20-F 1 d1285852_20-f.htm 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.
 

 
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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