrogas. The amount was repaid in June 2009. Interest payable in accordance with arms-length principles amounted to $1 million in the year ended December 31, 2009.
 
In November 2009, the Company provided a short-term unsecured loan of $28 million to Scorpion, increased to $80 million in December 2009. Additional loans were provided during 2010 and total outstanding at May 31, 2010 was $240 million at which time Seadrill obtained a controlling interest in Scorpion. The loan was repaid during the third quarter of 2010. Interest payable, agreed on an arms-length basis amounted to $5 million in 2010 in the period prior to obtaining control of Scorpion. $1.0 million of interest was payable to Scorpion in the year ended December 31, 2009.
 
Frontline provides management support and administrative services for the Company, and charged the Company fees of $2 million, $1 million and $0 million for these services in the years 2011, 2010 and 2009, respectively. These amounts are included in "General and administrative expenses".
 
C.
INTERESTS OF EXPERTS AND COUNSEL.
 
Not applicable.
 
ITEM 8.
FINANCIAL INFORMATION
 
A.
CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION
 
Please see the section of this Annual Report on Form 20-F entitled Item 18 "Financial Statements."
 
Legal Proceedings
 
The Company is routinely party, as plaintiff or defendant, to claims and lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the operation of our drilling units, in the ordinary course of our business or in connection with our acquisition activities. The Company believes that the resolution of such claims will not have a material adverse effect on our operations or financial condition, and currently has no outstanding legal proceeding which we consider to be material.
 
Dividend Policy
 
Under our bye-laws, our board of directors may declare cash dividends or distributions, and may also pay a fixed cash dividend biannually or on other dates. The objective of our board of directors is to generate competitive returns for our shareholders. Any dividends declared will be in the sole discretion of the board of directors and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities. Under Bermuda law, a company may not declare or pay a dividend, or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) the company is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of the company's assets would thereby be less than its liabilities.
 
In addition, since we are a holding company with no material assets other than the shares of our subsidiaries through which we conduct our operations, our ability to pay dividends will depend on our subsidiaries' distributing to us their earnings and cash flow.
 
For the years ended December 31, 2011, 2010, 2009 and 2008, we paid aggregate dividends to our shareholders in the amounts of $1,423 million ($3.135 per share), $990 million ($2.41 per share), $199 million ($0.50 per share) and $688 million ($1.75 per share), respectively. In February 2012, we declared a cash dividend of $0.80 which was paid out on March 23, 2012.
 
 
55
 
 
We have paid dividends as follows:
 
Payment date
 
Amount per share
 
2012
        
March 23, 2012
  
$
0.80
  
         
2011
 
 
 
 
March 16, 2011
 
$
0.875
 
June 17, 2011
  
$
0.75
  
September 20, 2011
  
$
0.75
  
December 21, 2011
 
$
0.76
 
 
 
 
 
 
2010
 
 
 
 
March 26, 2010
 
$
0.55
 
July 2, 2010
 
$
0.60
 
September 24, 2010
 
$
0.61
 
December 30, 2010
 
$
0.65
 
 
 
 
 
 
2009
 
 
 
 
December 7, 2009
 
$
0.50
 
 
 
 
 
 
2008
 
 
 
 
March 14, 2008
 
$
0.25
 
June 18, 2008
 
$
0.60
 
September 16, 2008
 
$
0.60
 
September 30, 2008
 
$
0.30
 

B.
SIGNIFICANT CHANGES
 
See Note 35 to our Consolidated Financial Statements.
 
ITEM 9.
THE OFFER AND LISTING
 
A.
OFFER AND LISTING DETAILS
 
Shares of our common stock, par value $2.00 per share, have traded on the Oslo Stock Exchange, or OSE, since November 22, 2005, under the symbol "SDRL" and on the New York Stock Exchange, or NYSE, on April 15, 2010, also under the symbol "SDRL."
 
The NYSE listing is intended to be the Company's "primary listing" and the OSE listing is intended to be the Company's secondary listing.
 
The following table sets forth the fiscal years high and low closing prices of our common shares since they began trading, on the OSE in November 2005 and on the NYSE in April 2010:
 
   
NYSE
    
OSE
  
   
High
(US$)
    
Low
(US$)
    
High
(NOK)
    
Low
(NOK)
  
Fiscal year ended December 31
                        
2011
     38.24       25.88       215.00       148.00  
2010
     34.76       18.09       207.80       115.90  
2009
                     149.80       47.00  
2008
                     179.75       41.60  
2007
                     134.25       91.10  
2006
                     114.50       55.75  

The following table sets forth, for each full financial quarter for the two most recent fiscal years, the high and low closing prices of our common shares trading on the OSE and NYSE:
 
   
NYSE
    
OSE
  
   
High
(US$)
    
Low
(US$)
    
High
(NOK)
    
Low
(NOK)
  
Fiscal year ended December 31, 2011
                        
First quarter
     38.24       32.08       215.00       184.50  
Second quarter
     37.10       32.38       203.40       176.40  
Third quarter
     35.96       26.32       194.80       148.00  
Fourth quarter
     35.85       25.88       205.90       151.00  
 
 
 
56
 
 
                         
   
NYSE
    
OSE
  
   
High
(US$)
    
Low
(US$)
    
High
(NOK)
    
Low
(NOK)
  
Fiscal year ended December 31, 2010
                        
First quarter
                 150.00       124.10  
Second quarter
     27.83       18.09       162.50       117.80  
Third quarter
     28.99       18.47       169.90       115.90  
Fourth quarter
     34.76       28.70       207.80       168.90  

   
OSE
  
   
High
(NOK)
    
Low
(NOK)
  
Fiscal year ended December 31, 2009
            
First quarter
     68.80       47.00  
Second quarter
     101.25       65.40  
Third quarter
     120.60       83.00  
Fourth quarter
     149.80       115.60  

   
OSE
  
   
High
(NOK)
    
Low
(NOK)
  
Fiscal year ended December 31, 2008
            
First quarter
     141.00       102.75  
Second quarter
     179.75       135.50  
Third quarter
     160.25       114.75  
Fourth quarter
     114.00       41.60  

The following table sets forth, for the six most recent months, the high and low closing prices of our common shares trading on the OSE and NYSE:
 
   
NYSE
    
OSE
  
   
High
(US$)
    
Low
(US$)
    
High
(NOK)
    
Low
(NOK)
  
April 2012 *
     38.21       35.78       220.00       209.64  
March 2012
     40.63       36.79       224.70       210.00  
February 2012
     42.07       37.19       231.70       216.40  
January 2012
     37.10       33.95       218.00       200.40  
December 2011
     35.85       31.88       205.90       190.80  
November 2011
     35.04       31.14       200.60       179.90  
October 2011
     34.32       25.88       188.00       151.00  
* For the period through and including April 24, 2012.
 
On April 24, 2012, the exchange rate between the Norwegian Kroner and the US dollar was NOK5.75 to one US dollar.
 
B.
MARKETS
 
Our common shares currently trade on the New York Stock Exchange and the Oslo Stock Exchange under the symbol "SDRL".
 
ITEM 10.
ADDITIONAL INFORMATION
 
A.
SHARE CAPITAL
 
Not applicable.
 
B.
MEMORANDUM OF ASSOCIATION AND BYE-LAWS
 
The Memorandum of Association of the Company was filed as Exhibit 1.1 to the Company's Registration Statement on Form 20-F (Registration No. 001-34667), which was filed with the Securities and Exchange Commission on March 25, 2010, and is hereby incorporated by reference into this Annual Report.
 
 
57
 

The object of our business, as stated in section six of our Memorandum of Association, is to engage in any lawful act or activity for which companies may be organized under the Companies Act, 1981 of Bermuda, as amended (or the Companies Act), other than to issue insurance or re-insurance, to act as a technical advisor to any other enterprise or business or to carry on the business of a mutual fund. Our Memorandum of Association and bye-laws do not impose any limitations on the ownership rights of our shareholders.
 
Shareholder Meetings. Under our Bye-laws, annual shareholder meetings will be held in accordance with the Companies Act at a time and place (other than Norway) selected by our board of directors. The quorum at any annual or general meeting is equal to one or more shareholders, either present in person or represented by proxy, holding in the aggregate shares carrying 33 1/3% of the exercisable voting rights. The meetings may be held at any place, in or outside of Bermuda that is not a jurisdiction which applies a controlled foreign company tax legislation or similar regime. Special meetings may be called at the discretion of the board of directors and at the request of shareholders holding at least one-tenth of all outstanding shares entitled to vote at a meeting. Annual shareholder meetings and special meetings must be called by not less than seven days' prior written notice specifying the place, day and time of the meeting. The board of directors may fix any date as the record date for determining those shareholders eligible to receive notice of and to vote at the meeting.
 
The Companies Act provides that a company must have a general meeting of its shareholders in each calendar year. The Companies Act does not impose any general requirements regarding the number of voting shares which must be present or represented at a general meeting in order for the business transacted at the general meeting to be valid. The Companies Act generally leaves the quorum for shareholders meeting to the company to determine in its Bye-laws. The Companies Act specifically imposes special quorum requirements where the shareholders are being asked to approve the modification of rights attaching to a particular class of shares (33.33%) or an amalgamation or merger transaction (33.33%) unless in either case the Bye-laws provide otherwise. The Company's Bye-laws do not provide for a quorum requirement other than 33.33%.
 
There are no limitations on the right of non-Bermudians or non-residents of Bermuda to hold or vote our common shares.
 
The key powers of our shareholders include the power to alter the terms of the Company's Memorandum of Association and to approve and thereby make effective any alterations to the Company's Bye-laws made by the directors. Dissenting shareholders holding 20% of the Company's shares may apply to the Court to annul or vary an alteration to the Company's Memorandum of Association. A majority vote against an alteration to the Company's Bye-laws made by the directors will prevent the alteration from becoming effective. Other key powers are to approve the alteration of the Company's capital including a reduction in share capital, to approve the removal of a director, to resolve that the Company be wound up or discontinued from Bermuda to another jurisdiction or to enter into an amalgamation or winding up. Under the Companies Act, all of the foregoing corporate actions require approval by an ordinary resolution (a simple majority of votes cast), except in the case of an amalgamation or merger transaction, which requires approval by 75% of the votes cast unless the Bye-Laws provide otherwise). The Company's Bye-laws only require an ordinary resolution to approve an amalgamation. In addition, the Company's Bye-laws confer express power on the board to reduce its issued share capital selectively with the authority of an ordinary resolution.
 
The Companies Act provides shareholders holding 10% of the Company's voting shares the ability to request that the board of directors shall convene a meeting of shareholders to consider any business which the shareholders wish to be discussed by the shareholders including (as noted below) the removal of any director. However, the shareholders are not permitted to pass any resolutions relating to the management of the Company's business affairs unless there is a pre-existing provision in the Company's Bye-Laws which confers such rights on the shareholders. Subject to compliance with the time limits prescribed by the Companies Act, shareholders holding 20% of the voting shares (or alternatively, 100 shareholders) may also require the directors to circulate a written statement not exceeding 1000 words relating to any resolution or other matter proposed to be put before, or dealt with at, the annual general meeting of the Company.
 
Majority shareholders do not generally owe any duties to other shareholders to refrain from exercising all of the votes attached to their shares. There are no deadlines in the Companies Act relating to the time when votes must be exercised.
 
The Companies Act provides that a company shall not be bound to take notice of any trust or other interest in its shares. There is a presumption that all the rights attaching to shares are held by, and are exercisable by, the registered holder, by virtue of being registered as a member of the company. The company's relationship is with the registered holder of its shares. If the registered holder of the shares holds the shares for someone else (the beneficial owner) then if the beneficial owner is entitled to the shares, the beneficial owner may give instructions to the registered holder on how to vote the shares. The Companies Act provides that the registered holder may appoint more than one proxy to attend a shareholder meeting, and consequently where rights to shares are held in a chain the registered holder may appoint the beneficial owner as the registered holder's proxy.
 
Directors. The Companies Act provides that the directors shall be elected or appointed by the shareholders. A director may be elected by a simple majority vote of shareholders, at a meeting where shareholders holding not less than 33.33% of the voting shares are present in person or by proxy. A person holding 50% or more of the voting shares of the Company will be able to elect all of the directors, and to prevent the election of any person whom such shareholder does not wish to be elected. There are no provisions for cumulative voting in the Companies Act or the Bye-Laws and the Company's Bye-Laws do not contain any super-majority voting requirements. The appointment and removal of directors is covered by Bye-laws 89, 90 and 91.
 
 
58
 
 
There are procedures for the removal of one or more of the directors by the shareholders before the expiration of his term of office. Shareholders holding 10% or more of the voting shares of the Company may require the board of directors to convene a shareholder meeting to consider a resolution for the removal of a director. At least 14 days' written notice of a resolution to remove a director must be given to the director affected, and that director must be permitted to speak at the shareholder meeting at which the resolution for his removal is considered by the shareholders.
 
The Companies Act stipulates that an undischarged bankruptcy of a director (in any country) shall prohibit that director from acting as a director, directly or indirectly, and taking part in or being concerned with the management of a company, except with leave of the court. The Company's Bye-Law 92 is more restrictive in that it stipulates that the office of a Director shall be vacated upon the happening of any of the following events (in addition to the Director's resignation or removal from office by the shareholders):
 
 
·
If he becomes of unsound mind or a patient for any purpose of any statute or applicable law relating to mental health and the Board resolves that he shall be removed from office;
 
 
·
If he becomes bankrupt or compounds with his creditors;
 
 
·
If he is prohibited by law from being a Director; or
 
 
·
If he ceases to be a Director by virtue of the Companies Act.
 
Under the Company's Bye-laws, the minimum number of directors comprising the board of directors at any time shall be two. The board of directors currently consists of six directors. The minimum and maximum number of directors comprising the board of directors from time to time shall be determined by way of an ordinary resolution of the shareholders of the Company. The shareholders may, at the annual general meeting by ordinary resolution, determine that one or more vacancies in the board of directors be deemed casual vacancies. The board of directors, so long as a quorum remains in office, shall have the power to fill such casual vacancies. Each director will hold office until the next annual general meeting or until his successor is appointed or elected. The shareholders may call a Special General Meeting for the purpose of removing a director, provided notice is served upon the concerned director 14 days prior to the meeting and he is entitled to be heard. Any vacancy created by such a removal may be filled at the meeting by the election of another person by the shareholders or in the absence of such election, by the board of directors.
 
The Company's Bye-laws do not prohibit a director from being a party to, or otherwise having an interest in, any transaction or arrangement with the Company or in which the Company is otherwise interested. The Company's Bye-laws provide that a director who has an interest in any transaction or arrangement with the Company and who has complied with the provisions of the Companies Act and with its Bye-Laws with regard to disclosure of such interest shall be taken into account in ascertaining whether a quorum is present, and will be entitled to vote in respect of any transaction or arrangement in which he is so interested. The Company's Bye-law 97 provides its board of directors the authority to exercise all of the powers of the Company to borrow money and to mortgage or charge all  or any part of our property and assets as collateral security for any debt, liability or obligation. The Company's directors are not required to retire because of their age, and the directors are not required to be holders of the Company's common shares. Directors serve for one year terms, and shall serve until re-elected or until their successors are appointed at the next annual general meeting. The Company's Bye-laws provide that no director, alternate director, officer, person or member of a committee, if any, resident representative, or his heirs, executors or administrators, which we refer to collectively as an indemnitee, is liable for the acts, receipts, neglects, or defaults of any other such person or any person involved in our formation, or for any loss or expense incurred by us through the insufficiency or deficiency of title to any property acquired by us, or for the insufficiency of deficiency of any security in or upon which any of our monies shall be invested, or for any loss or damage arising from the bankruptcy, insolvency, or tortious act of any person with whom any monies, securities, or effects shall be deposited, or for any loss occasioned by any error of judgment, omission, default, or oversight on his part, or for any other loss, damage or misfortune whatever which shall happen in relation to the execution of his duties, or supposed duties, to us or otherwise in relation thereto. Each indemnitee will be indemnified and held harmless out of our funds to the fullest extent permitted by Bermuda law against all liabilities, loss, damage or expense (including but not limited to liabilities under contract, tort and statute or any applicable foreign law or regulation and all reasonable legal and other costs and expenses properly payable) incurred or suffered by him as such director, alternate director, officer, person or committee member or resident representative (or in his reasonable belief that he is acting as any of the above). In addition, each indemnitee shall be indemnified against all liabilities incurred in defending any proceedings, whether civil or criminal, in which judgment is given in such indemnitee's favor, or in which he is acquitted. The Company is authorized to purchase insurance to cover any liability it may incur under the indemnification provisions of its Bye-laws. The indemnification provisions are covered by Bye-laws 138 through 146.
 
 
59
 
 
Dividends. Holders of common shares are entitled to receive dividend and distribution payments, pro rata based on the number of common shares held, when, as and if declared by the board of directors, in its sole discretion. Any future dividends declared will be at the discretion of the board of directors and will depend upon our financial condition, earnings and other factors.
 
As a Bermuda exempted company, we are subject to Bermuda law relating to the payment of dividends. We may not pay any dividends if, at the time the dividend is declared or at the time the dividend is paid, there are reasonable grounds for believing that, after giving effect to that payment;
 
 
·
we will not be able to pay our liabilities as they fall due; or
 
 
·
the realizable value of our assets is less than our liabilities.
 
In addition, since we are a holding company with no material assets, and conduct our operations through subsidiaries, our ability to pay any dividends to shareholders will depend on our subsidiaries' distributing to us their earnings and cash flow. Some of our loan agreements currently limit or prohibit our subsidiaries' ability to make distributions to us and our ability to make distributions to our shareholders.
 
Oslo Stock Exchange. The Company's Bye-laws provide that any person, other than its registrar, who acquires or disposes of an interest in shares which triggers a notice requirement of the Oslo Stock Exchange must notify the Company's registrar immediately of such acquisition or disposal and the resulting interest of that person in shares.
 
The Company's Bye-law 39 requires the Company to provide notice to the Oslo Stock Exchange if a person (other than the Company's registrar) resident for tax purposes in Norway (or such other jurisdiction as the Board may nominate from time to time) is found to hold 50% or more of the Company's aggregate issued share capital, or holds shares with 50% or more of the outstanding voting power.
 
The Company's Bye-laws also require it to comply with requirements that the Oslo Stock Exchange may impose from time to time relating to notification of the Oslo Stock Exchange in the event of specified changes in the ownership of the Company's common shares.
 
Shares and preemptive rights. Subject to certain balance sheet restrictions, the Companies Act permits a company to purchase its own shares if it is able to do so without becoming cash flow insolvent as a result. The restrictions are that the par value of the share must be charged against the company's issued share capital account or a company fund which is available for dividend or distribution or be paid for out of the proceeds of a fresh issue of shares. Any premium paid on the repurchase of shares must be charged to the company's current share premium account or charged to a company fund which is available for dividend or distribution. The Companies Act does not impose any requirement that the directors shall make a general offer to all shareholders to purchase their shares pro rata to their respective shareholdings. The Company's Bye-Laws do not contain any specific rules regarding the procedures to be followed by the Company when purchasing its own shares, and consequently the primary source of the Company's obligations to shareholders when the Company tenders for its shares will be the rules of the listing exchanges on which the Company's shares are listed. The Company's power to purchase its own shares is covered by Bye-laws 9, 10 and 11.
 
The Companies Act and our Bye-Laws do not confer any pre-emptive, redemption, conversion or sinking fund rights attached to our common shares. Holders of common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Unless a different majority is required by law or by our Bye-laws, resolutions to be approved by holders of common shares require approval by a simple majority of votes cast at a meeting at which a quorum is present.
 
Bye-Law 8 specifically provides that the issuance of more shares ranking pari passu with the shares in issue shall not constitute a variation of class rights, unless the rights attached to shares in issue state that the issuance of further shares shall constitute a variation of class rights. Bye-Law 12 confers on the directors the right to dispose of any number of unissued shares forming part of the authorized share capital of the Company without any requirement for shareholder approval. The Company's power to issue shares is covered by Bye-laws 12, 13, 14, 15 and 97. Bye-law 89 contains certain stipulations regarding the Company's (or any of its subsidiaries') transactions with any of its Principal Shareholders (or any Associate of a Principal Shareholder). When Bye-law 89 applies, the Company is required to send to each shareholder a disclosure statement containing information about the proposed transaction. However, this Bye-Law provision specifically exempts from this requirement the issuance of new shares to a Principal Shareholder for cash.
 

 
60
 
 
Liquidation. In the event of our liquidation, dissolution or winding up, the holders of common shares are entitled to share in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.
 
Anti-Takeover Effects of Provisions of Our Constitutional Documents
 
Several provisions of our bye-laws may have anti-takeover effects. These provisions are intended to avoid costly takeover battles, lessen our vulnerability to a hostile change of control and enhance the ability of our board of directors to maximize shareholder value in connection with any unsolicited offer to acquire us. However, these anti-takeover provisions, which are summarized below, could also discourage, delay or prevent (1) the merger, amalgamation or acquisition of our company by means of a tender offer, a proxy contest or otherwise, that a shareholder may consider in its best interest and (2) the removal of our incumbent directors and executive officers.
 
Should a person or persons resident for tax purposes in Norway, other than Nordea Bank Norge ASA, become the holder of 50% or more of the aggregate of our issued and outstanding common stock, being held or owned directly or indirectly, we will be entitled to dispose of such number of shares that would reduce the person or persons ownership of our common stock to under 50%.
 
Where a person or entity becomes the owner of more than 30% of our issued and outstanding common stock, our board of directors can decline to register the acquired common shares in excess of 30% unless the acquirer makes an offer to purchase our remaining shares of common stock or agrees to sell part of the shares of common stock acquired to reduce the number of our common shares held by them to below 30% of our issued and outstanding common stock. Sale of the acquirer's shares over 30% of the issued and outstanding common stock must take place no later than two weeks from when his total share ownership rose above 30%, the acquisition date. Offers to purchase our remaining shares must occur within four weeks of the acquisition date and the offer price must be at least as high as the highest price paid by the acquirer in the six months prior to the acquisition date. Should the acquirer fail to reduce his common shares or make an offer for the outstanding common shares with the time period, the acquirer will not be able to exercise any rights associated with the shares in excess of 30% of our outstanding and issued common stock.
 
There is a statutory remedy under Section 111 of the Companies Act, which provides that a shareholder may seek redress in the Bermuda courts as long as such shareholder can establish that a company's affairs are being conducted, or have been conducted, in a manner oppressive or prejudicial to the interests of some part of the shareholders, including such shareholder.
 
C.
MATERIAL CONTRACTS
 
The Company has no material contracts other than those entered in the ordinary course of business.
 
D.
EXCHANGE CONTROLS
 
The Bermuda Monetary Authority, or the BMA, must give permission for all issuances and transfers of securities of a Bermuda exempted company like ours, unless the proposed transaction is exempted by the BMA's written general permissions. We have received general permission from the BMA to issue any unissued common shares and for the free transferability of our common shares as long as our common shares are listed on an "appointed stock exchange". Our common shares are listed on the Oslo Stock Exchange and the New York Stock Exchange, each of which is an "appointed stock exchange". Our common shares may therefore be freely transferred among persons who are residents and non-residents of Bermuda.
 
Although we are incorporated in Bermuda, we are classified as a non-resident of Bermuda for exchange control purposes by the BMA. Other than transferring Bermuda Dollars out of Bermuda, there are no restrictions on our ability to transfer funds into and out of Bermuda or to pay dividends to U.S. residents who are holders of Common Shares or other non-residents of Bermuda who are holders of our common shares in currency other than Bermuda Dollars.
 
In accordance with Bermuda law, share certificates may be issued only in the names of corporations, individuals or legal persons. In the case of an applicant acting in a special capacity (for example, as an executor or trustee), certificates may, at the request of the applicant, record the capacity in which the applicant is acting. Notwithstanding the recording of any such special capacity, we are not bound to investigate or incur any responsibility in respect of the proper administration of any such estate or trust.
 
We will take no notice of any trust applicable to any of our shares or other securities whether or not we had notice of such trust.
 

 
61
 

As an "exempted company", we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermudians, but as an exempted company, we may not participate in certain business transactions including: (i) the acquisition or holding of land in Bermuda (except that required for its business and held by way of lease or tenancy for terms of not more than 21 years) without the express authorization of the Bermuda legislature; (ii) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Business Development and Tourism of Bermuda; (iii) the acquisition of any bonds or debentures secured on any land in Bermuda except bonds or debentures issued by the Government of Bermuda or by a public authority in Bermuda; or (iv) the carrying on of business of any kind in Bermuda, except in so far as may be necessary for the carrying on of its business outside Bermuda or under a license granted by the Minister of Business Development and Tourism of Bermuda.
 
The Bermuda government actively encourages foreign investment in "exempted" entities like us that are based in Bermuda but do not operate in competition with local business. In addition to having no restrictions on the degree of foreign ownership, we are subject neither to taxes on our income or dividends nor to any exchange controls in Bermuda. In addition, there is no capital gains tax in Bermuda, and profits can be accumulated by us, as required, without limitation. There is no income tax treaty between the United States and Bermuda pertaining to the taxation of income other than applicable to insurance enterprises.
 
E.
TAXATION
 
The following is a discussion of the material Bermuda, United States federal income and other tax considerations with respect to the Company and holders of common stock. This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, investors whose functional currency is not the United States Dollars and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common stock, may be subject to special rules. This discussion deals only with holders who hold the common stock as a capital asset, generally for investment purposes. Shareholders are encouraged to consult their own tax advisors concerning the overall tax consequences arising in their own particular situation under United States federal, state, local or foreign law of the ownership of common stock.
 
If an entity treated as a partnership for U.S. federal income tax purposes holds common stock, the U.S. federal income tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership.  Partners of partnerships holding the common stock are encouraged to consult their own tax advisors.
 
Bermuda and Other Non-United States Tax Considerations
 
As of the date of this Annual Report, we are not subject to taxation under the laws of Bermuda. Distributions we receive from our subsidiaries also are not subject to any Bermuda tax. As of the date of this Annual Report, there is no Bermuda income, corporation or profits tax, withholding tax, capital gains tax, capital transfer tax, or estate duty or inheritance tax payable by non-residents of Bermuda in respect of capital gains realized on a disposition of our common stock or in respect of distributions they receive from us with respect to our common stock. This discussion does not, however, apply to the taxation of persons ordinarily resident in Bermuda. Bermuda shareholders should consult their own tax advisors regarding possible Bermuda taxes with respect to dispositions of, and distributions on, our common stock.
 
We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, the imposition of any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035. This assurance is subject to the proviso that it is not to be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967.  The assurance does not exempt us from paying import duty on goods imported into Bermuda.  In addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government.  We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government.
 
Bermuda currently has no tax treaties in place with other countries in relation to double-taxation or for the withholding of tax for foreign tax authorities.
 
Dividends distributed by Seadrill Limited out of Bermuda
 
Currently, there is no withholding tax payable in Bermuda on dividends distributed from Seadrill Limited to its shareholders.
 
 
62
 

Taxation of rig owning entities
 
The majority of our drilling rigs are owned in tax-free jurisdictions such as Bermuda, the Cayman Islands and Liberia. There is no taxation of the rig owners' income in these jurisdictions. The remaining drilling rigs are owned in jurisdictions with income or tonnage taxation of the rig owners' income. These jurisdictions are Hungary, Norway and Singapore.
 
Please also see the section below entitled "Taxation in country of drilling operations".
 
Taxation in country of drilling operations
 
Income derived from drilling operations is generally taxed in the country where these operations take place The taxation of income derived from drilling operations could be based on net income, deemed income, withholding taxes and or other bases, depending upon the applicable tax legislation in each country of operation.  Some countries levy withholding taxes on bareboat charter payments (internal rig rent), branch profits, crew, dividends, interest and management fees.
 
Drilling operations can be carried out by locally incorporated companies, foreign branches of operating companies or foreign branches of the rig owning entities. We elect the appropriate structure with due regard to the applicable legislation of each country where the drilling operations occur.
 
Taxation may also extend to the rig owning entity in some of the countries where the drilling operations are performed.
 
Net income
 
Net income corresponds to gross income derived from the drilling operations less tax-deductible costs (i.e. operating costs, crew, insurance, management fees and capital costs (internal bareboat fee; tax depreciation; interest costs) incurred in relation to those operations).  In addition to net income tax, withholding tax on branch profits, dividends, internal bareboat fees, among other items, may also be levied.
 
Net income taxation for an international drilling contractor is complex, and pricing of internal transactions (e.g., rig sales; bareboat fees; services) will allocate overall taxable income between the relevant countries. We apply Organization for Economic Cooperation and Development, or OECD, Transfer Pricing Guidelines as a basis to arrive at pricing for internal transactions. OECD Transfer Pricing Guidelines describe various methods to price internal services on terms believed by us to be no less favorable than are available from unaffiliated third parties. However, some tax authorities could disagree with our transfer pricing methods and disputes may arise in regards to correct pricing.
 
Deemed income
 
Deemed income tax is normally calculated based on gross turnover, which can include or exclude reimbursables and often reflects an assumed profit ratio, multiplied by the applicable corporate tax rate. Some countries will also levy withholding taxes on the distribution of dividend and/or branch profits at the deemed tax rate.
 
Withholding and other taxes
 
Some countries base their taxation solely on withholding tax on gross turnover.  In addition, some countries levy stamp duties, training taxes or similar taxes on the gross turnover.
 
Customs duties
 
Customs duties are generally payable on the importation of drilling rigs, equipment and spare parts into the country of operation, although several countries provide exemption from such duties for the temporary importation of drilling rigs. Such exemption may also apply to the temporary importation of equipment.
 
Taxation of other income
 
Other income related to crewing, management fees and technical services will generally be taxed in the country where the service provider is resident, although withholding tax and/or income tax may also be imposed in the country where the drilling operations take place.
 

 
63
 

Dividends and other investment income will be taxable in accordance with the legislation of the country where the company holding the investment is resident. For companies resident in Bermuda, there is currently no tax on these types of income.
 
Some countries levy withholding taxes on outbound dividends and interest payments.
 
Capital gains taxation
 
In respect of drilling rigs located in Bermuda, the Cayman Islands, Liberia and Singapore, no capital gains tax is payable in these countries upon the sale or disposition of a rig. However, some countries may impose a capital gains tax or a claw-back of tax depreciation (on a full or partial basis) upon the sale of a rig during or attributable to such time as the rig is operating within such country, or within a certain time after completion of such drilling operations, or when the rig is exported after completion of such drilling operations.
 
Other taxes
 
Our operations may be subject to sales taxes, value added taxes, or other similar taxes in various countries.
 
Taxation of shareholders
 
Taxation of shareholders will depend upon the jurisdiction where the shareholder is a tax resident. Shareholders should seek advice from their tax advisor to determine the taxation to which they may be subject based on the shareholder's circumstances.
 
United States Federal Income Tax Considerations
 
The following are the material United States federal income tax consequences to us of our activities and to U.S. Holders and Non-U.S. Holders, each as defined below, of the ownership of our common stock.  This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, investors whose functional currency is not the United States Dollar and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common stock, may be subject to special rules.  The following discussion of United States federal income tax matters is based on the United States Internal Revenue Code of 1986, as amended, or the Code, judicial decisions, administrative pronouncements, and existing and proposed regulations issued by the United States Department of the Treasury, or the Treasury Regulations, all of which are subject to change, possibly with retroactive effect.  The discussion below is based, in part, on the description of our business in this Annual Report and assumes that we conduct our business as described.  Unless otherwise noted, references in the following discussion to the "Company," "we" and "us" are to Seadrill Limited and its subsidiaries on a consolidated basis.
 
United States Federal Income Taxation of U.S. Holders
 
As used herein, the term "U.S. Holder" means a beneficial owner of common stock that is a United States citizen or resident, United States corporation or other United States entity taxable as a corporation, an estate the income of which is subject to United States federal income taxation regardless of its source, or a trust if a court within the United States is able to exercise primary jurisdiction over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust.
 
If a partnership holds our common stock, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner in a partnership holding our common stock, you are encouraged to consult your tax advisor.
 
Distributions
 
Subject to the discussion of passive foreign investment companies below, any distributions made by us with respect to our common stock to a U.S. Holder will generally constitute dividends, which may be taxable as ordinary income or "qualified dividend income" as described in more detail below, to the extent of our current or accumulated earnings and profits, as determined under United States federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder's tax basis in his common stock on a dollar-for-dollar basis and thereafter as capital gain. Because we are not a United States corporation, U.S. Holders that are corporations will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. Dividends paid with respect to our common stock will generally be treated as "passive category income" or, in the case of certain types of U.S. Holders, "general category income" for purposes of computing allowable foreign tax credits for United States foreign tax credit purposes.
 

 
64
 

Dividends paid on our common stock to a U.S. Holder who is an individual, trust or estate, or a "U.S. Individual Holder" will generally be treated as "qualified dividend income" that is taxable to such U.S. Individual Holders at preferential tax rates (through 2012) provided that (1) the common stock is readily tradable on an established securities market in the United States (such as the New York Stock Exchange, on which our common stock is traded; (2) we are not a passive foreign investment company for the taxable year during which the dividend is paid or the immediately preceding taxable year (which, as discussed below, we are not and do not anticipate being in the future); (3) the U.S. Individual Holder has owned the common stock for more than 60 days in the 121-day period beginning 60 days before the date on which the common stock becomes ex-dividend; and (4) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property. There is no assurance that any dividends paid on our common stock will be eligible for these preferential rates in the hands of a U.S. Individual Holder.  Legislation has been previously introduced in the U.S. Congress which, if enacted in its present form, would preclude our dividends from qualifying for such preferential rates prospectively from the date of its enactment.  Any dividends paid by the Company which are not eligible for these preferential rates will be taxed as ordinary income to a U.S. Individual Holder.
 
Special rules may apply to any "extraordinary dividend", generally, a dividend paid by us in an amount which is equal to or in excess of 10% of a shareholder's adjusted tax basis (or fair market value in certain circumstances) in a share of common stock. If we pay an "extraordinary dividend" on our common stock that is treated as "qualified dividend income," then any loss derived by a U.S. Individual Holder from the sale or exchange of such common stock will be treated as long-term capital loss to the extent of such dividend.
 
Sale, Exchange or other Disposition of Common Stock
 
Assuming we do not constitute a passive foreign investment company for any taxable year, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other disposition of our common stock in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder's tax basis in such stock. Such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder's holding period is greater than one year at the time of the sale, exchange or other disposition. Such capital gain or loss will generally be treated as United States source income or loss, as applicable, for United States foreign tax credit purposes. A U.S. Holder's ability to deduct capital losses is subject to certain limitations.
 
Passive Foreign Investment Company Status and Significant Tax Consequences
 
Special United States federal income tax rules apply to a U.S. Holder that holds stock in a foreign corporation classified as a passive foreign investment company, or PFIC, for United States federal income tax purposes. In general, a foreign corporation will be treated as a PFIC with respect to a United States shareholder, if, for any taxable year in which such shareholder holds stock in such foreign corporation, either:
 
 
·
at least 75% of the corporation's gross income for such taxable year consists of passive income (e.g. dividends, interest, capital gains and rents derived other than in the active conduct of a rental business); or
 
 
·
at least 50% of the average value of the assets held by the corporation during such taxable year produce, or are held for the production of, passive income.
 
For purposes of determining whether a foreign corporation is a PFIC, it will be treated as earning and owning its proportionate share of the income and assets, respectively, of any of its subsidiary corporations in which it owns at least 25% of the value of the subsidiary's stock.
 
Income earned by a foreign corporation in connection with the performance of services would not constitute passive income. By contrast, rental income would generally constitute "passive income" unless the foreign corporation is treated under specific rules as deriving its rental income in the active conduct of a trade or business or is received from a related party.
 
We presently believe that we are not a PFIC and do not anticipate becoming a PFIC.  This is, however, a factual determination made on an annual basis and is subject to change.  Therefore, we can give you no assurance as to our PFIC status.
 
As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different United States federal income taxation rules depending on whether the U.S. Holder makes an election to treat us as a "Qualified Electing Fund," which election we refer to as a "QEF election." As an alternative to making a QEF election, a U.S. Holder should be able to make a "mark-to-market" election with respect to our common stock, as discussed below. In addition, if we were to be treated as a PFIC for any taxable year after 2010, a U.S. Holder would be required to file an annual report with the United States Internal Revenue Service, or the IRS, for that year with respect to such U.S. Holder's common stock.
 

 
65
 

Taxation of U.S. Holders Making a Timely QEF Election
 
If a U.S. Holder makes a timely QEF election, which U.S. Holder we refer to as an "Electing Holder," the Electing Holder must report each year for United States federal income tax purposes his pro rata share of our ordinary earnings and our net capital gain, if any, for our taxable year that ends with or within the taxable year of the Electing Holder, regardless of whether or not distributions were received from us by the Electing Holder. The Electing Holder's adjusted tax basis in the common stock would be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that had been previously taxed would result in a corresponding reduction in the adjusted tax basis in the common stock and would not be taxed again once distributed. An Electing Holder would generally recognize capital gain or loss on the sale, exchange or other disposition of our common stock. A U.S. Holder would make a QEF election with respect to any taxable year during which the Company is a PFIC by filing IRS Form 8621 with his United States federal income tax return. If we were aware that we or any of our subsidiaries were to be treated as a PFIC for any taxable year, we would, if possible, provide each U.S. Holder with all necessary information in order to make the QEF election described above.  If we were to be treated as a PFIC, a U.S. Holder would be treated as owning his proportionate share of stock in each of our subsidiaries which is treated as a PFIC and a separate  QEF election would be necessary with respect to each subsidiary.  It should be noted that we may not be able to provide such information if we did not become aware of our status as a PFIC in a timely manner.
 
Taxation of U.S. Holders Making a "Mark-to-Market" Election
 
Alternatively, if we were to be treated as a PFIC for any taxable year and, as we anticipate, our stock is treated as "marketable stock," a U.S. Holder would be allowed to make a "mark-to-market" election with respect to our common stock, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations.  The "mark-to-market" election will not be available for any of our subsidiaries. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the common stock at the end of the taxable year over such holder's adjusted tax basis in the common stock. The U.S. Holder would also be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder's adjusted tax basis in the common stock over its fair market value at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder's tax basis in his common stock would be adjusted to reflect any such income or loss amount. Gain realized on the sale, exchange or other disposition of our common stock would be treated as ordinary income, and any loss realized on the sale, exchange or other disposition of the common stock would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included as ordinary income by the U.S. Holder.  It should be noted that the mark-to-market election would likely not be available for any of our subsidiaries which are treated as PFICs.
 
Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election
 
Finally, if we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a "mark-to-market" election for that year, whom we refer to as a "Non-Electing Holder," would be subject to special rules with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common stock in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder's holding period for the common stock), and (2) any gain realized on the sale, exchange or other disposition of our common stock. Under these special rules:
 
 
·
the excess distribution or gain would be allocated ratably over the Non-Electing Holders' aggregate holding period for the common stock;
 
 
·
the amount allocated to the current taxable year and any taxable year before we became a PFIC would be taxed as ordinary income; and
 
 
·
the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.
 
These penalties would not apply to a pension or profit sharing trust or other tax-exempt organization that did not borrow funds or otherwise utilize leverage in connection with its acquisition of our common stock. If a Non-Electing Holder who is an individual dies while owning our common stock, such Non-Electing Holder's successor generally would not receive a step-up in tax basis with respect to such common stock.
 

 
66
 

United States Federal Income Taxation of "Non-U.S. Holders"
 
A beneficial owner of our common stock that is not a U.S. Holder is referred to herein as a "Non-U.S. Holder."
 
Dividends on Common Stock
 
Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on dividends received from us with respect to our common stock, unless that income is effectively connected with the Non-U.S. Holder's conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to those dividends, that income is subject to United States federal income tax only if it is attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States.
 
Sale, Exchange or Other Disposition of Common Stock
 
Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on any gain realized upon the sale, exchange or other disposition of our common stock, unless:
 
 
·
the gain is effectively connected with the Non-U.S. Holder's conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to that gain, that gain is subject to United States federal Income tax only if it is attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States; or
 
 
·
the Non-U.S. Holder is an individual who is present in the United States for 183 days or more during the taxable year of disposition and other conditions are met.
 
If a Non-U.S. Holder is engaged in a United States trade or business for United States federal income tax purposes, the income from the common stock, including dividends and the gain from the sale, exchange or other disposition of the common stock that is effectively connected with the conduct of that United States trade or business will generally be subject to United States federal income tax in the same manner as discussed in the previous section relating to the United States federal income taxation of U.S. Holders. In addition, if the Non-U.S. Holder is a corporation, the Non-U.S. Holder's earnings and profits that are attributable to the effectively connected income, subject to certain adjustments, may be subject to an additional United States federal branch profits tax at a rate of 30%, or at a lower rate as may be specified by an applicable United States income tax treaty.
 
Backup Withholding and Information Reporting
 
In general, dividend payments, and other taxable distributions, made by the Company to you within the United States will be subject to information reporting requirements. Such payments will also be subject to backup withholding if paid to a U.S. Individual Holder who:
 
 
·
fails to provide an accurate taxpayer identification number;
 
 
·
is notified by the IRS that he has failed to report all interest or dividends required to be shown on his United States federal income tax returns; or
 
 
·
in certain circumstances, fails to comply with applicable certification requirements.
 
Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on IRS Form W-8BEN, W-8ECI or W-8IMY, as applicable.
 
If a Non-U.S. Holder sells his common stock to or through a United States office of a  broker, the payment of the proceeds is subject to both United States backup withholding and information reporting unless the Non-U.S. Holder certifies that he is a non-United States person, under penalties of perjury, or otherwise establishes an exemption. If a Non-U.S. Holder sells his common stock through a non-United States office of a non-United States broker and the sales proceeds are paid to the Non-U.S. Holder outside the United States then information reporting and backup withholding generally will not apply to that payment.  However, United States information reporting requirements, but not backup withholding, will apply to a payment of sales proceeds, even if that payment is made to a Non-U.S. Holder outside the United States, if the Non-U.S. Holder sells his common stock through a non-United States office of a broker that is a United States person or has some other contacts with the United States.
 

 
67
 

Backup withholding is not an additional tax.  Rather, a taxpayer generally may obtain a refund of any amounts withheld under backup withholding rules that exceed the taxpayer's United States federal income tax liability by filing a refund claim with the IRS.
 
Pursuant to recently enacted section 6038D of the Code and the proposed and temporary Treasury Regulations promulgated thereunder, individuals who are U.S. Holders (and to the extent specified in the applicable Treasury Regulations, certain individuals who are non-U.S. Holders and certain U.S. entities) who hold "specified foreign financial assets" (as defined in section 6038D of the Code and the applicable Treasury Regulations) are required to file IRS Form 8938 (Statement of Specified Foreign Financial Assets) with information relating to each such asset for each taxable year in which the aggregate value of all such assets exceeds $75,000 at any time during the taxable year or $50,000 on the last day of the taxable year.  Specified foreign financial assets would include, among other assets, our common stock, unless the common stock were held through an account maintained with a U.S. financial institution.  Substantial penalties apply to any failure to timely file IRS Form 8938, unless the failure is shown to be due to reasonable cause and not due to willful neglect.  Additionally, the statute of limitations on the assessment and collection of U.S. federal income tax with respect to a taxable year for which the filing of IRS Form 8938 is required may not close until three years after the date on which IRS Form 8938 is filed.  U.S. Holders (including U.S. entities) and Non-U.S. Holders are encouraged to consult their own tax advisors regarding their reporting obligations under section 6038D of the Code.
 
Other Tax Considerations
 
In addition to the tax consequences discussed above, we may be subject to tax in one or more other jurisdictions where we conduct activities.  The amount of any such tax imposed upon our operations may be material.
 
F.
DIVIDENDS AND PAYING AGENTS
 
Not applicable.
 
G.
STATEMENT BY EXPERTS
 
Not applicable.
 
H.
DOCUMENTS ON DISPLAY
 
We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. In accordance with these requirements we file reports and other information with the Commission. These materials, including this Annual Report on Form 20-F and the accompanying exhibits, may be inspected and copied at the public reference facilities maintained by the Commission at 100 F Street, NE, Room 1580, Washington, D.C. 20549.  You may obtain information on the operation of the public reference room by calling 1 (800) SEC-0330, and you may obtain copies at prescribed rates from the Public Reference Section of the Commission at its principal office in Washington, D.C.  The Commission maintains a website (http://www.sec.gov.) that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. In addition, documents referred to in this Annual Report on Form 20-F may be inspected at our principle executive offices at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton, Bermuda HM 08 and at the offices of Seadrill Management AS at Løkkeveien 111, 4007 Stavanger, Norway.
 
I.
SUBSIDIARY INFORMATION
 
Not applicable
 
ITEM 11.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We are exposed to various market risks, including foreign currency fluctuations, changes in interest rates, equity and credit risk.  Our policy is to hedge our exposure to these risks where possible, within boundaries deemed appropriate by management.  We accomplish this by entering into a variety of derivative instruments and contracts to maintain the desired level of risk exposure. We may enter into derivative instruments from time to time for speculative purposes.
 
Foreign Exchange Risk
 
The Company and the majority of its subsidiaries use the US dollar as their functional currency because the majority of their revenues and expenses are denominated in US dollars. Accordingly, the Company's reporting currency is also US dollars. We do, however, earn revenue and incur expenses in other currencies and there is thus a risk that currency fluctuations could have an adverse effect on the value of our cash flows.
 

 
68
 

Our foreign currency risk arises from:
 
 
·
the measurement of debt and other monetary assets and liabilities denominated in foreign currencies converted to US dollars, with the resulting gain or loss recorded as "Other financial items";
 
 
·
changes in the fair value of foreign currency forward contracts, which are recorded as "Other financial items";
 
 
·
the impact of fluctuations in exchange rates on the reported amounts of our revenues and expenses which are contracted in foreign currencies; and
 
 
·
foreign subsidiaries whose accounts are not maintained in US dollars, which when converted into US dollars can result in exchange adjustments which are recorded as a component in shareholders' equity.
 
We use foreign currency forward contracts and cross currency interest rate swaps to manage our exposure to foreign currency risk on certain assets, liabilities and future anticipated transactions. Such derivative contracts do not qualify for hedge accounting treatment and are recorded in the balance sheet under "Other current assets" if the contracts have a net positive fair value, and under "Other current liabilities" if the contracts have a net negative fair value, with changes in the fair value recorded in the statement of operations under "Other financial items".
 
At December 31, 2011, we had various contracts to sell approximately $264 million between January 2012 and November 2012 for Norwegian Kroner at exchange rates ranging from NOK/$5.75 to NOK/$6.4. The fair value of our currency forward contracts and cross currency interest rate swap contracts as of December 31, 2011, and December 31, 2010, was as follows:
 
 
 
December 31, 2011
 
 
December 31, 2010
 
(In millions of US dollars)
 
Notional Amount
 
 
Fair value
 
 
Notional Amount
 
 
Fair Value
 
Other current assets (liabilities)
 
 
264
 
 
 
(1)
 
 
 
345
 
 
 
4
 
 
A 1% change in the exchange rate between the US dollar and the bought forward currencies would result in a fair value gain or loss of $3 million that would be reflected in our Consolidated Statements of Operations, based on our currency forward contracts as of December 31, 2011.
 
Interest Rate Risk
 
A significant portion of our debt obligations and surplus funds placed with financial institutions are subject to movements in interest rates. It is our policy to obtain the most favorable interest rates available without increasing our foreign currency exposure. In keeping with this, our surplus funds are placed in fixed deposits with reputable financial institutions which yield better returns than bank deposits. The deposits generally have short-term maturities so as to provide us with the flexibility to meet working capital and capital investments.
 
We use interest rate swaps to manage our exposure to interest rate risks. Interest rate swaps are used to convert floating rate debt obligations to a fixed rate in order to achieve an overall desired position of fixed and floating rate debt. The extent to which interest rate swaps are used is determined by reference to our net debt exposure and our views regarding future interest rates. Most of our interest rate swaps do not qualify for hedge accounting and movements in their fair values are reflected in the statement of operations under "gain/(loss) on derivative financial instruments". Interest rate swap agreements that have a positive fair value are recorded as "Other current assets", while swaps with a negative fair value are recorded as "Other current liabilities".
 
As of December 31, 2011, we were party to interest rate swap agreements with a combined outstanding principal amount of approximately $4.7 billion, as compared to $2.7 billion in 2010, at rates between 2.06% per annum and 4.63% per annum. The swap agreements mature between September 2012 and December 2018. The fair values of our interest rate swaps as of December 31, 2011, and December 31, 2010, were as follows:
 
 
 
December 31, 2011
 
 
December 31, 2010
 
(In millions of US dollars)
 
Outstanding principal
 
 
Fair value
 
 
Outstanding principal
 
 
Fair Value
 
Other current assets (liabilities)
 
 
4,738
 
 
 
(347
)
 
 
2,706
 
 
 
(146
)

 

 
69
 

In addition to the above interest rate swaps, two of our fully-consolidated VIEs have executed interest rate cash flow hedges in the form of interest rate swaps. Movements in their fair value are reflected in "Accumulated other comprehensive income (loss)", with their fair value recorded as "Other current assets" or "Other current liabilities". As of December 31, 2011, the fully-consolidated VIEs had entered into interest rate swap agreements with a combined outstanding principal amount of $1.0 billion, as compared to $1.1 billion in 2010, at rates between 2.19% per annum and 3.89% per annum. These swap agreements mature between October 2012 and August 2013, and their fair values as of December 31, 2011, and December 31, 2010, were as follows:
 
 
 
December 31, 2011
 
 
December 31, 2010
 
(In millions of US dollars)
 
Outstanding principal
 
 
Fair value
 
 
Outstanding principal
 
 
Fair Value
 
Other current assets (liabilities)
 
 
988
 
 
 
(26
)
 
 
1,132
 
 
 
(45
)

As of December 31, 2011, our net exposure to floating interest rate fluctuations on our outstanding debt was $2.7 billion, compared with $2.8 billion as of December 31, 2010, based on our total net interest bearing debt of $9.5 billion less the $5.7 billion notional principal of our floating to fixed interest rate swaps, less the $1.1 billion in fixed interest loans. A 1% change in short-term interest rates would thus increase or decrease our interest expense by approximately $27 million on an annual basis as of December 31, 2011, as compared to $28 million in 2010.
 
Equity risk
 
As of December 31, 2011, we had entered into a TRS contract indexed to 2,000,000 of our own shares, whereby we carry the risk of fluctuations in the market price of our shares. The settlement amount for the contract will be (A) the market value of the shares at the date of settlement plus the amount of dividends paid on the shares by us between entering into and settling the contract, less (B) the reference price of the shares agreed at the inception of the contract plus the counterparty's financing costs. Settlement will be either a payment from or to the counterparty, depending on whether (A) is more or less than (B). The contract was scheduled to expire in March 2012 and the agreed reference price was NOK177.21 per common share. The open position at December 31, 2011, exposes us to market risk associated with our share price, and it is estimated that a 10% reduction in the price below the value at December 31, 2011, would generate an adverse fair value adjustment of up to $7 million, which would be recorded in the Statement of Operations.
 
In March 2012, these contracts were settled and we simultaneously entered into a new TRS agreement for 2,000,000 of our common shares as underlying security with an agreed reference price of NOK222.69 per share and an expiration date in September 2012.
 
In addition to the above TRS agreement, which has our own share as underlying security, we may from time to time enter into short-term TRS arrangements relating to securities in other companies.
 
The fair market value of our $650 million 3.375% convertible bond as of December 31, 2011 was $736 million.
 
We hold equity investments in several other companies in our industry that own and/or operate offshore drilling units with similar characteristics to our own fleet of rigs or deliver various oil services. These investments provide us with additional exposure to market segments in which we operate or other oil services. These include:
 
 
·
a 39.9% equity interest in the Archer Limited (OSE:ARCHER), a Bermuda oil service company;
 
 
·
a 23.6% equity interest in SapuraCrest, a Malaysian oil services company;
 
 
·
a 49% equity interest in Varia Perdana Sdn Bhd, or Varia Perdana, a Malaysian company;
 
 
·
a 33.75% equity interest in Asia Offshore Drilling Ltd. (OSE: AOD), a Bermuda offshore drilling company; and
 
 
·
a 28.5% equity interest in Sevan Drilling ASA (OSE: SEVDR), a Norwegian offshore drilling company.
 
If the market value of any of these investments should fall below the recorded book value, and this decrease in market value is determined to be other than temporary, there could be an impairment charge recognized in our profit and loss statement.
 
Concentration of credit risk
 
The market for our services is the offshore oil and gas industry, and the customers consist primarily of major integrated oil companies, independent oil and gas producers and government-owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral in our business agreements. Reserves for potential credit losses are maintained when necessary.
 

 
70
 

The following table shows those of our customers who have generated 10% or more of our contract revenues in one of the periods shown:
 
 
 
Year ended December 31,
 
Customer
 
2011
 
2010
 
2009
Petrobras
 
 
17
%
 
 
17
%
 
 
10
%
Statoil
 
 
7
%
 
 
15
%
 
 
17
%
Total
 
 
15
%
 
 
10
%
 
 
13
%
Shell
 
 
10
%
 
 
9
%
 
 
10
%
Exxon
 
 
10
%
 
 
7
%
 
 
12
%
Other customers
 
 
41
%
 
 
42
%
 
 
38
%
Total
 
 
100
%
 
 
100
%
 
 
100
%

We may also face credit related losses in the event that counterparties to our derivative financial instrument contracts do not perform according to the terms of the contract. The credit risk arising from these counterparties relates to unrealized profits from foreign exchange forward contracts and interest rate swaps. We generally do not require collateral for our financial instrument contracts. We do, however, enter into master netting agreements with our counterparties to derivative financial instrument contracts to mitigate our exposure to counterparty credit risks. These agreements provide us with the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting against them any amounts that the counterparty may owe us.
 
In the opinion of management, our counterparties are creditworthy financial institutions, and we do not expect any significant loss to result from their non-performance. The credit exposure of interest rate swap agreements, currency option contracts and foreign currency contracts is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements.
 
ITEM 12.
DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
 
A.
DEBT SECURITIES
 
Not applicable.
 
B.
WARRANTS AND RIGHTS
 
Not applicable.
 
C.
OTHER SECURITIES
 
Not applicable.
 
D.
AMERICAN DEPOSITORY SHARES
 
Not applicable.
 
PART II
 
ITEM 13.
DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
 
Neither we nor any of our subsidiaries have been subject to a material default in the payment of principal, interest, a sinking fund or purchase fund installment or any other material default that was not cured within 30 days. In addition, the payments of our dividends are not and have not been in arrears, or have not been subject to material delinquency that was not cured within 30 days.
 
ITEM 14.
MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
 
None.
 
 
71
 
 
ITEM 15
CONTROLS AND PROCEDURES
 
a)
Disclosure Controls and Procedures
 
Management assessed the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule13a-15(e) of the Exchange Act as of December 31, 2011. Based upon that evaluation the Principal Executive Officer and Principal Financial Officer concluded that the Company's disclosure controls and procedures are effective as of the evaluation date.
 
b)
Management's annual report on internal controls over financial reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) promulgated under the Exchange Act.
 
Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers and effected by the Company's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
 
 
·
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
 
 
·
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of Company's management and directors; and
 
 
·
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree or compliance with the policies or procedures may deteriorate.
 
Management conducted the evaluation of the effectiveness of the internal controls over financial reporting using the control criteria framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO, published in its report entitled Internal Control-Integrated Framework.
 
Our management with the participation of our Principal Executive Officer and Principal Financial Officer assessed the effectiveness of the design and operation of the Company's internal controls over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2011. Based upon that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company's internal controls over financial reporting are effective as of December 31, 2011.
 
The effectiveness of the Company's internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers AS, an independent registered public accounting firm, as stated in their report which appears herein.
 
c)
Attestation report of the registered public accounting firm
 
The independent registered public accounting firm that audited the Consolidated Financial Statements, PricewaterhouseCoopers AS, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2011, appearing under Item 18, and such report is incorporated herein by reference.
 
d)
Changes in internal control over financial reporting
 
There were no changes in our internal controls over financial reporting that occurred during the period covered by this Annual Report that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
 
ITEM 16.
RESERVED
 
 
72
 
 
ITEM 16A.
AUDIT COMMITTEE FINANCIAL EXPERT.
 
Our Board of Directors has determined that the sole member of the audit committee, Kate Blankenship, is an independent Director and is the Audit Committee Financial Expert.
 
ITEM 16B.
CODE OF ETHICS
 
We have adopted a Code of Ethics that applies to all entities controlled by the Company and its employees, directors, officers and agents of the Company. We have posted a copy of our Code of Ethics on our website at www.seadrill.com. We will provide any person, free of charge, a copy of our Code of Ethics upon written request to our registered office.
 
ITEM 16C.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
Our principal account for the fiscal years ended December 31, 2011 and 2010 was PricewaterhouseCoopers AS. The following table sets forth the fees related to audit and other services provided by PricewaterhouseCoopers AS:
 
 in US dollars
 
2011
 
 
2010
 
 
 
 
 
 
  
 
Audit fees (a)
 
 
3,610,668
 
 
  
3,081,603
 
Audit-related fees (b)
 
 
522,618
 
 
  
251,446
 
Taxation fees (c)
 
 
68,977
 
 
  
239,222
 
All other fees (d)
 
 
54,746
 
 
  
-
 
Total
 
 
4,257,010
 
 
  
3,572,271
 
 
a)
Audit fees
 
Audit fees represent professional services rendered for the audit of our annual financial statements and services provided by the principal accountant in connection with statutory and regulatory filings or engagements.
 
b)
Audit-related fees
 
Audit-related fees consist of assurance and related services rendered by the principal accountant related to the performance of the audit or review of our financial statements which have not been reported under Audit fees above.
 
c)
Taxation fees
 
Taxation fees represent fees for professional services rendered by the principal accountant for tax compliance, tax advice and tax planning.
 
d)
All other fees
 
All other fees include services other than audit fees, audit-related fees and taxation fees set forth above.
 
e)
Audit Committee's Pre-Approval Policies and Procedures
 
Our Board of Directors has adopted pre-approval policies and procedures in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X that require the Board to approve the appointment of our independent auditor before such auditor is engaged, and approve each of the audit and non-audit related services to be provided by such auditor under such engagement by the Company. All services provided by the principal auditor in 2011 and 2010 were approved by the Board pursuant to the pre-approval policy.
 
ITEM 16D.
EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
 
Not applicable.
 
 
73
 
 
ITEM 16E.
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
 
Purchases of our common shares of par value $2.00 each have been made as follows:
 
Period
  
Total number of
shares purchase
  
Average price
paid per share
  
Total number of shares
 purchased as part of
publicly announced
plans or programs
  
Maximum number
(or approximate US dollar value) of shares that may yet be purchased under the plans or programs
January 2011
  
750,000(1)
  
NOK202.00
  
-
  
-
April 2011
  
1,155,000(1)
  
NOK183.93
  
 
  
 
May 2011
  
1,345,000(1)
  
NOK183.42
        
Total
  
3,250,000(1)
  
NOK187.89
  
-
  
-

1)
The shares repurchased in the period were not part of a publicly announced plan or program. The repurchases were made in open-market transactions.
 
2)
A share repurchase program was approved by the Board in 2007, authorizing us to buy back shares which may either be cancelled or held as treasury shares to meet our obligations relating to our share option scheme.
 
3)
As of April 24, 2012, Hemen is party to TRS agreements relating to 3,900,000 of our common shares with a reference price of NOK225.22 per share and Drew Investment Ltd., a company controlled by board member Tor Olav Trøim, is party to TRS agreements relating to 400,000 of our common shares with a reference price of NOK209.17 per share.
 
ITEM 16F.
CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT
 
Not applicable.
 
ITEM 16G.
CORPORATE GOVERNANCE
 
Pursuant to an exception under the NYSE listing standards available to foreign private issuers, we are not required to comply with all of the corporate governance practices followed by U.S. companies under the NYSE listing standards, which are available at www.nyse.com.  Pursuant to Section 303.A.11 of the NYSE Listed Company Manual, we are required to list the significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies. Set forth below is a list of those differences:
 
 
·
Independence of Directors. The NYSE requires that a U.S. listed company maintain a majority of independent directors. As permitted under Bermuda law and our bye-laws, two members of our board of directors, Ms. Kate Blankenship and Mr. Carl Steen, are independent according to the NYSE's standards for independence applicable to a foreign private issuer.
 
 
·
Executive Sessions.  The NYSE requires that non-management directors meet regularly in executive sessions without management. The NYSE also requires that all independent directors meet in an executive session at least once a year. As permitted under Bermuda law and our bye-laws, our non-management directors do not regularly hold executive sessions without management and we do not expect them to do so in the future.
 
 
·
Nominating/Corporate Governance Committee.  The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Bermuda law and our bye-laws, we do not currently have a nominating or corporate governance committee.
 
 
·
Audit Committee.  The NYSE requires, among other things, that a listed U.S. company have an audit committee with a minimum of three members, all of whom are independent. As permitted by Rule 10A-3 under the Exchange Act, our audit committee consists of one independent member of our Board, Ms. Kate Blankenship.
 
 
·
Corporate Governance Guidelines.  The NYSE requires that a listed U.S. Company adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Bermuda law and we have not adopted such guidelines.
 
We believe that our established corporate governance practices satisfy the NYSE listing standards.
 
ITEM 16H.
MINE SAFETY DISCLOSURE.
 
Not applicable.
 
74
 
 
PART III
 
ITEM 17.                   FINANCIAL STATEMENTS
 
See Item 18.
 
ITEM 18.
FINANCIAL STATEMENTS
 
The following financial statements listed below and set forth on pages F-1 through F-50 are filed as part of this Annual Report on
Form 20-F:
 
Consolidated Financial Statements of Seadrill Limited
 
Index to Consolidated Financial Statements of Seadrill Limited
F-1
Report of Independent Registered Public Accounting Firm – PricewaterhouseCoopers AS
F-2
Consolidated Statements of Operations for the years ended December 31 2011, 2010 and 2009
F-3
Consolidated Statements of Comprehensive Income for the years ended December 31 2011, 2010 and 2009
F-4
Consolidated Balance Sheets as of December 31 2011 and 2010
F-5
Consolidated Statements of Cash Flows for the years ended December 31 2011, 2010 and 2009
F-6
Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31 2011, 2010 and 2009
F-8
Notes to Consolidated Financial Statements
F-9

ITEM 19.
EXHIBITS
 
 
Exhibit
Number
 
Description
 
 
1.1*
Memorandum of Association of Seadrill Limited.(1)
1.2 *
Bye-Laws of Seadrill Limited as adopted by the sole shareholder on May 13, 2005 and as amended by resolution of the shareholders at the Annual General Meeting held on December 1, 2006 and as further amended by resolution of the shareholders at the Annual General Meeting held on September 28, 2007 (1)
   
1.3 *
Certificate of Incorporation of Seadrill Limited delivered May 10, 2005 (1)
1.4 *
Certificate of Deposit of Memorandum of Increase of Share Capital delivered May 13, 2005 (1)
1.5 *
Certificate of Deposit of Memorandum of Increase of Share Capital delivered August 8, 2005 (1)
1.6 *
Certificate of Deposit of Memorandum of Increase of Share Capital delivered December 20, 2006 (1)
1.7 *
Certificate of Incorporation on Name Change delivered December 20, 2006 (1)
2.1 *
Form of Common Stock Certificate (1)
4.1 *
Share Option Scheme dated December 1, 2006 (1)
4.2 *
Bermuda Tax Assurance (1)
8.1
Subsidiaries of the Company
11.1 *
Code of Ethics (2)
12.1
Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities
Exchange Act, as amended.
12.2
Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
13.1
Certification of the Principal Executive Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2
Certification of the Principal Financial Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
________
* Incorporated by reference

 
(1) Incorporated by reference to the Company's registration statement on Form 20-F, filed on March 18, 2010
 
(2) Incorporated by reference to the Company's annual report on Form 20-F, filed on May 5, 2010




 
75
 

Index to Consolidated Financial Statements of Seadrill Limited

Report of Independent Registered Public Accounting Firm
F-2
 
 
Consolidated Statements of Operations for the years ended December 31, 2011, 2010, and 2009
F-3
 
 
Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010, and 2009
F-4
 
 
Consolidated Balance Sheets as of December 31, 2011 and 2010
F-5
 
 
Consolidated Statements of Cash flows for the years ended December 31, 2011, 2010, and 2009
F-6
 
 
Consolidated Statements of Changes in Equity for the years ended December 31, 2011, 2010, and 2009
F-8
 
 
Notes to Consolidated Financial Statements
F-9


 
F-1
 
 
 
Report of Independent Registered Public Accounting Firm
 
To the Board of Directors and Shareholders of Seadrill Limited
 
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, consolidated statements of cash flows, consolidated statements of comprehensive income and consolidated statements of changes in equity present fairly, in all material respects, the financial position of Seadrill Limited and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three  years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's annual report on internal control over financial reporting appearing under item 15(b) of Seadrill Limited's Annual Report on Form 20-F. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our audits (which were integrated audits in 2011 and 2010). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
/s/PricewaterhouseCoopers AS
 
PricewaterhouseCoopers AS
Oslo, Norway
April 27, 2012
  

 
F-2
 

Seadrill Limited
CONSOLIDATED STATEMENTS OF OPERATIONS
for the years ended December 31, 2011, 2010 and 2009
(In US$ millions, except per share data)
 
 
 
 
 
2011
 
 
2010
 
 
2009
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
 
Contract revenues
 
 
4,095
 
 
 
3,823
 
 
 
3,045
 
Reimbursables
 
 
96
 
 
 
192
 
 
 
166
 
Other revenues
 
 
1
 
 
 
26
 
 
 
43
 
Total operating revenues
 
 
4,192
 
 
 
4,041
 
 
 
3,254
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain on sale of assets
 
 
22
 
 
 
26
 
 
 
71
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
Vessel and rig operating expenses
 
 
1,585
 
 
 
1,605
 
 
 
1,253
 
Reimbursable expenses
 
 
90
 
 
 
179
 
 
 
155
 
Depreciation and amortization
 
 
563
 
 
 
480
 
 
 
396
 
General and administrative expenses
 
 
202
 
 
 
178
 
 
 
149
 
Total operating expenses
 
 
2,440
 
 
 
2,442
 
 
 
1,953
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net operating income
 
 
1,774
 
 
 
1,625
 
 
 
1,372
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial items
 
 
 
 
 
 
 
 
 
 
 
 
Interest income
 
 
21
 
 
 
42
 
 
 
78
 
Interest expense
 
 
(295
)
 
 
(312
)
 
 
(228
)
Share in results from associated companies (loss)/gain
 
 
(420
)
 
 
48
 
 
 
92
 
Impairment loss on marketable securities
 
 
(10
)
 
 
(15
)
 
 
-
  
(Loss)/gain on derivative financial instruments
 
 
(346
)
 
 
(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)
 
 
(18
)
 
 
(26
)
 
 
(25
)
Gain on loss of control in subsidiary
 
 
540
 
 
 
  -
 
 
 
 -
 
Gain on realization of marketable securities
 
 
416
 
 
 
  -
 
 
 
  -
 
Other financial items
 
 
9
 
 
 
39
 
 
 
54
 
Total financial items
 
 
(103
)
 
 
(294
)
 
 
101
  
 
 
 
 
 
 
 
 
 
 
 
 
 
Income before income taxes
 
 
1,671
 
 
 
1,331
 
 
 
1,473
  
 
 
 
 
 
 
 
 
 
 
 
 
 
Income taxes
 
 
(189
)
 
 
(159
)
 
 
(120
)
Net income
 
 
1,482
 
 
 
1,172
 
 
 
1,353
  
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to the non-controlling interest
 
 
81
 
 
 
55
 
 
 
92
  
Net income attributable to the parent
 
 
1,401
 
 
 
1,117
 
 
 
1,261
 
Basic earnings per share (US dollar)
 
 
3.05
 
 
 
2.73
 
 
 
3.16
  
Diluted earnings  per share (US dollar)
 
 
2.96
 
 
 
2.73
 
 
 
3.00
  
Declared regular dividend per share (US dollar)
 
 
3.06
 
 
 
2.535
 
 
 
1.05
 
Declared extraordinary dividend per share (US dollar)
 
 
-
 
 
 
0.20
 
 
 
-
 

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

 
F-3
 


Seadrill Limited
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 for the years ended December 31, 2011, 2010 and 2009
(In US$ millions)
 

 
 
2011
 
 
2010
 
 
2009
 
Net income
 
 
1,482
 
 
 
1,172
 
 
 
1,353
  
 
 
 
 
 
 
 
 
 
 
 
 
 
Other comprehensive income/(loss), net of tax:
 
 
 
 
 
 
 
 
 
 
 
 
Change in unrealized (loss)/gain on marketable securities
 
 
(291
)
 
 
(25
)
 
 
317
  
Change in unrealized foreign exchange differences
 
 
38
 
 
 
27
 
 
 
30
  
Change in actuarial (loss)/gain relating to pension
 
 
(3
)
 
 
(32
)
 
 
14
  
Change in unrealized gain/(loss) on interest rate swaps in subsidiaries
 
 
1
  
 
 
(2
)
 
 
-
 
Deconsolidation of  subsidiaries
    
(63
)
    
-
      
-
  
Change in unrealized gain/(loss) on interest rate swaps in VIEs
 
 
20
  
 
 
(11
)
 
 
15
  
Other comprehensive (loss)/income:
 
 
(298
)
 
 
(43
)
 
 
376
  
 
 
 
 
 
 
 
 
 
 
 
 
 
Total comprehensive income for the period
 
 
1,184
 
 
 
1,129
 
 
 
1,729
  
Comprehensive income attributable to the parent
 
 
1,073
 
 
 
1,081
 
 
 
1,620
  
Comprehensive income attributable to the non-controlling interest
 
 
111
 
 
 
48
 
 
 
109
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The total balance of accumulated other comprehensive income as of December 31 is made up as follows:
 
 
 
 
 
 
 
 
 
 
 
 
Unrealized gain on marketable securities
 
 
1
 
 
 
292
 
 
 
317
 
Unrealized gain on foreign exchange
 
 
54
 
 
 
96
 
 
 
80
 
Actuarial (loss)/gain relating to pension
 
 
(11
)
 
 
(15
)
 
 
11
  
Unrealized (loss) on interest rate swaps in subsidiaries
 
 
-
  
 
 
(1
)
 
 
-
 
Change in unrealized (loss)/gain on interest rate swaps in VIEs
 
 
(49
)
 
 
(49
)
 
 
(49
)
Accumulated other comprehensive (loss)/income at December 31
 
 
(5
)
 
 
323
 
 
 
359
 

Note: All items of other comprehensive income/(loss) are stated net of tax.
 
The applicable amount of income taxes associated with each component of other comprehensive income is $0 due to the fact that the items relate to companies domiciled in non-taxable jurisdictions. However, for actuarial loss related to pension, the accumulated applicable amount of income taxes is $3 million as this item is related to companies domiciled in Norway where the tax rate is 28%.
 
See accompanying notes that are an integral part of these Consolidated Financial Statements.
 
 
F-4
 

Seadrill Limited
CONSOLIDATED BALANCE SHEETS
 for the years ended December 31, 2011 and 2010
(In US$ millions)
 
 
 
2011
 
 
2010
 
ASSETS
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
Cash and cash equivalents
 
 
483
 
 
 
755
 
Restricted cash
 
 
232
 
 
 
155
 
Marketable securities
 
 
24
 
 
 
598
 
Accounts receivables, net
 
 
720
 
 
 
828
 
Amount due from related party
 
 
185
 
 
 
140
 
Other current assets
 
 
323
 
 
 
407
 
Total current assets
 
 
1,967
 
 
 
2,883
 
Non-current assets
 
 
 
 
 
 
 
 
Investment in associated companies
 
 
721
 
 
 
205
 
Newbuildings
 
 
2,531
 
 
 
1,247
 
Drilling units
 
 
11,223
 
 
 
10,795
 
Goodwill
 
 
1,320
 
 
 
1,676
 
Other intangible assets
 
 
0
 
 
 
57
 
Restricted cash
 
 
250
 
 
 
305
 
Deferred tax assets
 
 
33
 
 
 
30
 
Equipment
 
 
25
 
 
 
158
 
Other non-current assets
 
 
234
 
 
 
141
 
Total non-current assets
 
 
16,337
 
 
 
14,614
 
Total assets
 
 
18,304
 
 
 
17,497
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
 
Current portion of long-term debt
 
 
1,419
 
 
 
981
 
Trade accounts payable
 
 
38
 
 
 
95
 
Other current liabilities
 
 
1,314
 
 
 
1,438
 
Total current liabilities
 
 
2,771
 
 
 
2,514
 
Non-current liabilities
 
 
 
 
 
 
 
 
Long-term interest bearing debt
 
 
8,574
 
 
 
8,176
 
Long-term debt due to related parties
 
 
435
 
 
 
435
 
Deferred taxes
 
 
34
 
 
 
181
 
Other non-current liabilities
 
 
188
 
 
 
254
 
Total non-current liabilities
 
 
9,231
 
 
 
9,046
 
 
 
 
 
 
 
 
 
 
Commitments and contingencies
 
 
-
 
 
 
-
 
 
 
 
 
 
 
 
 
 
Equity
 
 
 
 
 
 
 
 
Common shares of par value US$2.00 per share: 800,000,000 shares authorized 467,772,174 outstanding at December 31, 2011 (December, 31 2010: 443,125,691)
 
 
935
 
 
 
886
 
Additional paid in capital
 
 
2,097
 
 
 
1,217
 
Contributed surplus
 
 
1,956
 
 
 
1,956
 
Accumulated other comprehensive (loss)/ income
 
 
(5
)
 
 
323
 
Accumulated earnings
 
 
994
 
 
 
1,016
 
Non-controlling interest
 
 
325
 
 
 
539
 
Total equity
 
 
6,302
 
 
 
5,937
 
Total liabilities and  equity
 
 
18,304
 
 
 
17,497
 

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

 
F-5
 


Seadrill Limited
CONSOLIDATED STATEMENT OF CASH FLOWS
for the years ended December 31, 2011, 2010 and 2009
(In US$ millions)
 
 
 
2011
 
 
2010
 
 
2009
 
Cash Flows from Operating Activities
 
 
 
 
 
 
 
 
 
Net income
 
 
1,482
 
 
 
1,172
 
 
 
1,353
  
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
 
563
 
 
 
480
 
 
 
396
 
Amortization of deferred loan charges
 
 
31
 
 
 
43
 
 
 
23
 
Amortization of unfavorable contracts
 
 
(24
)
 
 
(39
)
 
 
(43
)
Amortization of favorable contracts
 
 
23
 
 
 
13
 
 
 
-
 
Amortization of mobilization revenue
 
 
(96
)
 
 
(86
)
 
 
(50
)
Impairment loss on marketable securities
 
 
10
 
 
 
15
 
 
 
-
 
Share of results from associated companies loss/ (gain)
 
 
420
  
 
 
(48
)
 
 
(92
)
Share-based compensation expense
 
 
10
 
 
 
11
 
 
 
16
 
Gain on disposal of fixed assets
 
 
(22
)
 
 
(26
)
 
 
(71
)
Unrealized (gain)/loss related to derivative financial instruments
 
 
261
 
 
 
97
  
 
 
(153
)
Non cash gain recognized related to realization of marketable securities
 
 
(416
)
 
 
(43
)
 
 
(16
)
Non cash gain recognized related to loss of control
    
(540
)
    
-
      
-
  
Dividend received from associated company
 
 
57
 
 
 
61
 
 
 
41
 
Deferred income tax expense
 
 
(9
)
 
 
110
 
 
 
2
 
Unrealized foreign exchange loss/ (gain) on long term interest bearing debt
 
 
(5
)
 
 
(4
)
 
 
28
  
Non-cash loss recognized on extinguishment of convertible debt
 
 
-
 
 
 
48
 
 
 
-
 
Non-cash gains recognized on acquisition of subsidiaries
 
 
-
  
 
 
(167
)
 
 
-
 
Changes in operating assets and liabilities, net of effect of acquisitions
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized mobilization fees received from customers
 
 
58
 
 
 
109
 
 
 
166
 
Trade accounts receivable
 
 
(52
)
 
 
(163
)
 
 
(111
)
Trade accounts payable
 
 
(35
)
 
 
(15
)
 
 
(35
)
Prepaid expenses/accrued revenue
 
 
79
  
 
 
(107
)
 
 
(71
)
Other, net
 
 
21
  
 
 
(161
)
 
 
69
 
Net cash provided by operating activities
 
 
1,816
 
 
 
1,300
 
 
 
1,452
 

 
F-6
 


Seadrill Limited
CONSOLIDATED STATEMENT OF CASH FLOWS
for the years ended December 31, 2011, 2010 and 2009
(In US$ millions)
 
 
 
2011
 
 
2010
 
 
2009
 
Cash Flows from Investing Activities
 
 
 
 
 
 
 
 
 
Additions to newbuilding
 
 
(2,381
)
 
 
(2,006
)
 
 
(1,153
)
Additions to rigs and equipment
 
 
(162
)
 
 
(362
)
 
 
(216
)
Sale of rigs and equipment
 
 
245
 
 
 
55
 
 
 
393
 
Investment in subsidiaries, net of cash acquired
 
 
(26
)
 
 
(152
)
 
 
 -
  
Cash deconsolidated upon loss of control in subsidiary
    
(127
)
    
-
      
-
  
Change in margin calls and other restricted cash
 
 
(43
)
 
 
51
 
 
 
344
  
Investment in associated companies
 
 
(287
)
 
 
(13
)
 
 
(33
)
Proceed from repayment of short term loan to related parties
 
 
-
 
 
 
90
 
 
 
115
 
Short-term loan granted to related parties
 
 
-
  
 
 
(160
)
 
 
(170
)
Purchase of marketable securities
 
 
(13
)
 
 
(15
)
 
 
(263
)
Proceeds from realization of marketable securities
 
 
161
 
 
 
215
 
 
 
59
 
Net cash used in investing activities
 
 
(2,633
)
 
 
(2,297
)
 
 
(924
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flows from Financing Activities
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from debt
 
 
5,929
 
 
 
3,902
 
 
 
2,407
 
Repayments of debt
 
 
(4,116
)
 
 
(1,870
)
 
 
(2,491
)
Debt fees paid
 
 
(49
)
 
 
(33
)
 
 
(43
)
Change in current liability related to share forward contracts
 
 
-
  
 
 
(12
)
 
 
(68
)
Paid to non-controlling interests
 
 
(95
)
 
 
(292
)
 
 
(68
)
Contribution from non-controlling interests
 
 
418
 
 
 
289
 
 
 
-
 
Purchase of treasury shares
 
 
(130
)
 
 
(42
)
 
 
 -
  
Proceeds from sale of treasury shares
 
 
21
 
 
 
23
 
 
 
9
 
Dividends paid
 
 
(1,440
)
 
 
(990
)
 
 
(199
)
Proceeds from issuance of equity
 
 
-
 
 
 
318
 
 
 
 -
 
Net cash provided by/(used in) financing activities
 
 
538
 
 
 
1,293
  
 
 
(453
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect of exchange rate changes on cash and cash equivalents
 
 
7
  
 
 
(1
)
 
 
9
  
 
 
 
 
 
 
 
 
 
 
 
 
 
Net (decrease)/ increase in cash and cash equivalents
 
 
(272
)
 
 
295
 
 
 
84
  
Cash and cash equivalents at beginning of the period
 
 
755
 
 
 
460
 
 
 
376
 
Cash and cash equivalents at the end of period
 
 
483
 
 
 
755
 
 
 
460
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary disclosure of cash flow information
 
 
 
 
 
 
 
 
 
 
 
 
Interest paid
 
 
282
 
 
 
284
 
 
 
231
 
Taxes paid
 
 
188
 
 
 
134
 
 
 
138
 

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

 
F-7
 


Seadrill Limited
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
for the years ended December 31, 2011, 2010 and 2009
(In US$ millions)
 
 
 
Share
Capital
 
 
Additional
paid-in
capital
 
 
Contributed surplus
 
 
Accumulated other comprehensive income
 
 
Retained Earnings
 
 
Non-controlling interest
 
 
Total equity
 
Balance at December 31, 2008
 
 
797
 
 
 
35
 
 
 
1,956
 
 
 
1
 
 
 
(160
)
 
 
593
 
 
 
3,222
 
Sale of treasury shares
 
 
1
 
 
 
8
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
 
Employee stock options issued
 
 
 
 
 
 
16
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
16
 
Convertible loan-equity portion
 
 
 
 
 
 
105
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
105
 
Unrealized gain on marketable securities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
317
 
 
 
 
 
 
 
 
 
 
 
317
 
Foreign exchange differences
 
 
 
 
 
 
 
 
 
 
 
 
 
 
29
 
 
 
 
 
 
 
1
 
 
 
30
 
Changes in actuarial gain relating to pension
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12
 
 
 
 
 
 
 
1
 
 
 
13
 
Change in unrealized gain on interest rate swaps in VIEs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15
 
 
 
15
 
Net paid to non-controlling interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(68
)
 
 
(68
)
Dividend paid
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(199
)
 
 
 
 
 
 
(199
)
Net income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,261
 
 
 
92
 
 
 
1,353
 
Balance at December 31, 2009
 
 
798
 
 
 
164
 
 
 
1,956
 
 
 
359
 
 
 
902
 
 
 
634
 
 
 
4,813
 
Sale of treasury shares
 
 
3
 
 
 
20
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
23
 
Purchase of treasury shares
 
 
(4
)
 
 
(38
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(42
)
Issuance of shares
 
 
27
 
 
 
292
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
289
 
 
 
608
 
Induced conversion of convertible bonds
 
 
62
 
 
 
647
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
709
 
Employee stock options issued
 
 
 
 
 
 
11
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
11
 
Convertible loan-equity portion
 
 
 
 
 
 
121
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
121
 
Unrealized gain on marketable securities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18
 
 
 
 
 
 
 
 
 
 
 
18
 
Realized gain/loss on marketable securities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(43
)
 
 
 
 
 
 
 
 
 
 
(43
)
Foreign exchange differences
 
 
 
 
 
 
 
 
 
 
 
 
 
 
16
 
 
 
 
 
 
 
11
 
 
 
27
 
Changes in actuarial gain/losses relating to pension
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(26
)
 
 
 
 
 
 
(6
)
 
 
(32
)
Change in unrealized gain/loss on interest rate swaps in VIEs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(11
)
 
 
(11
)
Change in unrealized gain/loss on interest rate swaps in subsidiaries
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1
)
 
 
 
 
 
 
(1
)
 
 
(2
)
Step-up acquisition of Scorpion
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(13
)
 
 
13
 
 
 
0
 
Contribution by non-controlling interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
282
 
 
 
282
 
Paid to non-controlling interest in Scorpion
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(292
)
 
 
(292
)
Dividend paid to non-controlling interest in VIE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(435
)
 
 
(435
)
Dividend paid
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(990
)
 
 
 
 
 
 
(990
)
Net income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,117
 
 
 
55
 
 
 
1,172
 
Balance at December 31, 2010
 
 
886
 
 
 
1,217
 
 
 
1,956
 
 
 
323
 
 
 
1,016
 
 
 
539
 
 
 
5,937
 
Sale of treasury shares
    
1
      
20
                                      
21
  
Purchase of treasury shares
    
(5
)
    
(120
)
                            
(5
)
    
(130
)
Employee stock options issued
            
10
                                      
10
  
Change in actuarial gain/losses relating to pension
                            
(3
)
                    
(3
)
Private placement in subsidiary
            
307
                              
118
      
425
  
Costs related to capital increase in subsidiary
            
(7
)
                                    
(7
)
(Un)realized gain/loss on marketable securities
                            
(291
)
                    
(291
)
Foreign exchange differences
                            
28
              
10
      
38
  
Change in unrealized loss on interest rate swaps in VIEs
                                            
20
      
20
  
Change in unrealized loss on interest rate swaps in subsidiaries
                            
1
                      
1
  
Dividend payment
                                    
(1,423
)
    
(17
)
    
(1,440
)
Dividend paid to Non-controlling interest in VIE
                                            
(23
)
    
(23
)
Shares purchased from non controlling interests
            
(4
)
                            
(68
)
    
(72
)
Deconsolidation of subsidiaries
                            
(63
)
            
(330
)
    
(393
)
Induced conversion of convertible bonds
    
53
      
674
                                      
727
  
Net income
                                    
1,401
      
81
      
1,482
  
Balance at December 31, 2011
    
935
      
2,097
      
1,956
      
(5
)
    
994
      
325
      
6,302
  

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

 
F-8
 

Note 1- General information
 
Seadrill Limited ("Seadrill" or the "Company") was incorporated in Bermuda in May 2005, and is a listed company on the Oslo Stock Exchange and the New York Stock Exchange. Seadrill, through a number of acquisitions of other companies and contracts for newbuildings, has developed into one of the largest international offshore drilling contractors, providing services within drilling and well services. As of December 31, 2011 the Company owned a versatile fleet consisting of drillships, jack-up rigs, semi-submersible rigs and tender rigs for operations in shallow and deepwater areas, as well as benign and harsh environments, totaling 55 offshore drilling units, including fifteen units under construction.
 
In addition to owning and operating offshore floaters, jack-up rigs and tender rigs, we provide platform drilling, well intervention and engineering services through the separately Oslo Stock Exchange listed company Seawell Limited, now renamed Archer Ltd ("Archer"), a Bermuda company in which we own 39.9% at the end of December 2011. Effective from February 2011, Archer is no longer fully consolidated into our financial statements, but accounted for as an investment in an associated company.
 
As used herein, and unless otherwise required by the context, the term "Seadrill" refers to Seadrill Limited and the terms "Company", "we", "Group", "our" and words of similar import refer to Seadrill and its consolidated companies. The use herein of such terms as group, organization, we, us, our and its, or references to specific entities, is not intended to be a precise description of corporate relationships.
 
Basis of presentation
 
The financial statements are presented in accordance with generally accepted accounting principles in the United States of America (US GAAP). The amounts are presented in United States dollar (US dollar) rounded to the nearest million, unless otherwise stated.
 
In 2011 we have changed the presentation of unbilled revenue, previously presented as other current assets, now presented under the Accounts receivable line in the Consolidated Balance Sheet. We have adjusted December 2010 figures accordingly for comparison.
 
We have in 2010 and 2011 significantly expanded our fleet of drilling rigs through acquisitions of new rigs and newbuilding orders. In response to this development and the deconsolidation of Archer, management has reviewed our internal reporting structure including the operating and reporting business segments. This review has resulted in a change in our reporting segments reflecting how the chief operating decision makers assess performance and allocates resources. This change had effect from January 1, 2011, but the segments have also been retrospectively recasted for comparison. The new segments are floaters, jack-up rigs, tender rigs and well services.
 
The accompanying consolidated financial statements present the financial position of Seadrill Limited, the consolidated subsidiaries and the group's interest in associated entities. Investments in companies in which the Company directly or indirectly holds more than 50% of the voting control are consolidated in the financial statements, as well as certain variable interest entities of which the Company is deemed to be the primary beneficiary.
 
In accordance with  US GAAP, Seadrill's acquisition of Scorpion Offshore Ltd in June 2010 and Archer's acquisitions of Universal Wireline Inc in January 2011, Gray Wireline Service Inc in December 2010, Rig Inspection Services limited in August 2010 have been accounted for as purchases in accordance with Statement of Financial Accounting Standards No. 141R (currently Accounting Standards Codification (ASC) Topic 805 Business Combinations). These acquisitions are described in more detail in Note 25 (Acquisitions). The fair value of the assets acquired and liabilities assumed were included in the Company's consolidated financial statements beginning on the date when control was achieved.
 
Derivative financial instruments, financial instruments that are held for trading or classified as available-for-sale and other investments in entities owned less than 20% where the Company does not exercise significant influence, are recognized at fair value if fair value is readily determinable.
 
Non-current assets and disposal groups held for sale are stated at the lower of their carrying amount or fair value less costs of sale.
 
The accounting policies set out below have been applied consistently to all periods in these consolidated financial statements.
 
Basis of consolidation
 
The consolidated financial statements include the assets and liabilities of the Company and its subsidiaries and certain variable interest entities, ("VIE"s) in which the Company is deemed to be the primary beneficiary. All intercompany balances and transactions have been eliminated on consolidation.
 
 
F-9
 
 
A variable interest entity is defined in Accounting Standards Codification ("ASC") Topic 810 "Consolidation" ("ASC 810") as a legal entity where either (a) the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated support; (b) equity interest holders as a group lack either i) the power to direct the activities of the entity that most significantly impact on its economic success, ii) the obligation to absorb the expected losses of the entity, or iii) the right to receive the expected residual returns of the entity; or (c) the voting rights of some investors in the entity are not proportional to their economic interests and the activities of the entity involve or are conducted on behalf of an investor with a disproportionately small voting interest.
 
ASC 810 requires a variable interest entity to be consolidated by its primary beneficiary, being the interest holder, if any, which has both (1) the power to direct the activities of the entity which most significantly impact on the entity's economic performance, and (2) the right to receive benefits or the obligation to absorb losses from the entity which could potentially be significant to the entity.
 
We evaluate our subsidiaries, and any other entities in which we hold a variable interest, in order to determine whether we are the primary beneficiary of the entity, and where it is determined that we are the primary beneficiary we fully consolidate the entity.
 
Investment in companies in which we hold an ownership interest of between 20% and 50%, and over which we exercise significant influence, but do not consolidate, are accounted for using the equity method. The Company records its investments in associated companies and its share of earnings or losses in the consolidated statements of operations as "Share in results from associated companies". The excess, if any, of purchase price over book value of the Company's investments in equity method investees is included in the accompanying consolidated balance sheets in "Investment in associated companies".
 
Investments in companies in which our ownership is less than 20% are valued at fair value unless it is not possible to estimate fair value, then the cost method is used.
 
Intercompany transactions and internal sales have been eliminated on consolidation. Unrealized gains and losses arising from transactions with associates are eliminated to the extent of the Company's interest in the entity.
 
Note 2- Accounting policies
 
Use of estimates
 
Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Contract revenue
 
A substantial majority of the Company's revenues are derived from dayrate based drilling contracts (which may include lump sum fees for mobilization and demobilization) and other service contracts. Both dayrate based and lump sum fee revenues are recognized rateably over the contract period when services are rendered. Under some contracts, the Company is entitled to additional payments for meeting or exceeding certain performance targets. Such additional payments are recognized when any uncertainties are resolved or upon completion of the drilling program.
 
In connection with drilling contracts, the Company may receive lump sum fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to commencement of drilling services. These up-front fees are recognized as revenue over the contract term, excluding option periods.
 
In some cases, the Company may receive lump sum non-contingent fees or dayrate based fees from customers for demobilization upon completion of a drilling contract. Non-contingent demobilization fees are recognized as revenue over contract term, excluding option periods not exercised by our customers. Contingent demobilization fees are recognized as earned upon completion of the drilling contract.
 
Fees received from customers under drilling contracts for capital upgrades are deferred and recognized over the contract term, excluding option periods not exercised.
 
Reimbursables
 
Reimbursements received for the purchases of supplies, personnel services and other services provided on behalf of and at the request of our customers in accordance with a contract or agreement are recorded as revenue. The related costs are recorded as reimbursable expenses in the same period.
 
 
F-10
 
 
Other revenues
 
In a business combination there may exist favorable and unfavorable drilling contracts which are recorded at fair value at the date of acquisition when the purchase price allocation is prepared. A favorable or unfavorable drilling contract is a contract that has a dayrate which differs from prevailing market rates at the time of acquisition. The net present value of such contracts is recorded as an asset or liability at the purchase date and subsequently recognized as revenue or reduction to revenue over the contract term.
 
Mobilization and demobilization expenses
 
Demobilization costs are costs related to the transfer of a vessel or drilling rig to a safe harbor or different geographic area and are expensed as incurred.
 
Mobilization costs incurred as part of a contract are capitalized and recognized as expense over the contract term, excluding option periods not exercised by our customers. The costs of relocating drilling units that are not under contract are expensed as incurred.
 
Repairs, maintenance and periodic surveys
 
Costs related to periodic overhauls of drilling units are capitalized under drilling units and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic overhauls are included in depreciation and amortization expense.
 
Costs for other repair and maintenance activities are included in vessel and rig operating expenses and expensed when the repairs and maintenance take place.
 
Foreign currencies
 
The Company and the majority of its subsidiaries use the US dollar as their functional currency because the majority of their revenues and expenses are denominated in US dollars. Accordingly, the Company's reporting currency is also US dollars. For subsidiaries that maintain their accounts in currencies other than US dollars, the Company uses the current method of translation whereby the statements of operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in shareholders' equity.
 
Transactions in foreign currencies are translated into US dollar at the rates of exchange in effect at the date of the transaction. Foreign currency assets and liabilities are translated using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the consolidated statements of operations.
 
Current and non-current classification
 
Receivables and liabilities are classified as current assets and liabilities respectively, if their maturity is within one year of the balance sheet date. Otherwise, they are classified as non-current assets and liabilities.
 
Cash and cash equivalents
 
Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.
 
Restricted cash
 
Restricted cash consists of bank deposits which have been pledged as collateral for certain guarantees issued by a bank or minimum deposits which must be maintained in accordance with contractual arrangements. Restricted cash with maturity longer than one year are classified on a separate line as non-current assets.
 
Marketable securities
 
Marketable equity securities held by the Company are considered to be available-for-sale and, as such, are recorded at fair value with resulting unrealized gains and losses recorded as a separate component of accumulated other comprehensive income in shareholders' equity. The company also holds marketable securities considered to be trading securities and as such, are recorded at fair value with resulting unrealized gains and losses recorded through the profit and loss statement. Gains and losses on forward contracts to purchase marketable equity securities that do not meet the definition of a derivative are accounted for as available-for-sale.
 
 
F-11
 
 
Receivables
 
Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. The Company establishes reserves for doubtful accounts on a case-by-case basis when it is unlikely that required payments of specific amounts will occur. In establishing these reserves, the Company considers the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. Receivable amounts determined as being unrecoverable are written off.
 
Impairment of marketable securities and equity method investees
 
The Company analyzes its 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 that may have a significant adverse effect on the fair value of the investment. The Company records an impairment charge for other-than-temporary declines in fair value when the fair value is not anticipated to recover above cost within reasonably 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.
 
Newbuildings
 
The carrying value of rigs under construction ("Newbuildings") represents the accumulated costs at the balance sheet date. Cost components include payments for yard installments and variation orders, construction supervision, equipment, spare parts, capitalized interest, costs related to first time mobilization and commissioning costs. No charge for depreciation is made until commissioning of the newbuilding has been completed and it is ready for its intended use.
 
The Company may have options agreements with shipyards to order new rigs at fixed or variable prices which require some or no additional payment upon exercise. Payments for rig purchase options are capitalized at the time when option contracts are acquired or entered into. The Company reviews the expected future cash flows, which would result from the exercise of each option contract on a contract by contract basis to determine whether the carrying value of the option is recoverable.
 
Capitalized interest
 
Interest expenses are capitalized during construction of newbuildings based on accumulated expenditures for the applicable project at the Company's current rate of borrowing. The amount of interest expense capitalized in an accounting period shall be determined by applying an interest rate ("the capitalization rate") to the average amount of accumulated expenditures for the asset during the period. The capitalization rates used in an accounting period shall be based on the rates applicable to borrowings outstanding during the period. The Company does not capitalize amounts beyond the actual interest expense incurred in the period.
 
If the Company's financing plans associate a specific new borrowing with a qualifying asset, the Company uses the rate on that borrowing as the capitalization rate to be applied to that portion of the average accumulated expenditures for the asset that does not exceed the amount of that borrowing. If average accumulated expenditures for the asset exceed the amounts of specific new borrowings associated with the asset, the capitalization rate to be applied to such excess shall be a weighted average of the rates applicable to other borrowings of the Company.
 
Drilling units
 
Rigs, vessels and equipment are recorded at historical cost less accumulated depreciation. The cost of these assets less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of the Company's floaters, jack-up rigs 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.
 
 
F-12
 
 
Assets are classified as held for sale when management is actively committed to a probable asset sale within one year of an asset ready for immediate sale. Cost of property and equipment sold or retired, with the related accumulated depreciation and write-downs are removed from the balance sheet, and resulting gains or losses are included in the consolidated statement of operations.
 
Other equipment
 
Other equipment is recorded at historical cost less accumulated depreciation and is depreciated over its estimated remaining useful life, which is between three and five years depending on the type of asset.
 
Goodwill
 
The Company allocates the purchase price of acquired businesses to the identifiable tangible and intangible assets and liabilities acquired, with any remaining amount being capitalized as goodwill. Goodwill is tested for impairment at least annually at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. The Company has determined that its reporting units are the same as the operating segments for the purpose of allocating goodwill and the subsequent testing of goodwill for impairment. The goodwill impairment test requires the Company to compare the fair value of its reporting units to their carrying value.  In the event that the fair value is less than carrying value, the Company must perform an exercise similar to a purchase price allocation in a business combination in order to determine the amount of the impairment charge.
 
We perform our annual test of goodwill impairment as of December 31 for each reporting unit, based on discounted cash flows. For the impairment testing we have used expected future cash flows applying contract dayrates during the firm contract periods and estimated forecasted dayrates for the periods after expiry of firm contract periods. We have assumed zero escalation of dayrates for the periods. The estimated future cash flows have been based on remaining economic useful lives for the assets, and discounted using a weighted average cost of capital (WACC).
 
We have also performed sensitivity analysis using different scenarios regarding future cash flows (being a product of dayrate levels, utilization rates, operational expenses, and maintenance expenses), remaining economic useful lives of the assets and discount rates showing acceptable tolerance to changes in underlying assumptions in the impairment model before changes in assumptions would result in impairment.
 
In September 2011, the Financial Accounting Standards Board, or FASB, issued new guidance relative to the test for goodwill impairment. The new guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two step goodwill impairment test. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We have decided to early adopt this new guidance. For the year-ended December 31, 2011, we concluded it was not necessary to perform the two step goodwill impairment test.
 
Other intangible assets
 
Other intangible assets are recorded at historical cost less accumulated amortization. The cost of these assets less estimated residual value is amortized on a straight-line basis over the estimated remaining economic useful lives. Other intangible assets include technology and customer relationships.
 
Impairment of long-lived assets
 
The carrying value of long-lived assets that are held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset's carrying value and fair value.
 
Defined benefit pension plans
 
The Company has several defined benefit plans which provide retirement, death and early termination benefits. The Company's net obligation is calculated separately for each plan by estimating the amount of the future benefit that employees have earned in return for their cumulative service.
 
 
F-13
 
 
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.
 
Treasury shares
 
Treasury shares are recognized at cost as a component of equity. The purchase of treasury shares reduces the Company's share capital by the nominal value of the acquired treasury shares. The amount paid in excess of the nominal value is treated as a reduction of additional paid-in capital.
 
Derivative Financial Instruments and Hedging Activities
 
The Company's interest-rate swap agreements, foreign currency options and forward exchange contracts are recorded at fair value. Changes in the fair value of interest-rate swap agreements, forward exchange and currency options contracts, which have not been designated as hedging instruments, are recorded as a gain or loss as a separate line item within Financial Items.
 
Changes in the fair value of any derivative instrument that we have formally designated as a hedge, are recognized in the "Accumulated other comprehensive income (loss)" in the Consolidated Balance Sheets. Any change in fair value relating to an ineffective portion of a designated hedges is charged to the income statement. When the hedged item affects the income statement, the gain or loss included in accumulated other comprehensive income (loss) is reported on the same line in the Consolidated Statements of Income as the hedged item.
 
Financial instruments such as forward contracts to purchase shares that do not qualify as derivative instruments are not recognized on the balance sheet, unless deemed impaired. Such instruments are off-balance sheet transactions and result in only disclosures.
 
Income taxes
 
Seadrill is a Bermuda company. Currently, Seadrill is not required to pay taxes in Bermuda on ordinary income or capital gains as we qualify as an exempt company. The Company has received written assurance from the Minister of Finance in Bermuda that, it will be exempt from taxation until March 2035. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently income taxes have been recorded in these jurisdictions when appropriate.
 
Significant judgment is involved in determining the Group-wide provision for income taxes. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. Seadrill recognizes tax liabilities based on its assessment of whether its tax positions are more likely than not sustainable, based on the technical merits and considerations of the relevant taxing authority's widely understood administrative practices and precedence.
 
Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantially enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted or substantially enacted.
 
Deferred charges
 
Loan related costs, including debt arrangement fees, are capitalized and amortized over the term of the related loan and are included in interest expense.
 
Convertible debt
 
Convertible bond loans issued by the Company include both a loan component (host contract) and an option to convert the loan to shares (embedded derivative).
 
 
F-14
 
 
An embedded derivative, such as a conversion option, may be separated from its host contract and accounted for separately if certain criteria are met (including if the contract that embodies both the embedded derivative and the host contract is not measured at fair value, the economic characteristics and risks of the embedded derivative instrument are not clearly and closely related to the economic characteristics and risks of the host contract and if a separate instrument with the same terms as the embedded instrument would be a derivative).
 
If an embedded derivative instrument is separated from its host contract, the host contract shall be accounted for based on generally accepted accounting principles applicable to instruments of that type which do not contain embedded derivative instruments.
 
Total Return Equity Swaps
 
From time to time, the Company enters into total return equity swaps ("TRS") indexed to the Company's own shares, where the counterparty acquires shares in the Company and the Company carries the risk of fluctuations in the share price of the acquired shares. The fair value of each TRS is recorded as an asset or liability, with the changes in fair value recorded in the consolidated statement of operations. The Company may, from time to time, enter into TRS arrangements indexed to shares in other companies and these are accounted for in the same way.
 
Share-based compensation
 
The Company has established an employee share ownership plan under which employees, directors and officers of the Group may be allocated options to subscribe for new shares in the ultimate parent, Seadrill Limited. The compensation cost for stock options is recognized as an expense over the service period based on the fair value of the options granted.
 
The fair value of the share options issued under the Company's employee share option plans is determined at grant date taking into account the terms and conditions upon which the options are granted, and using a valuation technique that is consistent with generally accepted valuation methodologies for pricing financial instruments, and that incorporates all factors and assumptions that knowledgeable, willing market participants would consider in determining fair value. The fair value of the share options is recognized as personnel expenses with a corresponding increase in equity over the period during which the employees become unconditionally entitled to the options. Compensation cost is initially recognized based upon options expected to vest with appropriate adjustments to reflect actual forfeitures. National insurance contributions arising from such incentive programs are expensed when the options are exercised.
 
Provisions
 
A provision is recognized in the balance sheet when the Company has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.
 
Segment reporting
 
We have in 2010 and 2011 significantly expanded our fleet of drilling rigs through acquisitions of new rigs and newbuilding orders. In response to this development and the deconsolidation of Archer, management has reviewed our internal reporting structure including the operating and reporting business segments. This review has resulted in a change in our reporting segments reflecting how the chief operating decision makers assess performance and allocates resources. This change had effect from January 1, 2011, but the segments have also been retrospectively recasted for comparison. The new segments are floaters, jack-up rigs, tender rigs and well services.
 
As of December 31, 2011, the Company has three reportable business segments which include floaters, jack-up rigs and tender rigs. The well services business segment included the activities of Archer which performs various services related to platform drilling, drilling facility engineering, well intervention and oilfield services. With effect from the end of February 2011, Archer has been deconsolidated and the well services segment is no longer part of our consolidated financial statements.
 
Related parties
 
Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence. All transactions between the related parties are based on the principle of arm's length (estimated market value).
 
 
F-15
 
 
Issuance of shares by a subsidiary/associate
 
As of January 1, 2009 ASC 810-10-65 (FAS 160) was implemented which precludes a company from recognizing a profit when its subsidiary or associate issues its stock to third parties at a price per share in excess of its carrying amount if such profit is realizable. Effective from January 1, 2009 any profit of future issuance of shares by a subsidiary/associate will hence be recorded as equity transactions.
 
Earnings per share
 
Basic earnings per share ("EPS") is calculated based on the income (loss) for the period available to common stockholders divided by the weighted average number of shares outstanding for basic EPS for the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments which for the Company includes share options and convertible debt. The determination of dilutive earnings per share requires the Company to potentially make certain adjustments to net income and for the weighted average shares outstanding used to compute basic earnings per share unless anti-dilutive.
 
Reclassifications
 
Certain reclassifications have been made to prior period amounts to conform with the current year presentation. These reclassifications did not have a material effect on the consolidated financial statements.
 
New Accounting Pronouncements
 
In May 2011, the FASB issued Accounting Standards Update, or ASU, 2011-04 "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs (International Financial Reporting Standards)". In general, ASU 2011-04 clarifies the FASB's intent about the application of existing fair value measurement and disclosure requirements, and for many of these requirements the amendments are not intended to result in any change in the application of ASC Topic 820, "Fair Value Measurement". At the same time, there are some amendments that do change particular principles or requirements relating to fair value measurement and disclosure.  ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. Its adoption is not expected to have a material impact on the Company's disclosures or consolidated financial position, results of operations, and cash flows.
 
In June 2011, the FASB issued ASU 2011-05 "Presentation of Comprehensive Income" in order to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. ASU 2011-05 eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity, and requires entities to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. ASU 2011-05 is effective for fiscal years beginning after December 15, 2011, although early adoption is permitted. Its adoption is not expected to have a material impact on the Company's disclosures or consolidated financial position, results of operations, and cash flows.
 
In September 2011, the FASB issued new guidance relative to the test for goodwill impairment. The new guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. The company has decided to early adopt this new guidance.
 
In December 2011, the FASB issued ASU 2011-11 "Disclosures about Offsetting Assets and Liabilities" in order to standardize the disclosure requirements under US GAAP and IFRS relating to both instruments and transactions eligible for offset in financial statements. ASU 2011-11 is applicable for annual reporting periods beginning on or after January 1, 2013. Its adoption is not expected to have a material impact on the Company's disclosures.
 
Note 3 – Segment information
 
Operating segments
 
The Company provides drilling and related services to the offshore oil and gas industry. The split of our organization into segments has historically been based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure.
 
 
F-16
 
 
We have in 2010 and 2011 significantly expanded our fleet of drilling rigs through acquisitions of new rigs and newbuilding orders. In response to this development and the deconsolidation of Archer, management has reviewed our internal reporting structure including the operating and reporting business segments. This review has resulted in a change in our reporting segments reflecting how the chief operating decision makers assess performance and allocates resources. This change had effect from January 1, 2011, but the segments have also been retrospectively recasted for comparison sake.
 
We currently operate in the following three segments:
 
Floaters: The Company offers services encompassing drilling, completion and maintenance of offshore wells. The drilling contracts relate to employment of semi-submersible rigs and drillships.
 
Jack-up rigs: The Company offers services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to Jack-up rigs for operations in harsh and benign environment.
 
Tender Rigs: The Company operates self-erecting tender rigs and semi-submersible tender rigs, which are used for production drilling and well maintenance in benign environments.
 
Segment results are evaluated on the basis of operating profit, and the information given below is based on the internal reporting structure used in the reporting to the Executive Management and the Board. The accounting principles for the segments are the same as for the Company's Consolidated Financial Statements.
 
Revenues (excluding gain on sale of drilling units)
                     
 
(In US$ millions)
 
2011
 
 
2010
 
2009
 
 
 
 
 
 
 
 
 
Floaters
 
 
2,694
 
 
 
2,264
 
 
1,864
Jack-up rigs
    
776
      
578
    
388
Tender Rigs
 
 
589
 
 
 
482
 
 
392
Well Services
 
 
133
 
 
 
717
 
 
610
Total
 
 
4,192
 
 
 
4,041
 
 
3,254
 
Depreciation and amortization
                        
 
(In US$ millions)
 
2011
 
 
2010
 
2009
 
 
 
 
 
 
 
 
 
Floaters
 
 
358
 
 
 
301
 
 
261
Jack-up rigs
    
135
      
99
    
72
Tender Rigs
 
 
63
 
 
 
57
 
 
42
Well Services
 
 
7
 
 
 
23
 
 
21
Total
 
 
563
 
 
 
480
 
 
396
 
Operating Income – net income
 
 
(In US$ millions)
 
2011
 
 
2010
 
2009
 
 
 
 
 
 
 
 
 
 
Floaters
 
 
1,328
 
 
 
1,140
 
 
912
 
Jack-up Rigs
    
220
      
199
    
229
  
Tender Rigs
 
 
221
 
 
 
222
 
 
174
 
Well Services
 
 
5
 
 
 
64
 
 
57
 
Operating income
 
 
1,774
 
 
 
1,625
 
 
1,372
 
  Unallocated items:
 
 
 
 
 
 
 
 
 
 
 
Total financial items
 
 
(103
)
 
 
(294
)
 
101
  
Income taxes
 
 
(189
)
 
 
(159
)
 
(120
)
Gain on issuance of shares by subsidiary
 
 
-
 
 
 
-
 
 
-
 
Net income
 
 
1,482
 
 
 
1,172
 
 
1,353
  
 
 
F-17
 
 
Total assets
 
 
(In US$ millions)
 
2011
 
 
2010
 
 
 
 
 
 
 
 
Floaters
 
 
12,600
 
 
 
11,650
 
Jack-up Rigs
    
4,200
      
3,538
  
Tender Rigs
 
 
1,504
 
 
 
1,322
 
Well Services
 
 
-
 
 
 
987
 
Total
 
 
18,304
 
 
 
17,497
 
 
Goodwill
 
 
(In US$ millions)
 
2011
 
 
2010
 
 
 
 
 
 
 
 
Floaters
 
 
890
 
 
 
890
 
Jack-up Rigs
    
281
      
281
  
Tender Rigs
 
 
149
 
 
 
149
 
Well Services
 
 
-
 
 
 
356
 
Total
 
 
1,320
 
 
 
1,676
 
 
As a consequence of the change in segment structure from 2011, the Goodwill has been reassigned to the reporting units affected using a relative fair value allocation approach.
 
 
Total liabilities
 
 
(In US$ millions)
 
2011
 
 
2010
 
 
 
 
 
 
 
 
Floaters
 
 
8,274
 
 
 
8,092
 
Jack-up Rigs
    
2,745
      
2,406
  
Tender Rigs
 
 
983
 
 
 
630
 
Well Services
 
 
-
 
 
 
432
 
Total
 
 
12,002
 
 
 
11,560
 
 
Capital expenditures – fixed assets
 
 
(In US$ millions)
 
2011
 
 
2010
 
 
2009
 
 
 
 
 
 
 
 
 
 
 
Floaters
  
 
1,805
 
 
 
1,330
 
 
 
936
 
Jack-up Rigs
    
495
      
877
      
155
  
Tender Rigs
 
 
243
 
 
 
134
 
 
 
247
 
Well Services
 
 
-
 
 
 
27
 
 
 
31
 
Total
 
 
2,543
 
 
 
2,368
 
 
 
1,369
 
 
Geographic segment data
 
Revenues are attributed to geographical segments based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents the Company's revenues and fixed assets by geographic area:
 
Revenues (excluding gain on sale of assets)
 
 
(In US$ millions)
 
2011
 
 
2010
 
 
2009
 
 
 
 
 
 
 
 
 
 
 
Norway
 
 
966
 
 
 
1,393
 
 
 
1,235
 
UK
 
 
56
 
 
 
151
 
 
 
149
 
Brunei
 
 
54
 
 
 
66
 
 
 
42
 
Thailand
 
 
303
 
 
 
165
 
 
 
112
 
Malaysia
 
 
207
 
 
 
62
 
 
 
108
 
 
 
F-18
 
 
Congo
 
 
-
 
 
 
37
 
 
 
70
 
Nigeria
 
 
235
 
 
 
204
 
 
 
155
 
Australia
 
 
-
 
 
 
-
 
 
 
112
 
USA
 
 
202
 
 
 
186
 
 
 
147
 
Brazil
 
 
913
 
 
 
710
 
 
 
500
 
China
 
 
299
 
 
 
230
 
 
 
178
 
Indonesia
 
 
130
 
 
 
159
 
 
 
179
 
Philippines
 
 
-
 
 
 
109
 
 
 
54
 
Vietnam
 
 
157
 
 
 
150
 
 
 
105
 
Angola
 
 
337
 
 
 
182
 
 
 
27
 
Red Sea
 
 
-
 
 
 
68
 
 
 
1
 
Trinidad & Tobago
    
41
      
-
      
-
  
Saudi Arabia/Kuwait
 
 
127
 
 
 
69
 
 
 
-
 
Mexico
    
49
      
-
      
-
  
Other
 
 
116
 
 
 
100
 
 
 
80
 
Total
 
 
4,192
 
 
 
4,041
 
 
 
3,254
 
 
Fixed assets – operating drilling units (1)
 
 
(In US$ millions)
 
2011
 
 
2010
 
 
 
 
 
 
 
 
Norway
 
 
2,007
 
 
 
1,321
 
UK
 
 
-
 
 
 
751
 
Brunei
 
 
38
 
 
 
210
 
Thailand
 
 
605
 
 
 
397
 
Malaysia
 
 
333
 
 
 
250
 
Nigeria
 
 
1,191
 
 
 
601
 
USA
 
 
496
 
 
 
515
 
Brazil
 
 
2,096
 
 
 
2,804
 
China
 
 
1,091
 
 
 
1,171
 
Indonesia
 
 
321
 
 
 
570
 
Vietnam
 
 
336
 
 
 
521
 
Angola
 
 
979
 
 
 
1,020
 
Trinidad & Tobago
 
 
424
 
 
 
-
 
Saudi Arabia
 
 
331
 
 
 
345
 
Mexico
    
605
      
-
  
Other
 
 
370
 
 
 
319
 
Total
 
 
11,223
 
 
 
10,795
 
 
(1) The fixed assets referred to in the table are the Company's operating drilling units. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.
 
Note 4 – Taxation
 
Income taxes consist of the following:
 
 
 
Year ended December 31
 
 
(In millions of US dollar)
 
2011
 
 
2010
 
 
2009
 
 
 
 
 
 
 
 
 
 
 
Current tax expense:
 
 
 
 
 
 
 
 
 
  Bermuda
 
 
-
 
 
 
-
 
 
 
-
 
  Foreign
 
 
328
 
 
 
184
 
 
 
118
 
Deferred tax expense:
 
 
 
 
 
 
 
 
 
 
 
 
  Bermuda
 
 
-
 
 
 
-
 
 
 
-
 
  Foreign
 
 
24
  
 
 
14
  
 
 
(3
)
  Deferred taxes acquired during the year
 
 
-
 
 
 
-
 
 
 
-
  
  Tax related to internal sale of assets in subsidiary,  amortized for group purposes
 
 
(163
)
 
 
(39
)
 
 
5
  
Total provision
 
 
189
 
 
 
159
 
 
 
120
 
Effective tax rate
 
 
11.3
%
 
 
12.1
%
 
 
8.1
%
 
 
F-19
 
 
The Company, including its subsidiaries, is taxable in several jurisdictions based on its rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, the Company may pay tax within some jurisdictions even though it might have an overall loss at the consolidated level.
 
The income taxes for the years ended December 31 differed from the amount computed by applying the statutory income tax rate of 0 % as follows:
 
 
 
Year ended December 31
 
 
(In millions of US dollar)
 
2011
 
 
2010
 
 
2009
 
 
 
 
 
 
 
 
 
 
 
Income taxes at statutory rate
 
 
-
 
 
 
-
 
 
 
-
 
Effect of transfers to new tax jurisdictions
 
 
(163
)
 
 
(39
)
 
 
5
  
Effect of change in taxable currency
 
 
-
 
 
 
-
 
 
 
-
 
Effect of taxable income in various countries
 
 
352
 
 
 
198
 
 
 
115
 
Total
 
 
189
 
 
 
159
 
 
 
120
 
 
Deferred Income Taxes
 
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The net deferred tax assets (liabilities) consist of the following:
 
Deferred Tax Assets:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Pension
 
 
11
 
 
 
15
 
Tax loss carry forward
 
 
-
 
 
 
10
 
Unfavorable contracts
 
 
-
 
 
 
2
 
Provisions
 
 
15
 
 
 
-
 
Property, plant and equipment
 
 
9
 
 
 
-
 
Other
 
 
8
 
 
 
5
 
Gross deferred tax asset
 
 
43
 
 
 
32
 
 
Deferred Tax Liability:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Property, plant and equipment
 
 
-
 
 
 
62
 
Long term maintenance
 
 
-
 
 
 
48
 
Gain from sale of fixed assets
 
 
31
 
 
 
64
 
Other
 
 
13
 
 
 
24
 
Gross deferred tax liability
 
 
44
 
 
 
198
 
 
 
 
 
 
 
 
 
 
Net deferred tax
 
 
1
 
 
 
166
 
 
Net deferred taxes are classified as follows:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Short-term deferred tax asset
 
 
10
 
 
 
2
 
Long-term deferred tax asset
 
 
33
 
 
 
30
 
Short-term deferred tax liability
 
 
10
 
 
 
17
 
Long-term deferred tax liability
 
 
34
 
 
 
181
 
Net deferred tax
 
 
1
 
 
 
166
 
 
 
F-20
 
 
Future taxable income justifies the inclusion of tax loss carry-forward in the calculation of net deferred taxes.
 
Uncertain tax positions
 
In October 2011, the tax authorities in Norway issued a tax reassessment pertaining to tax filings made by our consolidated subsidiary, North Atlantic Drilling Limited ("North Atlantic") for the years 2007 through 2009. The following issues were addressed in the tax reassessment:
 
 
a)
the Company's 2007 tax positions relating to a possible taxable gain arising from the transfer of certain legal entities to a different tax jurisdiction.  These positions also affect the relevant filed tax assessments for 2008, 2009 and 2010.  To the extent there is a taxable gain, there is also an uncertainty related to the amount of such gain, and this, in turn, is affected by the timing of the transfer of the domiciles of the legal entities to a new tax jurisdiction.  In the Company's opinion, the transfer by the legal entities of their domiciles took place in December 2007.
 
 
b)
the principles for conversion of the functional currency for several Norwegian subsidiaries for tax reporting purposes. In the Company's view, applicable tax legislation is subject to various interpretations related to the calculation of the tax basis measured in Norwegian kroner. There is ongoing correspondence with tax authorities with regards to calculation methods for conversion of accounts in functional currency to taxable income in Norwegian kroner.
 
The total remaining claim following the tax reassessment is approximately $263 million and is calculated based on tax reassessments received, reduced with payments and ordinary current tax accruals in 2010 and 2011.
 
Management remains of the opinion that the tax authorities' position, related to item a) above, is based on an unconstitutional retroactive application of the law. We will vigorously defend ourselves against this claim and we have filed legal action in Norway to mitigate the liability. As for item b) above, we are in the process of filing an appeal
 
Management has performed an analysis for uncertain tax positions in the various jurisdictions in which the Company operates, in accordance with ASC Topic 740 Income Taxes. Based on the analysis, the Company has recorded a tax expense of $9 million in the profit and loss statement and $39 million as deferred charges, amortized over the remaining lifetime of the sold drilling units. Correspondingly, a short term tax liability related to uncertain tax positions of $48 million has been recorded in 2011.
 
The changes to our liabilities related to unrecognized tax benefits, excluding interest and penalties that we recognize as a component of income tax expense, where as follows:
 
 
 
Year ended December 31
 
 
(In millions of US dollar)
 
2011
 
 
2010
 
 
2009
 
Balance beginning of period
 
-
  
 
-
 
 
-
 
Additions for prior years tax positions
    
48
      
-
      
-
 
Balance end of period
 
 
48
 
 
 
-
 
 
 
-
 
 
In addition to this, a provision of $15 million has been recorded as tax expense in the profit and loss statement related to item b) above with a corresponding short term tax liability.
 
In relation  to the above mentioned possible tax claims, Seadrill Limited has in 2012 provided North Atlantic Drilling Limited with a liquidity facility covering any liquidity exposure for North Atlantic Drilling Limited and where Seadrill Limited will keep North Atlantic Drilliing Limited harmless for any tax claim exceeding $63 million related to the move of legal entities to a new tax jurisdiction and the use of US dollar as the functional currency for tax reporting purposes.
 
Based on the analysis, the Company has not made any other provisions for uncertain tax positions than the one described above.
 
The parent company, Seadrill Limited, is headquartered in Bermuda where we have been granted a tax exemption until 2035.  Other jurisdictions in which the Company and its subsidiaries operate are taxable based on rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction.  Thus, the Company may pay tax within some jurisdictions even though it may have an overall loss at the consolidated level.  The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:
 
Jurisdiction
Earliest Open Year
Australia
2008
Nigeria
2007
Norway
2007
Thailand
2003
 
 
F-21
 
 
Note 5 – Earnings per share
 
The components of the numerator and denominator for the calculation of basic and diluted earnings per share resulting from continuing operations are as follows:
 
 
 
Net income
 
 
Weighted average million of shares outstanding
 
Earnings per share
 
2009
 
 
 
 
 
 
 
 
 
 
 
Earnings per share
 
 
1,261
 
 
 
399
 
 
3.16
 
Effect of dilution:
 
 
 
 
 
 
 
 
 
 
 
     Convertible bonds
 
 
50
 
 
 
36
 
 
 
 
     Share options
 
 
-
 
 
 
2
 
 
 
 
Diluted earnings per share
 
 
1,311
 
 
 
437
 
 
3.00
 
2010
 
 
 
 
 
 
 
 
 
 
 
Earnings per share
 
 
1,117
 
 
 
409
 
 
2.73
 
Effect of dilution:
 
 
 
 
 
 
 
 
 
 
 
     Convertible bonds
 
 
228
 
 
 
60
 
 
 
 
     Share options
 
 
-
 
 
 
2
 
 
 
 
Diluted earnings per share**
 
 
1,345
 
 
 
471
 
 
2.73
 
2011
 
 
 
 
 
 
 
 
 
 
 
Earnings per share
 
 
1,401
      
459
 
 
3.05
 
Effect of dilution:
 
 
          
 
 
 
 
     Convertible bonds
 
 
45
      
28
 
 
 
 
     Share options
 
 
-
      
1
 
 
 
 
Diluted earnings per share
 
 
1,446
 
 
 
488
 
 
2.96
 
 
**The loss on debt extinguishment of $145 million has been added back to net income in addition to interests expenses related to the convertible bonds. These effects are anti-dilutive, and exceed the effect of increased denominator when calculating the diluted earnings per share. As a consequence of this, the diluted earnings per share equal basic earnings per share.
 
Note 6 – Other revenues
 
Other revenues comprise the following items:
 
 
 
Year ended December 31
 
 
(In US$ millions)
 
2011
 
 
2010
 
 
2009
 
 
 
 
 
 
 
 
 
 
 
Amortization of unfavorable contracts
 
 
24
 
 
 
39
 
 
 
43
 
Amortization of favorable contracts
 
 
(23
)
 
 
(13
)
 
 
-
 
Total
 
 
1
 
 
 
26
 
 
 
43
 
 
The unfavorable contract values arose from the acquisition of Smedvig and Eastern Drilling and represent the net present value of the existing contracts compared to the current market rates, discounted at the weighted average cost of capital. The estimated unfavourable contract values have been amortized and recognized under other revenues over the terms of the contracts, ranging from two to five years and are fully amortized at December 31, 2011. The favourable contract values arose from the acquisition of Scorpion in June 2010 and are amortized over a period ranging from 20 to 36 months.  As of December 31, 2011 unamortized amount of favorable contracts amounted to US$14 million.
 
 
F-22
 
 
Note 7 – Gain on sale of assets
 
The Company has recognized the following gains and losses on sales of assets:
 
 
(In millions of US dollar)
 
Net proceeds
 
 
Book value on
disposal
 
 
Gain/Loss
 
Year ended December 31, 2011:
 
 
 
 
 
 
 
 
 
 
 
 
Sale of jack-up West Juno
 
 
248
 
 
 
226
 
 
 
22
 
Total for year ended December 31, 2011
 
 
248
 
 
 
226
 
 
 
22
 
Year ended December 31, 2010:
                        
Sale of Jack-up rig West Larissa
    
55
      
29
      
26
  
Total for year ended December 31, 2010
    
55
      
29
      
26
  
     
 
                  
Year ended December 31, 2009:
                        
Sale of jack-up rig West Ceres
 
 
178
 
 
 
157
 
 
 
21
 
Gain on disposal of jack-up rig West Atlas
 
 
200
 
 
 
142
 
 
 
58
 
Gain on sale of Seadrill's share in Chestnut field
 
 
4
 
 
 
0
 
 
 
4
 
Loss related to jack-up newbuild*
 
 
11
 
 
 
23
 
 
 
(12
)
Total for year ended December 31, 2009
 
 
393
 
 
 
322
 
 
 
71
 
 
* Loss incurred due to the PPL yard exercising their option to purchase the construction contract for one jack-up rig.
 
Note 8 – Operational leases
 
The Company has operating leases relating to premises, the most significant being its offices in Stavanger, Singapore, Houston, Rio de Janeiro, Dubai and Aberdeen. In the years ended December 31, 2011, 2010 and 2009 rental expenses amounted to $20 million, $21 million and $14 million, respectively. Future minimum rental payments are as follows:
 
Year
 
US$million
 
2012
 
 
17
  
2013
 
 
9
  
2014
 
 
6
  
2015
 
 
5
  
2016
 
 
4
  
2017 and thereafter
 
 
10
  
Total
 
 
51
  
 
Note 9 – Impairment loss on marketable securities and investments in associated companies
 
As at December 31, 2011, the Company owns a number of shares, share purchase agreements and bonds in companies including Archer Ltd., Asia Offshore Drilling Ltd., Varia Perdana Bhd., Sevan Drilling, SapuraCrest Bhd, Seahawk Drilling Inc., Ensco plc, Petromena and Golden Close Marine.
 
In 2011 the Company determined that the declines in fair value of the Archer investment were other than temporary based primarily upon its evaluation of the severity of the excess of its cost basis over the market price of the security and the prospects for recovery within 2012. As a result, an impairment loss was recognized reducing its cost basis of this associated company to the market price of the shares in question as of December 31, 2011, which was $393 million. The impairment loss amounted to $463 million and is presented as share of result from associated companies in the consolidated statements of operations.
 
Also the Company determined that the decline in fair value of its Seahawk shares was other than temporary and as a result, an impairment loss was recognized reducing its cost basis to the market price of the shares in question as of December 31, 2011. The impairment loss amounted to $10 million and has been classified as a separate line item in the consolidated statements of operations.
 
In 2010 the Company determined that the decline in fair value of its Seahawk shares was other than temporary and as a result, an impairment loss was recognized reducing its cost basis to the market price of the shares in question as of December 31, 2010. The loss of $15 million was classified as a separate line item in the income statement.
 
For the twelve month period ended December 31, 2009 no impairment losses were recognized for the securities.
 
Note 10 – Other financial items
 
The main items reported within Other financial items are detailed below.
 
In the twelve months ended December 31, 2011, the Company recorded a gain of $7 million in Commercial Interest Reference Rate (CIRR) amortization.
 
 
F-23
 
 
In the twelve months ended December 31, 2010, the Company recorded a gain of $43 million on the partial redemption of its investment in the Petromena NOK2 billion bond. The Company also recorded a gain of $8 million in CIRR amortization and a loss of $11 million related to unamortized funding arrangement fees.
 
In the twelve months ended December 31, 2009, the Company recorded a gain of $16 million on the partial redemption of its investment in the Petromena NOK2 billion bond, and the receipt of shares to the value of $25 million in Seahawk as dividend in kind paid by Pride.
 
Note 11 – Deconsolidation of subsidiary
 
Prior to February 23, 2011, Seawell Ltd was a consolidated subsidiary of Seadrill. On February 23, 2011, the stockholders in Allis-Chalmers Inc approved a merger agreement and a plan of merger, involving Allis-Chalmers, Seawell and Wellco Sub Company, pursuant to which Allis-Chalmers would become a subsidiary of Seawell. At the same time Seawell was renamed Archer.
 
As of February 23, 2011, we held 117,798,650 shares in Archer. Based on closing share price of NOK34.00 on February 23, 2011, this ownership had a gross value of $711 million. As a consequence of the merger, our ownership interest in Archer was reduced from 52.3% to 36.4%, and as such, Archer was deconsolidated as of February 23, 2011.
 
A change in control is considered a re-measurement event; therefore, upon losing control of Archer, we have re-measured at fair value any retained equity interest in the former subsidiary.
 
(In US$ millions)
 
December
31, 2011
 
         
Fair value of the consideration received
 
 
-
 
Fair value of the retained non-controlling investment
 
 
711
 
The carrying amount of non-controlling interest in Archer
 
 
330
 
The carrying amount of Archer's assets and liabilities
 
 
(564)
 
Accumulated translation adjustments recycled from OCI into profit & loss
 
 
70
 
Accumulated actuarial loss recycled from OCI into profit & loss
 
 
(7)
 
Total gain
 
 
540
 
 
Subsequent to the deconsolidation, the Company has purchased shares in Archer for $167 million, increasing our ownership to 39.9%. The total carrying value has been impaired in the fourth quarter of 2011, refer note 9 "Impairment loss on marketable securities and investments in associated companies".
 
In August 2010, Archer issued 115,400,000 new shares of par value $2.00 each at a price of NOK23.00 per share, raising a total of NOK2.6 billion. The Company subscribed for 34,873,000 of the new shares and, at the same time purchased an additional 1,757,000 shares. As a result, the Company's shareholding was reduced from 73.8% to 52.3%. Following the FASB authoritative guidance amending the accounting and reporting requirements for decreases in ownership of a subsidiary, issued in January 2010, this transaction was recorded as non-controlling interest in the balance sheet.
 
Note 12 – Restricted cash
 
Restricted cash includes:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
CIRR deposits (see Note below)
 
 
298
 
 
 
355
 
Margin calls related to share forward agreements
 
 
137
 
 
 
61
 
Restricted deposit related to loan facility
 
 
5
 
 
 
-
 
Tax withholding deposits
 
 
42
 
 
 
44
 
Total restricted cash
 
 
482
 
 
 
460
 
Long-term restricted cash (related to CIRR deposits and loan facility)
 
 
250
 
 
 
305
 
Short-term restricted cash
 
 
232
 
 
 
155
 
 
Note: CIRR deposits are cash deposited with commercial banks, which match Commercial Interest Reference Rate ("CIRR") loans from Exportfinans ASA, the Norwegian export credit agency (see Note 22). The deposits are used to make repayments of the CIRR loans.
 
 
F-24
 
 
Note 13 – Marketable securities
 
Marketable securities held by the Company are equity securities considered to be available-for-sale securities or trading securities.
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Original cost
 
 
24
 
 
 
306
 
Unrealized gain on marketable securities
 
 
-
 
 
 
292
 
Carrying value
 
 
24
 
 
 
598
 
 
The net unrealized holding gains as of December 31, 2011 amounted to $0 million. This represents the net of $1 million unrealized gain recorded in accumulated other comprehensive income in the balance sheet and an unrealized loss of $1 million recorded through the profit and loss statement.
 
The unrealized holding gains as of December 31, 2010 were recorded in accumulated other comprehensive income in the balance sheet.
 
Marketable securities held by us include approximately 3.5% of the issued shares of Ensco plc. ("Ensco"), 9.2% of the issued shares of Seahawk Drilling Inc. ("Seahawk"), 81.1% of the partially redeemed Petromena NOK2,000 million bond ("Petromena") and 3.3% of Golden Close Maritime bond ("Golden Close"). Marketable securities and changes in their carrying value are as follows:
 
(In US$ millions)
Pride
Ensco
Seahawk
Petromena
Golden Close
Other bonds
Total
               
Historic cost at December 31, 2010
268
-
10
13
15
-
306
Fair Market value adjustments recognized via OCI as of December 31, 2010
276
-
-
16
-
-
292
Net book value at December 31, 2010
544
-
10
29
15
-
598
Additions
-
5
-
-
-
13
18
Fair market value adjustments recognized via OCI
140
-
-
(16)
1
-
125
Release of OCI into profit & loss
(416)
-
-
  
-
-
(416)
Realization of historic cost
(268)
-
-
(9)
-
(13)
(290)
Other than temporary impairments
-
-
(10)
-
-
-
(10)
Historic cost at Dec 31, 2011
-
5
0
4
15
0
24
Fair Market value adjustments recognized via OCI as of December 31, 2011
-
-
-
-
1
0
1
Fair Market value adjustments recognized via P&L
-
(1)
-
-
-
0
(1)
Net book value at December 31, 2011
0
4
0
4
16
0
24
 
Refer also to note 34 "Gain on realization of marketable securities".
 
Note 14 – Accounts receivable
 
Accounts receivable are presented net of allowances for doubtful accounts. The allowance for doubtful accounts receivables at December 31, 2011 was $25 million (2010: $25 million).
 
The Company did not recognize any bad debt expense in 2011 or 2010, but has instead reduced contract revenue for the disputed amounts.
 
 
F-25
 
Note 15 – Other current assets
 
Other current assets include:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Prepaid expenses/accrued revenue
 
 
25
 
 
 
113
 
Deferred charges – short term portion
 
 
26
 
 
 
21
 
Unrealized gain on total return swap agreements
 
 
11
 
 
 
38
 
Reimbursable amounts due from customers
 
 
154
 
 
 
74
 
Insurance claim proceeds (re West Atlas)
 
 
-
 
 
 
25
 
Favorable contracts
 
 
12
 
 
 
23
 
Other
 
 
95
 
 
 
113
 
Total other current assets
 
 
323
 
 
 
407
 
 
Note 16 – Investment in associated companies
 
The Company has the following investments that are recorded using the equity method:
 
 
 
December
31, 2011
 
December
31, 2010
 
December
31, 2009
 
 
 
 
 
 
 
 
 
 
Scorpion Offshore Limited ("Scorpion")
 
 
-
*
 
 
-
*
 
 
38.6
%
SapuraCrest Bhd ("SapuraCrest")
 
 
23.6
%
 
 
23.6
%
 
 
23.6
%
Varia Perdana Sdn Bhd ("Varia Perdana")
 
 
49.0
%
 
 
49.0
%
 
 
49.0
%
Tioman Drilling Company Sdn Bhd ("Tioman")
 
 
49.0
%
 
 
49.0
%
 
 
49.0
%
C6 Technologies AS ("C6")**
 
 
-
  
 
 
50.0
%
 
 
-
 
Archer ("Archer")**
 
 
39.9
%
 
 
-
  
 
 
-
  
Asia Offshore Drilling ("AOD")
 
 
33.8
%
 
 
-
  
 
 
-
  
Sevan Drilling ("Sevan Drilling")
 
 
28.5
%
 
 
-
  
 
 
-
  

* During 2010 the Company's ownership in Scorpion increased from 38.6% to 100%, As such Scorpion was fully consolidated into Seadrill's financial statements as of December 31, 2010. (Reference note 25 Acquisitions)
 
** In February 2011, we deconsolidated our majority-owned subsidiary Archer (formerly Seawell Limited). Archer is now accounted for as an associated company (Reference note 11)
 
Summarized balance sheet information of the Company's equity method investees is as follows:
 
 
 
As of December 31, 2011
 
(In US$ millions)
 
Current assets
 
 
Non-current
assets
 
 
Current liabilities
 
 
Non-current liabilities
 
SapuraCrest
 
 
716
      
514
      
505
      
198
 
Varia Perdana
 
 
136
      
157
      
64
      
33
 
Tioman
 
 
80
      
-
      
70
      
-
 
Archer
 
 
638
      
2,176
      
466
      
1,061
 
AOD
 
 
49
      
122
      
3
      
-
 
Sevan Drilling
 
 
224
      
1,375
      
117
      
810
 
TOTAL
 
 
1,843
      
4,344
      
1,225
      
2,102
 

 
 
As of December 31, 2010
 
(In US$ millions)
 
Current assets
 
 
Non-current assets
 
 
Current liabilities
 
 
Non-current liabilities
 
SapuraCrest
 
 
742
 
 
 
463
 
 
 
596
 
 
 
136
 
Varia Perdana
 
 
131
 
 
 
157
 
 
 
50
 
 
 
34
 
Tioman
 
 
111
 
 
 
-
 
 
 
96
 
 
 
-
 
C6
 
 
4
 
 
 
9
 
 
 
-
 
 
 
-
 
TOTAL
 
 
988
 
 
 
629
 
 
 
742
 
 
 
170
 
 
 
F-26
 
 
Summarized statement of operations information for the Company's equity method investees is as follows:
 
 
 
Year ended December 31, 2011
 
(In US$ millions)
 
Operating revenues
 
 
Net
operating
income
 
 
Net
income
 
SapuraCrest
 
 
866
      
166
      
147
 
Varia Perdana
 
 
119
      
96
      
96
 
Tioman
 
 
190
      
(2
)
    
(4
)
Archer
 
 
1,855
      
(16
)
    
(77
)
AOD
 
 
-
      
(4
)
    
(4
)
Sevan Drilling
 
 
116
      
8
      
(50
)
TOTAL
 
 
3,146
      
248
      
108
 

 
 
 
Year ended December 31, 2010
 
(In US$ millions)
 
Operating
revenues
 
 
Net
operating
income
 
 
Net
income
 
SapuraCrest
 
 
1,043
 
 
 
118
 
 
 
122
 
Varia Perdana
 
 
164
 
 
 
99
 
 
 
99
 
Tioman
 
 
247
 
 
 
9
 
 
 
5
 
C6
 
 
-
 
 
 
(1
)
 
 
(1
)
TOTAL
 
 
1,454
 
 
 
225
 
 
 
225
 

 
 
Year ended December 31, 2009
 
(In US$ millions)
 
Operating
revenues
 
 
Net
operating
income
 
 
Net
income
 
Scorpion
 
 
345
 
 
 
109
  
 
 
61
  
SapuraCrest
 
 
1,063
 
 
 
117
 
 
 
98
 
Varia Perdana
 
 
145
 
 
 
93
 
 
 
92
 
Tioman
 
 
239
 
 
 
9
  
 
 
7
 
TOTAL
 
 
1,792
 
 
 
328
 
 
 
258
 
 
 
Scorpion is a jack-up drilling rig company incorporated in Bermuda that was listed on the Oslo Stock Exchange until Seadrill's takeover in 2010.
 
SapuraCrest is a company incorporated and listed on the Malaysian stock exchange, which provides drilling and related services to offshore oil and gas industries in Malaysia and other countries.
 
Varia Perdana is a company incorporated in Malaysia, which operates a fleet of tender rigs. It is 51% owned by SapuraCrest Bhd and 49% owned by Seadrill.
 
Tioman is a company incorporated in Malaysia, which provides well services. It is 51% owned by SapuraCrest Bhd. and 49% owned by Seadrill.
 
Archer is a company listed in Oslo Stock Exchange and provides drilling and well services.
 
Asia Offshore Drilling was established by Mermaid Maritime Public Company Limited in late 2010 when two MOD-V B Class jack-up rigs were ordered at Keppel FELS in Singapore. AOD has additional option agreements for construction of two similar units and the Company is now responsible for the construction supervision, project management and commercial management of all of AODs jack-up rigs.
 
Sevan Drilling is a Norwegian public limited liability company (ASA), with its tax residency in Norway. The company was listed on the Oslo Axess in May 2011 and transferred to Oslo Stock Exchange in February 2012.
 
 
F-27
 
 
At the year-end the book values of the Company's investment in associated companies are as follows:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
SapuraCrest
 
 
106
 
 
 
86
 
Tioman
 
 
1
 
 
 
3
 
Varia Perdana
 
 
102
 
 
 
111
 
C6
 
 
-
 
 
 
5
 
Archer
 
 
393
 
 
 
-
 
AOD
 
 
53
 
 
 
-
 
Sevan Drilling
 
 
66
 
 
 
-
 
Total
 
 
721
 
 
 
205
 
 
At year-end the share of recorded equity in the statutory accounts of the Company's associated companies are as follows:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
December
31, 2009
 
 
 
 
 
 
 
 
 
 
 
Scorpion
 
 
-
 
 
 
-
 
 
 
200
 
SapuraCrest
 
 
124
 
 
 
112
 
 
 
99
 
Tioman
 
 
5
 
 
 
7
 
 
 
7
 
Varia Perdana
 
 
96
 
 
 
100
 
 
 
104
 
C6
 
 
-
 
 
 
6
 
 
 
-
 
Archer
 
 
514
 
 
 
-
      
-
 
AOD
 
 
57
 
 
 
-
      
-
 
Sevan Drilling
 
 
188
 
 
 
-
      
-
 
Total
 
 
984
 
 
 
225
 
 
 
410
 
 
Note 17 – Newbuildings
 
(In US$ millions)
  
December
31, 2011
    
December
31, 2010
  
Opening balance
    
1,247
      
1,431
  
Additions
    
2,308
      
1,947
  
Capitalized interest and loan related costs
    
73
      
59
  
Re-classified as Drilling Units
    
(1,097
)
    
(2,190
)
Closing balance
    
2,531
      
1,247
  
 
Note 18 – Drilling units
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
Cost
 
 
12,898
 
 
 
11,928
 
Accumulated depreciation
 
 
(1,675
)
 
 
(1,133
)
Net book value
 
 
11,223
 
 
 
10,795
 

Depreciation and amortization expense was $547 million, $448 million and $369 million for the years ended December 31, 2011, 2010 and 2009, respectively.
 
Note 19 – Goodwill and other intangible assets
 
In January 2011, our subsidiary Archer (formerly named Seawell) acquired Universal Wireline for $26 million on a debt and cash free basis, however Universal was deconsolidated together with Archer in February 2011. There were no other acquisitions in 2011. In the year ended December 31, 2010 the Company acquired several entities which have been consolidated into its financial statements since their acquisition dates – see Note 25 " Business Acquisitions". The assets and liabilities of the acquired entities were measured at fair value at their date of acquisition, and the purchase price paid in excess of the net fair value of the identifiable assets and liabilities acquired was allocated to goodwill. Goodwill relates to human capital, synergies and expected market opportunities. All of the goodwill acquired in the years ended December 31, 2010 was assigned to the Well Services operating segment. There were no acquisitions in 2009.
 
As a consequence of the change in segment structure from 2011, the goodwill has been reassigned to the reporting units affected using a relative fair value allocation approach. Please refer to note 3 "Segment information".
 
As described in Note 2 "Accounting policies", the Company tests the value of goodwill at the end of each financial year and if the book value exceeds the fair value an impairment loss is taken. In the years ended December 31, 2011, 2010 and 2009 no impairment losses were recognized.
 
 
F-28
 
 
Goodwill:
 
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
Net book balance at January 1
 
 
1,676
 
 
 
1,596
 
Goodwill acquired during the year
 
 
-
 
 
 
85
 
Impairment losses
 
 
-
 
 
 
-
 
Currency adjustments
    
15
      
(5)
  
Deconsolidation Archer
 
 
(371)
  
 
 
-
 
Net book balance of December 31
 
 
1,320
 
 
 
1,676
 
 
Other intangible assets:
 
Other intangible assets relate to customer relationships, technology and trademarks within the operating segment Well Services.
 
(In US$ millions)
  
December
31, 2011
    
December
31, 2010
  
Net book balance at January 1
    
57
      
23
  
Intangible assets acquired during the year
    
-
      
38
  
Depreciation
    
-
      
(4)
  
Deconsolidation Archer
    
(57)
      
-
  
Net book balance of December 31
    
-
      
57
  

Note 20 – Equipment
 
Equipment consists of office equipment, furniture and fittings.
 
(In US$ millions)
  
December
31, 2011
    
December
31, 2010
  
Cost
    
40.0
      
279
  
Accumulated depreciation
    
(15.0
)
    
(121
)
Net book value
    
25.0
      
158
  
 
Depreciation and amortization expense was $16 million, $27 million and $27 million for the years ended December 31, 2011, 2010 and 2009, respectively.
 
Note 21 –  Other non-current assets
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
Other non-current assets consists of:
 
 
 
 
 
 
Long-term part of deferred charges
 
 
65
 
 
 
54
 
Deferred tax effect of internal transfer of assets
 
 
149
 
 
 
71
 
Favorable contracts
 
 
2
 
 
 
15
 
Other
 
 
18
 
 
 
1
 
Total  other non-current assets
 
 
234
 
 
 
141
 
 
Deferred charges represent debt arrangement fees that are capitalized and amortized to interest expense over the life of the debt instrument.
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Debt arrangement fees
 
 
204
 
 
 
157
 
Accumulated amortization
 
 
(113
)
 
 
(82
)
Total book value
 
 
91
 
 
 
75
 
Less: Short-term portion
 
 
(26
)
 
 
(21
)
Long-term portion
 
 
65
 
 
 
54
 
Amortization for the period
 
 
31
 
 
 
43
 
 
 
F-29
 
 
Note 22 – Long-term interest bearing debt and interest expenses
 
As of December 31, 2011 and 2010, the Company had the following debt facilities:

(In US$ millions)
 
2011
 
 
2010
 
Credit facilities
 
 
 
 
 
 
$1,500 facility
 
 
-
  
 
 
1,060
 
$1,500 facility
 
 
1,059
  
 
 
1,027
 
$800 facility
 
 
272
  
 
 
636
 
$585 facility
 
 
337
  
 
 
387
 
$100 facility
 
 
74
  
 
 
80
 
$700 facility
 
 
630
  
 
 
700
 
$1,200 facility
 
 
1,000
  
 
 
1,133
 
$550 multicurrency facility (Archer)
 
 
-
  
 
 
189
 
NOK other loans and leasings (Archer)
 
 
-
  
 
 
5
  
$1,121 Lloyd's facility
    
985
      
-
  
$2,000 facility (North Atlantic)
    
1,917
      
-
  
$170 facility
    
92
      
-
  
$550 facility
    
550
      
-
  
$400 facility
    
400
      
-
  
Total Bank Loans + other
 
 
7,316
  
 
 
5,217
 
Ship Finance International Loans
 
 
    
 
 
 
 
$170 facility
 
 
-
  
 
 
101
 
$700 facility
 
 
470
  
 
 
546
 
$1,400 facility
 
 
939
  
 
 
1,099
 
Total Ship Finance Facilities
 
 
1,409
  
 
 
1,746
 
Bonds and convertible bonds
 
 
    
 
 
 
 
Bonds
 
 
425
  
 
 
552
 
Convertible bonds
 
 
545
  
 
 
1,287
 
Total Bonds
 
 
970
  
 
 
1,839
 
Other credit facilities with corresponding restricted cash deposit
 
 
298
  
 
 
355
 
 
 
 
    
 
 
 
 
Total interest bearing debt
 
 
9,993
  
 
 
9,157
 
Less: current portion
 
 
(1,419)
  
 
 
(981
)
Long-term portion of interest bearing debt
 
 
8,574
  
 
 
8,176
 
 
The outstanding debt as of December 31, 2011 is repayable as follows:
 
Year ending December 31
(In US$ millions)
 
 
 
2012
 
 
1,419
 
2013
 
 
2,332
 
2014
 
 
1,389
 
2015
 
 
1,787
 
2016 and thereafter
 
 
3,171
 
Effect of amortization of convertible bond
 
 
(105
)
Total debt
 
 
9,993
 

Credit facilities
 
$1,500 million secured credit facility
 
In June 2009, the Company entered into a $1,500 million senior secured loan facility with a syndicate of banks and export credit facility agents, to partly fund the acquisition of the jack-up rigs West Capella, West Sirius, West Ariel and West Aquarius, which have been pledged as security. The net book value at December 31, 2011 of the units pledged as security is $1,783 million. The facility bears interest at LIBOR plus 3.25% per annum and is repayable over a term of five years. The outstanding balance at December 31, 2011 was $1,059 million and was fully drawn. At maturity a balloon payment of $662 million is due.
 
 
F-30
 
 
$800 million secured term loan
 
In August 2005, the Company entered into a $300 million secured term loan facility with a syndicate of banks to partly fund the acquisition of two semi-submersible rigs, West Eminence and West Phoenix, which have been pledged as security. The facility was amended and increased in 2006 to $800 million. The facility was amended again in 2011 due to West Phoenix was moved to North Atlantic. As a result of this, only West Eminence was pledged as security as per December 31, 2011. The net book value at December 31, 2011 of the unit pledged as security is $656 million. The facility consists of two tranches, and bears interest at LIBOR plus 1.70% and 3.25% per annum. The final repayment of $183 million is due in 2013.
 
$585 million secured term loan
 
In December 2006, the Company 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.  In 2011 the number of rigs pledged as security has been reduced to 7. The net book value at December 31, 2011 of the units pledged as security is $375 million. The facility bears interest at LIBOR plus between 0.70% and 1.00% per annum depending on the ratio of net debt to EBITDA, and is repayable over a term of six years. At maturity a balloon payment of $300 million is due.
 
$100 million secured term loan
 
In April 2008, the Company entered into a $100 million secured term loan facility with a two banks to partly fund the acquisition of the tender rig T-11, which has been pledged as security. The net book value at December 31, 2011 of the unit pledged as security is $81 million. The facility bears interest at a fixed rate of 3.03% per annum and is repayable over a term of six years. At maturity a balloon payment of $60 million is due.
 
$700 million secured term loan
 
In October 2010, the Company entered into a $700 million secured loan facility with a syndicate of banks to partly fund the acquisition of seven jack-up drilling rigs, which have been pledged as security. The net book value at December 31, 2011 of the units pledged as security is $1,154 million. The facility bears interest at LIBOR plus 2.50% per annum and is repayable over a term of five years. At maturity a balloon payment of $350 million is due.
 
$1,200 million secured term loan
 
In June 2010, the Company entered into a $1,200 million secured facility with a group of various commercial lending institutions and export credit agencies. The loan is secured by first priority mortgages on one ultra-deepwater semi-submersible drilling rig (West Orion), one ultra-deepwaterdrillship (West Gemini) and one tender rig (West Vencedor). The net book value at December 31, 2011 of the units pledged as security is $1,524 million. The facility bears interest at LIBOR plus 2.25% per annum and is repayable over a term of five years. At maturity a balloon payment of $567 million is due.
 
$1,121 million secured credit facility
 
 In January 2011, the Company entered into a $1,121 million secured credit facilty with Lloyds TSB to fund the acquisition of two ultra-deepwater semi-submersible rigs, West Leo and West Pegasus, which has been pledged as security. The net book value at December 31, 2011 of the units pledged as security is $1,170 million. The facility bears interest at LIBOR plus a margin and is repayable over a term of seven years. At maturity a balloon payment of $498 is due.
 
$2,000 million secured credit facility
 
In april 2011, our subsidiary North Atlantic Drilling Ltd entered into a $2,000 million secured credit facility with a syndicate of banks to partly fund the acquisition of 6 drilling units from Seadrill Ltd, which have been pledged as security. The net book value at December 31, 2011 of the units pledged as security is $2,485 million. The facility has a six year tenor and bears interest at LIBOR plus 2.00% per annum. At maturity a balloon payment of $1,000 million is due.
 
$170 million secured loan facility
 
In February 2007, the Company entered into a sale and leaseback agreement for the jack-up rig West Prospero with Rig Finance II Ltd, at that time a subsidiary of Ship Finance Limited. In February 2007 Rig Finance II Ltd entered into a $170 million secured term loan facility with a syndicate of banks to partly fund the acquisition of West Prospero, which has been pledged as security. In June 2011, the Company acquired all the shares of Rig Finance II Limited. The net book value at December 31, 2011 of the unit pledged as security is $181 million. The facility bears interest at LIBOR plus 0.90 % to 1.20% per annum depending on the ratio of market value to loan, and is repayable over a term of six years. At maturity a balloon payment of $79 million is due.
 
 
F-31
 
 
$550 million secured credit facility
 
In December 2011, the Company entered into a $550 million secured credit facility with a syndicate of banks to partly fund the delivery of the ultra-deepwater semi-submersible drilling unit West Capricorn, which has been pledged as security. The net book value at December 31, 2011 of the unit pledged as security is $764 million. The facility has a five year trenor and bears interest at LIBOR plus a margin. At maturity a balloon payment of $275 million is due.
 
$400 million secured credit facility
 
In December 2011, the Company entered into a $400 million secured credit facility with a syndicate of banks. The Jack-Up rigs West Cressida, West Callisto, West Leda and West Triton has been pledged as security. The net book value of at December 31, 2011 of the units pledged as security is $757 million. The facility has a five year tenor and bears interest of LIBOR plus 2.50% per annum. At maturity a balloon payment of $200 million is due.
 
Ship Finance International Loans
 
In May 2008, the Company entered into a sale and leaseback agreement for the drillship West Polaris with SFL West Polaris Limited, a subsidiary of Ship Finance. SFL West Polaris Limited is consolidated as a VIE by the Company. In July 2008 SFL West Polaris Limited entered into a $700 million secured term loan facility with a syndicate of banks to partly fund the acquisition of West Polaris, which has been pledged as security. The net book value at December 31, 2011 of the unit pledged as security is $614 million. The facility bears interest at LIBOR plus 1.25% per annum and is repayable over a term of five years.
 
In September 2008, the Company entered into a sale and leaseback agreement for the two semi-submersible rigs West Taurus and West Hercules with SFL Deepwater Ltd, a subsidiary of Ship Finance. SFL Deepwater Ltd is consolidated as a VIE by the Company. In September 2008 SFL Deepwater Ltd entered into a $1,400 million secured term loan facility with a syndicate of banks to partly fund the acquisition of West Taurus and West Hercules, which have been pledged as security. The net book value at December 31, 2011 of the units pledged as security is $1,021 million. The facility bears interest at LIBOR plus 1.40% per annum and is repayable over a term of five years.
 
Bonds and convertible bonds
 
NOK500 million floating interest rate bonds
 
In September 2005, the Company raised $87 million (NOK500 million) through the issue of a seven year bond. The bond bears interest of NIBOR plus 1.60% per annum, payable quarterly in arrears. NOK50 million of the bonds have subsequently been repurchased by the Company.
 
$350 million fixed interest rate bond
 
In October 2010, the Company's raised $350 million through the issue of a five year bond which matures in October 2015. Interest on the bonds bears a fixed interest of 6.50% per annum, payable semi-annually in arrears.
 
3.375% Convertible Bonds due 2017
 
In October 2010, the Company issued at par $650 million of convertible bonds. Interest on the bonds is fixed at 3.375%, payable semi-annually in arrears. The bonds are convertible into Seadrill Limited 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 $34.17. For accounting purposes $121 million was, at the time of issuance of the bonds, allocated to the bond equity component and $529 million to the bond liability component. This is 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 bond contains covenants, the principle one requiring the Company to maintain a market adjusted equity ratio of at least 30.0%.
 
3.625% Convertible Bonds due 2012
 
In November 2007, the Company issued at par $1,000 million of convertible bonds. Interest on the bonds is fixed at 3.625% per annum, payable semi-annually in arrears and the bonds are convertible into Seadrrill Limited common shares by the holders at any time up to 10 banking days prior to November 8, 2012, and in addition, the Company had a right to redeem the bonds at par plus accrued interest at any time following November 29, 2010, if certain conditions were met. At time of issuance the conversion price was set at $34.47 per share, representing a 45.0% premium to the share price at the time. The conversion price was subsequently reduced to $28.49 due to dividend distributions as of December 31, 2010.
 
 
F-32
 
 
On December 16, 2010, the Company announced a conversion incentive period for the holders of up to $250 million of the bonds, and subsequently accepted early conversion of same $250 million amount. In May 2011 we exercised the embedded call option and, as a consequence, the remaining convertible bonds outstanding were settled. Bondholders representing $721 million had requested conversion within the conversion date stipulated in the loan agreement, while other $28 million were redeemed at par.
 
Commercial Interest Reference Rate (CIRR) Credit Facilities
 
In April 2008, the Company entered into a CIRR term loan for NOK850 million with Eksportfinans ASA, the Norwegian export credit agency. The loan bears fixed interest at 4.56% per annum and is repayable over a term of eight years. The outstanding balance at December 31, 2011 was $83 million (NOK500 million).
 
In June 2008, the Company entered into a CIRR term loan for NOK904 million with Eksportfinans ASA. The loan bears fixed interest at 4.15% per annum and is repayable over a term of eight years. The outstanding balance at December 31, 2011 was $89 million (NOK532 million).
 
In July 2008, the Company entered into a CIRR term loan for NOK1,011 million with Eksportfinans ASA. The loan bears fixed interest at 4.15% per annum and is repayable over a term of twelve years. The outstanding balance at December 31, 2011 was $126 million (NOK758 million).
 
In connection with the above three CIRR fixed interest term loans totaling $298 million (NOK1,790 million), fixed interest cash deposits equal to the total outstanding loan balances have been established with commercial banks. The collateral cash deposits are reduced in parallel with repayments of the CIRR loans and receive fixed interest at the same rates as those paid on the CIRR loans. The collateral cash deposits are classified as "restricted cash" in the balance sheet, and the effect of these arrangements is that the CIRR loans have no effect on net interest bearing debt.
 
Covenants on loans and bonds
 
Bank Loans
 
In addition to security provided to lenders in the form of pledged assets, bank loan agreements generally contain financial covenants, the main ones being as follows:
 
 
·
Aggregated minimum liquidity requirement for the group: to maintain cash and cash equivalents of at least $155 million within the group.
 
 
·
Interest coverage ratio: to maintain an EBITDA to interest expense ratio of at least 2.5:1.
 
 
·
Current ratio: to maintain current assets to current liabilities ratio of at least 1:1. Current assets are defined as book value less minimum liquidity, but including up to 20.0% of shares in listed companies owned 20.0% or more. Current liabilities are defined as book value less the current portion of long term debt.
 
 
·
Equity ratio: to maintain total equity to total assets ratio of at least 30.0%. Both equity and total assets are adjusted for the difference between book and market values of drilling units.
 
 
·
Leverage ratio: to maintain a ratio of net debt to EBITDA no greater than 4.5:1. Net debt is calculated as all interest bearing debt less cash and cash equivalents excluding minimum liquidity requirements.
 
Bonds
 
For the Company's outstanding bonds, the main covenants are as follows;
 
 
·
Equity Ratio; to maintain a total equity to total assets ratio of at least 30.0%. Both equity and total assets are adjusted for the difference between book value and market values of drilling units.
 
 
·
Equity ratio; to maintain a ratio of adjusted equity to total liabilities of at least 40.0%. Adjusted shareholder's equity is book value of equity adjusted for the difference between book and market values of drilling units.
 
 
F-33
 
 
We are in compliance with all financial loan covenants as of December 31, 2011, except for our subsidiary NADL, which recognized a temporary period of non-compliance, which was remedied during the first quarter of 2012.
 
Note 23 – Other current liabilities
 
Other current liabilities are comprised of the following:
 
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Taxes payable
 
 
309
 
 
 
97
 
Employee withheld taxes, social security and vacation payment
 
 
95
 
 
 
96
 
Short-term portion of unfavorable contract values
 
 
-
 
 
 
23
 
Accrued interest expense
 
 
30
 
 
 
22
 
Liabilities relating to investment in shares (1)
 
 
-
 
 
 
540
 
Short term portion of deferred mobilization revenues
 
 
115
 
 
 
82
 
Derivative financial instruments (2)
 
 
414
 
 
 
192
 
Accrued expenses
    
279
      
246
  
Other current liabilities
 
 
72
 
 
 
140
 
Total other current liabilities
 
 
1,314
 
 
 
1,438
 

(1) Liabilities relating to the Company's share forward contracts are recorded as short-term debt.
 
(2) Derivative financial instruments consist of unrealized losses on various types of derivatives.
 
Note 24 – Other non-current liabilities
 
Other non-current liabilities are comprised of the following:
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
 
 
 
 
 
 
 
Accrued pension liabilities
 
 
43
 
 
 
75
 
Long-term portion of unfavorable contract values
 
 
-
 
 
 
4
 
Long term portion of deferred mobilization revenues
 
 
130
 
 
 
146
 
Other non-current liabilities
 
 
15
 
 
 
29
 
Total other non-current liabilities
 
 
188
 
 
 
254
 
 
Note 25 – Business Acquisitions
 
Acquisitions in 2011
 
In January 2011, our then subsidiary Archer  acquired Universal Wireline for $26 million on a debt and cash free basis, however Universal was deconsolidated together with Archer in February 2011. There were no other business acquisitions in the year ended December 31, 2011.
 
Acquisitions in 2010
 
Scorpion Offshore Ltd ("Scorpion")
 
Scorpion was established and incorporated in Bermuda with the purpose of operating a fleet of offshore drilling rigs and is listed on the Oslo Stock Exchange. Seadrill acquired its first shares in Scorpion and entered into forward contracts for the purchase of Scorpion shares in early 2008. In April 2010, Seadrill increased its ownership to 40.0 percent at a price per Scorpion share of NOK36.00. 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, Seadrill increased its ownership to 50.1 percent of the outstanding shares and 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 the holders of 48.7 percent of the total number of outstanding shares had accepted the offer increasing our ownership to 98.8 percent of the outstanding shares and votes in Scorpion. On September 20, 2010, Seadrill informed remaining Scorpion shareholders of its intention to exercise its right under Bermuda company law to compulsory acquire all remaining outstanding shares in Scorpion. The compulsory acquisition was completed on October 25, 2010 and the company's shares were delisted from the Oslo Stock Exchange on November 17, 2010. As of December 31, 2011 Seadrill's ownership in Scorpion is 100%.
 
 
F-34
 
 
Seadrill has applied the purchase method in this business combination (ASC topic 805). As part of the process, a valuation analysis has been performed to determine the fair values of certain identifiable intangible assets of Scorpion as of the acquisition date. The determination of the value of these components required the Company to make various estimates and assumptions. Critical estimates in valuing certain of the intangible assets include but are not limited to the net present value of future expected cash flows from operations.
 
The allocation of the purchase price of Scorpion was based upon fair value studies.
 
Acquisition consideration
 
(In US$ millions)
 
 
 
Cash
 
 
57
 
Fair Value of previously held 40% equity interest
 
 
226
 
Fair Value of Non Controlling Interests
 
 
282
 
Total acquisition consideration
 
 
565
 
 
On May 28, 2010 the Company acquired control of Scorpion, and remeasured the previously held 40.0% equity interest to its fair value. The difference between the $115 million book value and the $226 million fair value of the previously held 40.0% interest was recorded as a gain on a separate line item under financial items in the consolidated statement of operations in the year ended December 31, 2010.
 
As a result of the acquisition of control, we also recognized a gain on a bargain purchase as the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired. We subsequently performed a reassessment of the values of all assets acquired, liabilities assumed, and consideration transferred. The reassessment confirmed our initial gain on bargain purchase.
 
During the third and fourth quarter of 2010, the Company acquired the remaining shares in Scorpion for a total amount of $292 million, increasing the Company's ownership in Scorpion to 100% of the outstanding shares as of December 31, 2010. With effect from June 1, 2010, the results of Scorpion's operations were included in our consolidated financial statements.
 
Gray Wireline Service, Inc
 
In December 2010, Archer, acquired Gray Wireline Service, Inc. ("Gray"), an independent cased hole wireline company in the U.S. The purchase price was US$ 161 million.
 
Rig Inspection Services Limited
 
In August 2010, Archer acquired Rig Inspection Services Limited ("RIS"), a private company with offices in Singapore and Australia. The purchase price was US$ 9 million.
 
The purchase price of the acquired companies has been allocated as follows:
 
(In US$ millions)
 
Scorpion
 
 
Gray
 
 
RIS
 
 
Total
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Intangible assets
 
 
-
 
 
 
36
 
 
 
2
 
 
 
38
 
Goodwill
 
 
-
 
 
 
80
 
 
 
5
 
 
 
85
 
Fixed assets
 
 
1,234
 
 
 
44
 
 
 
-
 
 
 
1,278
 
Receivables and other current assets
 
 
210
 
 
 
33
 
 
 
3
 
 
 
246
 
Total assets
 
 
1,444
 
 
 
193
 
 
 
10
 
 
 
1,647
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred tax
 
 
-
 
 
 
25
 
 
 
-
 
 
 
26
 
Payables and other current liabilities
 
 
823
 
 
 
8
 
 
 
1
 
 
 
831
 
Total liabilities
 
 
823
 
 
 
33
 
 
 
1
 
 
 
857
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchase Price
 
 
565
 
 
 
161
 
 
 
9
 
 
 
735
 
Gain on bargain purchase
 
 
56
 
 
 
-
 
 
 
-
 
 
 
56
 
 
 
F-35
 
 
Acquisitions in 2009
 
There has been no business acquisitions in the year ended December 31, 2009.
 
Our business acquisitions have been accounted for in accordance with our Accounting policies detailed in Note 2 above, and the basis of presentation of all business combinations is described under Basis of presentation in Note 1 above.
 
Note 26 – Non-controlling interest
 
The Company's consolidated Statement of Operations, Balance Sheet and Statement of Cash Flows include North Atlantic, whose issued share capital is 76.7% owned by the Company. The part of North Atlantic's total shareholders' equity not attributable to the Company is included in non-controlling interest.
 
In 2007 and 2008 the Company entered into five sale and leaseback arrangements for drilling rigs with Ship Finance, who incorporated subsidiary companies for the sole purpose of owning and leasing the rigs. The Company has recognized these subsidiary companies as VIEs and concluded that Seadrill is their primary beneficiary. Accordingly, these subsidiary companies are included in the Company's consolidated accounts, with the Ship Finance equity in these companies included in non-controlling interest. In 2011, the Company acquired all the shares in one of these Ship Finance companies, Rig Finance II Ltd for $47 million. As a consequence of this, Rig Finance II Ltd is no longer treated as a VIE but a wholly owned subsidiary.
 
Changes in non-controlling interest in 2011, 2010 and 2009 are as follows:
 
(In US$ millions)
 
Scorpion
 
 
Archer
 
 
Ship
Finance
 
 North Atlantic
Total
  
 
January 1, 2009
 
 
-
 
 
 
14
 
 
 
579
  
-
 
 
593
 
Changes in 2009
 
 
-
 
 
 
9
 
 
 
(60)
  
-
  
 
(51
)
2009 net income
 
 
-
 
 
 
7
 
 
 
85
  
 -
 
 
92
 
December 31, 2010
 
 
-
 
 
 
30
 
 
 
604
  
  -
 
 
634
 
Changes in 2010
 
 
2
 
 
 
295
 
 
 
(447
)
-
 
 
(150
)
2010 net income
 
 
  (2
)
 
 
1
 
 
 
56
  
  -
 
 
55
 
December 31, 2010
 
 
-
      
326
      
213
  
-
    
539
  
Changes in 2011
 
 
-
      
(320
)
    
(46)
  
71
    
(295
)
2011 net (loss)/income
 
 
-
      
(6)
      
48
  
39
    
81
  
December 31, 2011
 
 
-
 
 
 
-
 
 
 
215
  
 110
 
 
325
 
 
Note 27 – Share capital
 
 
 
2011
 
 
2010
 
 
2009
 
All shares are common shares of $2.00 par value each
 
Shares
 
 
$millions
 
 
Shares
 
 
$millions
 
 
Shares
 
 
$millions
 
Authorized share capital
 
 
800,000,000
 
 
 
1,600
 
 
 
800,000,000
 
 
 
1,600
 
 
 
800,000,000
 
 
 
1,600
 
 
 
Issued and fully paid share capital
 
 
469,250,933
 
 
 
938
 
 
 
443,308,487
 
 
 
887
 
 
 
399,133,216
 
 
 
798
 
Treasury shares held by Company
 
 
(1,478,759
)
 
 
(3
)
 
 
(182,796
)
 
 
(1
)
 
 
(110,200
)
 
 
-
  
Outstanding shares in issue
 
 
467,772,174
 
 
 
935
 
 
 
443,125,691
 
 
 
886
 
 
 
399,023,016
 
 
 
798
 
 
As of December 31, 2011, the Company's shares are listed on the Oslo Stock Exchange and the New York Stock Exchange.
 
The Company was incorporated on May 10, 2005 and 6,000 ordinary shares of par value $2.00 each were issued. Since incorporation the number of issued shares has increased from 6,000 to 469,250,933 of par value $2.00 each as of December 31, 2011. The number of shares issued in 2011 was 25,942,446, all due to conversion of convertible debt instruments
 
A share repurchase program was approved by the Board in 2007 giving the Company the authorization to buy back shares. Shares bought back under the authorization may be cancelled or held as treasury shares. Treasury shares may be held to meet the Company's obligations relating to the share option scheme (see Note 28). As at December 31, 2011 the Company held 1,478,759 treasury shares and net shares outstanding at December 31, 2011 were 467,772,174.
 
Note 28 – Share option plans
 
The fair value of share options granted is recognized as personnel expenses, and in the year ended December 31, 2011, $10 million (2010: $11 million) were expensed in the income statement. There were no effects on taxes in the financial statements. However if the option is exercised a tax benefit will be recorded, as the gain is recorded as deductible for tax purposes. If the Company has to expense social security taxes related to the benefit of options exercised such expenses will be recorded at the exercise date.
 
 
F-36
 
 
In May 2005, a general meeting of the Company approved authorizing the Board of Directors to establish and maintain an option scheme (the "Seadrill Scheme") for encouraging the holding of shares in the Company. The Seadrill Scheme will expire in May 2016.  The Seadrill Scheme permits the board of directors, at its discretion, to grant options to acquire shares in the Company to employees and directors of the Company or its subsidiaries.  The options are not transferable. The subscription price is at the discretion of the board of directors, provided the subscription price is never reduced below the par value of the share. The subscription price for certain options granted under the scheme will be reduced by the amount of all dividends declared by the Company in the period from the date of grant until the date the option is exercised. Options granted under the scheme will vest at a date determined by the board at the date of the grant.  The options granted under the plan to date vest over a period of one to five years.  There is no maximum number of shares authorised for awards of equity share options and authorised, unissued or treasury shares of the Company may be used to satisfy exercised options.
 
In November 2011, 1,786,771 share options were granted. Their fair value was estimated on the date of the grant using a Black Scholes option valuation model, under the following assumptions: 0.67% risk-free interest rate, volatility of 24.3%, 0% dividend yield and an expected option term of four years. The risk-free interest rates were estimated using the US Treasury yield curve in effect at the time of grant for instruments with a similar life. The dividend yield has been estimated at 0% as the exercise price is reduced by all dividends declared by the Company from the date of grant to the exercise date.  It is also assumed that 100% of options granted will vest.
 
The following summarizes share option transactions related to the Seadrill Scheme in 2011, 2010 and 2009:
 
 
 
2011
 
 
2010
 
 
2009
 
 
 
Options
 
 
Weighted average exercise price
US$
 
 
Options
 
 
Weighted average exercise price
US$
 
 
Options
 
 
Weighted average exercise price
US$
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding at beginning of year
 
 
5,512,400
      
20.30
 
 
 
6,199,833
      
13.87
 
 
 
5,978,100
 
 
 
18.11
 
Granted
 
 
1,786,771
      
34.68
 
 
 
1,910,000
      
29.94
 
 
 
1,026,000
 
 
 
14.45
 
Exercised
 
 
(1,638,165
)
    
16.33
 
 
 
(2,329,000
)
    
11.88
 
 
 
(607,600
)
 
 
14.84
 
Forfeited
 
 
(240,568
)
    
21.98
 
 
 
(268,433
)
    
14.99
 
 
 
(196,667
)
 
 
19.42
 
Outstanding at end of year
 
 
5,420,438
      
26.16
 
 
 
5,512,400
      
20.30
 
 
 
6,199,833
 
 
 
13.87
 
Exercisable at end of year
 
 
1,598,412
      
19.82
 
 
 
1,645,333
      
16.03
 
 
 
2,682,811
 
 
 
12.20
 
 
Options granted in 2006 had initial exercise prices between $2.23 and NOK102 ($16.28) per share, may be exercised one third each year beginning 12 months after they were granted, and expired between May 2010 and September 2011. Options granted in 2007 had initial exercise prices between NOK98.63 ($15.23) and NOK129.63 ($22.35) per share, may be exercised one third each year beginning 12 months after they were granted, and expired in September 2011. Options granted in 2008 had been repriced with exercise prices now being NOK 90.83 ($14.09) and NOK104.64 ($16.24) per share; they may be exercised one third each year beginning 12 months after they were granted, and expire in May 2014. These same prices and dates apply to the options granted in 2009. Options granted in April 2010 had exercise price of NOK 137.40 ($23.13), may be exercised one third after 12 or 15 months and expire in March/June 2015. Options granted in November 2010 had exercise prices of NOK 192.90 ($31.4) for American citizens or residents and NOK 185.20 ($31.06) for non-Americans. They may be exercised one fifth each year beginning 12 months after they were granted and expire in December 2015. Options granted in November 2011 had exercise prices of NOK202.10 ($34.68) and can be exercised one fourth at a time, after the first 18, 36, 48 and 60 months from the grant date. They expire in December 2016.
 
The weighted average grant-date fair value of options granted during 2011 is $7.07 per share (2010: $8.96 per share, 2009: $5.63 per share). The exercise price of all options is reduced by the amount of any dividends declared.
 
As of December 31, 2011 there was $ 20 million in unrecognized compensation costs relating to non-vested options granted under the Options Schemes (2010: $19 million). This amount will be recognized as expenses of $9 million in 2012, $5 million in 2013, $3 million in 2014, $2 million in 2015 and $1 million in 2016.
 
There were 5,420,438 options outstanding at December 31, 2011 (2010: 5,512,400). Their weighted average remaining contractual life was 45 months (2010: 41 months) and their weighted average fair value was $11.20 per option (2010: $11.29 per option). The weighted average parameters used in calculating these weighted average fair values are as follows: risk-free interest rate 2.72 % (2010: 3.83%), volatility 31 % (2010: 34%), dividend yield 0% (2010: 0%), option holder retirement rate 0% (2010: 0%) and expected term 5 years (2010: 5 years).
 
 
F-37
 
 
During 2011 the total intrinsic value of options exercised was $32 million (2010: $22 million, 2009: $5 million) on the day of exercise. The intrinsic value of options fully vested but not exercised at December 31, 2011 was $22 million and their average remaining term was 35 months.
 
Note 29 - Pension benefits
 
The Company has a defined benefit pension plan covering substantially all Norwegian employees. A significant part of this plan is administered by a life insurance company.
 
In June 2009 we introduced a defined contribution plan for all new employees employed onshore. Under the new scheme, the Company contributes to the employee's pension plan amounts ranging into five to eight percent of the employee's annual salary. Existing onshore staff was given an option to join the new scheme or continue with their previous defined benefit plan.
 
For onshore employees in Norway, continuing with the defined benefit plan, the primary benefits are retirement pension of approximately 66 percent of salary at retirement age of 67 years, together with a long-term disability pension. The retirement pension per employee is capped at an annual payment of 66 percent of the total of 12 times the Norwegian Social Security Base. Most employees in this group may choose to retire at 62 years of age on a pre-retirement pension. Offshore employees in Norway have retirement and long-term disability pension of approximately 60 percent of salary at retirement age of 67. Offshore employees on mobile units may choose to retire at 60 years of age on a pre-retirement pension.
 
On December 31, 2006, Seadrill adopted the recognition and disclosure provisions of ASC Topic 715 Compensation – Retirement Benefits (formerly SFAS No.158, Employer's Accounting for Defined Benefit Pension and other Postretirement Plans, an amendment of formerly FASB Statements No. 87, 88 and 123(R)). ASC Topic 715 requires the recognition of the funded status of the Defined Benefit and Postretirement Benefits Other Than Pensions ("OPEB") plans on the December 31, 2006 balance sheet with a corresponding adjustment to accumulated other comprehensive income. The adjustment to accumulated other comprehensive income at adoption represents the net unrecognized actuarial losses, unrecognized prior service costs, and unrecognized transition obligation remaining from the initial application of ASC Topic 715, all of which were previously netted against the plans' funded status on the balance sheet. These amounts will be subsequently recognized as net periodic pension cost pursuant to our historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension cost in the same periods will be recognized as a component of 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.
 
Effect of formerly SFAS No. 158 on the consolidated balance sheet
 
(in US$ millions)
 
2011
 
 
2010
 
  
 
 
 
 
 
 
 
  
Non-current liabilities
 
 
15
  
 
 
23
    
Deferred tax
 
 
(4
 )
 
 
(6
)
  
Shareholders equity
 
 
(11
 ) 
 
 
(16
 )  
 
Annual pension cost
 
(in US$ millions)
 
2011
 
 
2010
 
 
2009
 
 
 
 
 
 
 
 
 
 
 
Benefits earned during the year
 
 
9
 
 
 
18
 
 
 
18
 
Interest cost on prior years' benefit obligation
 
 
5
 
 
 
9
 
 
 
9
 
Gross pension cost for the year
 
 
14
 
 
 
27
 
 
 
27
 
Expected return on plan assets
 
 
(5
)
 
 
(8
)
 
 
(7
)
Administration charges
 
 
0
 
 
 
1
 
 
 
1
 
Net pension cost for the year
 
 
9
 
 
 
20
 
 
 
20
 
Social security cost
 
 
1
 
 
 
3
 
 
 
3
 
Amortization of actuarial gains/losses
 
 
(0
)
 
 
(1
)
 
 
(1
)
Amortization of prior service cost
 
 
  
 
 
 
  
 
 
 
  
 
Amortization of net transition assets
 
 
  
 
 
 
3
 
 
 
  
 
Total net pension cost
 
 
10
 
 
 
19
 
 
 
23
 
 
 
F-38
 
 
The funded status of the defined benefit plan
 
(in US$ millions)
 
December 31, 2011
 
 
December 31, 2010
 
Projected benefit obligations
 
 
128
 
 
 
215
 
Plan assets at market value
 
 
(91
)
 
 
(150
)
Accrued pension liability exclusive social security
 
 
37
 
 
 
65
 
Social security related to pension obligations
 
 
6
 
 
 
10
 
Accrued pension liabilities
 
 
43
 
 
 
75
 
 
Change in benefit obligations
 
(in US$ millions)
 
2011
 
 
2010
 
 
 
 
 
 
 
 
Benefit obligations at beginning of year
 
 
215
 
 
 
171
 
Deconsolidation of Archer
    
(104
 )    
-
  
Interest cost
 
 
5
 
 
 
9
 
Current service cost
 
 
9
 
 
 
18
 
Benefits paid
 
 
(2
)
 
 
(3
)
Change in unrecognized actuarial gain
 
 
8
  
 
 
23
  
Foreign currency translations
 
 
(4
)
 
 
(1
)
Other adjustments
    
-
      
(2
)
Benefit obligations at end of year
 
 
128
 
 
 
215
  
 
Change in pension plan assets
 
(in US$ millions)
 
2011
 
 
2010
 
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
 
 
150
 
 
 
135
 
Deconsolidation of Archer
    
(60
 )    
-
  
Estimated return
 
 
5
 
 
 
8
 
Contribution by employer
 
 
7
 
 
 
24
 
Administration charges
 
 
(0
)
 
 
(1
)
Benefits paid
 
 
(1
)
 
 
(2
)
Change in unrecognized actuarial loss
 
 
(8
)
 
 
(13
)
Foreign currency translations
 
 
(2
)
 
 
(2
)
Fair value of plan assets at end of year
 
 
91
 
 
 
150
 

Pension obligations are actuarially determined and are critically affected by the assumptions used, including the expected return on plan assets, discount rates, compensation increases and employee turnover rates. The Company periodically reviews the assumptions used, and adjusts them and the recorded liabilities as necessary.
 
The expected rate of return on plan assets and the discount rate applied to projected benefits are particularly important factors in calculating the Company's pension expense and liabilities. The Company evaluates assumptions regarding the estimated rate of return on plan assets based on historical experience and future expectations on investment returns, which are calculated by a third party investment advisor utilizing the asset allocation classes held by the plan's portfolios. The discount rate is based on the Norwegian government 10 year-bond effective yield. Changes in these and other assumptions used in the actuarial computations could impact the projected benefit obligations, pension liabilities, pension expense and other comprehensive income.
 
Assumptions used in calculation of pension obligations
 
2011
 
 
2010
 
 
2009
 
 
 
  
 
 
 
 
 
 
 
Rate of compensation increase at the end of year
 
  
4.00
%
 
 
4.00
%
 
 
4.25
%
Discount rate at the end of year
 
  
3.90
%
 
 
4.20
%
 
 
5.40
%
Prescribed pension index factor
 
  
1.10
%
 
 
2.00
%
 
 
2.50
%
Expected return on plan assets for the year
 
  
4.80
%
 
 
4.60
%
 
 
5.60
%
Employee turnover
 
  
4.00
%
 
 
4.00
%
 
 
4.00
%
Expected increases in Social Security Base
 
  
3.75
%
 
 
3.75
%
 
 
4.00
%
Expected annual early retirement from age 60/62:
 
    
 
 
 
  
 
 
 
 
 
Offshore personnel fixed installations
 
      
 
 
30.0
%
 
 
30.0
%
Offshore personnel Mobile units and onshore employees
 
  
50.0
%
 
 
50.0
%
 
 
50.0
%
 
 
F-39
 
 
The weighted-average asset allocation of funds related to the Company's defined benefit plan at December 31, was as follows:
 
Pension benefit plan assets
 
2011
 
 
2010
 
 
 
 
 
 
 
 
Equity securities
 
 
10.4
%
 
 
15.6
%
Debt securities
 
 
48.6
%
 
 
49.1
%
Real estate
 
 
18.0
%
 
 
16.1
%
Money market
 
 
21.7
%
 
 
13.2
%
Other
 
 
1.20
%
 
 
6.00
%
Total
 
 
100.0
%
 
 
100.0
%
 
The investment policies and strategies for the pension benefit plan funds do not use target allocations for the individual asset categories. The investment objectives are to maximize returns subject to specific risk management policies. The Company diversifies its allocation of plan assets by investing in both domestic and international fixed income securities and domestic and international equity securities. These investments are readily marketable and can be sold to fund benefit payment obligations as they become payable. The estimated yearly return on pension assets was 4.60 percent in 2011 and 5.30 percent in 2010.
 
Cash flows - Contributions expected to be paid
 
The table below shows the Company's expected annual pension plan contributions under defined benefit plans for the years 2012-2021. The expected payments are based on the assumptions used to measure the Company's obligations at December 31, 2011 and include estimated future employee services.
 
 (in US$ millions)
 
 
December 31 2011
 
 
 
 
 
 
2012
 
 
 
8
 
2013
 
 
 
8
 
2014
 
 
 
9
 
2015
 
 
 
10
 
2016
 
 
 
10
 
2017-2021
 
 
 
65
 
Total payments expected during the next 10 years
      
110
  
 
Note 30 – Related party transactions
 
The Company transacts business with the following related parties, being companies in which our principal shareholders Hemen Holding Ltd and Farahead Investments Inc (hereafter jointly referred to as "Hemen") and companies associated with Hemen have a significant interest:
 
 
·
Ship Finance International Limited ("Ship Finance")
 
 
·
Asia Offshore Drilling Limited ("AOD")
 
 
·
Scorpion Offshore Ltd ("Scorpion")
 
 
·
Metrogas Holdings Inc ("Metrogas")
 
 
·
Frontline Management (Bermuda) Limited ("Frontline")
 
The Company has entered into sale and lease back contracts for several drilling units with Ship Finance, a company in which our principal shareholders Hemen and companies associated with Hemen have a significant interest. Hemen is controlled by trusts established by the Company's President and Chairman Mr. John Fredriksen for the benefit of his immediate family. The Company has determined that the Ship Finance subsidiaries, which own the units, are variable interest entities (VIEs), and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company's consolidated accounts. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in the Company's consolidated accounts (See also note 33).
 
 
F-40
 
 
In the 12 months ended December 31, 2011, the Company incurred the following lease costs on units leased back from Ship Finance subsidiaries.
 
Rig
 
In millions of
US dollar
 
West Prospero
 
 
7
 
West Polaris
 
 
126
 
West Hercules
 
 
120
 
West Taurus
 
 
112
 
Total
 
 
365
 
 
These lease costs are eliminated on consolidation.
 
On June 24, 2011, we entered into a share sale and purchase agreement with Ship Finance, where we acquired all the shares of Rig Finance II Limited, which was the owner of West Prospero. The acquisition price for the shares amounted to $47 million. This transaction is accounted for as an equity transaction and no gain or loss is recognized.
 
In July 2011, we participated in a private placement in Asian Offshore Drilling (AOD) and were allocated shares for $54 million, which corresponds to a 33.75% ownership stake. AOD was established by Mermaid Maritime Public Company Limited in late 2010 when two MOD-V B Class jack-up rigs where ordered at Keppel FELS in Singapore. AOD had additional option agreements for construction of two similar units. Furthermore, it was agreed that we would be responsible for the construction supervision, project management and commercial management of all of AODs jack-up rigs. The total amount of management fees amounted to $2 million for the 12 months ended December 31, 2011.
 
In December 2010, we agreed to amend the original sale and leaseback agreement with Rig Finance II Ltd. granting them a put option exercisable at the end of the lease period at which point in time the jack-up rig West Prospero could be sold to Seadrill at a fixed price of $40 million.
 
On July 1, 2010 our fully consolidated VIEs, SFL Deepwater Ltd and SFL Polaris Ltd, paid a dividend of $290 million and $145 million respectively to Ship Finance. Ship Finance simultaneously granted loans to SFL Deepwater Ltd and SFL Polaris Ltd for the same amounts. The loans bear interest at 4.5% per annum and comprise the balance of $435 million, reported as long-term debt due to related parties in our balance sheet as of December 31, 2011.
 
As of December 31, 2009, the Company had a receivable on Ship Finance of $90 million related to an unsecured credit facility. The loan was repaid on March 30, 2010. Interest payable by Ship Finance, agreed on an arms-length basis, is paid monthly. Interest of $0, $3 and $9 million was received from Ship Finance in the twelve months ended December 31, 2011, 2010 and 2009 respectively.
 
In April 2009, the Company obtained an unsecured credit facility loan of $60 million from Metrogas. The amount was repaid in June 2009. Interest payable in accordance with arms-length principles amounted to $1 million in the twelve months ended December 31, 2009.
 
In November 2009, the Company provided a short-term unsecured loan of $28 million to Scorpion, increased to $80 million in December 2009. Additional loans were provided during 2010 and total outstanding at May 31, 2010 was $240 million at which time Seadrill obtained a controlling interest in Scorpion. The loan was repaid during the third quarter of 2010.. Interest payable, agreed on an arms-length basis amounted to $5 million in 2010 in the period prior to obtaining control of Scorpion. $1.0 million of interest was payable to Scorpion in the twelve months ended December 31, 2009.
 
Frontline provides management support and administrative services for the Company, and charged the Company fees of $2 million, $1 million and $0 million for these services in the years 2011, 2010 and 2009, respectively. These amounts are included in "General and administrative expenses".
 
Note 31 – Risk management and financial instruments
 
The majority of our gross earnings from rigs and vessels are receivable in US dollars and the majority of our other transactions, assets and liabilities are denominated in US dollars, the functional currency of the Company. However, the Company has operations and assets in a number of countries worldwide and incurs expenditures in other currencies, causing its results from operations to be affected by fluctuations in currency exchange rates, primarily relative to the US dollar. The Company is also exposed to changes in interest rates on floating interest rate debt, and to the impact of changes in currency exchange rates on NOK denominated debt. There is thus a risk that currency and interest rate fluctuations will have a negative effect on the value of the Company's cash flows.
 
 
F-41
 
 
Interest rate risk management
 
The Company's exposure to interest rate risk relates mainly to its floating interest rate debt and balances of surplus funds placed with financial institutions. This exposure is managed through the use of interest rate swaps and other derivative arrangements. The Company's ambition is to obtain the most favorable interest rate borrowings available without increasing its foreign currency exposure. Surplus funds are generally placed in fixed deposits with reputable financial institutions, yielding higher returns than are available on overnight deposits in banks. Such deposits generally have short-term maturities, in order to provide the Company with flexibility to meet all requirements for working capital and capital investments. The extent to which the Company utilizes interest rate swaps and other derivatives to manage its interest rate risk is determined by the net debt exposure and its views on future interest rates.
 
Interest rate swap agreements not qualified as hedge accounting
 
At December 31, 2011, the Company had interest rate swap agreements with an outstanding principal of $4,738 million (2010: $2,706 million). In addition, the Company had outstanding cross currency interest rate swaps at December 31, 2011 with a principal amount of $34 million (2010: $174 million) These agreements do not qualify for hedge accounting, and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Statement of Operations under "Gain/(loss) on derivative financial instruments". The combined total fair value of the interest rate swaps and cross currency interest swaps outstanding December 31, 2011 amounted to a liability of $345 million (2010: a liability of $145 million).
 
The Company's interest rate swap and cross currency interest rate swap agreements as at December 31, 2011, were as follows:
 
 
Outstanding principal
 
Receive rate
 
Pay rate
 
Length of contract
 
(In US$ millions)
 
 
 
 
 
 
50
 
3 month LIBOR
 
 
4.63
%
May 2005 - May 2015
34 (NOK 220 mill)
 
3 month NIBOR+1.2%
 
3 month LIBOR+1.3
%
Sept 2005 - Sept 2012
300
 
3 month LIBOR
 
 
3.16
%
Dec 2008 - Dec 2018
150
 
3 month LIBOR
 
 
3.34
%
June 2013 - June 2018
150
 
3 month LIBOR
 
 
3.30
%
June 2013 - June 2018
200
 
3 month LIBOR
 
 
2.83
%
Jan 2011 - Jan 2018
200
  
3 month LIBOR
    
3.27
%
Mar 2013 - Mar 2018
350
 
3 month LIBOR
 
 
3.80
%
 Sep 2011 - Sep 2017
300
 
3 month LIBOR
 
 
3.54
%
   Sep 2011 - Jun 2017
88
 
6 month LIBOR
 
 
3.83
%
Mar 2008 - Sep 2016
350
 
3 month LIBOR
 
 
3.36
%
Sep 2011 - Sep 2016
100
 
3 month LIBOR
 
 
2.22
%
Jan 2011 - Jan 2016
100
  
3 month LIBOR
    
2.24
%
Jan 2011 - Jan 2016
200
  
3 month LIBOR
    
2.17
%
Jan 2011 - Jan 2016
200
  
3 month LIBOR
    
2.17
%
Jan 2011 - Jan 2016
250
  
3 month LIBOR
    
2.71
%
May 2009 - May 2014
250
  
3 month LIBOR
    
2.62
%
May 2009 - May 2014
500
  
3 month LIBOR
    
2.06
%
Mar 2009 - Mar 2014
100
  
3 month LIBOR
    
2.17
%
Aug 2012 - Aug 2017
100
  
3 month LIBOR
    
2.17
%
Aug 2012 - Aug 2017
200
  
3 month LIBOR
    
2.57
%
June 2012 - June 2017
100
  
3 month LIBOR
    
2.56
%
June 2012 - June 2017
100
  
3 month LIBOR
    
2.74
%
May 2012 - May 2017
200
  
3 month LIBOR
    
2.14
%
May 2011 - Jan 2016
200
  
3 month LIBOR
    
2.14
%
May 2011 - Jan 2016
             
 
The counterparties to the above agreements are DnBNOR Bank ASA, Swedbank AB, Fokus Bank, ABN Amro and ING Bank N.V. Credit risk exists to the extent that the counterparties are unable to perform under the contracts, but this risk is considered remote as the counterparties are banks which have all provided loan finance to us and the interest rate swaps are related to those financing arrangements.
 
 
F-42
 
 
Interest rate hedge accounting
 
Two of the Ship Finance subsidiaries consolidated by the Company as VIE's have entered into interest rate swaps in order to mitigate the Company's exposure to variability in cash flows for future interest payments on the loans taken out to finance the acquisition of West Polaris and West Taurus.  These interest rate swaps qualify for hedge accounting and any changes in their fair value are included in "Other comprehensive income/loss". Below is a summary of the notional amounts, fixed interest rates payable and durations of these interest rate swaps.
 
 
Outstanding principal
Receive rate
 
Pay rate
 
Length of contract
(In US$ millions)
 
 
 
 
 
470 (West Polaris )
1 month LIBOR
 
 
3.89
%
July 2008 - Oct 2012
518 (West Taurus)
1 month LIBOR
 
 
2.19
%
Dec 2008 - Aug 2013
 
In the year ended December 31, 2011 the above two VIE Ship Finance subsidiaries recorded fair value gains of $20 million on their interest rate swaps. These gains were recorded by those VIEs as "Other comprehensive income" but due to their ownership by Ship Finance these gains are allocated to "Non-controlling interest" in our equity statement.
 
 
Any change in fair value resulting from hedge ineffectiveness is recognized immediately in earnings. The two VIEs  and therefore the Company, did not recognize any gain or loss due to hedge ineffectiveness in the consolidated financial statements during the years ended December 31, 2011, 2010 and 2009 relating to derivative financial instruments.
 
Foreign currency risk management
 
The Company uses foreign currency forward contracts and other derivatives to manage its exposure to foreign currency risk on certain assets, liabilities and future anticipated transactions. Such derivative contracts do not qualify for hedge accounting treatment and are recorded in the balance sheet under receivables if the contracts have a net positive fair value, and under other short-term liabilities if the contracts have a net negative fair value. At December 31, 2011, the Company had forward contracts and cross currency interest rate swaps to sell approximately $264 million between January 2012 and November 2012 at exchange rates ranging from NOK5.75 to NOK6.40 per US dollar. The total fair value of currency forward contracts December 31, 2011 amounted to minus $3 million (2010: $3 million unrealized gain).
 
Total Return Swap Agreements
 
In June and July 2008, the Company entered into Total Return Swap ("TRS") agreements with a total of 4,500,000 common shares in Seadrill as underlying security. The agreements were scheduled to expire in December 2008 and the initially agreed reference prices were in a range of NOK141.2 to NOK157.8 per share. In November 2008, these agreements were terminated and simultaneously a new TRS agreement with 4,500,000 common shares in Seadrill as underlying security was entered into. This agreement was scheduled to expire in February 2009 and the agreed reference price was NOK56.7 per share. In February 2009, the contract was extended to August 2009 and the new reference price was NOK61.3 per share. In August 2009, the contract was settled and simultaneously a new TRS agreement with 4,500,000 shares in Seadrill as underlying security was entered into. This agreement expired in February 2010 and the agreed reference price was NOK98.44 per share.
 
In February 2010, these agreements were settled and the Company simultaneously entered a new TRS agreement for 3,500,000 of common shares in Seadrill with an agreed reference price of NOK125.70 per share and an expiration date in February 2011. In September 2010, the Company 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 common shares.
 
In January 2011, the Company partly settled the TRS agreement and further reduced the number of underlying Seadrill Limited shares by 750,000 shares from 2,750,000 to 2,000,000 common shares.
 
In September 2011, the contract was settled and simultaneously a new TRS agreement with 2,000,000 Seadrill Limited shares as underlying security was entered into. This agreement expires in March 2012 and the agreed reference price was NOK177.21 per share.
 
The total realized and unrealized gain relating to TRS agreements in 2011 amounted to $5 million (2010 $27 million).
 
 
F-43
 
 
Credit risk
 
The Company has financial assets, including cash and cash equivalents, marketable securities, other receivables and certain amounts receivable on derivative instruments, mainly forward exchange contracts and interest rate swaps. These assets expose the Company to credit risk arising from possible default by the counterparty. The Company considers the counterparties to be creditworthy financial institutions and does not expect any significant loss to result from non-performance by such counterparties. The Company, in the normal course of business, does not demand collateral. The credit exposure of interest rate swap agreements, currency option contracts and foreign currency contracts is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements. It is the Company's policy to enter into master netting agreements with the counterparties to derivative financial instrument contracts, which give the Company the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes to the Company.
 
Fair values
 
The carrying value and estimated fair value of the Company's financial instruments at December 31, 2011 and December 31, 2010 are as follows:
 
 
 
December 31, 2011
    
December 31, 2010
 
(In US$ millions)
 
Fair value
    
Carrying
value
    
Fair value
    
Carrying
value
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
 
483
      
483
      
755
      
755
 
Restricted cash
 
 
482
      
482
      
460
      
460
 
Current portion of long-term debt
    
1,419
      
1,419
      
981
      
981
 
Long-term portion of floating rate debt
 
 
7,711
      
7,711
      
6,509
      
6,509
 
Long term portion of fixed rate CIRR loans
 
 
250
      
250
      
305
      
305
 
Fixed interest convertible bonds
 
 
735
      
545
      
1,535
      
1,287
 
 
 
 
                          
 
 
 
 
                          
 
 
The carrying value of cash and cash equivalents and restricted cash, which are highly liquid, is a reasonable estimate of fair value.
 
The fair value of the current and long-term portion of floating rate debt is estimated to be equal to the carrying value since it bears variable interest rates, which are reset on a quarterly basis. This debt is not freely tradable and cannot be purchased by the Company at prices other than the outstanding balance plus accrued interest.
 
The fair value of the long-term portion of the fixed rate CIRR loans is equal to the carrying value, as they are matched with equal balances of restricted cash.
 
The convertible bonds are freely tradable and their fair value has been set equal to the price at which they were traded at on December 31, 2011 and 2010.
 
Financial instruments that are measured at fair value on a recurring basis:
 
 
 
Fair value
 
 
Fair value measurements
at reporting date using
 
 
 
 
 
 
Quoted Prices in Active Markets for Identical Assets
 
 
Significant Other Observable Inputs
 
 
Significant Unobservable Inputs
 
(In US$ millions)
 
December
31, 2011
 
 
(Level 1)
 
 
(Level 2)
 
 
(Level 3)
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Marketable securities
 
 
24
 
 
 
4
 
 
-
 
 
 
20
 
TRS equity swap contracts
 
 
11
  
 
 
-
 
 
 
11
 
 
 
-
 
Other derivative instruments – short term receivable
 
 
3
 
 
 
1
 
 
 
2
 
 
 
-
 
Total assets
 
 
38
 
 
 
5
 
 
 
13
 
 
 
20
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate swap contracts – short term payable
 
 
372
 
 
 
-
 
 
 
372
 
 
 
-
 
Currency forward contracts – short term payable
    
3
              
3
          
Other derivative instruments – short term payable
    
39
              
39
          
Total liabilities
 
 
414
 
 
 
-
 
 
 
414
 
 
 
-
 
 
 
F-44
 

 
 
 
Fair value
 
 
Fair value measurements
at reporting date using
 
 
 
 
 
 
Quoted Prices in Active Markets for Identical Assets
 
 
Significant Other Observable Inputs
 
 
Significant Unobservable Inputs
 
(In millions of US dollar)
 
December
31, 2010
 
 
(Level 1)
 
 
(Level 2)
 
 
(Level 3)
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Marketable securities
 
 
598
 
 
 
554
 
 
-
 
 
 
44
 
Currency forward contracts –  short term receivable
 
 
3
 
 
 
-
 
 
 
3
 
 
 
-
 
TRS equity swap contracts
 
 
38
 
 
 
-
 
 
 
38
 
 
 
-
 
Other derivative instruments – short term receivable
 
 
7
 
 
 
7
 
 
 
-
 
 
 
-
 
Total assets
 
 
646
 
 
 
561
 
 
 
41
 
 
 
44
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate swap contracts – short term payables
 
 
144
 
 
 
-
 
 
 
144
 
 
 
-
 
Total liabilities
 
 
144
 
 
 
-
 
 
 
144
 
 
 
-
 
 
Roll forward of fair value measurements using unobservable inputs (Level 3):
 
 
(In US$ millions)
 
 
 
Beginning balance January 1, 2011
 
 
44
 
Realization
 
 
(22
)
Purchase
 
 
13
 
Changes in fair value of bonds
    
 (15
 )
Closing balance December 31, 2011
 
 
20
 
 
ASC Topic 820 Fair Value Measurement and Disclosures (formerly FAS 157) emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, ASC Topic 820 establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within levels one and two of the hierarchy) and the reporting entity's own assumptions about market participant assumptions (unobservable inputs classified within level three of the hierarchy).
 
Level one input utilizes unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Level two inputs are inputs other than quoted prices included in level one that are observable for the asset or liability, either directly or indirectly. Level two inputs may include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability, other than quoted prices, such as interest rates, foreign exchange rates and yield curves that are observable at commonly quoted intervals. Level three inputs are unobservable inputs for the asset or liability, which are typically based on an entity's own assumptions, as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability.
 
Quoted market prices are used to estimate the fair value of marketable securities, which are valued at fair value on a recurring basis.
 
The fair value of total return equity swaps is calculated using the closing prices of the underlying listed shares, dividends paid since inception and the interest rate charged by the counterparty.
 
The fair values of interest rate swaps and forward exchange contracts are calculated using well-established independent valuation techniques applied to contracted cash flows and LIBOR and NIBOR interest rates as of December 31, 2011.
 
 
F-45
 
 
The fair value of other derivative instruments is calculated using the closing prices of the underlying securities, dividends paid since inception and the interest charged by the counterparty.
 
Retained Risk
 
a) Physical Damage Insurance
 
The Company retains the risk, through self-insurance, for the deductibles relating to physical damage insurance on the Company's rig fleet, currently a maximum of $5 million per occurrence.
 
b) Loss of Hire Insurance
 
The Company purchases insurance to cover the Deepwater rigs, 3 semi tenders and the North Atlantic fleet for loss of revenue in the event of extensive downtime caused by physical damage, where such damage is covered under the Company's physical damage insurance. The Company's self-insured retentions under the loss of hire insurance are up to 60 days after the occurrence of the physical damage. Thereafter, under the terms of the insurance, the Company is compensated for loss of revenue for a period ranging from 210 days up to 290 days. The Company retains the risk that the repair of physical damage takes longer than the total number of days in the loss of hire policy.
 
Concentration of risk
 
The Company has financial assets, including cash and cash equivalents, marketable securities, other receivables and certain derivative instrument receivable amounts. These other assets expose the Company to credit risk arising from possible default by the counterparty. There is also a concentration of credit risk with respect to cash and cash equivalents to the extent that most of the amounts are carried with DnB NOR Bank ASA, Nordea Bank Finland Plc, Fokus Bank, and ING Bank N.V. The Company considers these risks to be remote.
 
In the year ended December, 31, 2011, 17% of the Company's contract revenues were received from Petroleo Brasileiro S.A ("Petrobras") (2010: 17%), 15% from Total S.A Group ("Total") (2010: 10%), 10% from Exxon Mobil Corp ("Exxon") (2010: 7%), 10% from Royal Dutch Shell Group ("Shell") (2010: 9%) and 7% from Statoil ASA ("Statoil": 15%).  There is thus a concentration of revenue risk towards Petrobras, Total, Exxon, Shell and Statoil.
 
Note 32 – Commitments and contingencies
 
Legal Proceedings:
 
The Company is a party, as plaintiff or defendant, to several lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the operation of its drilling units, in the ordinary course of business or in connection with its acquisition activities.  The Company believes that the resolution of such claims will not have a material adverse effect on the Company's operations or financial condition. The Company's best estimate of the outcome of the various disputes has been reflected in the financial statements of the Company as of December 31, 2011.
 
Pledged assets
 
The book value of assets pledged under mortgages and overdraft facilities at December 31, 2011 was $12,567 million (2010: $10,090 million).
 
Purchase Commitments
 
At December 31, 2011, the Company had contractual commitments under fifteen newbuilding contracts totaling $3,012 million (2010: $2,073 million). The contracts are for the construction of two semi-submersible rigs, six jack-up rigs, three drillships and four tender rigs.
 
The maturity schedule for the contractual commitments as of December 31, 2011 is as follows:
 
 (In US$ millions)
 
2012
 
 
2013
 
 
2014
 
 
2015
 
 
2016
 
 
2017 and thereafter
 
Newbuildings
 
 
506
 
 
 
2,506
 
 
 
  
 
 
 
-
 
 
 
-
 
 
 
-
 
Total
 
 
506
 
 
 
2,506
 
 
 
  
 
 
 
-
 
 
 
-
 
 
 
-
 
 
 
F-46
 
 
Guarantees
 
The Company has issued guarantees in favor of third parties as follows, which is the maximum potential future payment for each type of guarantee:
 
 
(In US$ millions)
 
December
31, 2011
 
 
December
31, 2010
 
Guarantees to customers of the Company's own performance
 
 
1,553
 
 
 
1,615
 
Guarantee in favor of banks
 
 
764
 
 
 
771
 
Guarantee in favor of suppliers
 
 
2,023
 
 
 
2,040
 
Guarantee in favor of Variable Interest Entities
 
 
1,949
 
 
 
2,218
 
Total
 
 
6,289
 
 
 
6,644
 
 
Note 33 – Variable Interest Entities (VIEs)
 
As of December 31, 2011, the Company leased a drillship and two semi-submersible rigs from VIEs under finance leases. Each of the units had been sold by the Company to single purpose subsidiaries of Ship Finance Ltd and simultaneously leased back by the Company on bareboat charter contracts for a term of 15 years. The Company has several options to repurchase the units during the charter periods, and obligations to purchase the assets at the end of the 15 year lease period. The following table gives a summary of the sale and leaseback arrangements, as of December 31, 2011:
 
Unit
Effective
from
 
Sale value
(In US$ millions)
 
 
First
repurchase
option
(In US$ millions)
 
Month of first
repurchase
option
 
Last
repurchase
option *
(In US$ millions)
 
Month of last
repurchase
Option *
West Polaris
July 2008
 
 
850
 
 
 
548
 
September 2012
 
 
178
 
June 2023
West Taurus
Nov 2008
 
 
850
 
 
 
418
 
February 2015
 
 
149
 
Nov 2023
West Hercules
Oct  2008
 
 
850
 
 
 
580
 
August 2011
 
 
135
 
Aug 2023
                               
 
* For the unit West Polaris, Ship Finance has a put option exercisable at the end of the lease terms by which the vessel may be sold to Seadrill for a fixed price of $75 million. For West Taurus and West Hercules repurchase obligations at the end of the lease terms have been agreed, at $149 million and $135 million, respectively.
 
The Company has determined that the Ship Finance subsidiaries, which own the units, are variable interest entities (VIEs), and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company's consolidated accounts. The Company did not record any gains from the sale of the units, as they continued to be reported as assets at their original cost in the Company's balance sheet at the time of each transaction. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in the Company's consolidated accounts. At December 31, 2011 the units are reported under drilling units in the Company's balance sheet.
 
The bareboat charter rates are set on the basis of a Base LIBOR Interest Rate for each bareboat charter contract, and thereafter are adjusted for differences between the LIBOR fixing each month and the Base LIBOR Interest Rate for each contract. A summary of the bareboat charter rates per day for each unit is given below. The amounts shown are based on the Base LIBOR Interest Rate, and reflect average rates for the year.
 
 
 
 
 
 
2012
 
 
2013
 
 
2014
 
 
2015
 
 
2016
 
 
 
Base LIBOR
Interest Rate
 
 
(In US$
 thousands)
 
 
(In US$
thousands)
 
 
(In US$
thousands)
 
 
(In US$
thousands)
 
 
(In US$
thousands)
 
West Polaris
 
 
2.85
%
 
 
323.5*
      
223.3
      
176.5
      
175.4
      
170.0
 
West Taurus
 
 
4.25
%
 
 
311.9*
      
316.2*
      
320.7
      
165.0
      
158.8
 
West Hercules
 
 
4.25
%
 
 
250.0
      
250.0
      
238.5
      
180.0
      
172.5
 
 
* For a period the interest rates for West Polaris and West Taurus have been fixed at 3.89% and 2.17%, respectively, and the bareboat charter rate for these two units is fixed regardless of movements in LIBOR interest rates. These fixed charter rates are reflected in the above table.
 
 
F-47
 
 
The assets and liabilities in the statutory accounts of the VIEs are as follows:
 
 
(In US$ millions)
 
 
 
SFL
West
Polaris
Limited
 
 
SFL
Deepwater
Ltd.
 
 
Name of unit
 
 
 
West
Polaris
 
 
West
Taurus/
West
Hercules
 
 
 
 
 
 
 
 
 
 
Investment in finance lease
 
 
 
 
611
 
 
 
1,240
 
Other assets
 
 
 
 
12
 
 
 
23
 
Total assets
 
 
 
 
623
 
 
 
1,263
 
Long term debt
 
 
 
 
398
 
 
 
822
 
Other liabilities
 
 
 
 
174
 
 
 
326
 
Total liabilities
 
 
 
 
572
 
 
 
1,148
 
Equity
 
 
 
 
51
 
 
 
115
 
Book value of units in the Company's consolidated accounts
 
 
 
 
614
 
 
 
1,021
 
 
Note 34 – Gain on realization of marketable securities
 
On February 7, 2011, Ensco plc ("Ensco") (NYSE: ESV) and Pride International, Inc. ("Pride") (NYSE: PDE) jointly announced that they have entered into a definitive merger agreement under which Ensco will combine with Pride in a cash and stock transaction. On May 31, 2011, Ensco announced the completion of its acquisition of Pride International, after both companies received shareholder approvals. Under the terms of the merger agreement, Pride stockholders received 0.4778 newly-issued shares of Ensco plus $15.60 in cash for each share of Pride common stock.
 
The merger represents a realization of our previously held Pride positions. The accumulated other-comprehensive income effect related to our holding in Pride amounted to $416 million as of May 31, 2011. This amount has been released into the profit and loss statement upon our acceptance of the Ensco offer, and the gain is presented on a separate line item in our financial statements. The cash effect of this transaction was $141 million in 2011.
 
Note 35 – Subsequent Events
 
On January 31, 2012  the Company completed a NOK1,250 million senior unsecured bond issue with maturity date February 13, 2014.. An application will be made for the bonds to be listed on Oslo Børs.. The net proceeds from the bond issue will be used for general corporate purposes. In conjunction with the bond issue, Seadrill has repurchased bonds with nominal value of NOK332 million in the SME05 (ISIN: NO 001 028379.9) maturing at September 28, 2012. Remaining outstanding amount in SME05 after the buy-backs will be NOK169 million.
 
On February 29, 2012, Hemen agreed to sell up to 24 million shares of Seadrill Ltd common stock ("Shares") to investors in an offering and enter into a privately negotiated cash or physically settled put option transaction with Goldman Sachs International ("Seller Put Option") with a 90 day average maturity on 24 million shares. The agreement involves a combined purchase price of NOK 236.3176 per Share and Seller Put Option. Following the transaction, Hemen has reduced its holding of Shares from 28% to 23% of the issued and outstanding share capital of Seadrill Limited. If all put options are exercised with physical delivery at expiry Hemen's position in Seadrill will remain as before the transaction, with 28% ownership.
 
In February 2012, we ordered two 12,000 ft dual derrick ultra-deepwater drillships to be constructed at Samsung. The drillships are of the same design as the three previous dual derrick drillships that we ordered from Samsung in the fourth quarter 2010 and first quarter 2011. The total project price per drillship is estimated to be under $600 million, which includes a turnkey contract with the yard, project management, drilling and handling tools, spares, capitalized interest and operations preparations.
 
In February 2012, we disposed of our 3.5% holding in Ensco Plc, which we have had since Ensco acquired Pride International Inc. in 2011.
 
On March 27, 2012, our subsidiary North Atlantic completed a private placement of 150,000,000 new ordinary shares at US$ 2.00 per share, raising gross proceeds of US$300 million. Seadrill Limited was allocated 75,000,000 shares in the private placement and following the transaction we own 73.2% of North Atlantic.
 
On March 31, 2012, we obtained a short-term unsecured credit facility of $84 million from Metrogas, The amount is repayable in June 2012 and bears interest in accordance with arms-length principles.
 
 
F-48
 
 
On April 2, 2012, North Atlantic entered into a contract with Jurong Shipyard in Singapore for the construction of a new harsh environment semi-submersible drilling rig to be delivered by the first quarter 2015. Total estimated project costs for the new rig, including a turnkey contract with the yard, project management, drilling and handling tools, spares, capitalized interest and operations preparations, is estimated to be approximately $650 million.
 
On April 12, 2012, we exercised an option to build a new tender rig at the COSCO Nantong Shipyard in China. The new unit, T18, is scheduled for delivery in the fourth quarter 2013. Total project price is estimated at $135 million, including project management, drilling and handling tools, spares, and capitalized interest.
 
On April 20, 2012, we issued a claim against the Norwegian Tax Authorities. The claim is challenging their tax re-assessment related to change of tax jurisdiction for some of our subsidiaries and calculation of taxable gains (See Note 4 to our Consolidated Financial Statements).
 

 
F-49
 

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.

Seadrill Limited
(Registrant)


Date: April 27, 2012

 
By:
/s/ Alf C. Thorkildsen
 
Name:
Alf C. Thorkildsen
 
Title:
Chief Executive Officer of Seadrill Management AS
(Principal Executive Officer of Seadrill Limited)