Seadrill 20F 2009 Annual report

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

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from ____ to ____

[ ] 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, 2009, there were 399,023,016 shares of the Registrant's common stock, $2.00 par value, outstanding.

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

[ ] Yes	[ X ] 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.

[ ] Yes	[ X ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months

[ ] Yes	[ ] No

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

Large accelerated filer [ ]	Accelerated filer [ ]

Non-accelerated filer [X]

(Do not check if a smaller reporting company)

Smaller reporting company [ ]

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

[ X ] U.S. GAAP

[ ] International Financial Reporting Standards as issued by the International Accounting Standards Board

[ ] Other

If "Other" has been checked in response to the previous question, indicate by check mark which

financial statement item the Registrant has elected to follow.

[ ] Item 17

[ ] Item 18

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

[ ] Yes	[ X ] No

FORWARD LOOKING STATEMENTS

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

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

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

In addition to these important factors and matters discussed elsewhere in this Annual Report, and in the documents incorporated by reference in this Annual Report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include factors related to the offshore drilling market, including supply and demand, utilization rates, dayrates, customer drilling programs, commodity prices, effects of new rigs on the market and effects of declines in commodity prices and downturn in global economy on market outlook for our various geographical operating sectors and classes of rigs, 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.

TABLE OF CONTENTS

PART I

ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	5
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	5
ITEM 3.	KEY INFORMATION	5
ITEM 4.	INFORMATION ON THE COMPANY	17
ITEM 4A.	UNRESOLVED STAFF COMMENTS	28
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	28
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	45
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	49
ITEM 8.	FINANCIAL INFORMATION	51
ITEM 9.	THE OFFER AND LISTING	52
ITEM 10.	ADDITIONAL INFORMATION	53
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	62
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	64

PART II

ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	65
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	65
ITEM 15.	CONTROLS AND PROCEDURES	65
ITEM 16.	RESERVED	65
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT.	65
ITEM 16B.	CODE OF ETHICS	65
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	65
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	66
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	66
ITEM 16F.	CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT	67
ITEM 16G.	CORPORATE GOVERNANCE	67

PART III

ITEM 17.	FINANCIAL STATEMENTS	68
ITEM 18.	FINANCIAL STATEMENTS	68
ITEM 19.	EXHIBITS	69

PART 1.

As used in this Annual Report, unless the context otherwise requires, references to "Seadrill Limited," the "Company," "we," "us," "Group," "our" and words of similar import refer to Seadrill Limited, its subsidiaries and its other consolidated entities. Unless otherwise indicated, all references to "USD", "US$" and "$" in this report are to, and amounts are represented in, U.S. 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, 2009, 2008 and 2007 and the selected balance sheet data of the Company with respect to the fiscal years ended December 31, 2009 and 2008 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, 2006 and the period from May 10, 2005 (date of incorporation) to December 31, 2005 and the selected balance sheet data with respect to the fiscal years ended December 31, 2007 and 2006 and the period from May 10, 2005 (date of incorporation) to December 31, 2005 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 U.S. Dollars. We refer you to the notes to our consolidated financial statements for a discussion of the basis on which our consolidated financial statements are presented.

	Year ended December 31,									Period from May 10, 2005 (inception) to December 31,
	2009		2008			2007		2006		2005
	(in millions of U.S. dollars except common share and per share data)
Statement of Operations Data:
Total operating revenues		3,254		2,106			1,552		1,155		27
Net operating income		1,372		649			489		226		(15	)
Net income (loss)		1,353		(123	)		515		245		(8	)
Earnings per share, basic	$	3.16	$	(0.41	)	$	1.28	$	0.62	$	(0.04	)
Earnings per share, diluted	$	3.00	$	(0.41	)	$	1.20	$	0.61	$	(0.04	)
Dividends declared		199		688			-		-		-
Dividends declared per share	$	0.50	$	1.75			-		-		-

	Year ended December 31,												Period from May 10, 2005 (inception) to December 31,
	2009			2008			2007			2006			2005
		(in millions of U.S. dollars except common share and per share data)
Balance Sheet Data (at end of period):
Cash and cash equivalents		460			376			997			210			52
Drilling units		7,515			4,645			2,452			2,293			178
Newbuildings		1,431			3,661			3,340			2,025			439
Investment in associated companies		321			240			176			238			153
Goodwill		1,596			1,547			1,510			1,256			-
Total assets		13,831			12,305			9,293			6,743			1,149
Interest bearing debt (including current portion)		7,396			7,437			4,601			2,815			314
Share capital		798			797			797			766			458
Shareholders' equity		4,813			3,222			3,728			2,927			802
Common shares outstanding, in millions		399.0			398.4			398.5			383.1			229.1
Weighted average common shares outstanding		398.5			398.3			392.8			352.1			190.9

Other Financial Data:
Net cash provided by operating activities		1,452			401			486			174			11
Net cash used in investing Activities		(924	)		(3,847	)		(1,868	)		(3,180	)		(256	)
Net cash provided by financing activities		(454	)		2,826			2,168			3,162			294
Capital expenditure		(1,369	)		(2,768	)		(1,738	)		(1,196	)		(269	)

B. CAPITALIZATION AND INDEBTEDNESS

Not applicable.

C. REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

D. RISK FACTORS

Our assets are primarily engaged in offshore contract drilling for the oil and gas industry in benign and harsh environments worldwide, including ultra-deepwater environments. The following summarizes some of the risks that may materially affect our business, financial condition or results of operations. Unless otherwise indicated in this Annual Report on Form 20-F for the year ended December 31, 2009, all information concerning our business and our assets is as at April 26, 2010.

Risks Relating to Our Industry

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

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

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

worldwide demand for oil and gas;

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

expectations regarding future energy prices;

advances in exploration and development technology;

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

the level of production in non-OPEC countries;

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

local and international political, economic and weather conditions;

domestic and foreign tax policies;

the development and exploitation of alternative fuels;

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

political and military conflicts in oil-producing and other countries; and

volatility in the exchange rate of the U.S Dollar against other currencies.

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

In response to improved market conditions in 2007 and 2008 which were associated with historically high oil and gas prices, offshore drilling contractors ordered new drilling units to meet their customers' then increasing demand for services. In the past significant spikes in oil and gas prices have led to high levels of rig construction orders. This is often followed by a period of sharp and sudden declines in oil and gas prices and an oversupply of drilling units, which in turn results in declines in utilization and dayrates, and an increase in the number of idle drilling units without long-term contracts. The worldwide fleet of dynamically positioned deepwater drilling units currently consists of 65 units. An additional 69 deepwater units are under construction or on order, which would bring the expected total fleet to 134 units in 2013 when the last of the currently ordered units are scheduled to be delivered. The strong growth in deepwater units is due to the increased focus of oil companies on existing and new deepwater regions for exploration and production, and the inability to upgrade or modify the existing mid-water fleet to undertake deepwater drilling campaigns. At the same time, there are 60 jack-up rigs currently under construction, while the existing worldwide fleet of jack-up rigs contains 459 units with an average age of approximately 25 years. The growth in newbuilding jack-up rigs is targeted at oil companies with the need for more advanced and effective jack-up rigs. However, the majority of the newbuilding jack-up rigs have been ordered on speculation, i.e. without fixed employment, and not all of these rigs have secured contracts for future work. This could intensify price competition as scheduled delivery dates come closer, resulting in a reduction in dayrates. Lower utilization and dayrates could adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates could also have a material adverse effect on the value of our assets.

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 we currently own or may acquire in the future may increase or decrease depending on a number of factors, including:

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

types, sizes and ages of drilling units;

supply and demand for drilling units;

costs of newbuildings;

prevailing level of drilling services contract dayrates;

governmental or other regulations; and

technological advances.

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

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

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

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

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

terrorist acts, war, civil disturbances and piracy;

seizure, nationalization or expropriation of property or equipment;

political unrest;

labor unrest and strikes;

foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;

the inability to repatriate income or capital;

complications associated with repairing and replacing equipment in remote locations;

import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;

regulatory or financial requirements to comply with foreign bureaucratic actions; and

changing taxation policies.

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

the equipping and operation of drilling units;

repatriation of foreign earnings;

oil and gas exploration and development;

taxation of offshore earnings and the earnings of expatriate personnel;

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

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

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

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

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

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

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

Hurricanes Ivan, Katrina, Rita, and Ike have caused damage to a number of drilling units unaffiliated to us in the U.S. Gulf of Mexico. In June 2009, the Minerals Management Service, or MMS, of the U.S. Department of the Interior issued the latest guidelines for jack-up drilling rig fitness requirements for the 2009 hurricane season. Also in June 2009, the MMS issued the latest guidelines for tie-downs on any drilling units and permanent equipment and facilities attached to an outer continental shelf production platform, and guidelines for moored drilling rig fitness requirements for the 2009 hurricane season. These guidelines continued requirements on the offshore oil and gas industry, in an attempt to improve the stations that house the moored units and increase the likelihood of survival of jack-up rigs and other offshore drilling units during a hurricane. The guidelines also provided for enhanced information and data requirements from oil and gas companies operating properties in the U.S. Gulf of Mexico. We do not have any jack-up rigs or moored drilling units operating in the U.S. Gulf of Mexico. However, we currently have operating in the U.S. Gulf of Mexico one ultra-deepwater semi-submersible drilling rig that is self propelled and equipped with thrusters and other machinery, which enable the rig to move between drilling locations and remain in position while drilling without the need for anchors. Nevertheless, it is possible that the MMS may issue guidelines for future hurricane seasons and may take other steps which could increase the cost of operations and implementation of such guidelines, or reduce the area of operations for our ultra-deepwater drilling unit.

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

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

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

We are currently involved in various litigation matters, none of which we expect to have a material adverse effect on us. We anticipate that we will be involved in litigation matters from time to time in the future. The operating hazards inherent in our business expose us to litigation, including personal injury litigation, environmental litigation, contractual litigation with clients, intellectual property litigation, tax or securities litigation, and maritime lawsuits including the possible arrest of our drilling units. We cannot predict with certainty the outcome or effect of any claim or other litigation matter. Any future litigation may have an adverse effect on our business, financial position, results of operations and our ability to pay dividends, because of potential negative outcomes, the costs associated with prosecuting or defending such lawsuits, and the diversion of management's attention to these matters.

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

As a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. Dollars. Accordingly, we may experience currency exchange losses in situations where 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 incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. A discussion of our policy and exposure to exchange rate fluctuations is given in Item 11 "Quantitative and Qualitative Disclosures about Market Risk".

Our business involves 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, and failure of subcontractors to perform or supply goods or services, or personnel shortages. We customarily provide contract indemnity to our customers for claims that could be asserted by us relating to damage to or loss of our equipment, including rigs and claims that could be asserted by us or our employees relating to personal injury or loss of life.

Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our clients generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurance that these clients will be willing or financially able to indemnify us against all these risks. We maintain insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. We have no insurance coverage for named storms in the U.S. Gulf of Mexico and war perils worldwide. Furthermore, pollution and environmental risks generally are not totally insurable.

We maintain a portion of deductibles for damage to our offshore drilling equipment and third-party liabilities. With respect to hull and machinery we generally maintain a deductible per occurrence up to $1.7 million. However, in the event of a total loss or a constructive total loss of a drilling unit, such loss is fully covered by our insurance with no deductible. For general and marine third-party liabilities we generally maintain up to $250,000 deductible per occurrence on personal injury liability for crew claims as well as non-crew claims and per occurrence on third-party property damage.

If a significant accident or other event occurs and is not fully covered by our insurance or an enforceable or recoverable indemnity from a client, it could adversely affect our consolidated statement of financial position, results of operations or cash flows. The amount of our insurance may 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 substantially more risk through self-insurance in the future. Moreover, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

As of April 26, 2010, all of the drilling units that we owned or operated were covered by existing insurance policies.

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

The majority of the intellectual property rights relating to our drilling rigs and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services, replacement parts, or could be required to cease use of some equipment. We could also be required to pay royalties for the use of equipment. These consequences of technology disputes involving our suppliers could adversely affect our financial results and operations. We have provisions in most of our supply contracts to provide indemnity from the supplier against intellectual property lawsuits. However, we cannot be assured that our suppliers will be willing or financially able to honor their indemnity obligations, or 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 be assured that these provisions will fully protect us from the adverse consequences of such technology disputes.

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:

improve our existing services and related equipment;

address the increasingly sophisticated needs of our customers; and

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

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

Risks Relating to Our Company

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

As of December 31, 2009, we had $7.4 billion in principal amount of debt, representing approximately 61% of our total capitalization. Our current indebtedness and future indebtedness which we may incur could affect our future operations, as a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes. Covenants contained in our debt agreements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities, and our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited. Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our newbuilding projects, will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent that we are unable to repay our indebtedness as it becomes due or at maturity, we may need to refinance our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments.

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

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

We rely heavily 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, 2009, our five largest customers accounted for approximately 79% of our future contracted revenues, or order backlog. Our results of operations could be materially adversely affected if any of our major customers failed to compensate us for our services, were to terminate our contracts with or without cause, failed to renew its existing contracts or refused to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates.

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

Rig construction projects are subject to risks of delay or cost overruns inherent in any large construction project from numerous factors, including shortages of equipment, materials or skilled labor, unscheduled delays in the delivery of ordered materials and equipment or shipyard construction, failure of equipment to meet quality and/or performance standards, financial or operating difficulties experienced by equipment vendors or the shipyard, unanticipated actual or purported change orders, inability to obtain required permits or approvals, unanticipated cost increases between order and delivery, design or engineering changes and work stoppages and other labor disputes, adverse weather conditions or any other events of force majeure. Significant cost overruns or delays could adversely affect our financial position, results of operations and cash flows. Additionally, failure to complete a project on time may result in the delay of revenue from that rig. New drilling rigs may experience start-up difficulties following delivery or other unexpected operational problems that could result in uncompensated downtime, which also could adversely affect our financial position, results of operations and cash flows or the cancellation or termination of drilling contracts.

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

Some of our customers have the right to terminate their drilling contracts upon the payment of an early termination fee. However, such payments may not fully compensate us for the loss of the contract. Under certain circumstances our contracts may permit a customer to terminate their contract early without the payment of any termination fee, 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. Many of these events are 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.

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

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 and demand for contract drilling services, which in turn affect dayrates, and the operational performance of our fleet of drilling rigs. 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 the unit is performing and the age and condition of the equipment. In connection with new assignments, we might incur expenses relating to preparation for operations under a new contract. The expenses may vary based on the scope and length of such required preparations and the duration of the firm contractual period over which such expenditures are amortized. In situations where our rigs incur idle time between assignments, the opportunity to reduce the size of our crews on those rigs is limited as the crews will be engaged in preparing the rig for its next contract. In a situation where a rig 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 rigs be idle for a longer period, we will seek to redeploy crew members, who are not required to maintain the rigs, to active rigs to the extent possible. However, there can be no assurance that we will be successful in reducing our costs.

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

Most of the units in our fleet have long-term contracts. The average contract length as of December 31, 2009, is 36 months for our deepwater units, 25 months for our tender rigs and ten months for our jack-up rigs, excluding the four jack-up rigs under construction. The majority of these contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from term contracts, most of our contracts include escalation provisions. These provisions allow us to adjust the dayrates based on stipulated costs increases including wages, insurance and maintenance cost. However, because these escalations are normally performed on a semi-annual or annual basis, the timing and amount awarded as a result of such adjustments may differ from our actual cost increases, which could adversely affect our financial performance. Shorter term contracts normally do not contain escalations provisions.

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

We have six contracts that expire in 2010, six contracts that expire in 2011 and seven contracts that expire in 2012. Our ability to renew these contracts or obtain new contracts will depend on the prevailing market conditions. In cases where we are not able to obtain new contracts in direct continuation, or where new contracts are entered into at dayrates substantially below the existing dayrates or on terms 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, 2009, the future contracted revenue for our fleet of drilling units, or contract drilling backlog, was approximately $10.4 billion under firm commitments. We may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse conditions resulting in lower dayrates. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

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

The oilfield services industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Our larger competitors' greater resources could allow them to better withstand industry downturns, compete more effectively on the basis of technology and geographic scope and retain skilled personnel. We believe 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 than our products and services, or expand into service areas where we operate. Competitive pressures or other factors also may result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations and financial condition. In addition, competition among oilfield services and equipment providers is affected by each provider's reputation for safety and quality.

Uncertainty relating to the development of the world economy may reduce demand for our drilling services or result in contract delays or cancellations.

We depend on our customers' willingness and ability to make operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. Recent deterioration of the world economy has caused a decline in oil and gas prices from previous high levels, which in turn has caused a number of oil and gas producers to adjust future capital budgets. Limitations on the availability of capital or higher costs of capital for financing expenditures, or the desire to preserve liquidity, may cause these and other customers to make additional reductions in future capital budgets and outlays. Such adjustments could reduce demand for our products and services, which could adversely affect our results of operations and cash flows. We cannot assure you that our customers will increase their capital budgets in response to the recent recovery in crude oil prices, which were approximately $83 per barrel as of April 26, 2010, after hitting a low of approximately $40 per barrel in late 2008 and early 2009.

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 recent drop in energy prices and utilization rate has to some extent reduced the need for people related to international jack-up rigs. For deepwater operations utilization rates remain high and the number of deepwater units in operation is growing as a result of the delivery of units ordered in the period 2005 to 2008. This is expected to increase the demand for qualified personnel with deepwater experience in particular. If this expansion continues and is coupled with improved demand for drilling services in general, shortages of qualified personnel could develop, creating upward pressure on wages and making it more difficult to staff and service our rigs. Such developments could adversely affect our financial results and cashflow.

Our labor costs and the operating restrictions which 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 have restricted ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.

The failure to consummate or integrate acquisitions of other businesses and assets in a timely and cost-effective manner could have an adverse effect on our financial condition and results of operations.

Acquisition of assets or businesses that expand our drilling and well services operations is an important component of our business strategy. We believe that acquisition opportunities may arise from time to time, and any such acquisition could be significant. Any acquisition could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Certain acquisition and investment opportunities may not result in the consummation of a transaction. In addition, we may not be able to obtain acceptable terms for the required financing for any such acquisition or investment

that arises. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our common stock. Our future acquisitions present a number of risks, including the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets, the risk of failing to successfully and timely integrate the operations or management of any acquired businesses or assets and the risk of diverting management's attention from existing operations or other priorities. If we fail to consummate and integrate our acquisitions in a timely and cost-effective manner, our financial condition and results of operations will be adversely affected.

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

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

Interest rate fluctuations could affect our profitability, earnings and cash flow.

In order to finance our growth we have incurred significant amounts of debt. With the exception of our 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 profitability, earnings and cash flow. In order to manage our exposure to interest rate fluctuations, we use interest rate swaps to effectively fix some 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, 2009, our total net floating rate debt amounted to $5.0 billion and we had entered into interest rate swaps in order to effectively fix the interest rate for a principal amount of $4.1billion.

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 and regulations are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, treaties and regulations 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, treaties or regulations, 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.

While we believe that we are not currently a PFIC and do not anticipate becoming a PFIC, United States tax authorities could treat us as a "passive foreign investment company," which could have adverse United States federal income tax consequences to United States holders.

A foreign corporation will be treated as a "passive foreign investment company," or PFIC, for United States federal income tax purposes if either (1) at least 75 percent of its gross income for any taxable year consists of certain types of "passive income" or (2) at least 50 percent of the average value of the corporation's assets produce or are held for the production of those types of "passive income." For purposes of these tests, "passive income" includes dividends, interest, and gains from the sale or exchange of investment property and rents and royalties other than rents and royalties which are received from unrelated parties in connection with the active conduct of a trade or business but does not include income derived from the performance of services.

If the IRS were to find that we are or have been a PFIC for any taxable year, our United States shareholders will face adverse United States 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 "Tax Considerations – United States Federal Income Taxation of U.S. Holders"), such shareholders would be liable to pay United States 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 our common shares, as if the excess distribution or gain had been recognized ratably over the shareholder's holding period of our common shares. See "Tax Considerations— United States Federal Income Taxation of U.S. Holders" for a more comprehensive discussion of the United States federal income tax consequences to United States shareholders if we are treated as a PFIC.

Risks Relating to Our Common Shares

There is no assurance that an active and liquid trading market for our common shares will be sustained in the United States.

Our common shares were listed on the NYSE on April 15, 2010 under the symbol "SDRL". Our common shares have been listed on the Oslo Stock Exchange since November 2005, also under the symbol "SDRL". There is no assurance that an active and liquid trading market for our common shares will be sustained in the United States.

Our common share price may be highly volatile.

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

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

We are a Bermuda exempted company. Our Memorandum of Association and Bye-laws and The Companies Act, 1981 of Bermuda, or the Companies Act, govern our affairs. The Companies Act does not as 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. 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 6.6% of our majority-owned subsidiary Seawell Limited, or Seawell. One of our directors, Kate Blankenship is also a director of Frontline, Ship Finance and Seawell and another of our directors, Kathrine Fredriksen, the daughter of

John Fredriksen, is also a director of Frontline. Mr. Fredriksen, Mrs. Blankenship and Ms. Fredriksen owe fiduciary duties to each of Seadrill, Frontline and Ship Finance 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 or Ship Finance than they do for us. We cannot assure you that any of these conflicts of interest will be resolved in our favor.

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

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

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

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

ITEM 4. INFORMATION ON THE COMPANY

A. HISTORY AND DEVELOPMENT OF THE COMPANY

The Company

We were incorporated under the laws of Bermuda on May 10 ,2005, and our shares of common stock have been listed on the Oslo Stock Exchange under the symbol "SDRL" since November 2005. Our principal executive offices are located at Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton, HM 08, Bermuda and our telephone number is +1 (441) 295-6935.

We are an offshore drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of jack-up rigs, tender rigs, semi-submersible rigs and drillships, which operate in shallow, mid and deepwater areas as well as benign and harsh environments. A description of our different types of drilling units is given in Item 4.B "Business Overview". We operate through subsidiaries located throughout the world, including in Bermuda, Norway, the Cayman Islands, the British Virgin Islands, Cyprus, Nigeria, Liberia, Hungary, Singapore, Brazil, Hong Kong, Panama, the United Kingdom, Denmark, Malaysia, Brunei and the United States. We own and operate a fleet of 36 offshore drilling units, including eight units under construction, which consist of 10 jack-up rigs, 10 semi-submersible rigs, four drillships and 12 tender rigs. The units under construction consist of two semi-submersible rigs, one drillship, one tender rig and four jack-up rigs, including one jack-up rig for which we have a purchase option that we intend to exercise. Four of the above units were sold to and leased back from wholly-owned subsidiaries of Ship Finance, a related party, and these subsidiaries are fully consolidated in our financial statements as variable interest entities, or VIEs, in which we hold the primary interest (see Note 33 to the Consolidated Financial Statements). In addition we operate five tender rigs in association with Varia Perdana Sdn Bhd, or Varia Perdana, a Malaysian company in which we have a 49% ownership interest. We have a contractual right not to take delivery of one of the four newbuilding jack-up rigs currently under construction. If we exercise this right we will forfeit the installment paid to date on the newbuilding.

We own a 73.8% interest in the well services company Seawell. Seawell provides services in platform drilling, facility engineering, modular rig, well intervention and oilfield technologies, and drilling and well services and has approximately 2,600 employees. Seawell currently operates on nearly 50 installations in the North Sea and has offices in Stavanger and Bergen in Norway, Aberdeen and Newcastle in the United Kingdom, Houston in the United States, Esbjerg in Denmark, Rio de Janeiro in Brazil and Kuala Lumpur in Malaysia.

We also hold investments in several other companies in our industry that we consider to be strategic investments, including

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

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

- 40.0% equity interest in Scorpion Offshore Limited, or Scorpion, a Bermuda jack-up rig company. In April 2010 we acquired 1.3 million shares in Scorpion, which increased our shareholding from 38.6% to 40.0%. This acquisition triggered an obligation to make a mandatory cash offer for Scorpion's remaining shares or reduce our shareholding below 40%. On April 12, 2010, we announced that we plan to make a cash offer for the remaining shares in Scorpion.

We consider strategic investments to be investments in companies that own and/or operate offshore drilling rigs with similar characteristics to our own fleet of rigs and that provide us with additional exposure to market segments in which we operate or a new market segment. Further, we view investments as strategic that potentially advance the development of our Company in accordance with our business strategy, particularly relating to consolidation in the offshore drilling rig industry.

Development of the Company

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

Subsequent to the above initial acquisitions, we have entered into further contracts for newbuildings and acquired other companies engaged in offshore drilling and related industries. As a result, our operations have expanded considerably and we now have approximately 7,600 skilled employees and an active fleet of 28 units, consisting of six jack-up rigs, eight semi-submersible rigs, three drillships and 11 tender rigs.

Acquisitions, Disposals and Other Transactions

Acquisitions and other transactions

In the year ended December 31, 2007, we acquired the following drilling units and entities involved in offshore drilling:

·	In January 2007, we took delivery of the new jack-up rig West Prospero from Keppel FELS Limited in Singapore for a total cost of $208 million and subsequently sold the unit to an affiliated company that is a subsidiary of Ship Finance, and leased the rig back.

·	In May 2007, we entered into an agreement with the Jurong Shipyard in Singapore for the construction of a new semi-submersible rig, West Orion, which we expect to be delivered in the second quarter of 2010 for a total cost of $675 million.

·	In June 2007, we entered into an agreement with Keppel FELS Limited in Singapore for the construction of a new tender rig, West Vencedor, which we expect to be delivered in the first quarter of 2010 for a total cost of $201 million.

·	In July 2007, we entered into a contract with the Samsung Shipyard in South Korea for the construction of a new drillship, West Gemini, which we expect to be delivered in the second quarter of 2010 for a total cost of $716 million.

·	In September 2007, we took delivery of the new jack-up rig West Atlas from Keppel FELS Limited in Singapore for a total cost of $155 million.

In September 2007, we established Seawell as a company providing drilling and well services. Our ownership interest in Seawell is currently approximately 73.8%. Seawell has entered into an agreement with the Norwegian Stock Broker Association, which provides an over-the-counter ("OTC") market for its shares.

In the year ended December 31, 2008, we acquired the following drilling units and entities involved in offshore drilling:

In the first quarter of 2008, the new semi-submersible rig West Phoenix was delivered from the Samsung Shipyard in South Korea and the new semi-submersible rig West Sirius was delivered from the Jurong Shipyard in Singapore, at total costs of $804 million and $561 million, respectively. Also in the first quarter of 2008, the new jack-up rig West Triton was delivered from the PPL Shipyard in Singapore at a total cost of $155 million.

In January 2008, Seawell acquired Noble Corporation's North Sea platform drilling division, a labor contract well services business, for an aggregate purchase price of $54 million. This purchase included labor contracts to service the drilling operations on 11 platforms in the UK sector of the North Sea.

·	In February 2008, we entered into a construction contract with Malaysia Marine and Heavy Engineering Sdn Bnd for the construction of a new tender rig T12, which we expect to be delivered in the first quarter of 2010 for a total cost of $123 million.

·	In February 2008, Seawell entered into an agreement for the construction of a new modular well service unit. The unit is expected to be delivered in the second half 2010 and will be primarily marketed for operations on platforms on the UK and Norwegian continental shelves.

·	In March 2008, we acquired all of the outstanding shares in Peak Well Solutions AS, a company which specializes in the production, manufacturing and installation of equipment for drilling rigs, for the aggregate purchase price of $85 million.

In April 2008, we announced that we had acquired beneficial ownership of 200,000 of the issued shares of Pride and had forward purchase contracts for a further 16,300,000 shares, totaling 9.5% of the issued share capital. Pride is one of the largest offshore drilling contractors listed on the NYSE. The aggregate purchase price of the investment in Pride was approximately $558 million. In August 2009, Pride spun off its mat-supported jack-up rigs into a new company, Seahawk Drilling Inc, which is listed on Nasdaq. In that connection we received a dividend in the form of shares in Seahawk Drilling Inc, corresponding to a 9.5% equity interest which we currently hold.

In April 2008, we acquired 8,100,000 shares of Scorpion Offshore Limited, or Scorpion, at a price of NOK80 per share, which increased our shareholding in Scorpion to 36% of Scorpion's outstanding shares, which is above the 33.3% threshold for making a mandatory tender offer for the remaining shares under the rules of the Oslo Stock Exchange. We conducted the mandatory tender offer at the offering price of NOK80 per share, which offer expired in June 2008. As a result of the tender offer, we registered acceptances for a further 1.1% of Scorpion's shares. As of January 20, 2010, we held a 39.6% equity interest in Scorpion, for which we paid an aggregate amount of $343 million. Scorpion is a drilling contractor listed on the Oslo Stock Exchange, with six recently completed newbuilding jack-up rigs and one additional newbuilding jack-up rig under construction. Under the Oslo Stock Exchange's mandatory offer rules, if we increase our equity interest in Scorpion to 40% or more, we will be required to make another tender offer for Scorpion's shares. Currently, we do not expect to trigger any further mandatory offerings or compulsory acquisitions. Please see "Subsequent Events" and "Summary of Oslo Stock Exchange Mandatory Offer Rules' below:

·	In May 2008, Seawell acquired Tecwel AS, a company which provides logging services to the oil industry worldwide, for an aggregate purchase price of $34 million.

In June 2008, we entered into agreements with Keppel FELS Limited in Singapore and the PPL Shipyard in Singapore for the construction of two new jack-up rigs each, all of which are scheduled for delivery in the second half of 2010. In January 2009 the terms of the agreements with the PPL Shipyard and Keppel FELS Limited were amended to include the option on our part not to take delivery of the second rig scheduled for delivery from each yard, while the PPL Shipyard had the option to terminate the construction contract for the second rig scheduled for delivery by them. In October 2009, the PPL Shipyard exercised its option to terminate the construction of one rig. The total cost of the three rigs currently remaining to be delivered is $658 million.

In June 2008, we entered into agreement with Keppel FELS Limited in Singapore for the construction of one new tender rig, West Berani III, with delivery expected in the first quarter of 2011 at a total cost of $119 million. Also in June 2008, we entered into agreement with the Jurong Shipyard in Singapore for the construction of one new semi-submersible drilling rig, West Capricorn, with delivery expected in fourth quarters of 2011 at a total cost of $771 million.

·	In the second quarter of 2008, we took delivery of the new tender rig T11 from Malaysia Marine and Heavy Engineering Sdn Bnd at a total cost of $96 million, and the new jack-up rig West Ariel from Keppel FELS Limited in Singapore at a total cost of $177 million.

·	In September 2008, following a series of transactions beginning in 2006, we acquired 22.7% of the total outstanding shares of SapuraCrest for a total purchase price of $124 million. SapuraCrest owns 51% of each of Varia Perdana and Tioman.

·	In the third quarter of 2008, we took delivery of the new drillship West Polaris from Samsung Heavy Industries in South Korea for a total cost of $695 million, and sold the unit to a subsidiary of Ship Finance, an affiliated company, and leased the rig back.

In the fourth quarter of 2008, we took delivery of the new semi-submersible rig West Hercules from the DSME Shipyard in South Korea and the new semi-submersible rig West Taurus from the Jurong Shipyard in Singapore, at total costs of $630 million and $531 million, respectively. These two rigs were sold to Ship Finance, an affiliated company, and leased back. Also in the fourth quarter of 2008, we took delivery of the new drillship West Capella from Samsung Heavy Industries in South Korea at a total cost of $640 million.

In the year ended December 31, 2009 we acquired the following drilling units and investments in entities involved in offshore drilling:

·	In the first quarter of 2009, we took delivery of the new semi-submersible rig West Aquarius from the DSME Shipyard in South Korea and the new semi-submersible rig West Eminence from the Samsung Shipyard in South Korea, at total costs of $630 million and $707 million, respectively.

In March 2009, we acquired an 81% interest in a bond issued by Petromena AS in the amount of NOK2.00 billion, at a cost of $183 million. The bond was secured by construction contracts for two new deepwater rigs scheduled for delivery later in 2009. Both rigs have subsequently been sold and as at December 31, 2009, we have received a partial repayment of the bond amounting to $101 million, including premium and accrued interest. Based on the achieved sales price of the rigs and the priority of the bonds, we expect to receive payments that equal 100% of the principal bond amount plus a 7% early redemption fee and accrued interests including penalty interests.

The total cost shown for the above drilling units consists of the accumulated historic cost paid to the shipyards, including amounts paid by entities prior to their acquisition by us. The cost shown includes capitalized interest and other ancillary costs.

Disposals

In February 2007, we sold our two FPSOs Crystal Ocean and Crystal Sea for $90 million and $80 million, respectively, recording gains totaling $124 million.

In July 2007, we entered into an agreement to sell the jack-up rig West Titania for a total consideration of $134 million. The jack-up rig was delivered to its new owner in the second quarter of 2008 and a gain on sale of $80 million was recorded.

In October 2007, we entered into an agreement to sell our entire holding of shares in Apexindo to third parties for a net consideration of approximately $220 million. The gain from the disposal was recorded in the first quarter of 2008 and amounted to approximately $150 million.

In July 2009, we exercised our option to repurchase the jack-up rig West Ceres from Rig Finance Ltd., a subsidiary of Ship Finance, an affiliated party, at the option price of $135.5 million. In July 2009, we sold the jack-up rig West Ceres to a third party for $175 million, recording a gain on sale of $21 million.

On November 30, 2009 our jack-up rig West Atlas was confirmed a constructive total loss following the damage caused by a blow-out and later fire on the Montara production platform in Australia where the rig was working for PTTEPA. The compensation from our insurers amounting to $200 million was received in December 2009. We have a contractual obligation to PTTEPA for removing the West Atlas wreck from the Montara field. Our insurance coverage provides for reimbursement of the costs related to such removal operations which are expected to be completed during 2010.

Subsequent Events

·	In the first quarter of 2010 we took delivery of the new tender rigs West Vencedor and T12 from the Keppel FELS shipyard in Singapore and Malaysia Marine and Heavy Engineering Sdn Bnd, at total costs of $209 million and $123 million, respectively.

In April 2010 we announced that we have acquired a purchase option from the Jurong shipyard in Singapore for a high specification, harsh environment jack-up rig of the CJ70 design. We have announced our intention to exercise this option and the rig is expected to be delivered in the first quarter of 2011 at an acquisition cost of $356 million, excluding capitalized interest and ancillary costs.

·	In April 2010 we took delivery of the new semi-submersible rig West Orion from the Jurong shipyard in Singapore. The rig will reported under newbuildings until it commences operations in Brazil in July 2010.

·	In April 2010, Seadrill Limited successfully completed a private placement of a total of 12.5 million shares, representing 3.1% of the issued capital, to a price of NOK151.50 per share. Gross proceeds amounted to NOK1,894 million (approximately US$322 million).

In April 2010 we acquired 1.3 million shares in Scorpion at a price of NOK36.00 per share, which increased our shareholding from 38.6% to 40.0%. The acquisition triggered an obligation on us to make a mandatory cash offer for Scorpion's remaining shares or to reduce our shareholding below 40%. We have announced that we will make a mandatory cash offer for the remaining shares in Scorpion. Please see "Summary of Oslo Stock Exchange Mandatory Offer Rules" below:

·	On April 30, 2010, the Company received a partial payment of the Petromena bond amounting to $165 million.

Summary of Oslo Stock Exchange Mandatory Offer Rules

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

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

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

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

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. 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 region, 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 400 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 rig. The modularized drilling package is lifted from the unit onto the platform prior to commencement of operations. The tender rig contains living quarters, helicopter deck, storage for drilling supplies, power machinery for running the drilling equipment and well completion equipment. There are two types of tender rigs, barge type and semi-submersible (semi-tender) type. Tender barges and semi-tenders are equipped with similar equipment but the semi-tender's semi-submersible hull structure allows the unit to operate in rougher weather conditions. Self-erecting tender rigs allow for drilling operations to be performed from platforms without the need for permanently installed drilling packages. Self-erecting tender rigs generally operate with crews of 60 to 85 people.

Seawell Limited

In addition to owning and operating offshore drilling units, we provide well services through Seawell, our majority owned subsidiary. Seawell provides platform drilling, facility engineering, modular rig, well intervention and oilfield technologies. Seawell currently operates on nearly 50 installations in the North Sea and has offices in Stavanger and Bergen in Norway, Aberdeen and Newcastle in the United Kingdom, Houston in the United States, Esbjerg in Denmark, Rio de Janeiro in Brazil and Kuala Lumpur in Malaysia.

We report our business in the following three operating segments:

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

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

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

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

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 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 dayrates. We have grown our company significantly since its incorporation in 2005 and have strong ambitions to continue the 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;

	·	develop our strong position in the tender rig market and pursue further growth in conventional waters as well as deepwater areas; and
	·	offer a diversified range of well services.

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

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 and ultra-deepwater areas, not only in existing offshore regions such as Brazil, U.S. Gulf of Mexico, Europe and West Africa but also expanding to India, Southeast Asia, China, East Africa, Mexican Gulf of Mexico, Australasia and the Mediterranean.

Mobile units

Developments in the oil and gas industry discussed above have caused a strong increase in demand for offshore drilling services, resulting in materially increased dayrates for drilling units.

For dynamically positioned deepwater units, dayrates increased from $290,000 in May 2005 at the inception of our Company to more than $600,000 in September 2008 just prior to the financial downturn in world markets. The increase in dayrates made it attractive for existing drilling contractors as well as new market participants to order new units to meet mounting demand. As a result, the worldwide fleet of dynamically positioned deepwater drilling units is expected to increase from 29 units in 2005 to 134 units in 2013, if all of the new units ordered between 2005 and 2008 are delivered. Most of these newbuildings were ordered on speculation, meaning that no drilling contract in place at the time the construction contract was entered into. As a result of favorable market developments, the majority of these units have secured term contracts on attractive terms. However, due to the sudden and immediate deterioration of overall market conditions in October 2008, there remain a significant number of units under construction that have not yet secured employment. Although the majority of these units will not be delivered before the end of 2010 or later, some of the owners of these units have limited or no operating experience in deepwater drilling, and there is a risk that they could be willing to accept contract conditions that deviate from prevailing market terms, in order to secure employment for their units and the financing necessary to take delivery of their newbuilds. This could adversely affect dayrates for deepwater drilling units in the short-term. Since October 2008, the number of new contracts entered into for dynamically positioned deepwater units has been limited. The most recent fixture was reported at approximately $450,000 per day. However, dayrate levels are typically dependant on country of operation, length of contract and overall contract terms

Since 2005 we have taken delivery of nine dynamically positioned ultra-deepwater units and have a further two ultra-deepwater units under construction. We believe the long-term prospects for deepwater drilling are positive given the expected growth in oil consumption from developing nations, limited or negative growth in oil reserves, and high depletion rates 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, US Gulf of Mexico, West Africa and elsewhere, along with improving access to promising offshore areas and new, more efficient technologies.

For jack-up rigs, dayrates increased from $90,000 from May 2005 to more than $200,000 per day in September 2008 as a consequence of a significant undersupply of available jack-ups in a period when oil and gas prices were increasing rapidly, thereby making extremely lucrative the drilling of new and previous oil and gas discoveries with a tie-back to the existing infrastructure. In response to this development, approximately 145 new jack-ups have been ordered bringing the total worldwide fleet of jack-ups up to 519, assuming all the ordered units are delivered. The majority of these newbuildings were ordered on speculation and the majority of the 61 jack-up rigs remaining to be delivered have at present not secured initial employment. In a period of considerable uncertainty relating to the development of the world economy and the direction of oil and gas prices, this could intensify price competition as scheduled delivery dates come closer, possibly impacting adversely on dayrates for jack-up rigs. Since October 2008, the utilization rate has been significantly reduced for the jack-up fleet bringing dayrates down sharply as well. As of April 2010, we believe market dayrates for new jack-up rigs are approximately $120,000 per day, depending on country of operation, length of contract and overall contract terms, and below $100,000 per day for older jack-up rigs. We believe that the industry will require more modern and more effective jack-ups, as approximately 70% of the current worldwide jack-up fleet is more than 20 years old. We expect operators to gradually replace older and incumbent drilling units with new, more modern and efficient rigs due to wells becoming increasingly technically challenging and consequently demanding with respect to rig equipment. This replacement could however take longer than previously anticipated, given the uncertainty surrounding the global economy.

Tender rigs

From May 2005 to September 2008 dayrates increased for barge-type tender rigs from $45,000 to $130,000 and for semi-submersible tender rigs from $70,000 to more than $200,000. The increase was due to a significant undersupply of available tender rigs and reduced competition from jack-ups due to the overall increase in offshore drilling activity. The tender rig market is a specialized niche, with the world fleet consisting of 29 units, including four units under construction. We are the largest operator in this segment with our fleet of 17 units, including the five units we operate in association with Varia Perdana and the unit we have under construction. Tender rigs are primarily used for development drilling based on term contracts, and this has historically made this market segment more resilient to the volatility in activity levels seen in the shallow water market and experienced by benign environment jack-ups. Nevertheless, the sharp drop in shallow water activity in 2008 and 2009 had an adverse impact on the tender rig market. The short-term effect is that tender rigs that have come off contracts since October 2008 have been warm stacked, as oil companies have postponed drilling activity in response to lower oil and gas prices. Accordingly, there were no tender rig fixtures in 2009. The most recent fixture in 2010 was at approximately $90,000 per day. We believe the market uncertainty is diminishing in response to more stable oil prices, and the long-term outlook for

tender rigs remains favorable, due to their versatility and lower construction costs compared to jack-up rigs. In addition, in recent years a combination of tender rigs and floating platforms, such as mini tension-leg platforms and spar platforms has been used in the development of deepwater oilfields, which has increased the market for tender rigs. Based on this we expect the market to continue to offer opportunities to build additional order backlog and earnings visibility.

Well services

Seawell is mainly involved in oil production activities in existing mature fields. The level of activity is therefore related to the development and level of the oil price. We believe that when oil prices are above $70 per barrel, oil companies will focus on maintaining their production from mature fields. Based on current market conditions, demand for drilling and well services is expected to remain high over the next few years. However, the activity level in 2010 will depend on the outcome of ongoing tendering activities, employment of the modular rig we have under construction, and our success in expanding our main products and services into new regions. We have also in response to the oil price developments in 2008 and the beginning of 2009 experienced pressure on pricing from our customers. This has resulted in lower contract rates, which in turn has causes us to emphasize our focus on cost control and utilization of synergies in order to maintain and grow profit levels.

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.

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, 2009 our five largest customers have been:

	-	Statoil ASA, or Statoil, accounting for approximately 17% of revenues;
	-	Total S.A. Group, or Total, accounting for approximately 13% of revenues;
	-	Exxon Mobil Corp, or Exxon, accounting for approximately 12% of revenues;
	-	Royal Dutch Shell, or Shell, accounting for approximately 10% of revenues; and
	-	Petròleo Brasileiro S.A., or Petrobras, accounting for approximately 10% of revenues.

No other customers have accounted for more than ten percent of our revenues in any period since inception. In the year ended December 31, 2008, our two largest customers were Statoil and Shell, who provided approximately 32% and 7% of our contract revenues, respectively. Statoil and Shell were also our largest customers in the year ended December 31, 2007, providing approximately 33% and 13% of our contract revenues, respectively. The loss of any of these significant customers could have a material adverse effect on our results of operations if they were not replaced by other customers.

Most of our drilling units are contracted to customers for periods between one and five years ahead, and our forward contracted revenue, or backlog, at December 31, 2009 totaled approximately $10.4 billion, with $8.6 billion of this amount attributable to our semi-submersible rigs and drillships. We expect approximately $3.1 billion of this backlog to be realized in 2010. Backlog for our drilling fleet is calculated as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization and demobilization, contract preparation and customer reimbursables. The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the backlog projections due to various factors. Downtime, caused by unscheduled repairs, maintenance, weather and other operating factors, may result in lower applicable dayrates than the full contractual operating dayrate.

The following table shows the percentage of rig days committed by year as of December 31 2009. The percentage of rig days committed is calculated as the ratio of total days committed under firm contracts to total available days in the period. Total available days for our units under construction are based on their expected delivery dates.

	Year ending December 31,
% of rig-days committed	2010			2011			2012

Jack-up rigs		62	%		7	%		0	%
Semi-submersible rigs		100	%		94	%		55	%
Drillships		88	%		75	%		70	%
Tender rigs		84	%		69	%		40	%

Competition

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

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

Offshore drilling contracts are generally awarded on a competitive bid basis. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability and sustainability, rig location, condition of equipment, operating integrity, safety performance record, crew experience, reputation, industry standing and client relations.

Competition for offshore drilling rigs is generally on a global basis, as rigs are highly mobile. However, the cost associated with mobilizing rigs between regions is sometimes substantial, as entering a new region could necessitate upgrades of the unit and its equipment to specific regional requirements. In particular, for rigs to operate in harsh environments, such as offshore Norway and Canada, as opposed to benign environments, such as the Gulf of Mexico, West Africa, Brazil, the Mediterranean and Southeast Asia, more demanding weather conditions would require more costly investment in the outfitting and maintenance of the drilling units.

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

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, liability due to control-of-well events and loss of hire insurance.

We maintain a portion of deductibles for damage to our offshore drilling equipment. With respect to hull and machinery, we currently have a deductible per occurrence of up to $1.7 million. However, a total loss or a constructive total loss of a drilling unit is covered by our insurance with no deductible. For general and marine third-party liabilities we generally maintain a deductible of up to $250,000 per occurrence on personal injury liability for crew claims, non-crew claims and third-party property damage. Furthermore, we purchase insurance to cover the loss of hire on our fleet due to physical damage. However, we have a deductible period up to 60 days after the occurrence of physical damage. Thereafter our insurance policies are limited to between 100 days and 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.

Environmental and Other Regulations in the Offshore Drilling Industry

Our offshore drilling operations include activities that are subject to numerous international, federal, state and local laws and regulations, including the International Convention for the Prevention of Pollution from Ships, or MARPOL, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or Bunker Convention, the U.S. Oil Pollution Act, or OPA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Outer Continental Shelf Lands Act, and Brazil's National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Law 9966/2000 relating to pollution in Brazilian waters. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection. In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part.

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

Our drilling units are subject not only to MARPOL regulation of air emissions, but also to the Bunker Convention's strict liability for pollution damage caused by discharges of bunker fuel in ratifying states. We believe that all of our drilling units are currently compliant in all material respects with these regulations. In October 2008, IMO's Maritime Environment Protection Committee, or MEPC, adopted

amendments to the Annex VI regulations that will 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.

Furthermore, any drillships we may operate in the waters of the U.S., including the U.S. territorial sea and the 200 nautical mile exclusive economic zone around the U.S., would have to comply with OPA and CERCLA regulations, as described above, that impose 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 Minerals Management Service of the U.S. Department of the Interior ("MMS") periodically issues guidelines for jack-up rig fitness requirements in the U.S. Gulf of Mexico and may take other steps that could increase the cost of operations or reduce the area of operations for our jack-up rigs, thus reducing their marketability. Implementation of MMS 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. Gulf of Mexico could be restricted by government regulation" in Item 3.D of this Annual Report.

Numerous governmental agencies issue such 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 could adversely affect our financial results. While we believe that we are in substantial compliance with the current laws and regulations, there is no assurance that compliance can be maintained in the future.

In addition to the MARPOL, OPA, and CERCLA requirements described above, our international operations in the offshore drilling segment are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the importation 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. A discussion of risks relating to environmental regulations can be found in Item 3.D "Risk Factors" of this Annual Report.

C. ORGANIZATIONAL STRUCTURE

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

Overall responsibility for the management of Seadrill Limited and its subsidiaries rests with the Board of Directors. The Board has organized the provision of management services through two subsidiaries incorporated in Norway, Seadrill Management AS, or Seadrill Management, and Seawell Management AS, or Seawell Management. The Board has defined the scope and terms of the services to be provided by these two companies and has provided authority for them 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 and/or Seawell Management to act on the Company's behalf.

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

D. PROPERTY, PLANT AND EQUIPMENT

We own a substantially modern fleet of drilling units. The following table sets forth the units that we own or have contracted for delivery as of April 26, 2010:

	Year	Water depth	Drilling depth	Current location	Month of
Unit	built	(feet)	(feet)		contract expiry

Jack-up rigs
West Larissa	1984	300	21,000	Vietnam	December 2010
West Janus	1985	330	21,000	Malaysia	August 2011
West Epsilon	1993	400	30,000	Norway	January 2015
West Prospero(SF)	2007	400	30,000	Red Sea	July 2010
West Triton	2008	375	30,000	South East Asia	September 2010
West Ariel	2008	400	30,000	Vietnam	October 2010
West Callisto (NB)	2010	400	30,000		April 2011
West Juno (NB)	2010	400	30,000
West Leda (NB)	2010	375	30,000		November 2010
CJ70 (NB)(1)	2011	450	40,000		August 2016

Tender rigs
T4	1981	410	20,000	Thailand	July 2013
T8	1982	410	20,000	Malaysia (warm stacked *)
T7	1983	410	20,000	Thailand	October 2011
West Pelaut	1994	6,500	30,000	Brunei	March 2012
West Menang	1999	6,500	30,000	Namibia (warm stacked *)	December 2010
West Alliance	2001	6,500	30,000	Malaysia	January 2015
West Setia	2005	6,500	30,000	Angola	August 2012
West Berani	2006	6,500	30,000	Indonesia	December 2011
T11	2008	6,500	30,000	Thailand	May 2013
T12	2010	6,500	30,000	Thailand	April 2011
West Vencedor	2010	6,500	30,000	Angola	April 2015
West Jaya (NB)	2011	6,500	30,000

Semi-submersible rigs
West Alpha	1986	2,000	23,000	Norway	June 2012
West Venture	2000	6,000	30,000	Norway	August 2015
West Phoenix	2008	10,000	30,000	Norway	January 2012
West Hercules (SF)	2008	10,000	35,000	China	November 2011
West Sirius	2008	10,000	35,000	Gulf of Mexico	July 2014
West Taurus (SF)	2008	10,000	35,000	Brazil	February 2015
West Eminence	2009	10,000	30,000	Brazil	July 2015
West Aquarius	2009	10,000	35,000	Indonesia	February 2013
West Orion (NB)	2010	10,000	35,000	In transit to Brazil	July 2016
West Capricorn (NB)	2011	10,000	35,000

Drillships
West Navigator	2000	7,500	35,000	Norway	December 2012
West Polaris (SF)	2008	10,000	35,000	Brazil	October 2012
West Capella	2008	10,000	35,000	Nigeria	April 2014
West Gemini (NB)	2010	10,000	35,000		September 2012

NB – Newbuilding.

SF – Unit owned by subsidiary of Ship Finance (see Note 33 to Consolidated Financial Statements).

(1) – We have an option to purchase this jack-up rig and have announced that we intend to exercise that option.

* - Warm stacked means that the unit is not operating, but is being maintained in a state of readiness for future operations.

In addition to the drilling units listed above, as at December 31, 2009 we have buildings, plant and equipment with a net book value of $115 million, including an office building in Bergen, a modular rig under construction for Seawell, and office equipment. Our offices in Stavanger in Norway, Singapore, Houston in the United States, Rio de Janeiro in Brazil and Aberdeen in the United Kingdom are leased and aggregate office rental costs were $13.7 million in 2009, and are expected to be approximately $20.0 million in 2010.

We do not have any material intellectual property rights

ITEM 4A. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

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

Overview

We were established in May 2005 with an operating fleet of five units. Since then, through investment in newbuildings and the acquisition of other companies, we have expanded our operations and now have approximately 7,600 skilled employees and an operating fleet of 28 drilling units. In addition, we have construction contracts for eight new units, including an option to purchase a jack-up rig which we intend to exercise, and we operate a further five units in association with Varia Perdana. A full fleet list is provided in Item 4.D "Information on the Company – Property, Plant and Equipment".

In addition to owning and operating offshore drilling units, we provide drilling and well services through Seawell, our majority owned subsidiary.

We have also made investments in other companies that are viewed as strategic investments, including Pride (9.4%), SapuraCrest (23.6%), Varia Perdana (49%) and Scorpion (40.0%). In compliance with the rules of the Oslo Stock Exchange, we have announced that we will make a mandatory cash offer for the remaining shares in Scorpion.

Fleet Development

The following table summarizes the development of our active fleet of drilling units, based on the dates when the units began operations:

Unit type	Mobile units segment				Tender rigs	Total units
Unit type	FPSOs	Jack-up rigs	Drillships	Semi-submersible rigs	Tender rigs	Total units
At December 31, 2005	2	3	-	-	-	5
additions in 2006		+2	+1	+2	+7	+12
At December 31, 2006	2	5	1	2	7	17
additions in 2007		+2			+1	+3
disposals in 2007	-2					-2
At December 31, 2007	-	7	1	2	8	18
additions in 2008		+2	+1	+2	+1	+6
disposals in 2008		-1				-1
At December 31, 2008	-	8	2	4	9	23
additions in 2009			+1	+4		+5
disposals in 2009		-2				-2
At December 31, 2009	-	6	3	8	9	26

The following rigs under construction are scheduled to be delivered after December 31, 2009:

In 2010: three jack-up rigs, two tender rigs, one semi-submersible rig and one drillship.

In 2011: one tender rig, one semi-submersible rig and one jack-up rig.

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 operating availability of our drilling units;

the daily operating revenues earned under our term contracts;

the daily operating expenses of our drilling units;

administrative expenses;

interest and other financial items; and

tax expenses.

Revenues

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

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

The terms and conditions of the contracts allow for compensation when factors influencing the drilling operation are outside our control, for example, weather, and also 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 day-rate 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 supplies, personnel and other services.

The following table summarizes our average daily revenues and economic utilization percentage by rig type for the periods under review:

	Year ended December 31,
	2009				2008				2007
	Average daily revenues		Economic utilization		Average daily revenues		Economic utilization		Average daily revenues		Economic utilization
	$			%	$			%	$			%
Jack-up rigs		130,000		70		196,000		92		172,000		85
Semi-submersible rigs		445,000		92		345,000		93		247,000		99
Drillships		497,000		94		251,000		66		206,000		83
Tender rigs		115,000		93		95,000		98		78,000		99

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 in operation 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 for 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 swaps and other derivative financial instruments.

Tax expenses reflect payable and deferred tax related to our rig owning and operating activities and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the tax is based on net income or deemed income based on 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 under the circumstances. Our critical accounting estimates are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. Significant accounting policies are discussed in our Notes to Consolidated Financial Statements – Note 2: Accounting policies. We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimation.

Drilling Units

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

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

We determine the carrying value of these assets based on policies that incorporate our estimates, assumptions and judgments relative to the carrying value, remaining useful lives and residual values. The assumptions and judgments we use in determining the estimated useful lives of our drilling units reflect both historical experience and expectations regarding future operations, utilization and performance. The use of different estimates, assumptions and judgments in establishing estimated useful lives would probably 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 evaluate the remaining useful lives of our drilling units 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 dayrates for the estimated remaining useful lives of the asset or group of assets being assessed. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not recoverable. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect management's assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets and could materially affect our results of operations.

Income Taxes

We are a Bermuda company and currently we are not required to pay taxes in Bermuda on ordinary income or capital gains. We have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 2016. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. The income tax rates and methods of computing taxable income vary substantially between jurisdictions. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates.

The determination and evaluation of our annual group income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events, such as the amount, timing and character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are sustainable and on estimates of taxes that will ultimately be due. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as returns are filed, or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as

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

Contingencies

We establish reserves for estimated loss contingencies when we believe a loss is probable and the amount of the loss can be reasonably estimated. Our contingent liability reserves relate primarily to litigation, indemnities and potential income and other tax assessments (see also "Income Taxes" above). Revisions to contingent liability 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 contingent liabilities 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. We perform an annual test of goodwill impairment 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 dayrates during the contract periods. For periods after expiry of the contract periods, dayrates are projected based on estimates regarding future market conditions, including zero escalation of dayrates. The estimated future cash flows are calculated based on remaining asset lives and are discounted using a weighted average cost of capital. We had no impairment of goodwill for the years ended December 31, 2009, 2008 and 2007, as the net present value of the estimated future cash flows supports the book value of goodwill. 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.

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 postretirement 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 estimates and assumptions could result in materially different carrying value pension obligations and could materially affect our results of operations.

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

Impairment of marketable securities and equity method investees

We analyze our available-for-sale securities and equity method investees for impairment during each reporting period to evaluate whether an event or change in circumstances has occurred in that period which may have a significant adverse effect on the fair value of the investment. We record an impairment charge for other-than-temporary declines in fair value when the fair value is not anticipated to recover above cost within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in fair value are not reflected in earnings until sale of the securities held as available for sale or of the equity method investee are sold. The evaluation of whether a decline in fair value is other-than-temporary requires a high degree of judgment and the use of different assumptions could materially affect our results of operations.

Recent accounting pronouncements

In December 2007, the Financial Accounting Standards Board ('FASB') issued Statements No. 141(R), Business Combinations, ("FAS 141(R)", (codified in ASC 805), and No. 160 Noncontrolling Interests in Consolidated Financial Statements, ("FAS 160"), (codified in ASC 810). Together these statements can affect the way companies account for future business combinations and noncontrolling interests. ASC 805 requires, amongst other changes, recognition of subsequent changes in the fair value of contingent consideration in the Statement of Operations rather than against Goodwill, and transaction costs to be recognized immediately in the Statement of Operations. ASC 810-10-65-1 clarifies the classification of noncontrolling interests in consolidated balance sheets and the accounting for and reporting of transactions between the reporting entity and holders of such noncontrolling interests. In particular the noncontrolling interest in subsidiaries should be presented in the consolidated balance sheet within equity, but separate from the parent's equity. Similarly the amount of net income attributable to the parent and to the minority interest be clearly identified and presented on the consolidated statement of income. Both these Statements are effective for transactions completed in fiscal years beginning after December 15, 2008. Adoption of these Statements by the Company in the financial statements beginning January 1, 2009 did not have a material effect on the Company's consolidated financial statements except that noncontrolling interests is classified as a component of equity.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1 (codified in ASC 825), Guidance on Interim Fair Value Disclosures, which expands the fair value disclosures required for all financial instruments within the scope of this topic to interim periods for publicly traded entities. Entities must disclose the method(s) and significant assumptions used to estimate the fair value of financial instruments in financial statements on an interim basis and to highlight any changes in the methods and significant assumptions from prior periods. The guidance is effective for interim and annual periods ending after June 15, 2009 and adoption of this FSP did not have a material effect on our consolidated financial statements.

In April 2009, the FASB issued FSP FAS 115-2 (codified in ASC 320) which provides additional guidance to highlight and expand on the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for a financial asset. The guidance is effective for interim and annual periods ending after June 15, 2009. Adoption of this FSP did not have a material effect t on our consolidated financial statements.

In May 2009, the FASB issued Statement No. 165 Subsequent Events, ('FAS 165'), (codified in ASC 855). This Statement provides guidance on management's assessment of subsequent events. The guidance clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date "through the date that the financial statements are issued or are available to be issued." Management must perform its assessment for both interim and annual financial reporting periods. The new guidance is effective prospectively for interim and annual periods ending after June 15, 2009. Adoption of the Statement did not have a material effect on the Company's consolidated financial statements. In February 2010 the FASB amended the subsequent events guidance issued in May 2009 to remove the requirement for SEC filers to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. The amendment is effective upon issuance. The adoption of this guidance did not have a material effect on our consolidated financial condition or results of operations.

In June 2009, the FASB issued Statement No. 168, Statement on Codification and Hierarchy of Generally Accepted Accounting Principles, ('FAS 168'), (codified in ASC 105). The standard is a replacement for FAS 162. The GAAP hierarchy will be modified to include only two levels of GAAP; authoritative and non-authoritative. The standard is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of this Standard did not have a material effect on the Company's consolidated financial statements.

In June 2009, the FASB issued Statement No. 167, Amendments to FASB Interpretation No. 46(R) (FAS 167) (codified in ASC 810). The amended guidance requires companies to qualitatively assess the determination of the primary beneficiary of a variable-interest entities ("VIEs") based on whether the entity (1) has the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. It also requires additional disclosures for any enterprise that holds a variable interest in a VIE. The new accounting and disclosure requirements become effective for the Company from January 1, 2010. The Company is currently assessing the impact of this amendment on its consolidated financial statements.

In January 2010, the FASB issued ASC 820 Improving Disclosures about Fair Value Measurements. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Company is currently assessing the impact of this amendment on its consolidated financial statements.

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 limit contract opportunities in the short term. Such adverse weather could include the hurricane season for our operations in the Gulf of Mexico, the winter season in offshore Norway, and the monsoon season in Southeast Asia.

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 profitability in the current and foreseeable economic environment, although it will have a moderate effect on operating and administration costs.

A. RESULTS OF OPERATIONS

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

The following table sets forth the Company's operating results for 2009 and 2008.

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

Total operating revenues

In US $millions	2009	2008	Increase

Mobile units	2,251	1,144	+97	%
Tender rigs	392	342	+15	%
Well services	610	620	-2	%
Total operating revenues	3,253	2,106	+54	%

Total operating revenues increased from $2.11 billion in 2008 to $3.25 billion in 2009. Total operating revenues are predominantly contract revenues with additional, relatively small amounts of reimbursables and other revenue.

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

In the tender rig operating segment, operating revenues increased by 15% from 2008 to 2009. The increase was mainly related to increased dayrates, which increased by approximately $20,000 per day to an average of $115,000 per day in 2009. The delivery of the

tender rig T11, which began operations in the second quarter of 2008, also contributed to the increase. These dayrate increases were partly offset by a decline in economic utilization from 98% in 2008 to 93% in 2009.

Total operating revenues for well services decreased from $620 million in 2008 to $610 million in 2009. A significant portion of well services activity takes place in Norway and operating revenues in Norwegian Kroner increased from NOK2.6 billion in 2008 to NOK2.8 billion in 2009. The Norwegian content represented approximately 73 percent of total revenues and revenues are generally fairly stable.

Gain on sale of assets

In 2009 there were gains on the disposals of the jack-up rigs West Ceres ($21 million) and West Atlas ($58 million), the former being sold and the latter being a total insured loss following a fire. Also in 2009 there was a $4 million gain on the sale of our interest in the Chestnut field and a loss of $12 million due to the PPL shipyard exercising its purchase option on the jack-up rig West Elara. In 2008, the jack-up rig West Titania was sold and a gain of $80 million was recorded. All of these units were in the mobile units operating segment.

Total operating expenses

In US$ millions	2009		2008		Increase

Mobile units		1,181		756		+56	%
Tender rigs		219		216		+1	%
Well services		552		565		-2	%
Total operating expenses		1,952		1,537		+27	%

Total operating expenses increased from $1.54 billion in 2008 to $1.95 billion in 2009, with the increase mainly in the mobile units segment. Total operating expenses consist of rig operating expenses, depreciation, reimbursable expenses and general and administrative expenses. Total general and administrative expenses increased to $149 million in 2009 compared to $126 million in of 2008. Reimbursable expenses in each segment were closely in line with reimbursable revenues.

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

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

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

Interest expense

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

Other financial items

In US$ millions	2009			2008			Change

Interest income		78			31			+152	%
Share in results of associated companies		92			15			+513	%
Gain on sale of associated companies		-			150			n/a
Impairment loss on marketable securities and investments in associated companies		-			(615	)		n/a
Gain / (loss) on derivative financial instruments		130			(353	)		n/a
Foreign exchange gain (loss)		(25	)		131			n/a
Other financial items		54			22			+145	%
Total other financial items		329			(619	)		n/a	%

n/a – percentage change has not been calculated as it is not considered to be meaningful due to one off or exceptional items.

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

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

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

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

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

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

Income taxes

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

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

Fiscal Year Ended December 31, 2008, compared to Fiscal Year Ended December 31, 2007.

The following table sets forth the Company's operating results for 2008 and 2007:

	Year ended December 31, 2008									Year ended December 31, 2007
In US $millions	Mobile units		Tender rigs		Well services		Total			Mobile units		Tender rigs		Well services		Total
Total operating revenues		1,144		342		620		2,106			837		266		449		1,552
Gain on sale of assets		80		-		-		80			124		-		-		124
Total operating expenses		756		216		565		1,537			612		169		406		1,187
Operating income		468		126		55		649			349		97		43		489
Interest expense								(130	)								(113	)
Other financial items								(619	)								11
Income before taxes								(100	)								387
Income taxes								(48	)								78
Gain on issuance of shares by subsidiary								25									50
Net income								(123	)								515

Total operating revenues

In US $millions	2008		2007		Increase

Mobile units		1,144		837		+37	%
Tender rigs		342		266		+29	%
Well services		620		449		+38	%
Total operating revenues		2,106		1,552		+36	%

Total operating revenues increased from $1.55 billion in 2007 to $2.11 billion in 2008, with increases in all three operating segments.

Total operating revenues in the mobile unit segment increased by $307 million to $1.14 billion in 2008. The number of drilling units in the mobile units segment increased from 10 at December 31, 2007 to 14 at December 31, 2008. Two new semi-submersible rigs were delivered and started operation during the year (West Sirius and West Hercules) along with one ultra-deepwater drillship (West Polaris) and two jack-up rigs (West Triton and West Ariel). The jack-up rig West Titania was sold. Although these units were delivered over the course of the year and some did not contribute fully to operating revenues during the year, the additional revenue generated by the new units, net of the rig sold, amounted to $208 million. The economic utilization of the mobile units fleet increased overall from 86% in 2007 to 88% in 2008. Average dayrates were also higher in 2008, although in the latter part of the year the jack-up rig market weakened to some extent, resulting in lower dayrates as well as periods with idle units.

In the tender rig operating segment, operating revenues increased from $266 million in 2007 to $342 million in 2008. The increase was partly due to the delivery of the newbuilding tender rig T11, which began operations in the second quarter of 2008 and contributed $29 million in revenue. In addition, average dayrates for the tender rig fleet were higher in 2008, although economic utilization declined from 100% in 2007 to 98% in 2008.

Total operating revenues for well services increased from $449 million (NOK 2,728 million) in 2007 to $620 million (NOK3,625 million) in 2008, mainly as a result of higher activity levels in continuing operations and significant contributions from businesses acquired in the year.

Gain on sale of assets

A gain on sale of assets of $80 million was recorded in 2008, arising from the sale of the jack-up rig West Titania. In 2007, a $124 million gain on sale of assets resulted from the sale of the two FPSO's Crystal Ocean and Crystal Sea. These three units were all in the mobile units operating segment.

Total operating expenses

In US$ millions	2008		2007		Increase

Mobile units		756		612		+24	%
Tender rigs		216		169		+28	%
Well services		565		406		+39	%
Total operating expenses		1,537		1,187		+29	%

Total operating expenses increased from $1.19 billion in 2007 to $1.54 billion in 2008, with increases in all three operating segments. Total operating expenses consist of rig operating expenses, depreciation, reimbursable expenses and general and administration expenses. Total general and administration expenses increased to $127 million in 2008 compared with $110 million in 2007. Reimbursable expenses in each segment were closely in line with reimbursable revenues.

Total operating expenses in the mobile units segment increased from $612 million in 2007 to $756 million in 2008. Vessel and rig operating expenses increased by $86 million in the same period mainly reflecting the expenses of the new units that came into operation during the 2008 period. Reimbursable expenses are at the same level on a year to year comparison and the margin is in the range of 5% to 10%. Depreciation and amortization increased from $135 million in 2007 to $173 million in 2008. Of the increase of $38 million, $25 million was related to our newbuildings delivered in 2008, while the majority of the remaining $13 million was related to newbuildings delivered during 2007 for which we have expensed a full year of depreciation in 2008 compared to only part of the year in 2007. General and administrative expenses for the mobile units segment increased from $73 million in 2007 to $92 million in 2008. The increase is related to an increase in geographical operations which require larger onshore support.

Total operating expenses for the tender rig segment increased from $169 million in 2007 to $216 million in 2008. Vessel and rig operating expenses increased in the same period from $101 million to $134 million. The increase of $33 million is primarily related to the new unit

T11, which commenced drilling operations in the second quarter of 2008. Depreciation and amortization amounted to 42 million in 2008, an increase of $3 million compared to the preceding year. The increase is related to the delivery of T11.

Total operating expenses for the well services division increased from $286 million in 2007 to $425 million in 2008. The increase is related to a corresponding increase in operating revenues. Depreciation and amortization increased from $9 million in 2007 to $19 million in 2008. Well Services has been involved in several acquisitions during 2008. The acquired companies have owned a significant amount of fixed assets that are depreciated based on a straight line basis, which has contributed to the increase.

Interest expense

Interest expense increased from $113 million in 2007 to $130 million in 2008 as a result of the increase in interest bearing debt used to finance new drilling units and acquisitions, partly offset by the 1.8% reduction in the weighted average interest rate payable in the year. In addition to the interest expense, interest costs incurred during the construction of newbuildings are capitalized, and capitalized interest amounted to $153 million in 2008 compared with $134 million in 2007.

Other financial items

In US$millions	2008			2007			Change

Interest income		31			24			+29	%
Share in results of associated companies		15			23			-35	%
Gain on sale of associated companies		150			-			n/a
Impairment loss on marketable securities and investments in associated companies		(615	)		-			n/a
Gain / (loss) on derivative financial instruments		(353	)		7			n/a
Foreign exchange gain (loss)		131			(53	)		n/a
Other financial items		22			10			+120	%
Total other financial items		(619	)		11			n/a.

n/a – percentage change has not been calculated as it is not considered to be meaningful due to one off or exceptional items

Interest income increased in 2008 as a result of increased levels of cash on deposit, consisting mainly of restricted cash.

The share in results of associated companies declined in 2008 due to the disposal during the year of our interest in Apexindo and the liquidation of Lisme AS, a Norwegian holding company in which we had a 44% interest, in 2007. The sale of shares in Apexindo resulted in a gain on disposal of $150 million.

At December 31, 2008, we beneficially owned shares, including share purchase agreements, in Pride, Scorpion and SapuraCrest. At December 31, 2008, we determined that the fair value of these investments was below their carrying value and that there was little prospect for a recovery in values in 2009. Accordingly, in 2008 we recognized an impairment charge of $615 million relating to these investments.

We have entered into interest rate swaps, forward exchange contracts and total return swap agreements, or TRS, none of which is accounted for as hedge accounting. Most of these arrangements were established in 2008 and the fair value of these derivative financial instruments at December 31, 2008 is reflected in the consolidated financial statements, resulting in fair value losses totaling $353 million. Of this total, $177 million arises from mark-to-market adjustments on our interest rate swaps (notional principal $1.78 billion at December 31, 2008) and $117 million from mark-to-market adjustments on our forward exchange contracts (forward sales of $0.47 billion at December 31, 2008). The remaining $59 million loss relates to a TRS agreement indexed to the market price of 4,500,000 of our common shares.

The foreign exchange gain in 2008 mainly results from debt denominated in Norwegian Kroner and the weakening of the Norwegian Kroner against the U.S. Dollar.

Other financial items consist of gains on the sale of marketable securities.

Income taxes

Income taxes amounted to a net cost of $48 million in 2008. In 2007, income taxes amounted to a net income of $78 million, mainly as a result of the restructuring of several rig-owning companies, which resulted in a non-recurring tax benefit of $75 million. For 2008, restructuring of rig ownership resulted in a non-recurring tax benefit of $43 million compared to a benefit of $75 million realized in 2007. The change in the Company's effective tax rate from a benefit of approximately 20.2% in 2007 to a cost of approximately 48.5% in 2008 was principally due to a higher portion of our income being generated in taxable jurisdictions in 2008, a smaller benefit arising from the

restructuring of the Company's rig-assets, and the nondeductible impairment loss on marketable securities which offset the nontaxable gain on the disposal of Apexindo shares earlier in the year. Impairment losses on marketable securities and gains and losses on the sales of shares in associated companies are reported in nontaxable jurisdictions. The Company's recent start up of jack up operations in Australia contributed to increased current tax in 2008.

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

Gain on issuance of shares by subsidiary

Our subsidiary Seawell concluded share issuances in both 2008 and 2007, raising a total of NOK190 million in 2008 and NOK275 million in 2007. We did not fully participate in the 2008 share issuance and as a result our holding in Seawell was reduced from 80% to 74%. We did not participate in the 2007 share issuance, which resulted in a reduction in our holding from 100% to 80%. These share issuances resulted in gains of $25 million and $50 million being recorded in 2008 and 2007, respectively. Due to a change in U.S. GAAP, any gains arising on the future issue of shares by Seawell while it is our subsidiary will be accounted for in shareholders equity and not in the statement of operations.

B. LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

Secured credit facilities

- $185 million secured term loan facility due 2010

- $800 million secured term loan facility due 2013

- $100 million secured term loan facility due 2010

- $585 million secured term loan facility due 2012

- $1.50 billion secured credit facility due 2014

- NOK1.50 billion senior debt facility due 2012

- $100 million secured term loan facility due 2014

- $1.50 billion senior secured credit facility due 2014

Ship Finance secured credit facilities

- $170 million secured term loan facility due 2013 (VIE)

- $700 million secured term loan facility due 2013 (VIE)

- $1.40 billion secured term loan facility due 2013 (VIE)

Unsecured bonds

- $30 million unsecured bond due 2012

- NOK500 million unsecured bond due 2012

- NOK800 million unsecured bond due 2011

Convertible bonds

- $1.00 billion 3.625% unsecured convertible bonds due 2012

- $500 million 4.875% unsecured convertible bonds due 2014

CIRR loans

- NOK1.75 billion Commercial Interest Reference Rate ("CIRR") credit facilities due 2016

- NOK1.01 billion Commercial Interest Reference Rate ("CIRR") credit facilities due 2020

At December 31, 2009, we had remaining contractual commitments relating to nine newbuilding contracts totaling $1.68 billion (December 31, 2008: $2.89 billion).

As of December 31, 2009, we had cash and cash equivalents totaling $602 million (2008: $657 million), including $142 million of restricted cash (2008: $281 million). In the year ended December 31, 2009, we generated cash from operations of $1.45 billion (2008: $0.40 billion), used $0.92 billion in investing activities (2008: $3.85 billion) and used $0.45 billion in financing activities (2008: $2.06 billion).

During the year ended December 312009 we paid cash dividends of $0.50 per common share, or a total of $0.20 billion (2008: $0.69 billion). A dividend of $0.55 per common share totaling $0.22 billion was declared on February 25, 2010, and paid on March 26, 2010.

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

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

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

Borrowings

As of December 31, 2009, we had total outstanding borrowings of $7.40 billion under our credit facilities, at an average interest rate of 2.77%. Outstanding borrowings at December 31, 2008, totaled $7.44 billion at an average interest rate of 3.53%.

In February 2005 Smedvig ASA ("Smedvig"), which we acquired in 2006, raised US$30.0 million through the issuance of a seven year bond which matures in February 2012. The bond bears quarterly interest of London Inter-Bank Offer Rate, or LIBOR, plus a margin.

In July 2005 we entered into a $185 million secured term loan facility to partly fund the acquisition of two jack-up rigs under construction. At December 31, 2009, the outstanding balance was $45 million (2008: $72 million). The facility bears interest at LIBOR plus a margin and is repayable over a term of five years.

In August 2005 we entered into a $300 million secured loan facility with a syndicate of banks. The facility was amended and increased in 2006 to $800 million. At December 31, 2009, the outstanding balance was $725 million (2008: $668 million). The facility consists of two tranches with differing interest rates and repayment schedules, and each tranche bears interest at LIBOR plus a margin. The final repayment of $368 million is due in December 2013.

In September 2005 we raised NOK500 million through the issuance of a seven year bond, which matures in September 2012. The bond bears quarterly interest of NIBOR (Norwegian Inter-Bank Offer Rate) plus a margin. At December 31, 2009, the outstanding balance was $87 million (2008: $71 million).

In October 2005 we entered into a $100 million secured term loan facility to partly fund the acquisition of newbuilding jack-up rigs. At December 31, 2009, the outstanding balance was $42 million (2008: $92 million). The facility bears interest at LIBOR plus a margin and is repayable over a term of five years.

In December 2006 we entered into a $585 million secured term loan facility with a syndicate of banks to partly fund the acquisition of eight tender rigs, which have been pledged as security. At December 31, 2009, the outstanding balance was $436 million (2008: $486 million). The facility bears interest at LIBOR plus a margin and is repayable over a term of six years. At maturity a balloon payment of $300 million is due.

In February 2007, our fully consolidated VIE Rig Finance II Ltd (which is wholly-owned by Ship Finance, a related party) entered into a $170 million secured term loan facility with a syndicate of banks, in order to partly fund the acquisition of the jack-up rig West Prospero. At December 31, 2009, the outstanding amount under the facility was $111 million (2008: $121 million). The facility bears interest at LIBOR plus a margin and is repayable over a term of six years. The facility is secured by the assets of Rig Finance II Ltd.

In June 2007 we entered into a $1.50 billion senior secured loan facility with a syndicate of banks to partly fund the acquisition of four drilling rigs West Alpha, West Epsilon, West Navigator and West Venture, which have been pledged as security. At December 31, 2009, the outstanding balance was $1.14 billion (2008: $1.34 billion). The facility bears interest at LIBOR plus a margin and is repayable over a term of seven years. A final payment of $600 million is due on maturity.

In November 2007 we issued at par $1.00 billion of convertible bonds, the proceeds of which were used to fund our construction program and for general corporate purposes. Interest on the bonds is fixed at 3.625% per annum, payable semi-annually in arrears. The bonds are convertible into Seadrill Limited common shares by the holders at any time up to 10 banking days prior to November 8, 2012. The conversion price set at the time of issuance was $34.474 per share, representing a 45% premium to the share price at the time. Since then, dividend distributions have reduced the conversion price to $30.78. Unless previously redeemed, converted or purchased and cancelled, the bonds mature in November 2012.

In December 2007 our 73.8% subsidiary Seawell entered into a NOK1.50 billion multi-tranche Senior Debt facility with a syndicate of banks to finance working capital. At December 31, 2009, the amount outstanding under this facility was NOK1.21 billion, equivalent to $211 million (2008: NOK1.42 billion equivalent to $203 million). The facility bears interest at NIBOR plus a margin and is repayable over a term of five years.

In April 2008 we entered into a $100 million secured term loan facility with two banks to partly fund the acquisition of a tender rig. At December 31, 2009, the outstanding amount on this facility was $86 million (2008: $97 million). The facility bears interest at fixed rates and is repayable over a term of six years. A final payment of $60 million is due on maturity.

In April 2008 we entered into a CIRR term loan for NOK850 million with Eksportfinans ASA, the Norwegian export credit agency. The loan bears interest at a fixed rate of 4.56% and is repayable over a term of eight years. The outstanding balance at December 31, 2009, was NOK750 million, equivalent to $121 million (2008: NOK800 million, equivalent to $114 million).

In June 2008 we entered into a CIRR term loan for NOK904 million with Eksportfinans ASA. The loan bears fixed interest at a fixed rate of 4.15% and is repayable over a term of eight years. The outstanding balance at December 31, 2009, was NOK744 million, equivalent to$129 million (December 31, 2008: NOK850 million, equivalent to $121 million).

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

In July 2008 our fully consolidated VIE SFL West Polaris Limited (which is wholly-owned by Ship Finance) entered into a $700 million secured term loan facility with a syndicate of banks, in order to partly fund the acquisition of the newbuilding drillship West Polaris. At December 31, 2009, the outstanding balance under the facility was $619 (2008: $688 million). The facility bears interest at LIBOR plus a margin and is repayable over a term of five years. The facility is secured by the assets of SFL West Polaris Limited.

In September 2008 our fully consolidated VIE SFL Deepwater Ltd (which is wholly-owned by Ship Finance) entered into a $1.40 billion secured term loan facility with a syndicate of banks, in order to partly fund the acquisition of the two semi-submersible rigs West Taurus and West Hercules. At December 31, 2009, the outstanding balance under the facility was $1.26 billion (2008: $1.14 billion). The facility bears interest at LIBOR plus a margin and is repayable over a term of five years. The facility is secured by the assets of SFL Deepwater Ltd.

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

In September 2009 we issued at par $500 million of senior unsecured convertible bonds, the proceeds of which are intended to be used for future growth. Interest on the bonds is fixed at 4.875%, payable semi-annually in arrears. The bonds are convertible into Seadrill Limited common shares at any time up to ten banking days prior to September 29, 2014. The conversion price at the time of issuance was $25.18 per share, representing a 35% premium to the share price at the time. Since then, dividend distributions have reduced the conversion price to $23.97. For accounting purposes $105 million has been allocated to the bond equity component and $395 million to the bond liability component, due to the cash settlement option stipulated in the bond agreement. Unless previously redeemed, converted or purchased and cancelled, the bonds mature in September 2014.

In October 2009 we issued a NOK800 million senior unsecured two year bond. The bond bears interest at NIBOR plus a margin and the proceeds are for general corporate purposes. At December 31, 2009, the outstanding balance was $134 million.

In the year ended December 31, 2009 ,we repaid in full (i) a short-term bridging loan ($792 million outstanding at December 31 2008), (ii) the loan entered into by our fully consolidated VIE Rig Finance Ltd to partly fund the acquisition of West Ceres, which was sold in July 2009 ($107 million outstanding at December 31, 2008) and (iii) two floating rate bonds totaling NOK1.00 billion which matured ($144 million outstanding at December 31, 2008).

In connection with the above three CIRR fixed interest term loans totaling NOK2.37 billion, three collateral cash deposits equal to the total outstanding loan balances have been established with commercial banks. The collateral cash deposits are reduced in parallel with repayments of the CIRR loans and receive fixed interest at the same rates as those paid on the CIRR loans. The collateral cash deposits are classified as "restricted cash" on the balance sheet, and the effect of these arrangements is that the CIRR loans have no effect on net interest bearing debt.

In addition to security provided to lenders in the form of pledged assets, which is the case for all of our credit facilities and bank loans, agreements relating to long-term debt generally contain financial covenants. The main financial covenants contained in our loan agreements are as follows:

	·	Minimum liquidity requirements: to maintain cash and cash equivalents of at least $100 million within the group.
	·	Interest coverage ratio: to maintain an EBITDA to interest expense ratio of 2.5:1.
	·	Current ratio: to maintain a current assets to current liabilities ratio of at least 1:1. Current assets are defined as book value less minimum liquidity, but including up to 20% of shares in listed companies of which we own 20% or more. Current liabilities are defined as book value less the current portion of long term debt.

	·	Equity ratio: to maintain a total equity to total assets ratio of at least 30%. Both equity and total assets are adjusted for the difference between book and market values of drilling units.
	·	Leverage ratio: to maintain a ratio of net debt to EBITDA no greater than 4.5:1. Net debt is calculated as all interest bearing debt less cash and cash equivalents excluding minimum liquidity requirements.

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

The main covenants for the Company's outstanding bonds are to maintain adjusted shareholders' equity of at least $1.50 billion and a ratio of adjusted shareholders' equity to total liabilities of at least 30% to 40%. Adjusted shareholder's equity is book value of equity adjusted for the difference between book and market values of drilling units.

We are in compliance with all financial loan covenants as at December 31, 2009. At December 31, 2009, three month U.S. Dollar LIBOR was 0.25% (2008: 1.43%) and three month NIBOR was 2.19% (2008: 3.97%).

Derivatives

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

At December 31, 2009, the Company and its consolidated subsidiaries, including VIEs, had entered into interest rate swap contracts with a combined outstanding principal amount of $4.12 billion at rates between 2.055% per annum and 4.629% per annum. The overall effect of these swaps is to fix the interest rate on $4.12 billion of floating rate debt at a weighted average interest rate of 3.26% per annum. At December 31, 2009, our net exposure to short term fluctuations in interest rates on our outstanding debt was $0.88 billion, based on our total net interest bearing debt of $6.59 billion less the $4.12 billion notional principal of our floating to fixed interest rate swaps, less the $1.59 billion in fixed interest loans.

Also at December 31, 2009, we had entered into forward exchange contracts to sell approximately $504 million in exchange for Norwegian Kroner and Singapore Dollars between January 2010 and September 2012, at exchange rates ranging from NOK5.71 to NOK6.40 per U.S. Dollar and from SGD1.39 to SGD1.42 per U.S. Dollar.

In June and July 2008 we entered into Total Return Swap ("TRS") agreements with a total of 4,500,000 of our own common shares as the underlying security. The agreements were scheduled to expire in December 2008 and the reference prices were in a range of NOK141.2 to NOK157.8 per share. In November 2008 these contracts were terminated and we simultaneously entered into a new TRS agreement with 4,500,000 of our common shares as underlying security, with an agreed reference price of NOK56.70 per share and an expiration date in February 2009. In February 2009, we entered into a new TRS agreement for the same number of shares with expiration date in August 2009 and the new reference price was NOK61.3 per share. In August 2009, we entered into a new TRS agreement for the same number of shares with an expiration date in February 2010 and an agreed reference price of NOK98.44 per share. In February 2010 these contracts were settled and we simultaneously entered a new TRS agreement for 3,500,000 of our common shares as underlying security with an agreed reference price of NOK125.70 per share and an expiration date in February 2011. The settlement amount for the TRS transaction will be (A) the market value of the shares at the date of settlement plus all dividends paid by the Company between entering into and settling the contract, less (B) the reference price of the shares agreed at the inception of the contract plus the counterparty's financing costs. Settlement will be either a payment from or to the counterparty, depending on whether (A) is more or less than (B). There is no obligation for us to purchase any shares under the agreement and this arrangement has been recorded as a derivative transaction, with the fair value of the TRS recognized as an asset or liability as appropriate, and changes in fair values recognized in the consolidated statement of operations.

In addition to the above TRS transactions, we may from time to time enter into short-term TRS arrangements relating to securities in other companies. The above TRS indexed to our own common shares was our only TRS agreement as at December 31, 2009.

Equity

At December 31, 2009, 2008 and 2007, our issued and fully paid share capital amounted to 399,133,216 common shares of par value $2.00 each, totaling $798 million. In 2007, we had two issuances of equity totaling 16 million new common shares for total proceeds of approximately $303 million. We had no issuances of equity in 2008 and 2009.

At December 31, 2009, we were holding 110,200 of our common shares as treasury shares (2008: 717,800; 2007: 608,700) and our net outstanding share capital amounted to $798 million (2008: $797 million; 2007: $797 million). A share repurchase program was approved by the Board in 2007, authorizing us to buy back shares which may be either cancelled, or held as treasury shares to meet our obligations relating to our share option scheme. Under the program we purchased 600,000 shares in the year ended December 31, 2008, and 950,000 shares in the year ended December 31, 2007. No shares were purchased in the year ended December 31, 2009. As of December 31, 2009, we have not cancelled any shares and have used 1,439,800 of them to meet our share option scheme obligations.

In May 2005 a general meeting of the Company approved authorizing the Board of Directors to establish and maintain an employee share option scheme, or the Option Scheme, in order to encourage the holding of shares in Seadrill by individuals including directors, officers and employees of Seadrill and its subsidiaries. The Board of Directors has made a number of grants pursuant to rules established to implement the Option Scheme. As of December 31, 2009, we have granted 8,340,667 options, of which 6,199,833 remain outstanding. The fair value cost of options granted is recognized in the statement of operations as an expense, with a corresponding amount credited to additional paid in capital (see Note 28 to the Consolidated Financial Statements). The additional paid-in capital arising from share options was $16 million in the year ended December 31, 2009 (2008: $15 million; 2007: $15 million).

As at December 31, 2009,our total additional paid-in capital amounted to $2.12 billion (2008: $1.99 billion; 2007: $1.98 billion), of which $1.96 billion arises from shares issued at a premium, with the remaining balance attributable to the Option Scheme, purchases and sales of treasury shares and the equity component of the 4.875% convertible bond.

As at December 31, 2009, we were party to a TRS agreement indexed to 4,500,000 of our shares, whereby we are exposed to movements in the price of our shares (see "Derivatives" above). In February 2010 the TRS agreement was settled and we entered into a new TRS agreement indexed to 3,500,000 of our shares.

Since January 1, 2010, we have issued 13,155,000 new common shares for total proceeds of approximately $323 million, which will be used to partly finance the potential acquisitions of the CJ70 design jack-up rig and further investment in Scorpion (see Item 5.F "Contractual Obligations" below) and general purposes.

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

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

D. TREND INFORMATION

The slowdown in the world economy following the credit crisis in the latter part of 2008 adversely affected activity levels in most areas of the offshore drilling industry. Although oil and gas prices increased significantly through 2009, oil companies retain a cautious attitude regarding the sustainability of the short-term price recovery. As such, and in spite of the fact that most oil companies express confidence in the long-term outlook for their business, uncertainty persists surrounding investment in exploration and production activities, resulting in postponement of drilling activities.

The area of the market and type of rig most impacted by the drop in activity has been benign environment jack-up rigs, where a significant number of units were stacked in the Gulf of Mexico, Africa and Southeast Asia regions. The nature of the jack-up market is that drilling assignments generally have a duration lasting from three to twelve months. The wells that are drilled are often tiebacks to existing infrastructure, which in many cases implies a higher break-even oil price for marginal projects. Furthermore, the demand side also consists of smaller operators, who are more dependent on funding through the financial markets. As a result, the market for benign environment jack-ups was adversely impacted by the uncertainty regarding future oil and gas prices and challenging financial markets. There have been, however, positive signs over the last few months in the form of increased activity from oil companies, with core demand being focused on high specification and modern assets. This has resulted in improved market conditions for new high specification jack-up rigs, which has positively impacted dayrates for such equipment, although demand for older jack-ups has remained weak with an uncertain near term outlook.

The market for dynamically positioned deepwater units has been less affected, due to the limited availability of such rigs in the short term and the continued long-term focus on this area of activity by super majors and national oil companies. Although there were fewer fixtures in 2009 compared to 2008, those that were announced, including sublets between oil companies, were at dayrates of approximately $500,000, which is relatively high by historical standards. In the first quarter 2010, we have seen market rates decreasing to around $450,000 per day. We believe that the long-term outlook for dynamically positioned deepwater rigs remains promising, due to expected strong demand, particularly in Brazil, West Africa, and the U.S. and Mexican Gulf of Mexico. However, in the near term we would not be surprised if the market was presented with some weak fixtures from smaller offshore drilling companies with short-term availability, due to financial strain and/or lack of operational track record in deep water.

The drop in shallow water activity, that severely affected the market for jack-up rigs, also adversely affected the market for tender rigs. Like jack-ups, tender rigs that have come off contract have been warm stacked due to oil companies postponing drilling activity in response to the uncertainty surrounding the direction of oil and gas prices. However, market enquiries from oil companies in 2010 suggest that demand is picking up, reinforcing what we believe is an attractive medium-term outlook for tender rigs. We have so far this year secured employment for the newbuild tender rig T12 for a one year assignment in Thailand. We believe that the market will continue to improve and offer opportunities to build additional order backlog and earnings visibility for this asset class.

E. OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2009, as described above, we were party to a TRS agreement indexed to our own common shares. The fair value of this position as at December 31, 2009, is reflected in the Consolidated Financial Statements included in Item 18 of this Annual Report.

At December 31, 2008, in addition to the TRS agreement indexed to our own shares, we had forward purchase contracts for 16,300,000 shares in Pride. The fair values of this position and the TRS agreement as at December 31, 2008, are reflected in the Consolidated Financial Statements included in Item 18 of this Annual Report. The forward purchase contracts for shares in Pride became effective in July 2009, and the shares are included in our Consolidated Balance Sheet as at December 31, 2009. We were not party to any other material off balance sheet arrangements at December 31, 2009, and December 31, 2008.

F. CONTRACTUAL OBLIGATIONS

At December 31, 2009, we had the following contractual obligations and commitments:

	Payment due by period
(In US$millions)	Less than 1 year		1 – 3 years		3 – 5 years		After 5 years		Total
3.625% convertible bonds due 2012		-		1,000		-		-		1,000
4.875% convertible bonds due 2014 (1)		-		-		500		-		500
Interest bearing debt		774		1,961		3,103		159		5,997
Total debt repayments (1)		774		2,961		3,603		159		7,497
Total interest payments (2)		321		579		218		11		1,129
Accrued pension liabilities		6		11		14		7		38
Other non-current liabilities		7		15		16		-		38
Total operating lease obligations		20		34		29		30		113
Total drilling unit purchases (3)		1,175		503		-		-		1,678
Total contractual cash obligations		2,303		4,103		3,880		207		10,493

(1) In September 2009 we issued $500 million of 4.875% convertible bonds due 2014. Due to the hybrid nature of this financial instrument, for accounting purposes the liability is divided into $395 million of debt and $105 million of equity. The above contractual obligations assume that none of the bonds are converted into common shares and that the full $500 million is repayable in 2014. Accordingly, total debt repayments shown above exceed by $101million the interest bearing debt shown in the consolidated balance sheet as at December 31, 2009.

(2) Interest payments are based on the existing borrowings of the Company and its consolidated subsidiaries. It is assumed that no refinancing of existing loans takes place and that there is no repayment on revolving credit facilities. Interest has been calculated using the US$Yield Curve published by Reuters, plus agreed margins for each loan facility. The effects of interest rate swaps have been included in the calculations.

(3) Drilling unit purchase commitments relate to three jack-up rigs ($454 million), three tender rigs ($143 million), two semi-submersible rigs ($781 million) and one drillship ($300 million). We have an option not to take delivery of one of the jack-up rigs, which if exercised would reduce the above commitments by $184 million. In April 2010 we announced that we have entered into an option agreement to buy a CJ70 design harsh environment jack-up rig from the Jurong shipyard. We intend to exercise the option, which will increase the above commitments by $354 million.

(4) In April 2010 we announced that we plan to make an offer for the outstanding shares in Scorpion which we do not already own. The planned offer is triggered by the Oslo Stock Exchange Mandatory Offer Rules, following our acquisition in April 2010 of shares in Scorpion at a price of NOK36.00 per share, which increased our shareholding in Scorpion to 40.0% of its issued share capital. If the offer is made at the price of NOK36.00 per share and is accepted by all of holders of the outstanding shares, the cost of acquiring the remaining shares in Scorpion will amount to approximately $330 million.

(5) The potential acquisitions of the CJ70 design jack-up rig and further investment in Scorpion will be partly financed by the private placement announced on April 12, 2010, of 12,500,000 common shares for gross proceeds of approximately $322 million. We are in the process of securing the necessary debt finance for the remainder of the investments.

G. SAFE HARBOR

See section entitled "Forward Looking Statements" in this Annual Report.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. DIRECTORS AND SENIOR MANAGEMENT

The following table sets forth information regarding our directors and officers, and also certain key employees within our operating subsidiaries, who are responsible for overseeing the management of our business.

Name	Age	Position
John Fredriksen	65	President, Director and Chairman of the Board
Tor Olav Trøim	47	Vice President and Director
Kate Blankenship	45	Director and Audit Committee member
Kjell E. Jacobsen	53	Director
Kathrine Fredriksen	26	Director
Georgina Sousa	59	Company Secretary
Alf C. Thorkildsen	53	Chief Executive Officer, Interim Chief Financial Officer and President, Seadrill Management AS
Per Wullf	50	Chief Operating Officer and Executive Vice President, Seadrill Management AS
Tim Juran	49	Executive Vice President Deepwater Western Hemisphere
Svend Anton Maier	45	Vice President Deepwater Eastern Hemisphere
Sveinung Lofthus	49	Senior Vice President Europe
Ian Shearer	48	Senior Vice President Asia Pacific Jack-ups
Alf Ragnar Løvdal	52	Senior Vice President Tender Rigs
Thorleif Egeli	46	Chief Executive Officer, Seawell Management AS

Certain biographical information about each of our directors, executive officers and key officers is set forth below.

John Fredriksen has served as Chairman of the Board, President and a director of the Company since its inception in May 2005. Mr. Fredriksen has established trusts for the benefit of his immediate family which control Hemen, our largest shareholder. Mr. Fredriksen is Chairman, President, Chief Executive Officer and a director of a related party Frontline, a Bermuda company listed on the NYSE, the Oslo Stock Exchange and the London Stock Exchange. He is also a director of a related party, Golar LNG Limited, or Golar, a Bermuda company listed on the Nasdaq Global Market and the Oslo Stock Exchange whose principal shareholder is World Shipholding Limited, a company indirectly influenced by trusts established by Mr. John Fredriksen for the benefit of his immediate family. He is also a director of a related party Golden Ocean Group Limited, or Golden Ocean, a Bermuda company publicly on the Oslo Stock Exchange whose principal shareholder is Hemen.

Tor Olav Trøim has served as Vice-President and a director of the Company since its inception in May 2005. Mr. Trøim graduated as M.Sc Naval Architect from the University of Trondheim, Norway in 1985. His careers include Equity Portfolio Manager with Storebrand ASA (1987-1990), and Chief Executive Officer for the Norwegian Oil Company DNO AS (1992-1995). Mr. Trøim serves as a director and Vice President of Golar, and as a director of three Oslo Stock Exchange listed companies, Golden Ocean, Aktiv Kapital ASA and Marine Harvest ASA. He served as a director of Frontline from November 1997 until February 2008. Mr. Trøim served as a director of Seatankers Management from 1995 until June 2009. He also has acted as Chief Executive Officer for Knightsbridge Tankers Limited, a Bermuda company listed on the Nasdaq Global Select Market, until September 2007 and for Golar until April 2006.

Kate Blankenship has served as a director of the Company since its inception in May 2005. Mrs. Blankenship has also served as a director of Frontline since 2003. Mrs. Blankenship joined Frontline in 1994 and served as its Chief Accounting Officer and Secretary until October 2005. Mrs. Blankenship has been a director of Ship Finance since October 2003. Mrs. Blankenship has been a director of Independent Tankers Corporation Limited since February 2008, Golar since July 2003 and Golden Ocean since November 2004. Mrs. Blankenship served as Chief Financial Officer of Knightsbridge Tankers Limited from April 2000 to September 2007 and its Secretary from December 2000 to March 2007. She is a member of the Institute of Chartered Accountants in England and Wales.

Kjell E. Jacobsen has served as a director of the Company since May 2008, when he was appointed to fill a casual vacancy on our board of directors. Mr. Jacobsen was Chief Executive Officer of Seadrill Management AS from 2006 until 2008. From 2002 to 2006, Mr. Jacobsen was the Chief Executive Officer of the Norwegian offshore drilling contractor, Smedvig. Between 1991 and 2002, Mr. Jacobsen held several senior positions, including his appointment as managing director of the mobile units of Smedvig. From 1981 to 1991, Mr. Jacobsen worked for Statoil and Citibank in both Oslo and London. Mr. Jacobsen graduated from the Norwegian Naval Academy in 1976 and from the Norwegian School of Economics and Business Administration in 1981.

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

Georgina Sousa has served as Company Secretary of the Company since February 2006. She is currently Head of Corporate Administration for Frontline. Until January 2007, she was Vice-President-Corporate Services of Consolidated Services Limited, a Bermuda Management Company, having joined the firm in 1993 as Manager of Corporate Administration. From 1976 to 1982 she was employed by the Bermuda law firm of Appleby, Spurling & Kempe as a Company Secretary and from 1982 to 1993 she was employed by the Bermuda law firm of Cox & Wilkinson as Senior Company Secretary.

Alf C. Thorkildsen was appointed Chief Executive Officer and President of Seadrill Management AS in June 2008. He is also acting as Interim Chief Financial Officer of Seadrill Management AS from April 2010 until October 2010, when a newly appointed Chief Financial Officer is scheduled to take up the position. From 2002 to 2006, Mr. Thorkildsen was the Chief Financial Officer in the offshore drilling contractor Smedvig, and following the acquisition of Smedvig by Seadrill Mr Thorkildsen served as the Chief Operating Officer of Seadrill Management AS until June 2008. Prior to joining Smedvig Mr. Thorkildsen worked for more than 20 years at Royal Dutch Shell plc, or Shell, in various senior positions. Mr. Thorkildsen graduated from the Norwegian School of Business Administration with a degree in economics and from Arizona State University with a Masters of Business Administration.

Per Wullf has served as the Chief Operating Officer and Executive Vice President of Seadrill Management AS since February 2009. Mr. Wullf has more than 28 years of experience in the international offshore and onshore drilling industry with A.P. Moller - Maersk A/S, serving as Managing Director for Maersk Drilling Norge AS from 2006 to 2009.

Tim Juran has served as the Executive Vice President, Deepwater Western Hemisphere since January 2007. Mr. Juran has more than 28 years of experience in the international offshore and onshore drilling industry, including several senior positions in Transocean Ltd. and Reading & Bates Drilling Company. Mr. Juran graduated from the University of Wisconsin - Platteville with a bachelor's degree in mining engineering.

Svend Anton Maier has served as the Vice President, Deepwater Eastern Hemisphere since February 2007. Mr. Maier has more than twenty years of experience in the offshore drilling industry. Prior to joining us, Mr. Maier held several senior positions in Transocean Ltd., including country manager in Nigeria, Equatorial Guinea and Gabon. Mr. Maier graduated from the Maritime Institute of Tønsberg with a degree in marine engineering.

Sveinung Lofthus has served as the Senior Vice President, Europe since 2005. Mr. Lofthus has more than 20 years experience in the international offshore and onshore drilling industry, including project and rig management positions in Smedvig. Mr. Lofthus graduated from the University of Stavanger with a degree in petroleum engineering.

Ian Shearer was appointed the Senior Vice President, Australasia Jack-ups in 2007. From 2004 to 2007 Mr. Shearer was responsible for our platform drilling services in the U.K. Mr. Shearer has 20 years of experience in the drilling industry, including several senior positions with Smedvig. He graduated from the University of Aberdeen with a bachelor's degree in mechanical engineering and from Robert Gordon's Institute of Technology, Aberdeen with an M.Sc in offshore engineering.

Alf Ragnar Løvdal was appointed Senior Vice President, Tender Rigs in April 2009. He was previously CEO in Seawell Management AS. Mr. Løvdal has 30 years of experience in the oil and gas industry, including 20 years responsibility for the well services business in the drilling contractor Smedvig. Before joining Smedvig, Mr. Løvdal held various positions in different oil service companies, including five years of offshore field experience with Schlumberger. He has a degree in mechanical engineering from Horten Engineering Academy in Norway.

Thorleif Egeli was appointed Chief Executive Officer of Seawell Management AS in October 2009. Mr. Egeli has more than 16 years of experience in the oil services industry, including his most recent position as Vice President, Schlumberger North America. He graduated from the Norwegian Technical University with a degree in mechanical engineering and has an MBA from the Erasmus School of Management, Rotterdam.

B. COMPENSATION

During the year ended December 31, 2009, we paid our directors and executive officers aggregate compensation of $8.3 million, including compensation in the form of options exercised. In addition we have incurred compensation expense in the aggregate amount of $0.1 million for their pension and retirement benefits. These amounts include compensation of $1.5 million paid to the CEO, and $0.02 million expensed for the CEO's pension and retirement benefits.

In the event the Chief Executive Officer resigns at the request of the board of directors, he will receive compensation equal to his salary for two years.

In addition to cash compensation, during 2009 we also recognized an expense of $5.7 million relating to stock options granted in 2006, 2007, 2008 and 2009 to certain of our directors and employees. The options vest over a three year period, with the first tranche vesting in May 2007, and they expire between September 2011 and May 2014. The exercise price of the options at December 31, 2009, was in the range $2.23 to NOK122.73 (equivalent to $21.29) per share, and for most options shall be reduced by the amount of any future dividends declared with respect to the common shares.

C. BOARD PRACTICES

Our board of directors is elected annually by a vote of a majority of the common shares represented at the meeting at which one or more holders of one-third of our outstanding common shares constitutes a quorum. In addition, the maximum and minimum number of directors is determined by our shareholders at the annual general meeting, but no less than two directors shall serve at any given time. We currently have a maximum number of directors of eight. Each director shall hold office until the next annual general meeting following his or her election or until his or her successor is elected.

Our board of directors currently consists of five directors. Three of our directors, John Fredriksen, Kathrine Fredriksen and Tor Olav Trøim may be deemed affiliated with our largest shareholder, Hemen. One of our directors, Kate Blankenship, is independent pursuant to Rule 10A-3 of the Securities and Exchange Commission, but is not considered independent pursuant to the rules of the Oslo Stock Exchange. Our current board of directors does not follow the recommendation of the Norwegian Code of Practice for Corporate Governance of two independent directors.

We currently have an audit committee, which is responsible for overseeing the quality and integrity of our financial statements and its accounting, auditing and financial reporting practices, our compliance with legal and regulatory requirements, the independent auditor's qualifications, independence and performance and our internal audit function. Our audit committee consists of Mrs. Blankenship.

In lieu of a compensation committee comprised of independent directors, our Board of Directors is responsible for establishing the executive officers' compensation and benefits. In lieu of a nomination committee comprised of independent directors, our Board of Directors is responsible for identifying and recommending potential candidates to become board members and recommending directors for appointment to board committees.

There are no service contracts between us and any of our Directors providing for benefits upon termination of their employment or service.

D. EMPLOYEES

As at April 26, 2010, we have approximately 7,600 employees, including approximately 1,100 contracted-in staff.

Some of our employees and our contracted labor, most of whom work in Brazil, Nigeria, Norway and the U.K., are represented by collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and have restricted ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.

We consider our relationships with the various unions as stable, productive and professional. At present, there are no ongoing negotiations or outstanding issues.

Total employees (including contracted-in staff )	December 31, 2007		December 31, 2008		December 31, 2009		April 26, 2010
Operating segments:
Mobile units		1,700		2,700		3,100		3,100
Tender rigs		1,500		1,700		1,800		1,800
Well services		1,500		2,400		2,600		2,600
Corporate		100		100		100		100
Total employees		4,800		6,900		7,600		7,600

Geographical location:
Norway		2,300		2,600		2,800		2,800
Rest of Europe		300		900		800		800
USA		-		300		300		250
South America		-		300		700		800
Asia and Australia		2,100		2,600		2,500		2450
Africa		100		200		500		500
Total employees		4,800		6,900		7,600		7,600

The number of employees has increased over the past three years as a result of the increase in our operating fleet of drilling units and business acquisitions.

E. SHARE OWNERSHIP

The table below shows the number of common shares beneficially owned and the percentage owned of our outstanding common shares for our directors, officers and key employees as of April 26, 2010, and the percentage held of the total common shares in issue. Also shown are their interests in share options awarded to them under the Option Scheme which was approved by the Company in May 2005. The subscription price for options granted under the scheme will normally be reduced by the amount of all dividends declared by the Company in the period from the date of grant until the date the option is exercised.

Director or Key Employee	Beneficial Interest in Common Shares of $2.00 each		Interest in Options
	Number of shares	%	Total number of options	Number of options vested	Exercise price	Expiry date
John Fredriksen (2)	(2)	(2)	-	-	-	-
Tor Olav Trøim (3)	635,000	(1)	-	-	-	-
Kate Blankenship	41,000	(1)	20,000	-	NOK 84.83	May 2014
Kjell E. Jacobsen	-	(1)	175,000 100,000	175,000 33,333	NOK 86.60 NOK 116.72	December 2011 January 2014
Kathrine Fredriksen	-	(1)	-	-	-	-
Georgina Sousa	-	(1)	-	-	-	-
Alf C. Thorkildsen	20,000	(1)	275,000 325,000	275,000 -	NOK 86.60 NOK 84.83	December 2011 May 2014
Per Wullf	-	(1)	150,000	-	NOK 84.83	May 2014
Tim Juran	855	(1)	150,000 140,000	150,000 -	NOK 98.63 NOK 104.64	September 2011 May 2014
Svend Anton. Maier	-	(1)	12,500 25,000 60,000	12,500 16,667 -	NOK 83.81 NOK 114.23 NOK 84.83	September 2011 September 2011 May 2014
Sveinung Lofthus	2,000	(1)	100,000 60,000	100,000 -	NOK 72.73 NOK 84.83	September 2011 May 2014
Ian Shearer	-	(1)	40,000 60,000	3,333 -	NOK 114.23 NOK84.83	September 2011 May 2014
Alf Ragnar Løvdal	-	(1)	40,000		NOK 90.83	May 2014
Thorleif Egeli	800	(1)	-	-	-	-

(1) less than one percent

(2) Hemen Holding Ltd, or Hemen, is a Cyprus holding company, the shares of which are held in trusts established by Mr. John Fredriksen for the benefit of his immediate family. Mr. Fredriksen disclaims beneficial ownership of the 133,097,583 shares of our common stock held by Hemen, except to the extent of his voting and dispositive interest in such shares of common stock. Mr. Fredriksen has no pecuniary interest in the shares held by Hemen. In addition, to the holdings of shares and options contained in the table above, as of April 26, 2010, Hemen is party to separate TRS agreements relating to 3,900,000 of our common shares.

(3) In addition to the holdings of shares and options contained in the table above, as of April 26, 2010, Drew Investment Ltd., a company controlled by Tor Olav Trøim, is party to separate TRS agreements relating to 400,000 of our common shares.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. MAJOR SHAREHOLDERS

The following table presents certain information as at April 6, 2010, regarding the ownership of our common shares with respect to each shareholder whom we know to beneficially own more than five percent of our outstanding common shares:

	Common Shares Held
Shareholder	Number		%
Hemen (1)		133,097,583		32.35	%
Folketrygdfondet (2)		27,001,030		6.56	%
Fidelity Management and Research Company (3)		20,501,728		5.10	%
Wellington Management Company LLP (3)		21,846,224		5.47	%

(1) Hemen, a Cyprus holding company, the shares of which are held in trusts established by Mr. John Fredriksen for the benefit of his immediate family.

(2) Folketrygdfondet manages the Government Pension Fund of Norway on behalf of the Norwegian Ministry of Finance.

(3) Share ownership information is based on Norwegian Securities Regulation notification statements, available on www.newsweb.no.

As of April 26, 2010, the Company had a single shareholder of record in the United States, in whose name all shareholdings in the United States are recorded. We had a total of 411,443,816 common shares outstanding as of April 26, 2010.

Our major shareholders have the same voting rights as our other shareholders. No corporation or foreign government owns more than 50% of our outstanding common shares. We are not aware of any arrangements, the operation of which may at a subsequent date result in a change in control of Seadrill.

B. RELATED PARTY TRANSACTIONS

The Company was formed on March 10, 2005, and its shares commenced trading on the Oslo Stock Exchange in November 2005. Its shares commenced trading on the New York Stock Exchange in April 2010. Since its formation, the Company's largest shareholder has been Hemen, which currently holds approximately 32% of our shares. Under the mandatory offer rules of the Oslo Stock Exchange described in Item 4.A "History and Development of the Company – Summary of Oslo Stock Exchange Mandatory Offer Rules", if Hemen were to acquire more than 1/3 of our shares, it could trigger the mandatory offer rules. Hemen has not advised us of any intention to do so.

The Company transacts business with the following related parties, being companies in which Hemen and companies associated with Hemen have a significant interest:

Ship Finance International Limited ("Ship Finance")

Metrogas Holdings Inc ("Metrogas")

Scorpion Offshore Ltd ("Scorpion")

Frontline Management (Bermuda) Limited ("Frontline")

In July 2006 we entered into a sale and leaseback agreement with Ship Finance, a company listed on the New York Stock Exchange in which Hemen indirectly controls approximately 43% of the outstanding shares. Under the agreement we sold the jack-up rig West Ceres to Rig Finance Ltd, or Rig Finance, a wholly-owned subsidiary of Ship Finance, for a total consideration of $210 million. Upon sale the rig was immediately leased back to us for a period of 15 years, with the Company having fixed price purchase options after three, five, seven, 10, 12 and 15 years. In July 2009, we exercised our option to repurchase West Ceres from Rig Finance at the option price of US$136 million. Lease payments to Rig Finance amounted to $20 million in 2009 (2008: $41 million).

In January 2007 we entered into a sale and leaseback agreement with Ship Finance, under which we sold the jack-up rig West Prospero to Rig Finance II Ltd, or Rig Finance II, a wholly-owned subsidiary of Ship Finance, for a total consideration of $210 million. Upon sale the rig was immediately leased back to us for a period of 15 years, with the Company having fixed price purchase options after three, five, seven, 10, 12 and 15 years. Lease payments to Rig Finance II amounted to $30 million in 2009 (2008: $46 million).

In May 2008 we entered into a sale and leaseback agreement with Ship Finance, under which the Company would sell the drillship West Polaris to SFL West Polaris, a wholly-owned subsidiary of Ship Finance, for a total consideration of $845 million upon completion of construction. Upon delivery the drillship was leased back to us for a period of 15 years, with the Company having fixed price purchase options after four, six, eight, 10, 12 and 15 years. In addition, Ship Finance has a right to sell the drillship to us after 15 years at a fixed price. Lease payments to SFL West Polaris amounted to $127 million in 2009 (2008: $37 million).

In September 2008 we entered into a sale and leaseback agreement with Ship Finance, under which we sold two newbuilding semi-submersible rigs West Hercules and West Taurus to SFL Deepwater Ltd, or SFL Deepwater, a wholly-owned subsidiary of Ship Finance, for a total consideration of $1.70 billion. Upon delivery the rigs were immediately leased back to us for a period of 15 years, with the Company having fixed price purchase options for West Hercules after three, six, eight, 10, and 12 years and for West Taurus after six, eight, 10 and 12 years. In addition, we have fixed price obligations to purchase the rigs after 15 years. Lease payments to SFL Deepwater amounted to $224 million in 2009 (2008: $29 million).

We consolidate the above four Ship Finance VIEs, Rig Finance, Rig Finance II, SFL West Polaris and SFL Deepwater, as it is has been determined that we are the primary beneficiary of the risks and rewards connected with the ownership of the units and the lease contracts. This has the effect that the Ship Finance equity in the VIEs, including their earnings, is attributable to non-controlling interests. Following our repurchase of West Ceres in July 2009, Rig Finance will no longer be a consolidated VIE.

In November 2008, the Company granted Ship Finance an unsecured short-term credit facility of $115 million. Ship Finance repaid $25 million in the first quarter of 2009 and the balance of $90 million was sold to Metrogas, a company indirectly controlled by trusts established by Mr. John Fredriksen for the benefit of his immediate family. In November 2009, the loan of $90 million was assigned back to the Company. At the same time the repayment schedule was amended to provide a maturity date of January 31, 2011. The agreed interest payable monthly by Ship Finance is based on terms believed by us to be no less favorable than are available from unaffiliated third parties. Interest receivable on the loan amounted to $8.8 million in 2009 (2008: $2.1 million).

In April 2009 the Company obtained an unsecured credit facility of $60 million from Metrogas, which was repaid in June 2009. Interest payable on the facility amounted to $0.7 million in 2009.

In November 2009, the Company granted Scorpion an unsecured short-term credit facility of $27.7 million, increasing to $79.7 million in December 2009. The applicable interest rate is based on terms believed by us to be no less favorable than are available from unaffiliated third parties and is due semi-annually. Interest received on the loan amounted to $1.0 million in 2009. In February 2010, the Company granted Scorpion a secured short-term credit facility of $49.5 million. The applicable interest rate is based on terms believed by us to be no less favorable than are available from unaffiliated third parties.

Frontline, a company indirectly controlled by Hemen, provides us with management support and administrative services. Fee payments to Frontline amounted to $0.2 million in 2009 (2008: $0.2 million) and are included in "General and administrative expenses", as they do not merit separate disclosure.

C. INTERESTS OF EXPERTS AND COUNSEL.

Not applicable.

ITEM 8. FINANCIAL INFORMATION

A. CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

Please see the section of this Annual Report on Form 20-F entitled Item 18 "Financial Statements."

Legal Proceedings

The Company is routinely party, as plaintiff or defendant, to claims and lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the operation of our drilling units, in the ordinary course of our business or in connection with our acquisition activities. The Company believes that the resolution of such claims will not have a material adverse effect on our operations or financial condition. The following dispute is the only legal proceeding which we consider to be material.

Gazprom dispute

At the end of 2005 and the beginning of 2006, the Company had a dispute with Gazprom in connection with the operations of the jack-up rig West Larissa, which was named Ekha at that time.

In May 2009, legal hearings took place in the High Court of Justice, London, and the Court has issued a decision with the following main conclusions:

The Company was awarded charter hire for the period from November 23, 2005, to January 9, 2006, being the date up to when the incident occurred. Including interest this amounted to approximately $6.8 million.

The Company was not awarded hire for the time after the incident, nor was the Company awarded any reimbursement for uninsured costs related to its claim.

The Court has ruled that Gazprom is entitled to recover costs and expenses related to West Larissa, where Gazprom can demonstrate that these were wasted as a consequence of Seadrill's actions during the incident. The Judge also ruled that Gazprom wrongfully terminated the Contract, and has thus rejected Gazprom's claim for losses associated with the contracting of another rig.

It is not possible at this stage to quantify the net outcome of this ruling. The amount of Gazprom's counter-claim, as well as responsibility for incurred legal costs, will be decided in a separate hearing at a later stage. The Court's decision has been appealed by the Company, and appeal hearings are scheduled to take place during the first half of 2010. The Company does not expect the final outcome to have a significant effect on its financial results.

Dividend Policy

Under our bye-laws, our board of directors may declare cash dividends or distributions, and may also pay a fixed cash dividend biannually or on other dates. Our Board of Directors' stated objective is to generate competitive returns for its shareholders. Any dividends declared will be in the sole discretion of the Board of Directors and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities. Under Bermuda law, the Board of Directors has no discretion to declare or pay a dividend if there are reasonable grounds for believing that (a) the Company is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of the Company's assets would thereby be less than the aggregate of its liabilities and issued share capital and share premium accounts.

In addition, since we are a holding company with no material assets other than the shares of our subsidiaries through which we conduct our operations, our ability to pay dividends will depend on our subsidiaries' distributing to us their earnings and cash flow.

Since our listing on the Oslo Stock Exchange in November 2005, we have paid dividends as follows:

Payment date	Amount per share
2010
March 26, 2010	$	0.55

2009
December 7, 2009	$	0.50

2008
March 14, 2008	$	0.25
June 18, 2008	$	0.60
September 16, 2008	$	0.60
September 30, 2008	$	0.30

B. SIGNIFICANT CHANGES

None

ITEM 9. THE OFFER AND LISTING

A. OFFER AND LISTING DETAILS

Shares of our common stock, par value $2.00 per share, have traded on the Oslo Stock Exchange, or OSE, since November 22, 2005, under the symbol "SDRL". The closing price of our shares on the Oslo Stock Exchange was NOK162.50 on April 26, 2010.

Shares of our common stock commenced trading on the New York Stock Exchange, or NYSE, on April 15, 2010, also under the symbol "SDRL". The closing price of our shares on the NYSE was $27.83 on April 26, 2010.

The NYSE listing is intended to be the Company's "primary listing" and the OSE listing is intended to be the Company's secondary listing.

The following table sets forth the fiscal years high and low closing prices of our common shares since they began trading on the Oslo Stock Exchange in November 2005:

	High NOK		Low (NOK)
Fiscal year ended December 31
2009		149.80		47.00
2008		179.75		41.60
2007		134.25		98.10
2006		114.50		55.75
2005		55.00		43.00

The following table sets forth, for each full financial quarter for the two most recent fiscal years, the high and low closing prices of our common shares trading on the Oslo Stock Exchange:

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

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

The following table sets forth, for the six most recent months, the high and low closing prices of our common shares trading on the Oslo Stock Exchange:

	High NOK		Low (NOK)
March 2010		143.00		136.20
February 2010		140.20		124.10
January 2010		150.00		132.50
December 2009		148.50		132.20
November 2009		139.00		117.00
October 2009		119.30		104.50

On April 26, 2010, the exchange rate between the Norwegian Kroner and the U.S. Dollar was NOK 5.86 to one U.S. Dollar (December 31, 2009: NOK 5.77 to one U.S. Dollar).

C. MARKETS

Our common shares currently trade on the New York Stock Exchange and the Oslo Stock Exchange under the symbol "SDRL".

ITEM 10. ADDITIONAL INFORMATION

A. SHARE CAPITAL

Not applicable.

B. MEMORANDUM AND ARTICLES OF ASSOCIATION

The Memorandum of Association of the Company was filed as Exhibit 1.1 to the Company's Registration Statement on Form 20-F (Registration No. 001-34667 ), which was filed with the Securities and Exchange Commission on March 25, 2010, and is hereby incorporated by reference into this Annual Report.

The object of our business, as stated in Section six of our Memorandum of Association, is to engage in any lawful act or activity for which companies may be organized under The Companies Act, 1981 of Bermuda, or the Companies Act, other than to issue insurance or re-insurance, to act as a technical advisor to any other enterprise or business or to carry on the business of a mutual fund. Our Memorandum of Association and Bye-laws do not impose any limitations on the ownership rights of our shareholders.

Under our Bye-laws, annual shareholder meetings will be held in accordance with the Companies Act at a time and place selected by our board of directors. The quorum at any annual or general meeting is equal to one or more shareholders, either present in person or represented by proxy, holding in the aggregate shares carrying 33 1/3 percent of the exercisable voting rights. The meetings may be held at any place, in or outside of Bermuda, other than Norway. Special meetings may be called at the discretion of the board of directors and at the request of shareholders holding at least one-tenth of all outstanding shares entitled to vote at a meeting. Annual shareholder meetings and special meetings must be called by not less than seven days' prior written notice specifying the place, day and time of the meeting. The board of directors may fix any date as the record date for determining those shareholders eligible to receive notice of and to vote at the meeting. No shareholder shall be entitled to attend unless written notice of the intention to attend and vote in person or by proxy, together with the power of attorney or other authority (if any) under which it is signed, or a notarized copy of that power of attorney, is sent to the Company Secretary, to reach the Registered Office by not later than 48 hours before the time for holding the meeting.

There are no pre-emptive, redemption, conversion or sinking fund rights attached to our shares of common stock. All or any of the rights attached to our shares may be altered by either the written consent or majority vote at a special general meeting of a majority of shareholders who hold at least 75% of the nominal value of our issued and outstanding shares. The holders of common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. There are no limitations on the right of non-Bermudians or non-residents of Bermuda to hold or vote our common shares. Unless a different majority is required by law or by our bye-laws under bye-law 57, resolutions to be approved by holders of common shares require approval by a simple majority of votes cast at a general meeting. Under our bye-laws, we have the power to purchase our shares of common stock for cancellation or to be held as treasury shares.

Our directors are elected by a majority of the votes cast at our annual general meeting. Our board of directors must consist of at least two members. The number of directors may be modified by simple majority of the votes cast at a general meeting. Each director serves from his or her election until his or her successor is duly elected and qualified except in the case of earlier resignation or removal. Under our bye-laws, our board of directors has the authority to appoint any individual to fill a casual vacancy on the board. In a director's absence, the director may appoint any person (including another director) to act as his or her alternate. Basic director fees are determined by majority vote at a general meeting, and the board of directors has the authority to grant additional fees for extraordinary services rendered as a director. Directors may participate fully in any transaction or arrangement where they have an interest, so long as they declare the nature of their interest at the first opportunity either in meeting or by writing to our board of directors. Under our bye-laws our board of directors has the authority to exercise all the powers of the Company to borrow money and to mortgage or charge our undertaking property, assets and uncalled capital in the course of managing our business, subject to the provisions of Bermuda law.

Our bye-laws provide that no director, alternate director, officer, member of a committee under bye-law 103, resident representative of the Company, or their heirs, executors or administrators, shall be liable for the acts, receipts, neglects, or defaults of any other such person or any person involved in our formation, or for any loss or expense incurred by us through the insufficiency or deficiency of title to any property acquired by us, or for the insufficiency or deficiency of any security in or upon which any of our monies shall be invested, or for any loss or damage arising from the bankruptcy, insolvency, or tortuous act of any person with whom any monies, securities, or effects shall be deposited, or for any loss occasioned by any error of judgment, omission, default, or oversight on his part, or for any other loss, damage or misfortune whatever which shall happen in relation to the execution of his duties, or supposed duties, to us or otherwise in relation thereto.

Bermuda law permits our bye-laws to contain provisions excluding personal liability of a director, alternate director, officer, member of a committee authorized under bye-Law 103, resident representative or their respective heirs, executors or administrators to the company for any loss, damage or expense (including but not limited to liabilities under contract, tort and statute or any applicable foreign law or regulation and all reasonable legal and other costs and expenses properly payable) incurred by him as such director, alternate director, officer, member of a committee authorized under bye-Law 103 or resident representative in the reasonable belief that he has been so appointed or elected notwithstanding any defect in such appointment or election.

Bermuda law also grants us the power generally to indemnify a director, alternate director, officer, member of a committee authorized under bye-law 103, resident representative or their respective heirs, executors or administrators to the company in defending any proceedings, whether civil or criminal, in which judgment is given in his favor, or in which he is acquitted, or in connection with any application under the Companies Act in which relief from liability is granted to him by the court.

Under our bye-laws, our shareholders agree to waive any claim or right of action they might have, whether individually or by right of the Company, against any director, alternate director, officer, person or member of a committee authorized under bye-law 103, resident representative of the company or any of their respective heirs, executors or administrators due to any action taken by any such person, or the failure of any such person to take any action in the performance of his duties, or supposed duties, to us or otherwise in relation thereto.

Notwithstanding any of the foregoing, no indemnity, waiver or exclusion of liability contained in our bye-laws in favor of any person is effective in respect of liabilities arising from such person's own fraud or dishonesty.

Under our bye-laws, our board of directors may in its sole discretion, declare dividends or distributions and pay a fixed cash dividend bi-annually or on other dates. Under Bermuda law, the board of directors has no discretion to declare or pay a dividend if there are reasonable grounds for believing that (a) the Company is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of the Company's assets would thereby be less than the aggregate of its liabilities and its issued share capital and share premium accounts.

In the event of our liquidation, dissolution or winding up, our shareholders have the right to receive a pro rata share, in a proportion equal to their proportionate shareholding, of the surplus assets of the Company after all of the Company's liabilities are discharged. A liquidator may, with the sanction of a 2/3 majority vote at a general meeting and after the discharge of all of the Company's liabilities, divide among our shareholders in specie or in kind the whole or any part of the remaining assets and may, for such purposes, assign such values as he deems fair.

Anti-Takeover Effects of Provisions of Our Constitutional Documents

Several provisions of our bye-laws may have anti-takeover effects. These provisions are intended to avoid costly takeover battles, lessen our vulnerability to a hostile change of control and enhance the ability of our board of directors to maximize shareholder value in connection with any unsolicited offer to acquire us. However, these anti-takeover provisions, which are summarized below, could also discourage, delay or prevent (1) the merger, amalgamation or acquisition of our company by means of a tender offer, a proxy contest or otherwise, that a shareholder may consider in its best interest and (2) the removal of our incumbent directors and executive officers.

Should a person or persons resident for tax purposes in Norway, other than Nordea Bank Norge ASA, become the holder of 50% or more of the aggregate of our issued and outstanding common stock, being held or owned directly or indirectly, we will be entitled to dispose of such number of shares that would reduce the person or persons ownership of our common stock to under 50%.

Where a person or entity becomes the owner of more than 30% of our issued and outstanding common stock, our board of directors can decline to register the acquired common shares in excess of 30% unless the acquirer makes an offer to purchase our remaining shares of common stock or agrees to sell part of the shares of common stock acquired to reduce the number of our common shares held by them to below 30% of our issued and outstanding common stock. Sale of the acquirer's shares over 30% of the issued and outstanding common stock must take place no later than two weeks from when his total share ownership rose above 30%, the acquisition date. Offers to purchase our remaining shares must occur within four weeks of the acquisition date and the offer price must be at least as high as the highest price paid by the acquirer in the six months prior to the acquisition date. Should the acquirer fail to reduce his common shares or make an offer for the outstanding common shares with the time period, the acquirer will not be able to exercise any rights associated with the shares in excess of 30% of our outstanding and issued common stock.

There is a statutory remedy under Section 111 of the Bermuda Companies Act 1981 which provides that a shareholder may seek redress in the Bermuda courts as long as such shareholder can establish that a company's affairs are being conducted, or have been conducted, in a manner oppressive or prejudicial to the interests of some part of the shareholders, including such shareholder.

C. MATERIAL CONTRACTS

The Company has no material contracts other than those entered in the ordinary course of business.

D. EXCHANGE CONTROLS

The Bermuda Monetary Authority (the "BMA") must give permission for all issuances and transfers of securities of a Bermuda exempted company like ours. We have received general permission from the BMA to issue any unissued common shares and for the free transferability of our common shares as long as our common shares are listed on an "appointed stock exchange". Our common shares are listed on the Oslo Stock Exchange and the New York Stock Exchange – each of which is an "appointed stock exchange". Our common shares may therefore be freely transferred among persons who are residents and non-residents of Bermuda.

Although we are incorporated in Bermuda, we are classified as a non-resident of Bermuda for exchange control purposes by the BMA. Other than transferring Bermuda Dollars out of Bermuda, there are no restrictions on our ability to transfer funds into and out of Bermuda or to pay dividends to US residents who are holders of Common Shares or other nonresidents of Bermuda who are holders of our common shares in currency other than Bermuda Dollars.

In accordance with Bermuda law, share certificates may be issued only in the names of corporations, individuals or legal persons. In the case of an applicant acting in a special capacity (for example, as an executor or trustee), certificates may, at the request of the applicant,

record the capacity in which the applicant is acting. Notwithstanding the recording of any such special capacity, we are not bound to investigate or incur any responsibility in respect of the proper administration of any such estate or trust.

We will take no notice of any trust applicable to any of our shares or other securities whether or not we had notice of such trust.

As an "exempted company", we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermudians, but as an exempted company, we may not participate in certain business transactions including: (i) the acquisition or holding of land in Bermuda (except that required for its business and held by way of lease or tenancy for terms of not more than 21 years) without the express authorization of the Bermuda legislature; (ii) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Finance of Bermuda; (iii) the acquisition of securities created or issued by, or any interest in, any local company or business, other than certain types of Bermuda government securities or securities of another "exempted company", "exempted partnership" or other corporation or partnership resident in Bermuda but incorporated abroad; or (iv) the carrying on of business of any kind in Bermuda, except in so far as may be necessary for the carrying on of its business outside Bermuda or under a license granted by the Minister of Finance of Bermuda.

The Bermuda government actively encourages foreign investment in "exempted" entities like us that are based in Bermuda but do not operate in competition with local business. In addition to having no restrictions on the degree of foreign ownership, we are subject neither to taxes on our income or dividends nor to any exchange controls in Bermuda. In addition, there is no capital gains tax in Bermuda, and profits can be accumulated by us, as required, without limitation. There is no income tax treaty between the United States and Bermuda pertaining to the taxation of income other than applicable to insurance enterprises.

E. TAXATION

The following is a discussion of the material Bermuda, United States federal income and other tax considerations with respect to the Company and holders of common shares. This discussion does not purport to deal with the tax consequences of owning common shares to all categories of investors, some of which, such as dealers in securities, investors whose functional currency is not the United States Dollar and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common shares, may be subject to special rules. This discussion deals only with holders who hold the common shares as a capital asset. Holders of common shares are encouraged to consult their own tax advisors concerning the overall tax consequences arising in their own particular situation under United States federal, state, local or foreign law of the ownership of common shares.

Bermuda and Other Non-U.S. Tax Considerations

As of the date of this document, we are not subject to taxation under the laws of Bermuda, and distributions to us by our subsidiaries also are not subject to any Bermuda tax. As of the date of this document, there is no Bermuda income, corporation or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by non-residents of Bermuda in respect of capital gains realized on a disposition of our common shares or in respect of distributions by us with respect to our common shares. This discussion does not, however, apply to the taxation of persons ordinarily resident in Bermuda. Bermuda holders should consult their own tax advisors regarding possible Bermuda taxes with respect to dispositions of, and distributions on, our common shares.

Under current Bermuda law, we are not subject to tax on income or capital gains. We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, the imposition of any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 28, 2016. This assurance is subject to the proviso that it is not to be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967. The assurance does not exempt us from paying import duty on goods imported into Bermuda. In addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government. We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government.

The March 28, 2016 date is common to all exempted companies incorporated in Bermuda. It is expected, based on past practices, that the Minister of Finance will extend that date and the application of the assurance. If the Minister of Finance does not grant a new exemption or extend our current assurance, and if the Bermudian Parliament passes legislation imposing taxes on exempted companies, we may become subject to taxation in Bermuda at some point after March 28, 2016.

Bermuda currently has no tax treaties in place with other countries in relation to double-taxation or for the withholding of tax for foreign tax authorities.

Dividends distributed by Seadrill Limited out of Bermuda

Currently, there are no withholding taxes payable in Bermuda on dividends distributed from Seadrill Limited to its shareholders.

Taxation of rig owning entities

The majority of our drilling rigs are owned in tax-free jurisdictions such as Bermuda, Cayman Islands and Liberia. There is no taxation of the rig owners' income in these jurisdictions. The remaining drilling rigs are owned in jurisdictions with income or tonnage taxation of the rig owners' income. These jurisdictions are Cyprus, Hong Kong, Hungary, Singapore and Svalbard.

Please also see the section below entitled "Taxation in country of drilling operations".

Taxation in country of drilling operations

Income derived from drilling operations is generally taxed in the country where these operations take place (currently including Angola, Australia, Brazil, China, Congo, Denmark, Indonesia, Malaysia, Nigeria, Norway, Thailand, UK, USA and Vietnam). The taxation of income derived from drilling operations could be based on net income, deemed income and/or withholding taxes etc, depending upon the applicable tax legislation in each country of operation. Some countries levy withholding taxes on bareboat charter payments (internal rig rent), branch profits, crew, dividends, interest and management fees.

Drilling operations can be carried out by locally incorporated companies, foreign branches of operating companies or foreign branches of the rig owning entities. We elect the appropriate structure having regard to the applicable legislation of each country where the drilling operations occur.

In some countries where the drilling operations are performed, a tax liability may also arise for the rig owning entity.

Net income

Net income corresponds to gross income for the drilling operations less tax-deductible costs (i.e. operating costs, crew, insurance, management fees and capital costs (internal bareboat fee or tax depreciation and interest costs) incurred in relation to those operations. In addition to net income tax, withholding tax on branch profits, dividends, internal bareboat fees etc may also be levied.

Net income taxation for an international drilling contractor is complex, and pricing of internal transactions (rig sales, bareboat fees and services etc.) will allocate overall taxable income between the relevant countries. We apply OECD Transfer Pricing Guidelines as a basis to arrive at pricing for internal transactions. OECD Transfer Pricing Guidelines describe various methods to arrive at pricing of internal services based on terms believed by us to be no less favorable than are available from unaffiliated third parties, and disputes can arise with tax authorities regarding whether the pricing of such internal transactions is correct.

Deemed income

Deemed income tax is normally calculated based on gross turnover, which can include or exclude reimbursables and often reflects an assumed profit ratio, multiplied by the applicable corporate tax rate. Some countries will also levy withholding taxes on the distribution of dividend/branch profits at the deemed tax rate.

Withholding taxes etc. in country of drilling operations

Some countries base their taxation solely on withholding tax on gross turnover. In addition, some countries levy stamp duties, training taxes or similar taxes on the gross turnover.

Customs duties

Customs duties are generally payable on the importation of drilling rigs, equipment and spares into the country of operation, although several countries provide exemption from such duties for the temporary importation of drilling rigs. This exemption may also apply to the temporary importation of equipment.

Taxation of other income

Other income related to crewing, management fees and technical services will be generally taxed in the country of residency of the service provider, although withholding tax and/or income tax may also be imposed in the country where the drilling operations take place.

Financial income, dividend income, and investment income will be taxable in accordance with the legislation applicable in the country in which the company holding the investment is resident. For companies resident in Bermuda, there is currently no tax on these types of income.

Some countries levy withholding taxes on outbound dividends and interest payments.

Capital gains taxation

For rigs located in Bermuda, Cayman Islands, Cyprus, Liberia and Singapore, no capital gains tax is payable in these countries. However, some countries may apply a capital gains tax or a claw-back of tax depreciation (whole or part) when drilling rigs are sold while working in the country of operation, or within a certain time after completion of such drilling operations, or when the rig is exported after completion of such drilling operations.

Other taxes

Our operations may be applicable to sales taxes, VAT or similar taxes in various countries.

Taxation of shareholders

Taxation of shareholders will depend upon the jurisdiction where the shareholder is a tax resident. Shareholders should seek advice from their tax advisor to establish the relevant taxation applicable to their circumstances.

United States Federal Income Tax Considerations

In the opinion of Seward & Kissel LLP, our United States counsel, the following are the material United States federal income tax consequences to us of our activities and to U.S. Holders and Non-U.S. Holders, each as defined below, of our common stock. This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, investors whose functional currency is not the United States Dollar and investors that own, actually or under applicable constructive ownership rules, 10 percent or more of our common stock, may be subject to special rules. The following discussion of United States federal income tax matters is based on the United States Internal Revenue Code of 1986, or the Code, judicial decisions, administrative pronouncements, and existing and proposed regulations issued by the United States Department of the Treasury, all of which are subject to change, possibly with retroactive effect. The discussion below is based, in part, on the description of our business as described herein and assumes that we conduct our business as described herein. Unless otherwise noted, references in the following discussion to the "Company," "we" and "us" are to Seadrill Limited and its subsidiaries on a consolidated basis.

United States Federal Income Taxation of U.S. Holders

As used herein, the term "U.S. Holder" means a beneficial owner of common stock that is a United States citizen or resident, United States corporation or other United States entity taxable as a corporation, an estate the income of which is subject to United States federal income taxation regardless of its source, or a trust if a court within the United States is able to exercise primary jurisdiction over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust.

If a partnership holds our common stock, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner in a partnership holding our common stock, you are encouraged to consult your tax advisor.

Distributions

Subject to the discussion of passive foreign investment companies below, any distributions made by us with respect to our common stock to a U.S. Holder will generally constitute dividends, which may be taxable as ordinary income or "qualified dividend income" as described in more detail below, to the extent of our current or accumulated earnings and profits, as determined under United States federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder's tax basis in his common stock on a dollar-for-dollar basis and thereafter as capital gain. Because we are not a United States corporation, U.S. Holders that are corporations will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. Dividends paid with respect to our common stock will generally be treated as "passive category income" or, in the case of certain types of U.S. Holders, "general category income" for purposes of computing allowable foreign tax credits for United States foreign tax credit purposes.

Dividends paid on our common stock to a U.S. Holder who is an individual, trust or estate (a "U.S. Individual Holder") will generally be treated as "qualified dividend income" that is taxable to such U.S. Individual Holders at preferential tax rates (through 2010) provided that (1) the common stock is readily tradable on an established securities market in the United States (such as the New York Stock Exchange, on which we plan to list our common stock); (2) we are not a passive foreign investment company for the taxable year during which the dividend is paid or the immediately preceding taxable year (as discussed below); and (3) the U.S. Individual Holder has owned the common stock for more than 60 days in the 121-day period beginning 60 days before the date on which the common stock becomes ex-dividend. There is no assurance that any dividends paid on our common stock will be eligible for these preferential rates in the hands of a U.S. Individual Holder. Legislation has been previously introduced in the U.S. Congress which, if enacted in its present form, may preclude our dividends from qualifying for such preferential rates prospectively from the date of the enactment. Any dividends paid by the Company which are not eligible for these preferential rates will be taxed as ordinary income to a U.S. Holder.

Special rules may apply to any "extraordinary dividend" generally, a dividend in an amount which is equal to or in excess of ten percent of a stockholder's adjusted basis (or fair market value in certain circumstances) in a share of common stock paid by us. If we pay an "extraordinary dividend" on our common stock that is treated as "qualified dividend income," then any loss derived by a U.S. Individual Holder from the sale or exchange of such common stock will be treated as long-term capital loss to the extent of such dividend.

Sale, Exchange or other Disposition of Common Stock

Assuming we do not constitute a passive foreign investment company for any taxable year, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other disposition of our common stock in an amount equal to the difference between the

amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder's tax basis in such stock. Such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder's holding period is greater than one year at the time of the sale, exchange or other disposition. Such capital gain or loss will generally be treated as United States source income or loss, as applicable, for U.S. foreign tax credit purposes. A U.S. Holder's ability to deduct capital losses is subject to certain limitations.

Passive Foreign Investment Company Status and Significant Tax Consequences

Special United States federal income tax rules apply to a U.S. Holder that holds stock in a foreign corporation classified as a passive foreign investment company (a "PFIC") for United States federal income tax purposes. In general, a foreign corporation will be treated as a PFIC with respect to a United States shareholder in such foreign corporation, if, for any taxable year in which such shareholder holds stock in such foreign corporation, either:

at least 75 percent of the corporation's gross income for such taxable year consists of passive income (e.g., dividends, interest, capital gains and rents derived other than in the active conduct of a rental business); or

at least 50 percent of the average value of the assets held by the corporation during such taxable year produce, or are held for the production of, passive income.

For purposes of determining whether a foreign corporation is a PFIC, it will be treated as earning and owning its proportionate share of the income and assets, respectively, of any of its subsidiary corporations in which it owns at least 25 percent of the value of the subsidiary's stock.

Income earned by a foreign corporation in connection with the performance of services would not constitute passive income. By contrast, rental income would generally constitute "passive income" unless the foreign corporation is treated under specific rules as deriving its rental income in the active conduct of a trade or business or is received from a related party.

We presently believe that we are not a PFIC and do not anticipate becoming a PFIC. This is, however, a factual determination made on an annual basis and is subject to change. Therefore, we can give you no assurance as to our PFIC status.

As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different taxation rules depending on whether the U.S. Holder makes an election to treat us as a "Qualified Electing Fund," which election we refer to as a "QEF election." As an alternative to making a QEF election, a U.S. Holder should be able to make a "mark-to-market" election with respect to our common stock, as discussed below.

Taxation of U.S. Holders Making a Timely QEF Election

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

Taxation of U.S. Holders Making a "Mark-to-Market" Election

Alternatively, if we were to be treated as a PFIC for any taxable year and, as we anticipate, our stock is treated as "marketable stock," a U.S. Holder would be allowed to make a "mark-to-market" election with respect to our common stock, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. The "mark-to-market" election will not be available for any of our subsidiaries. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the common stock at the end of the taxable year over such holder's adjusted tax basis in the common stock. The U.S. Holder would also be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder's adjusted tax basis in the common stock over its fair market value at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder's tax basis in his common stock would be adjusted to reflect any such income or loss amount. Gain realized on the sale, exchange or other disposition of our common stock would be treated as ordinary income, and any loss realized on the sale, exchange or other disposition of the common stock would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included by the U.S. Holder. It should be noted that the mark-to-market election would likely not be available for any of our subsidiaries which are treated as PFICs.

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election

Finally, if we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a "mark-to-market" election for that year, whom we refer to as a "Non-Electing Holder," would be subject to special rules with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common stock in a taxable year in excess of 125 percent of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder's holding period for the common stock), and (2) any gain realized on the sale, exchange or other disposition of our common stock. Under these special rules:

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

the amount allocated to the current taxable year and any taxable year before we became a PFIC would be taxed as ordinary income; and

the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

These penalties would not apply to a pension or profit sharing trust or other tax-exempt organization that did not borrow funds or otherwise utilize leverage in connection with its acquisition of our common stock. If a Non-Electing Holder who is an individual dies while owning our common stock, such holder's successor generally would not receive a step-up in tax basis with respect to such stock.

United States Federal Income Taxation of "Non-U.S. Holders"

A beneficial owner of common stock that is not a U.S. Holder is referred to herein as a "Non-U.S. Holder."

Dividends on Common Stock

Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on dividends received from us with respect to our common stock, unless that income is effectively connected with the Non-U.S. Holder's conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to those dividends, that income is taxable only if it is attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States.

Sale, Exchange or Other Disposition of Common Stock

Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on any gain realized upon the sale, exchange or other disposition of our common stock, unless:

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

the Non-U.S. Holder is an individual who is present in the United States for 183 days or more during the taxable year of disposition and other conditions are met.

If the Non-U.S. Holder is engaged in a United States trade or business for United States federal income tax purposes, the income from the common stock, including dividends and the gain from the sale, exchange or other disposition of the stock that is effectively connected with the conduct of that trade or business will generally be subject to regular United States federal income tax in the same manner as discussed in the previous section relating to the taxation of U.S. Holders. In addition, if you are a corporate Non-U.S. Holder, your earnings and profits that are attributable to the effectively connected income, which are subject to certain adjustments, may be subject to an additional branch profits tax at a rate of 30 percent, or at a lower rate as may be specified by an applicable income tax treaty.

Backup Withholding and Information Reporting

In general, dividend payments, or other taxable distributions, made within the United States to you will be subject to information reporting requirements. Such payments will also be subject to backup withholding tax if paid to a non-corporate U.S. Holder who:

fails to provide an accurate taxpayer identification number;

is notified by the Internal Revenue Service that he has failed to report all interest or dividends required to be shown on his federal income tax returns; or

in certain circumstances, fails to comply with applicable certification requirements.

Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on Internal Revenue Service Form W-8BEN, W-8ECI or W-8IMY, as applicable.

If a Non-U.S. Holder sells his common stock to or through a United States office or broker, the payment of the proceeds is subject to both United States backup withholding and information reporting unless the Non-U.S. Holder certifies that he is a non-U.S. person, under penalties of perjury, or otherwise establishes an exemption. If a Non-U.S. Holder sells his common stock through a non-United States office of a non-United States broker and the sales proceeds are paid to the Non-U.S. Holder outside the United States then information reporting and backup withholding generally will not apply to that payment. However, United States information reporting requirements, but not backup withholding, will apply to a payment of sales proceeds, even if that payment is made to a Non-U.S. Holder outside the United States, if the Non-U.S. Holder sells common stock through a non-United States office of a broker that is a United States person or has some other contacts with the United States.

Backup withholding tax is not an additional tax. Rather, a taxpayer generally may obtain a refund of any amounts withheld under backup withholding rules that exceed the taxpayer's income tax liability by filing a refund claim with the Internal Revenue Service.

Other Tax Considerations

In addition to the tax consequences discussed above, we may be subject to tax in one or more other jurisdictions where we conduct activities. The amount of any such tax imposed upon our operations may be material.

F. DIVIDENDS AND PAYING AGENTS

Not applicable.

G. STATEMENT BY EXPERTS

Not applicable.

H. DOCUMENTS ON DISPLAY

We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended. In accordance with these requirements we file reports and other information with the Commission. These materials, including this annual report on Form 20-F and the accompanying exhibits, may be inspected and copied at the public reference facilities maintained by the Commission at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling 1 (800) SEC-0330, and you may obtain copies at prescribed rates from the Public Reference Section of the Commission at its principal office in Washington, D.C. The Commission maintains a website (http://www.sec.gov.) that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. In addition, documents referred to in this annual report on Form 20-F may be inspected at our principle executive offices at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton, Bermuda HM 08 and at the offices of Seadrill Management AS at Løkkeveien 111, 4007 Stavanger, Norway.

I. SUBSIDIARY INFORMATION

Not applicable

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including foreign currency fluctuations, changes in interest rates, equity and credit risk. Our policy is to hedge our exposure to these risks where possible, within boundaries deemed appropriate by management. We accomplish this by entering into a variety of derivative instruments and contracts to maintain the desired level of risk exposure. We may enter into derivative instruments from time to time for speculative purposes.

Foreign Exchange Risk

Our foreign currency risk arises from:

the measurement of debt and other monetary assets and liabilities denominated in foreign currencies converted to U.S. Dollars, with the resulting gain or loss recorded as "Other financial items";

changes in the fair value of foreign currency forward contracts, which are recorded as "Other financial items";

the impact of fluctuations in exchange rates on the reported amounts of our revenues and expenses which are contracted in foreign currencies; and

foreign subsidiaries whose accounts are not maintained in U.S. Dollars, which when converted into U.S. Dollars can result in exchange adjustments which are recorded as a component in shareholders' equity.

We use foreign currency forward contracts to manage our exposure to foreign currency risk on certain assets, liabilities and future anticipated transactions. Such derivative contracts do not qualify for hedge accounting treatment and are recorded in the balance sheet under "Other current assets" if the forward contracts have a net positive fair value, and under "Other current liabilities" if the forward contracts have a net negative fair value, with changes in the fair value recorded in the statement of operations under "Other financial items". At December 31, 2009, we had various forward contracts to sell approximately $504 million between January 2010 and September 2012 for Norwegian Kroner and Singapore Dollars at exchange rates ranging from NOK/US$5.71 to NOK/US$6.40 and from SGD/US$1.39 to SGD/US$1.42. The fair value of our currency forward contracts as at December 3, 2009, and December 31, 2008, was as follows:

December 31, 2009

December 31, 2008

(In millions of U.S. Dollars)

Notional Amount

Fair value

Notional Amount

Fair Value

Other current assets (liabilities)

504

474

(21

)

A 1% change in the exchange rate between the U.S. Dollar and the bought forward currencies would result in a fair value gain or loss of $5.0 million that would be reflected in our Consolidated Statements of Operations, based on our currency forward contracts as at December 31,2009.

Interest Rate Risk

A significant portion of our debt obligations and surplus funds placed with financial institutions are subject to movements in interest rates. It is our policy to obtain the most favorable interest rates available without increasing our foreign currency exposure. In keeping with this, our surplus funds are placed in fixed deposits with reputable financial institutions which yield better returns than bank deposits. The deposits generally have short-term maturities so as to provide us with the flexibility to meet working capital and capital investments.

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

At December 31, 2009, we had entered into interest rate swap agreements with a combined outstanding principal amount of approximately $2.85 billion at rates between 2.06% per annum and 4.63% per annum. The swap agreements mature between December 2011 and December 2018. The fair values of our interest rate swaps as at December 31, 2009, and December 31, 2008, were as follows:

	December 31, 2009					December 31, 2008
(In millions of U.S. Dollars)	Outstanding principal		Fair value			Outstanding principal		Fair Value
Other current assets (liabilities)		2,854		(70	)		1,740		(146	)

In addition to the above interest rate swaps, two of our fully-consolidated VIEs have executed interest rate cash flow hedges in the form of interest rate swaps. Movements in their fair value are reflected in "Accumulated other comprehensive income (loss)", with their fair value recorded as "Other current assets" or "Other current liabilities". At December 31, 2009, the fully-consolidated VIEs had entered into interest rate swap agreements with a combined outstanding principal amount of $1.27 billion at rates between 2.19% per annum and 3.89% per annum. These swap agreements mature between October 2012 and August 2013, and their fair values as at December 31, 2009, and December 31, 2008, were as follows:

	December 31, 2009					December 31, 2008
D	Outstanding principal		Fair value			Outstanding principal		Fair Value
Other current assets (liabilities)		1,268		(33	)		1,139		(55	)

At December 31, 2009, our net exposure to floating interest rate fluctuations on our outstanding debt was $0.88billion, compared with $3.04 billion at December 31, 2008. This net exposure is based on our $5.00billion of floating rate debt less the $2.85billion outstanding principal covered by our interest rate swaps and less the $1.27 billion outstanding principal of our VIEs' interest rate hedges at December 31, 2009. A 1% change in short-term interest rates would thus increase or decrease our interest expense by approximately $9 million on an annual basis as of December 31, 2009 (December 31, 2008: $30 million).

Equity risk

At December 31, 2009, we had entered into a TRS contract indexed to 4,500,000 of our own shares, whereby we carry the risk of fluctuations in the market price of our shares. The settlement amount for the contract will be (A) the market value of the shares at the date of settlement plus the amount of dividends paid on the shares by us between entering into and settling the contract, less (B) the reference price of the shares agreed at the inception of the contract plus the counterparty's financing costs. Settlement will be either a payment from or to the counterparty, depending on whether (A) is more or less than (B). The contract was scheduled to expire in February 2010 and the agreed reference price was NOK98.44 per common share. The open position at December 31, 2009, exposes us to market risk associated with our share price, and it is estimated that a 10% reduction in the price below the value at December 31, 2009, would generate an adverse fair value adjustment of up to $7.7 million, which would be recorded in the Statement of Operations. In February 2010 the number of shares underlying the TRS agreement was reduced by 1,000,000 shares to 3,500,000 shares and the agreement was extended to February 2011. Early termination of this TRS agreement is possible. The new reference price is NOK125.70 per common share.

In addition to the above TRS transaction indexed to our own shares, we may from time to time enter into short-term TRS arrangements relating to securities in other companies.

The fair market value of our $1.00 billion 3.625% convertible bonds at December 31, 2009, was $1.00 billion (2008: $0.51 billion). The fair market value of our $0.50 billion 4.875% convertible bonds at December 31, 2009, was $0.61billion.

Concentration of credit risk

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

The following table shows those of our customers who have generated more than nine percent of our contract revenues in one of the periods shown:

	Year ended December 31,
Customer	2009			2008			2007
Statoil		17	%		32	%		33	%
Shell		10	%		7	%		13	%
Total		13	%		5	%		8	%
Exxon		12	%		5	%		6	%
Petrobras		10	%		-			-
Other customers		38	%		51	%		40	%
Total		100	%		100	%		100	%

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

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

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A. DEBT SECURITIES

Not applicable.

B. WARRANTS AND RIGHTS

Not applicable.

C. OTHER SECURITIES

Not applicable.

D. AMERICAN DEPOSITORY SHARES

Not applicable.

PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

Neither we nor any of our subsidiaries have been subject to a material default in the payment of principal, interest, a sinking fund or purchase fund installment or any other material default that was not cured within 30 days. In addition, the payments of our dividends are not and have not been in arrears, or have not been subject to material delinquency that was not cured within 30 days.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

ITEM 15T. CONTROLS AND PROCEDURES

a)	Disclosure Controls and Procedures

Management assessed the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule13a-15(e) of the Securities Exchange Act of 1934, as of December 31, 2009. Based upon that evaluation the Principal Executive Officer and Principal Financial Officer concluded that the Company's disclosure controls and procedures are effective as of the evaluation date.

b)	Management's annual report on internal controls over financial reporting

This annual report does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Company's registered public accounting firm, due to a transition period established by the rules of the Securities and Exchange Commission for newly public companies.

c)	Changes in internal control over financial reporting

There were no changes in our internal controls over financial reporting that occurred during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

ITEM 16. RESERVED

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT.

Our Board of Directors has determined that the sole member of the audit committee, Kate Blankenship, is an independent Director and is the Audit Committee Financial Expert.

ITEM 16B. CODE OF ETHICS

We have adopted a Code of Ethics that applies to all entities controlled by the Company and its employees, directors, officers and agents of the Company. We have posted a copy of our Code of Ethics on our website at www.seadrill.com. We will provide any person, free of charge, a copy of our Code of Ethics upon written request to our registered office.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our principal account for the fiscal years ended December 31, 2009 and 2008 was PricewaterhouseCoopers AS. The following table sets forth the fees related to audit and other services provided by PricewaterhouseCoopers AS:

	2009		2008

Audit fees (a)		1,583,833		1,116,997
Audit-related fees (b)		160,691		160,427
Taxation fees (c)		272,308		161,992
All other fees (d)		-		-
Total		2,016,832		1,439,416

a)	Audit fees

Audit fees represent professional services rendered for the audit of our annual financial statements and services provided by the principal accountant in connection with statutory and regulatory filings or engagements

b)	Audit-related fees

Audit-related fees consist of assurance and related services rendered by the principal accountant related to the performance of the audit or review of our financial statements which have not been reported under Audit Fees above.

c)	Taxation fees

Taxation fees represent fees for professional services rendered by the principal accountant for tax compliance, tax advice and tax planning.

d)	All other fees

All other fees include services other than audit fees, audit-related fees and taxation fees set forth above.

e)	Audit Committee's Pre-Approval Policies and Procedures

Our Board of Directors has adopted pre-approval policies and procedures in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X that require the Board to approve the appointment of our independent auditor before such auditor is engaged, and approve each of the audit and non-audit related services to be provided by such auditor under such engagement by the Company. All services provided by the principal auditor in 2009 and 2008 were approved by the Board pursuant to the pre-approval policy.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

Purchases of our common shares of par value $2.00 each have been made as follows:

Period	Total number of shares purchase	Average price paid per share	Total number of shares purchased as part of publicly announced plans or programs	Maximum number (or approximate Dollar value) of shares that may yet be purchased under the plans or programs
October 2007	450,000 (1)	NOK 125.79	-	-
November 2007	400,000 (1)	NOK 116.24	-	-
December 2007	100,000 (1)	NOK 115.00	-	-
January 2008	500,000 (1)	NOK115.84	-	-
June 2008	100,000 (1)	NOK 161.32	-	-
February 2010	1,000,000(1)	NOK 125.70	-	-
Total	2,550,000	NOK 123.27	-	-

1)	The shares repurchased in the period were not part of a publicly announced plan or program. The repurchases were made in open-market transactions.

A share repurchase program was approved by the Board in 2007, authorizing us to buy back shares which may either be cancelled or held as treasury shares to meet our obligations relating to our share option scheme. Of the 2,550,000 shares purchased and shown above, as at April 26, 2010, 1,705,600 have been utilized to meet our obligations relating to the share option scheme and 844,400 are being held as treasury shares.

At December 31, 2009, we were party to a Total Return Equity Swap ("TRS") agreement relating to 4,500,000 of our common shares - see Item 5.B "Liquidity and Capital Resources - Derivatives". In February 2010 the agreement was settled and we entered into a new TRS agreement relating to 3,500,000 of our common shares, with a reference price of NOK131.18 per share and an expiry date of February 2, 2011. At the same time we acquired 1,000,000 of our common shares at an average price of NOK125.70 to meet our share option scheme obligations.

4)	On April 15, 2010, Tor Olav Trøim purchased 10,000 of our common shares through market transactions at a price of $26.90 per share.

As of April 26, 2010, Hemen is party to TRS agreements relating to 3,900,000 of our common shares with a reference price of NOK153.26 per share and Drew Investment Ltd., a company controlled by Tor Olav Trøim, is party to TRS agreements relating to 400,000 of our common shares with a reference price of NOK148.55 per share.

ITEM 16F. CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

Pursuant to an exception under the NYSE listing standards available to foreign private issuers, we are not required to comply with all of the corporate governance practices followed by U.S. companies under the NYSE listing standards. The significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies are set forth below.

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

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

Audit Committee. The NYSE requires, among other things, that a listed U.S. company have an audit committee with a minimum of three members. As permitted by Rule 10A-3 under the Exchange Act, our audit committee consists of one independent member of our board of directors. Under the Audit Committee charter, the Audit Committee confers with the Company's independent registered public accounting firm and reviews, evaluates and advises the board of directors concerning the adequacy of the Company's accounting systems, its financial reporting practices, the maintenance of its books and records and its internal controls. In addition, the Audit Committee reviews the scope of the audit of the Company's financial statements and results thereof.

Corporate Governance Guidelines. The NYSE requires U.S. companies to adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Bermuda law and we have not adopted such guidelines.

PART III

ITEM 17. FINANCIAL STATEMENTS

See Item 18.

ITEM 18. FINANCIAL STATEMENTS

The following financial statements listed below and set forth on pages F-1 through F-77 are filed as part of this annual report on

Form 20-F:

Consolidated Financial Statements of Seadrill Limited
Index to Consolidated Financial Statements of Seadrill Limited	F-1
Report of Independent Registered Public Accounting Firm – PricewaterhouseCoopers AS	F-2
Consolidated Statements of Operations for the years ended December 31 2009, 2008 and 2007	F-3
Consolidated Statements of Comprehensive Income for the years ended December 31 2009, 2008 and 2007	F-4
Consolidated Balance Sheets as of December 31 2009 and 2008	F-5
Consolidated Statements of Cash Flows for the years ended December 31 2009, 2008 and 2007	F-6
Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31 2009, 2008 and 2007	F-8
Notes to Consolidated Financial Statements	F-9

ITEM 19.	EXHIBITS

Exhibit Number	Description

1.1*	Memorandum of Association of Seadrill Limited, or the Company, incorporated by reference to Exhibit 1.1 of the Company's Registration Statement, SEC File No.001-34667, filed on March 15 2010, which we refer to as the Original Registration Statement.
1.2 *	Bye-Laws of Seadrill Limited as adopted by the sole shareholder on May 13, 2005 and as amended by resolution of the shareholders at the Annual General Meeting held on December 1, 2006 and as further amended by resolution of the shareholders at the Annual General Meeting held on September 28, 2007
1.3 *	Certificate of Incorporation of Seadrill Limited delivered May 10, 2005
1.4 *	Certificate of Deposit of Memorandum of Increase of Share Capital delivered May 13, 2005
1.5 *	Certificate of Deposit of Memorandum of Increase of Share Capital delivered August 8, 2005
1.6 *	Certificate of Deposit of Memorandum of Increase of Share Capital delivered December 20, 2006
1.7 *	Certificate of Incorporation on Name Change delivered December 20, 2006
2.1 *	Form of Common Stock Certificate
4.1 *	Share Option Scheme dated December 1, 2006
4.2 *	Bermuda Tax Assurance
8.1	Subsidiaries of the Company
11.1	Code of Ethics
12.1	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
12.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
13.1	Certification of the Principal Executive Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2	Certification of the Principal Financial Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

________

* Incorporated by reference.

Index to Consolidated Financial Statements of Seadrill Limited

Report of Independent Registered Public Accounting Firm	Page 3

Consolidated Statements of Operations for the years ended December 31, 2009, 2008, and 2007	Page 4

Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008, and 2007	Page 5

Consolidated Balance Sheets as of December 31, 2009 and 2008	Page 6

Consolidated Statements of Cashflows for the years ended December 31, 2009, 2008, and 2007	Page 7

Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2009, 2008, and 2007	Page 9

Notes to Consolidated Financial Statements	Page 10

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Seadrill Limited:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, consolidated statements of cash flows, consolidated statements of comprehensive income and consolidated statements of changes in shareholders' equity present fairly, in all material respects, the financial position of Seadrill Limited and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers AS

PricewaterhouseCoopers AS

Stavanger, Norway

May 5, 2010

F-2

Seadrill Limited

CONSOLIDATED STATEMENT OF OPERATIONS

for the years ended December 31, 2009, 2008 and 2007

(In millions of US dollar, except per share data)

	2009			2008			2007

Operating revenues
Contract revenues		3,044.9			1,867.8			1,318.5
Reimbursables		166.0			163.5			146.6
Other revenues		43.0			74.5			87.0
Total operating revenues		3,253.9			2,105.8			1,552.1

Gain on sale of assets		71.1			80.1			124.2

Operating expenses
Vessel and rig operating expenses		1,252.8			1,021.6			755.4
Reimbursable expenses		154.9			156.6			139.4
Depreciation and amortization		395.9			233.2			182.9
General and administrative expenses		149.1			125.8			109.8
Total operating expenses		1,952.7			1,537.2			1,187.5

Net operating income		1,372.3			648.7			488.8

Financial items
Interest income		78.1			30.9			23.6
Interest expenses		(228.4	)		(130.0	)		(112.7	)
Share in results from associated companies		92.4			15.6			23.2
Gain on sale of associated companies		-			150.5			-
Impairment loss on marketable securities and investments in associated companies		-			(615.0	)		-
Gain / (loss) on derivative financial instruments		129.6			(353.3	)		6.9
Foreign exchange (loss) / gain		(25.4	)		130.8			(52.9	)
Other financial items		54.5			22.2			9.8
Total financial items		100.8			(748.3	)		(102.1	)

Income/(loss) before income taxes		1,473.1			(99.6	)		386.7

Income taxes		(120.0	)		(48.3	)		78.3
Gain on issuance of shares by subsidiary		-			25.2			50.0
Net income/ (loss)		1,353.1			(122.7	)		515.0

Net income/ (loss) attributable to the parent		1,261.2			(164.4	)		502.0
Net income attributable to the non-controlling interest		91.9			41.7			13.0
Basic earnings/ (loss) per share (US dollar)		3.16			(0.41	)		1.28
Diluted earnings/ (loss) per share (US dollar)		3.00			(0.41	)		1.20

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

F-3

Seadrill Limited

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

for the years ended December 31, 2009, 2008 and 2007

(In millions of US dollar, except per share data)

	2009			2008			2007
Net income/ (loss)		1,353.1			(122.7	)		515.0

Other comprehensive income/ (loss), net of tax:
Change in unrealized gain/ (loss) on marketable securities		317.1			(61.9	)		61.9
Change in unrealized foreign exchange differences		29.6			(28.2	)		33.9
Change in actuarial gain/ (loss) relating to pension		13.7			(5.8	)		7.1
Change in unrealized gain/ (loss) on interest rate swaps in VIEs		15.1			(55.2	)		-
Other comprehensive income/ (loss):		375.5			(151.1	)		102.9

Total comprehensive income/ (loss) for the period		1,728.6			(273.8	)		617.9
Comprehensive income/ (loss) attributable to the parent		1,619.8			(315.5	)		604.9
Comprehensive income attributable to the non-controlling interest		108.8			41.7			13.0


The total balance of accumulated other comprehensive income as at December 31 is made up as follows:
Unrealized gain on marketable securities		317.1			-			61.9
Unrealized gain on foreign exchange		80.1			57.5			85.7
Actuarial gain relating to pension		10.9			(1.4	)		4.4
Fair value (loss) in VIEs		(48.6	)		(55.2	)		-
Accumulated other comprehensive income at December 31		359.5			0.9			152.0

Note: All items of other comprehensive income / (loss) are stated net of tax.

The applicable amount of income taxes associated with each component of other comprehensive income is $0 due to the fact that the items relate to companies domiciled in non-taxable jurisdictions.

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

F-4

Seadrill Limited

CONSOLIDATED BALANCE SHEETS

for the years ended December 31, 2009, 2008 and 2007

(In millions of US dollar, except per share data)

	December 31, 2009		December 31, 2008
ASSETS
Current assets
Cash and cash equivalents		460.0		376.4
Restricted cash		142.1		280.7
Marketable securities		742.3		134.7
Accounts receivables, net		451.6		341.1
Amount due from related party		137.9		115.0
Other current assets		327.1		415.9
Total current assets		2,261.0		1,663.8
Non-current assets
Investment in associated companies		321.0		240.1
Newbuildings		1,430.9		3,660.5
Drilling units		7,514.3		4,645.5
Goodwill		1,596.0		1,547.3
Other intangible assets		23.5		20.1
Restricted cash		371.0		345.9
Deferred tax assets		13.4		9.7
Equipment		115.1		83.1
Amount due from related party		90.0		-
Other non-current assets		95.2		88.5
Total non-current assets		11,570.4		10,640.7
Total assets		13,831.4		12,304.5

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Current portion of long-term debt		774.1		746.1
Trade accounts payable		84.7		119.8
Other current liabilities		1,175.3		1,191.9
Total current liabilities		2,034.1		2,057.8
Non-current liabilities
Long-term interest bearing debt		6,621.8		6,690.7
Deferred taxes		124.5		125.0
Other non-current liabilities		238.1		209.0
Total non-current liabilities		6,984.4		7,024.7

Commitments and contingencies

Shareholders' equity
Common shares of par value US$2.00 per share: 800,000,000 shares authorized 399,023,016 outstanding at December 31, 2009 (December, 31 2008: 398,415,416)		798.0		796.9
Additional paid in capital		164.2		35.9
Contributed surplus		1,955.4		1,955.4
Accumulated other comprehensive income		359.5		0.9
Accumulated earnings/(deficit)		901.9		(159.9	)
Non-controlling interest		633.9		592.8
Total shareholders' equity		4,812.9		3,222.0
Total liabilities and shareholders' equity		13,831.4		12,304.5

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

F-5

Seadrill Limited

CONSOLIDATED STATEMENT OF CASH FLOWS

for the years ended December 31, 2009, 2008 and 2007

(In millions of US dollar)

	2009			2008			2007
Cash Flaws from Operating Activities
Net income/ (loss)		1,353.1			(122.7	)		515.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		395.9			233.2			182.9
Amortization of deferred loan chars		23.3			12.7			14.0
Amortization of unfavorable contracts		(43.0	)		(65.3	)		(87.0	)
Amortization of mobilization revenue		(49.8	)		(5.2	)		-
Impairment loss on marketable securities and investments in associated companies		-			615.0			-
Share of results from associated companies		(92.4	)		(15.6	)		(23.2	)
Share-based compensation expense		16.0			14.9			15.1
Gain on disposal of fixed assets		(71.1	)		(80.1	)		(124.2	)
Gain on issuance of shares in subsidiary		-			(25.2	)		(50.0	)
Gain on disposal of associated companies		-			(150.5	)		-
Unrealized (gain)/ loss related to derivative financial instruments		(152.9	)		168.8			(19.8	)
Realized gain on disposal of other investments		(15.9	)		(22.2	)		(9.8	)
Dividend received from associated company		41.2			-			5.4
Deferred income tax expense		2.2			22.6			(134.6	)
Unrealized foreign exchange loss/(gain) on long term interest bearing debt		28.0			(79.2	)		65.6
Changes in operating assets and liabilities, net of effect of acquisitions
Unrecognized mobilization fees received from customers		165.9			83.0			-
Trade accounts receivable		(110.5	)		(83.0	)		(26.4	)
Trade accounts payable		(35.1	)		(62.8	)		31.6
Prepaid expenses/accrued revenue		(71.5	)		(95.6	)		8.3
Other, net		68.6			58.2			123.1
Net cash provided by operating activities		1,452.0			401.0			486.0

F-6

Seadrill Limited

CONSOLIDATED STATEMENT OF CASH FLOWS

for the years ended December 31, 2009, 2008 and 2007

(In millions of US dollar)

	2009			2008			2007
Cash Flows from Investing Activities
Additions to newbuilding		(1,153.2	)		(2,591.2	)		(1,568.0	)
Additions to rigs and equipment		(216.2	)		(176.3	)		(169.6	)
Sale of rigs and equipment		392.9			103.8			199.9
Investment in subsidiaries, net of cash acquired		-			(173.2	)		(355.8	)
Change in margin calls and other restricted cash		344.6			(610.7	)		(15.9	)
Investment in associated companies		(32.9	)		(369.2	)		-
Proceed from repayment of short term loan to related parties		115.0			-			-
Short term loan granted to related parties		(169.7	)		(115.0	)		-
Proceeds on issuance of shares in subsidiary		-			25.2			50.0
Purchase of marketable securities		(263.0	)		(309.9	)		(141.4	)
Disposal of associated company		-			221.0			83.3
Sale of marketable securities		58.8			148.1			49.3
Net cash used in investing activities		(923.7	)		(3,847.4	)		(1,868.2	)

Cash Flows from Financing Activities
Proceeds from debt		2,407.3			5,150.0			3,947.4
Repayment of short term capital lease obligations		-			-			(0.1	)
Repayments of debt		(2,490.9	)		(2,107.7	)		(2,211.7	)
Debt fees paid		(42.7	)		(30.1	)		(21.1	)
Change in current liability related to share forward contracts		(68.6	)		67.6			109.0
Contribution (to) 1 from non-controlling interests		(68.0	)		440.1			40.0
Purchase of treasury shares		-			(13.7	)		(21.2	)
Proceeds from sale of treasury shares		8.8			8.3			21.4
Dividends paid		(199.4	)		(688.1	)		-
Proceedes from issuance of equity		-			-			303.9
Net cash provided by financing activities		(453.5	)		2,826.4			2,167.6

Effect of exchange rate changes on cash and cash equivalents		8.8			(0.6	)		1.2

Net increase / (decrease) in cash and cash equivalents		83.6			(620.6	)		786.6
Cash and cash equivalents at beginning of the year		376.4			997.0			210.4
Cash and cash equivalents at the end of period		460.0			376.4			997.0

Supplementary disclosure of cash flow information
Interest paid		230.5			245.4			247.0
Taxes paid		137.5			52.0			13.5

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

F-7

Seadrill Limited

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

for the years ended December 31, 2009, 2008 and 2007

(In millions of US dollar)

	Share Capital			Additional paid-in capital			Contributed surplus		Accumulated other comprehensive income			Retained Earnings			Non-controlling interest			Total shareholders' equity
Balance at December 31, 2006		766.3			1693.1			-		49.1			206.5			212.0			2927.0
Shares issued, net of issuance costs		32.0			271.9														303.9
Employee stock options issued					15.2														15.2
Unrealized gain / (loss) on marketable securities										61.9									61.9
Unrealized foreign exchange differences										33.9									33.9
Changes in actuarial gain i (loss) relating to pension										7.1									7.1
Effect of shares issued to non-controlling interest													(16.0	)					(16.0	)
Net purchase of treasury shares		(1.2	)		1.4														0.2
Change in non-controlling interest																(120.4	)		(120.4	)
Net income													502.0			13.0			515.0
Balance at December 31, 2007		797.1			1981.6			-		152.0			692.5			104.6			3727.8
Employee stock options issued					14.8														14.8
Unrealized gain / (loss) on marketable securities										(61.9	)								(61.9	)
Unrealized foreign exchange differences										(28.2	)								(28.2	)
Changes in actuarial gain / (loss) relating to pension										(5.8	)								(5.8	)
Net purchase of treasury shares		(0.2	)		(5.1	)													(5.3	)
Change in fair value of interest rate swaps in VIEs										(55.2	)								(55.2	)
Changes in non-controlling interest																446.5			446.5
Transfer between categories					(1955.4	)		1955.4											0.0
Dividend payment													(688.0	)					(688.0	)
Net income										-			(164.4	)		41.7			(122.7	)
Balance at December 31, 2008		796.9			35.9			1955.4		0.9			(159.9	)		592.8			3222.0
Sale of treasury shares		1.1			7.7														8.8
Employee stock options issued					15.7											0.3			16.0
Convertible loan-equity portion					104.9														104.9
Unrealized gain on marketable securities										317.1									317.1
Foreign exchange differences										29.2						0.4			29.6
Changes in actuarial gain relating to pension										12.3						1.4			13.7
Change in unrealized gain on interest rate swaps in VIEs																15.1			15.1
Net paid to non-controlling interest																(68.0	)		(68.0	)
Dividend payment													(199.4	)					(199.4	)
Net income													1261.2			91.9			1353.1
Balance at December 31, 2009		798.0			164.2			1955.4		359.5			901.9			633.9			4812.9

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

F-8

Note 1- General information

Seadrill Limited ("Seadrill" or the "Company") is a publicly listed company on the Oslo Stock Exchange and the New York Stock Exchange (refer note 34 subsequent events). The Company was incorporated in Bermuda in May 2005. Assisted by the acquisition of other companies and investment in newbuildings, Seadrill has developed into an international offshore drilling contractor providing services within drilling and well services, and at December 31, 2009 owned 35 offshore drilling units, including 9 units under construction. The Company's versatile fleet consists of drillships, jack-up rigs, semi-submersible rigs and tender rigs for operations in shallow and deepwater areas, as well as benign and harsh environments. In addition to owning and operating offshore mobile drilling units and tender rigs, the Company provides platform drilling, well intervention and engineering services through the separately over-the-counter ("OTC") listed subsidiary company Seawell Limited ("Seawell"), a Bermuda company in which the Company owned 74% at December 31, 2009.

As used herein, and unless otherwise required by the context, the term "Seadrill" refers to Seadrill Limited and the terms "Company", "we", "Group", "our" and words of similar import refer to Seadrill and its consolidated companies. The use herein of such terms as group, organization, we, us, our and its, or references to specific entities, is not intended to be a precise description of corporate relationships.

Basis of presentation

The financial statements are presented in accordance with generally accepted accounting principles in the United States of America (US GAAP). The amounts are presented in United States dollar rounded to the nearest hundred thousand, unless otherwise stated. Due to the implementation of new accounting rules, effective January 1, 2009 the Company changed the reporting of non-controlling interest (former called minority interest). The change requires non-controlling interests to be reported as equity in the consolidated balance sheet and requires net income attributable to controlling interest and to non-controlling interests to be shown sperately on the face of the statement of operations. As a result of our adoption, the Company modified the consolidated statements of operations to separately present net income (loss) attributable to non-controlling interest and net income attributable to controlling interest. Prior periods have been adjusted accordingly.

The accompanying consolidated financial statements present the financial position of Seadrill Limited, the consolidated subsidiaries and the group's interest in associated entities. Investments in companies in which the Company directly or indirectly holds more than 50 per cent of the voting control are consolidated in the financial statements, as well as certain variable interest entities in which the Company is deemed to be subject to a majority of the risk of loss from the variable interest entity's activities or entitled to receive a majority of the entity's residual returns, or both.

In accordance with US GAAP, Seawell's acquisition of the Noble Corporation North Sea Platform division ("Noble"), Peak Well Solutions AS ("Peak") and Tecwel AS ("Tecwel") in 2008, and the step-up acquisition of Eastern Drilling ASA ("Eastern Drilling") in 2007 have been accounted for as purchases in accordance with Statement of Financial Accounting Standards No. 141 "Business Combinations" (currently Accounting Standards Codification (ASC) Topic 805 Business Combinations). The fair value of the assets acquired and liabilities assumed were included in the Company's consolidated financial statements beginning on the date when control was achieved. Derivative financial instruments, financial instruments that are held for trading or classified as available-for-sale and other investments in entities owned less than 20 percent where the Company does not exercise significant influence, are recognized at fair value if fair value is readily determinable.

Non-current assets and disposal groups held for sale are stated at the lower of their carrying amount or fair value less costs of sale.

The accounting policies set out below have been applied consistently to all periods in these consolidated financial statements.

F-9

Basis of consolidation

The consolidated financial statements include controlled entities, which are those where the Company's voting interests exceed 50 percent or the Company has an interest in a Variable Interest Entity ("VIE") and the Company has been determined to be the primary beneficiary.

A variable interest entity ("VIE") is a legal entity where either (a) equity interest holders as a group lack the characteristics of a controlling financial interest, including: decision making ability and an interest in the entity's residual risks and rewards or (b) the equity holders have not provided sufficient equity investment to permit the entity to finance its activities without additional subordinated financial support, or where (c) the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both and substantially all of the entity's activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights. ASC Topic 810 Consolidation (formerly FIN 46(R)) requires a variable interest entity to be consolidated if any of its interest holders are entitled to a majority of the entity's residual return or are exposed to a majority of its expected losses.

Investment in companies in which the Company holds between 20 percent and 50 percent of an ownership interest, and over which the Company exercises significant influence, but does not consolidate, are accounted for using the equity method. The Company records its investments in associated companies and its share of earnings or losses in the consolidated statements of operations as "Share in results from associated companies". The excess, if any, of purchase price over book value of the Company's investments in equity method investees is included in the accompanying consolidated balance sheets in "Investment in associated companies".

Investments in companies in which the Company's ownership is less than 20 percent are valued at fair value unless it is not possible to estimate fair value, then the cost method is used.

Intercompany transactions and internal sales have been eliminated on consolidation. Unrealized gains and losses arising from transactions with associates are eliminated to the extent of the Company's interest in the entity.

Note 2- Accounting policies

Use of estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Contract revenue

A substantial majority of the Company's revenues are derived from dayrate based drilling contracts (which may include lump sum fees for mobilization and demobilization), and other service contracts. Both day rate based and lump sum fee revenues are recognized rateably over the contract period when services are rendered. Under some contracts, the Company is entitled to additional payments for exceeding performance targets. Such additional payments are recognized when any uncertainties are resolved or upon completion of the drilling program.

In connection with drilling contracts, the Company may receive lump sum fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to commencement of drilling services. These up-front fees are recognized as revenue over the contract term, excluding option periods.

In some cases, the Company may receive lump sum non-contingent fees or dayrate fees from customers for demobilization upon completion of a drilling program. Non-contingent demobilization fees are recognized as revenue over contract term, excluding option periods not exercised. Contingent demobilization fees are recognized as earned upon completion.

Fees received from customers under drilling contracts for capital upgrades are deferred and recognized over the contract term, excluding option periods not exercised.

Reimbursables

Reimbursements received for the purchase of supplies, personnel services and other services provided at the request of the Company's customers in accordance with a contract or agreement are recorded as revenue. The related costs are recorded as reimbursable expenses in the same period.

F-10

Other revenues

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

Mobilization and demobilization expenses

Demobilization costs are costs to return a vessel or drilling rig to a safe harbor or geographic area and are expensed as incurred.

Mobilization costs incurred as part of a contract are capitalized and recognized as expense over the contract term, excluding option periods not exercised. The costs of relocating drilling units that are not under contract are expensed as incurred.

Repairs, maintenance and periodic surveys

Costs related to periodic overhauls of drilling units are capitalized under drilling units and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic overhauls are included in depreciation and amortization expense.

Costs for other repair and maintenance activities are included in vessel and rig operating expenses and expensed when the repairs and maintenance take place.

Foreign currencies

The Company and the majority of its subsidiaries use the U.S. Dollar as their functional currency because the majority of their revenues and expenses are denominated in U.S. Dollars. Accordingly, the Company's reporting currency is also U.S. Dollars. For subsidiaries that maintain their accounts in currencies other than U.S. Dollars, the Company uses the current method of translation whereby the statements of operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in shareholders' equity.

Transactions in foreign currencies are translated into U.S. Dollars at the rates of exchange in effect at the date of the transaction. Foreign currency assets and liabilities are translated using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the consolidated statements of operations.

Current and non-current classification

Receivables and liabilities are classified as current assets and liabilities respectively, if their maturity is within one year of the balance sheet date. Otherwise, they are classified as non-current assets and liabilities.

Cash and cash equivalents

Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.

Restricted cash

Restricted cash consists of bank deposits which have been pledged as collateral for certain guarantees issued by a bank or minimum deposits which must be maintained in accordance with contractual arrangements. Restricted cash with maturity longer than one year are classified on a separate line as non-current assets.

Marketable securities

Marketable equity securities held by the Company are considered to be available-for-sale and, as such, are recorded at fair value with resulting unrealized gains and losses recorded as a separate component of accumulated other comprehensive income in shareholders' equity. Gains and losses on forward contracts to purchase marketable equity securities are accounted for as available-for-sale securities when they do not meet the definition of a derivative.

F-11

Receivables

Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. The Company establishes reserves for doubtful accounts on a case-by-case basis when it is unlikely that required payments of specific amounts will occur. In establishing these reserves, the Company considers the financial condition of the customer as well as specific circumstances such as customer disputes. Uncollectible trade accounts receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance.

Impairment of marketable securities and equity method investees

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

Newbuildings

The carrying value of rigs under construction ("Newbuildings") represents the accumulated costs at the balance sheet date. Cost components include payments for yard installments and variation orders, construction supervision, equipment, spare parts, capitalized interest, costs related to first time mobilization and commissioning costs. No charge for depreciation is made until commissioning of the newbuilding has been completed and it is ready for its intended use.

In some cases, the Company may have options with shipyards to construct rigs at fixed or variable prices which require some or no additional payment upon exercise. Payments for rig purchase options are capitalized at the time when option contracts are acquired or entered into. The Company reviews the expected future cash flows, which would result from the exercise of each option contract on a contract by contract basis to determine whether the carrying value of the option is recoverable.

Capitalized interest

Interest expenses are capitalized during construction of newbuildings based on accumulated expenditures for the applicable project at the Company's current rate of borrowing. The amount of interest expense capitalized in an accounting period shall be determined by applying an interest rate ("the capitalization rate") to the average amount of accumulated expenditures for the asset during the period. The capitalization rates used in an accounting period shall be based on the rates applicable to borrowings outstanding during the period. The Company does not capitalize amounts beyond the actual interest expense incurred in the period.

If the Company's financing plans associate a specific new borrowing with a qualifying asset, the Company uses the rate on that borrowing as the capitalization rate to be applied to that portion of the average accumulated expenditures for the asset that does not exceed the amount of that borrowing. If average accumulated expenditures for the asset exceed the amounts of specific new borrowings associated with the asset, the capitalization rate to be applied to such excess shall be a weighted average of the rates applicable to other borrowings of the Company.

Drilling units

Assets are classified as held for sale when management is actively committed to a probable asset sale within one year of an asset ready for immediate sale. Cost of property and equipment sold or retired, with the related accumulated depreciation and write-downs are removed from the balance sheet, and resulting gains or losses are included in the consolidated statement of operations.

F-12

Other equipment

Other equipment is recorded at historical cost less accumulated depreciation and is depreciated over its estimated remaining useful life, which approximates is between three and five years depending on the type of asset.

Goodwill

The Company allocates 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 at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. The Company has determined that its reporting units are the same as the operating segments for the purpose of allocating goodwill and the subsequent testing of goodwill for impairment. The goodwill impairment test requires the Company to compare the fair value of its reporting units to their carrying value. In the event that the fair value is less than carrying value, the Company must perform an exercise similar to a purchase price allocation in a business combination in order to determine the amount of the impairment charge.

The Company performs our annual test of goodwill impairment as of December 31 for each reporting segment, based on a discounted cash flow model. When testing for impairment we have used expected future cash flows using contract day rates during the contract periods. For periods after expiry of the contract periods, day rates have been forecasted based on estimates regarding future market conditions, including zero escalation of day rates. The estimated future cash flows have been calculated based on remaining asset lives. The estimated cash flows have been discounted using a weighted average cost of capital (WACC). We had no impairment of goodwill for the years ended December 31, 2009 and 2008 as the net present value of the estimated future cash flows justify the book value of goodwill. We have also performed sensitivity analysis 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.

Other intangible assets

Other intangible assets are recorded at historical cost less accumulated amortization. The cost of these assets less estimated residual value is amortized on a straight-line basis over the estimated remaining economic useful lives. Other intangible assets include technology and customer relationships.

Impairment of long-lived assets

The carrying value of long-lived assets that are held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset's carrying value and fair value.

Defined benefit pension plans

F-13

Treasury shares

Treasury shares are recognized as a separate component of shareholders' equity at cost. The purchase of treasury shares reduces the Company's share capital by the nominal value of the acquired treasury shares. The amount paid in excess of the nominal value is treated as a reduction of additional paid-in capital.

Derivative Financial Instruments and Hedging Activities

The Company's interest-rate swap agreements, foreign currency options and forward exchange contracts are recorded at fair value when they do not qualify as hedges for accounting purposes, as they are not designated as hedges of specific assets, liabilities or firm commitments. Consequently, changes in the fair value of interest-rate swap agreements, forward exchange and currency options contracts are recorded as a gain or loss under Other Financial Items. A hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability is designated as a cash flow hedge.[Missing Graphic Reference] When the interest swap qualifies for hedge accounting the Company has formally designated the swap instrument as a hedge of cash flows to be paid on the underlying loan, and when the hedge is effective, the changes in the fair value of the swap is recognized in the "Accumulated other comprehensive loss" line of the Consolidated Balance Sheets. Ineffective portions of the hedges are charged to the income statement. When the hedged item affects the income statement, the gain or loss included in accumulated other comprehensive income (loss) is reported on the same line in the Consolidated Statements of Income as the hedged item.

Financial instruments such as forward contracts to purchase shares that do not qualify as derivative instruments are not recognized on the balance sheet, unless deemed impaired. Such instruments are off-balance transactions and result in only disclosures.

Income taxes

Seadrill is a Bermuda company. Currently, Seadrill is not required to pay taxes in Bermuda on ordinary income or capital gains. The Company has received written assurance from the Minister of Finance in Bermuda that, it will be exempt from taxation until March 2016. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently income taxes have been recorded in these jurisdictions when appropriate.

Significant judgment is involved in determining the Group-wide provision for income taxes. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. The Group recognizes tax liabilities based on its assessment of whether its tax positions are sustainable and on estimates of taxes that will ultimately be due.

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between the carrying values for financial reporting purposes and the amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantially enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted or substantially enacted.

Deferred charges

Loan related costs, including debt arrangement fees, are capitalized and amortized over the term of the related loan and are included in interest expense.

Convertible debt

Convertible bond loans issued by the Company include both a loan component (host contract) and an option to convert the loan to shares (embedded derivative).

An embedded derivative, such as a conversion option, may be separated from its host contract and accounted for separately if certain criteria are met (including if the contract that embodies both the embedded derivative and the host contract is not measured at fair value, the economic characteristics and risks of the embedded derivative instrument are not clearly and closely related to the economic characteristics and risks of the host contract and if a separate instrument with the same terms as the embedded instrument would be a derivative).

F-14

If an embedded derivative instrument is separated from its host contract, the host contract shall be accounted for based on generally accepted accounting principles applicable to instruments of that type which do not contain embedded derivative instruments.

Total Return Equity Swaps

From time to time, the Company enters into total return equity swaps ("TRS") indexed to the Company's own shares, where the counterparty acquires shares in the Company and the Company carries the risk of fluctuations in the share price of the acquired shares. The fair value of each TRS is recorded as an asset or liability, with the changes in fair value recorded in the consolidated statement of operations. The Company may, from time to time, enter into TRS arrangements indexed to shares in other companies and these are accounted for in the same way.

Share-based compensation

The Company has established an employee share ownership plan under which employees, directors and officers of the Group may be allocated options to subscribe for new shares in the ultimate parent, Seadrill Limited. The compensation cost for stock options is recognized as an expense over the service period based on the fair value of the options granted.

The fair value of the share options issued under the Company's employee share option plans is determined at grant date taking into account the terms and conditions upon which the options are granted, and using a valuation technique that is consistent with generally accepted valuation methodologies for pricing financial instruments, and that incorporates all factors and assumptions that knowledgeable, willing market participants would consider in determining fair value. The fair value of the share options is recognized as personnel expenses with a corresponding increase in equity over the period during which the employees become unconditionally entitled to the options. Compensation cost is initially recognized based upon options expected to vest with appropriate adjustments to reflect actual forfeitures. National insurance contributions arising from such incentive programs are expensed when the options are exercised.

Provisions

A provision is recognized in the balance sheet when the Company has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.

Segment reporting

The Company has three reportable business segments which include mobile units, tender rigs and well services. The mobile unit segment reflects the activities of the Company's drillships, semi-submersible and jack-up rigs. The tender rigs business segment includes activities of the Company tender and semi-tender units. The well services business segment includes the activities of Seawell, the Company's 74% owned subsidiary (as of December 31, 2009) which performs various services related to platform drilling, drilling facility engineering, well intervention and oilfield services.

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence. All transactions between the related parties are based on the principle of arm's length (estimated market value).

Issuance of shares by a subsidiary/associate

For periods up to December 31, 2008, the Company recognized a profit when its subsidiary or associate issues its stock to third parties at a price per share in excess of its carrying amount if such profit was realizable. If such profit was not realizable, it was recorded as an increase to additional paid in capital. As of January 1, 2009 ASC 810-10-65 (FAS 160) was implemented which precludes a company from recognizing a profit when its subsidiary or associate issues its stock to third parties at a price per share in excess of its carrying amount if such profit is realizable. Effective from January 1, 2009 any profit of future issuance of shares by a subsidiary/associate will hence be recorded as equity transactions.

F-15

Earnings per share

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

Reclassifications

Certain reclassifications have been made to prior period amounts to conform with the current year presentation. These reclassifications did not have a material effect on the consolidated financial statements.

New Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board ('FASB') issued Statements No. 141(R), Business Combinations, ("FAS 141(R)", (codified in ASC 805), and No. 160 Noncontrolling Interests in Consolidated Financial Statements, ("FAS 160"), (codified in ASC 810). Together these statements can affect the way companies account for future business combinations and noncontrolling interests. ASC 805 requires, amongst other changes, recognition of subsequent changes in the fair value of contingent consideration in the Statement of Operations rather than against Goodwill, and transaction costs to be recognized immediately in the Statement of Operations. ASC 810-10-65-1 clarifies the classification of noncontrolling interests in consolidated balance sheets and the accounting for and reporting of transactions between the reporting entity and holders of such noncontrolling interests. In particular the noncontrolling interest in subsidiaries should be presented in the consolidated balance sheet within equity, but separate from the parent's equity. Similarly the amount of net income attributable to the parent and to the minority interest be clearly identified and presented on the consolidated statement of income. Both these Statements are effective for transactions completed in fiscal years beginning after December 15, 2008. Adoption of of these Statements by the Company in the financial statements beginning January 1, 2009 did not have a material effect on the Company's consolidated financial statements except that noncontrolling interests is classified as a component of equity.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1 (codified in ASC 825), Guidance on Interim Fair Value Disclosures, which expands the fair value disclosures required for all financial instruments within the scope of this topic to interim periods for publicly traded entities. Entities must disclose the method(s) and significant assumption used to estimate the fair value of financial instruments in financial statements on an interim basis and to highlight any changes in the methods and significant assumptions from prior periods. The guidance is effective for interim and annual periods ending after June 15, 2009 and adoption of this FSP did not have a material effect on our consolidated financial statements.

In May 2009, the FASB issued Statement No. 165 Subsequent Events, ('FAS 165'), (codified in ASC 855). This Statement provides guidance on management's assessment of subsequent events. The guidance clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date "through the date that the financial statements are issued or are available to be issued." Management must perform its assessment for both interim and annual financial reporting periods. The new guidance is effective prospectively for interim and annual periods ending after June 15, 2009. Adoption of the Statement did not have a material effect on the Company's consolidated financial statements. In February 2010, the FASB amended the subsequent events guidance issued in May 2009 to remove the requirement for SEC filers to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. The amendment is effective upon issuance. The adoption of this guidance did not have a material effect on our consolidated financial condition or results of operations.

In June 2009, the FASB issued Statement No. 168, Statement on Codification and Hierarchy of Generally Accepted Accounting Principles, ('FAS 168'), (codified in ASC 105). The standard is a replacement for FAS 162. The GAAP hierarchy will be modified to include only two levels of GAAP; authoritative and nonauthoritative. The standard is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of this Standard did not have a material effect on the Company's consolidated financial statements.

F-16

In June 2009, the FASB issued Statement No. 167, Amendments to FASB Interpretation No. 46(R) (FAS 167) (codified in ASC 810). The amended guidance requires companies to qualitatively assess the determination of the primary beneficiary of a variable-interest entities ("VIEs") based on whether the entity (1) has the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. It also requires additional disclosures for any enterprise that holds a variable interest in a VIE. The new accounting and disclosure requirements became effective for the Company from January 1, 2010. The Company is currently assessing the impact of this amendment on its consolidated financial statements.

Note 3 – Segment information

Operating segments

The Company provides drilling and related services to the offshore oil and gas industry. The split of our organization into segments is based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure. As of December 31, 2009, the Company reports its business in the following three operating segments:

· Mobile Units: The Company offers services encompassing drilling, completion and maintenance of offshore wells. The drilling contracts relate to semi-submersible rigs, jack-ups and drillships.

· Tender Rigs: The Company operates 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: The Company performs production drilling and maintenance activities on several fixed installations in the North Sea. The Company also provides wireline services including well maintenance, modification and abandonment.

Segment results are evaluated on the basis of operating profit, and the information given below is based on information used for internal reporting. The accounting principles for the segments are the same as for the Company's consolidated financial statements.

Revenues (including gain on sale of drilling units)

(In millions of US dollar)	2009		2008		2007

Mobile Units		2,323.2		1,224.2		961.6
Tender Rigs		392.0		341.4		265.7
Well Services		609.8		620.3		449.0
Total		3,325.0		2,185.9		1,676.3

Depreciation and amortization

(In millions of US dollar)	2009		2008		2007

Mobile Units		332.8		173.0		135.1
Tender Rigs		41.8		41.7		38.6
Well Services		21.3		18.5		9.2
Total		395.9		233.2		182.9

F-17

Operating income - net income (loss)

(In millions of US dollar)	2009			2008			2007

Mobile Units		1,141.3			467.7			348.6
Tender Rigs		173.5			126.1			97.0
Well Services		57.5			54.9			43.3
Operating income		1,372.3			648.7			488.8
Unallocated items:
Total financial items		100.8			(748.3	)		(102.1	)
Income taxes		(120.0	)		(48.3	)		78.3
Gain on issuance of shares by subsidiary		-			25.2			50.0
Net income (loss)		1,353.1			(122.7	)		515.0

Total assets

(In millions of US dollar)	2009		2008

Mobile Units		11,995.3		10,667.0
Tender Rigs		1,246.6		1,147.1
Well Services		589.5		490.4
Total		13,831.4		12,304.5

Goodwill:

(In millions of US dollar)	2009		2008

Mobile Units		1,170.9		1,170.9
Tender Rigs		149.3		149.3
Well Services		275.8		227.1
Total		1,596.0		1,547.3

Total liabilities

(In millions of US dollar)	2009		2008

Mobile Units		7,764.1		7,922.2
Tender Rigs		778.9		723.2
Well Services		475.5		437.1
Total		9,018.5		9,082.5

Capital expenditures – fixed assets

(In millions of US dollar)	2009		2008		2007

Mobile Units		1,091.4		2,581.5		1,654.7
Tender Rigs		246.8		177.0		66.0
Well Services		31.2		53.9		18.0
Total		1,369.4		2,812.4		1,738.7

F-18

Geographic segment data

Revenues are attributed to geographical segments based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents the Company's revenues and fixed assets by geographic area:

Revenues (including gain on sale of assets)

(In millions of US dollar)	2009		2008		2007

Norway		1,234.5		967.3		859.4
UK		149.1		172.0		73.6
Brunei		42.0		30.3		23.5
Thailand		111.9		110.1		38.5
Malaysia		108.3		249.1		136.7
Congo		70.4		87.2		66.8
Nigeria		154.7		65.4		56.7
Australia		112.5		190.5		269.7
USA		147.5		78.7		-
Brazil		500.5		25.1		-
China		177.6		25.5		-
Indonesia		178.7		-		-
Philippines		53.7		-		-
Vietnam		104.6		-		-
Angola		27.1		-		-
Red Sea		0.9		-		-
Other		151.0		184.7		151.4
Total		3,325.0		2,185.9		1,676.3

Fixed assets – operating drilling units 1)

(In millions of US dollar)	2009		2008

Norway		2,125.8		1,285.2
UK		-		-
Brunei		42.4		54.4
Thailand		120.1		319.0
Malaysia		125.6		530.1
Congo		-		93.6
Nigeria		625.8		158.7
Australia		-		296.2
USA		527.9		539.9
Brazil		1,882.5		698.6
China		605.2		631.4
Indonesia		720.9		-
Vietnam		192.5		-
Angola		86.1		-
Red Sea		195.8		-
Other		263.7		38.4
Total		7,514.3		4,645.5

1) The fixed assets referred to in the table are the Company's operating drilling units. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

F-19

Note 4 – Taxation

Income taxes consist of the follows:

	Year ended December 31
(In millions of US dollar)	2009			2008			2007

Current tax expense:
Bermuda		-			-			-
Foreign		118.2			69.1			56.3
Deferred tax expense:
Bermuda		-			-			-
Foreign		(2.9	)		28.8			(134.6	)
Deferred taxes acquired during the year		-			(6.2	)		-
Tax related to internal sale of assets in subsidiary, amortized for group purposes		4.7			(43.4	)		-
Total provision		120.0			48.3			(78.3	)
Effective tax rate		8.1	%		(48.5	%)		(20.2	%)

Norwegian tax rules allow for the offset of taxable income in one entity against taxable losses or carryforward losses in another entity within the same tax jurisdiction to reduce payable taxes (group tax relief). In 2009, 2008 and 2007 these rules reduced the company's payable tax by US$ 0.0, US$14.1 million and US$14.9 million respectively not reflected in the current tax expense above. However, the total tax expense is unaffected by these rules.

The Company, including its subsidiaries, is taxable in several jurisdictions based on its rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, the Company may pay tax within some jurisdictions even though it might have an overall loss at a consolidated level.

F-20

The income taxes for the years ended December 31 differed from the amount computed by applying the statutory income tax rate of 0 % as follows:

	Year ended December 31
(In millions of US dollar)	2009		2008			2007

Income taxes at statutory rate		-		-			-
Effect of transfers to new tax jurisdictions		4.7		(43.4	)		(75.0	)
Effect of change in taxable currency		-		-			(21.3	)
Effect of taxable income in various countries		115.3		91.7			18.0
Total		120.0		48.3			(78.3	)

Deferred Income Taxes

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The net deferred tax assets (liabilities) consist of the following:

Deferred Tax Assets:

(In millions of US dollar)	December 31, 2009		December 31, 2008		December 31, 2007

Pension		10.6		7.4		16.0
Tax loss carry forward		5.4		15.7		12.2
Unfavorable contracts		6.9		12.0		26.4
Other		4.1		0.0		5.6
Gross deferred tax asset		27.0		35.1		60.2

Deferred Tax Liability:

(In millions of US dollar)	December 31, 2009		December 31, 2008		December 31, 2007

Property, plant and equipment		84.7		74.8		135.5
Long term maintenance		15.3		15.3		11.0
Gain from sale of fixed assets		42.2		57.4		0.5
Other		0.0		3.2		0.0
Gross deferred tax liability		142.2		150.7		147.0

Net deferred tax		115.2		115.6		86.8

Net deferred taxes are classified as follows:

(In millions of US dollar)	December 31, 2009		December 31, 2008		December 31, 2007

Short-term deferred tax asset		0.5		0.0		5.6
Long-term deferred tax asset		13.4		9.8		3.7
Short-term deferred tax liability		4.6		0.4		0.1
Long-term deferred tax liability		124.5		125.0		96.1
Net deferred tax		115.2		115.6		86.8

Future taxable income justifies the inclusion of tax loss carry forward in the calculation of net deferred taxes.

F-21

In the fourth quarter of 2007 the Company established a new office and moved several Norwegian legal entities holding four rigs and one newbuilding contract to a different tax jurisdiction. The Company carried out an analysis under the current tax regulations relating to these transfers in accordance with ASC Topic 740 Income Taxes, and based on this analysis the Company recognized a tax benefit of approximately US$75 million in 2007.

With effect from January 1, 2007 the Company introduced US dollar as the functional currency for several Norwegian subsidiaries for statutory as well as tax reporting purposes. As a result, and for consolidation purposes, deferred taxes have been recalculated and adjusted as at January 1, 2007. The effect of the adjustment was a reduction of approximately US$21.3 million in the deferred tax liability as of December 31, 2006. The recalculation and adjustment of the tax position at January 1, 2007 and the calculation of current and deferred taxes for 2007 have been based on the Company's interpretation of current tax regulations.

At December 31, 2008 the Company performed an analysis for uncertain tax positions in the various jurisdictions in which the Company operates, in accordance with ASC Topic 740 Income Taxes.Based on the analysis no provision was made for the uncertain tax positions relating to the move of legal entities to a new tax jurisdiction or the use of US dollar as the functional currency for tax reporting purposes.

In late March 2010, the Company received a notice from the Norwegian tax authorities, although not taking any final position, questioning:

the Company's tax positions from 2007 relating to a possible taxable gain arising from the transfer of certain legal entities to a different tax jurisdiction. These positions also affect the relevant filed tax assessments for 2008 and 2009. To the extent there is a taxable gain, there is also an uncertainty related to the amount of such a gain, and this, in turn, is affected by the timing of the transfer of the legal entities in question of their domiciles to a new tax jurisdiction. In the Company's opinion, the transfer by the legal entities of their domiciles took place in December 2007, and that there was no legal basis for taxation of such a gain. The tax authorities have indicated that they are of the opinion that the move took place in the first half of 2008. The government changed its taxation of these kinds of transactions in the second half of 2008. Even if the tax authorities conclude that the move took place in first half of 2008, the Company's position is that there was no taxable gain as the tax authorities are seeking to apply new tax laws retroactively, and that a recent decision of the Supreme Court in Norway holds, in a similar case, that such retroactive application is against the law. Consequently, the Company has not made a provision for any tax related to the move of tax jurisdiction.

the principles for conversion of the functional currency for several Norwegian subsidiaries for tax reporting purposes. In the Company's view, applicable tax legislation is subject to various interpretations related to the calculation of the tax basis measured in Norwegian kroner. Seadrill is of the opinion that it is more likely than not that the current position taken by the Company will prevail and no tax provision has been made.

At December 31, 2009 the Company performed an analysis for uncertain tax positions in the various jurisdictions in which the Company operates, in accordance with ASC Topic 740 Income Taxes. The Company believes that it is more likely than not that a provision for an estimated total tax exposure up to approximately $190 million will not be required.

The parent company, Seadrill Limited, is headquartered in Bermuda which is a non-taxable jurisdiction. Other jurisdictions in which the Company and its subsidiaries operate are taxable based on rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, the Company may pay tax within some jurisdictions even though it may have an overall loss at the consolidated level. The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:

Jurisdiction	Earliest Open Year
Australia	2008
Nigeria	2007
Norway	2007
Thailand	2003

F-22

Note 5 – Earnings per share

The components of the numerator and denominator for the calculation of basic and diluted earnings per share resulting from continuing operations are as follows:

	Net income			Weighted average million of shares outstanding		Earnings per share
2007
Earnings per share		502.0			392.8		1.28
Effect of dilution:
Convertible bonds					29.0
Share options					1.5
Diluted earnings per share		502.0			423.3		1.20
2008
Earnings per share		(164.4	)		398.3		(0.41	)
Effect of dilution:
Convertible bonds					-
Share options					-
Diluted earnings per share*		(164.4	)		398.3		(0,41	)
2009
Earnings per share		1,261.2			398.5		3.16
Effect of dilution:
Convertible bonds		49.6			36.8
Share options					1.5
Diluted earnings per share		1,310.8			436.8		3.00

*Due to a net loss in 2008, share options and the convertible bond have been excluded from the calculation of diluted earnings per share, as they would have an antidilutive effect.

Note 6 – Other revenues

Other revenues comprise the following items:

	Year ended December 31
(In millions of US dollar)	2009		2008		2007

Amortization of unfavorable contracts		43.0		65.3		87.0
Other		0		9.2		0
Total		43.0		74.5		87.0

F-23

The unfavourable contract values arose from the acquisition of Smedvig and Eastern Drilling and represent the net present value of the existing contracts compared to the current market rates, discounted at the weighted average cost of capital. The estimated unfavourable contract values are amortized and recognized under other revenues over the terms of the contracts, ranging from two to five years.

Note 7 – Gain on sale of assets

The Company has recognized the following gains and losses on sales of assets:

(In millions of US dollar)	Net proceeds		Book value on disposal		Gain/Loss
Year ended December 31, 2009:
Sale of jack-up rig West Ceres		178.0		157.0		21.0
Gain on disposal of jack-up rig West Atlas		200.0		142.0		58.0
Gain on sale of Seadrill's share in Chestnut field		4.1		0.1		4.0
Loss related to jack-up West Elara*		10.8		22.8		-12.0
Total for year ended December 31, 2009		392.9		321.9		71.1
Year ended December 31, 2008:
Sale of jack-up West Titiania		131.4		51.3		80.1
Total for year ended December 31,2008		131.4		51.3		80.1
Year ended December 31,2007
Sale of FPSO Crystal Sea		80.0		25.3		54.7
Sale of FPSO Crystal Ocean		90.0		20.5		69.5
Total for year ended December 31, 2007		170.0		45.8		124.2

* Loss incurred due to the PPL yard exercising their option to purchase the construction contract of jack-up rig West Elara.

Note: FPSO is an acronym for floating production, storage and offloading vessels.

Note 8 – Operational leases

The Company has operating leases relating to premises, the most significant being its offices in Stavanger, Singapore, Houston, Rio de Janeiro and Aberdeen. In the years ended December 31, 2009, 2008 and 2007 rental expenses amounted to $13.7 million, $9.1 million and $8.4 million, respectively. Future minimum rental payments are as follows:

Year	US$million
2010		20.0
2011		18.1
2012		15.9
2013		14.3
2014		14.5
Thereafter		30.0
Total		112.8

Note 9 – Impairment loss on marketable securities and investments in associated companies

The Company holds a number of shares and share purchase agreements in Pride International Inc, Scorpion Offshore Ltd and SapuraCrest Bhd. As of December 31, 2008, the Company determined that the declines in fair value were other than temporary based primarily upon its evaluation of the severity of the excess of its cost basis over the market price of the security and the prospects for recovery within 2009. As a result of this evaluation the Company recognized an impairment charge so that its adjusted cost basis as of December 31, 2008 was equal to the market price of the securities. No impairment losses have been recognized in 2009 for these items.

F-24

The total impairment loss of US$615.0 million recorded in the year ended December 31, 2008 relates to write-downs in the values of marketable securities ($147.4 million), forward share contracts accounted for as marketable securities ($157.9 million) and associated companies ($309.7 million).

Note 10 – Other financial items

In the twelve months ended December 31, 2009, the Company recorded a gain of $15.9 million on the partial redemption of its investment in the Petromena NOK2,000 million bond, and the receipt of shares to the value of $25.2 million in Seahawk as a dividend in kind paid by Pride (see Note 13 – Marketable securities). These items are included in "other financial items" totaling $54.5 million.

Other financial items in the years ended December 31, 2008, 2007 consist of gains on the sale of marketable securities.

Note 11 – Gain on issuance of shares by subsidiary

In October 2007 Seawell issued 20 million new shares of par value $2.00 each for a price of NOK13.75 per share, raising a total of NOK275 million. The Company did not participate in this share issuance and as a result its holding was reduced from 100 percent to 80 percent. A gain of $50.0 million was recorded in the income statement as a result of this share issuance by Seawell.

In April 2008 Seawell issued 10 million new shares of par value $2.00 each for a price of NOK19.50 per share, raising a total of NOK195 million. The Company subscribed for two million of the new shares and at the same time sold 831,400 shares. As a result, the Company's shareholding was reduced from 80 percent to 73.79 percent. A gain of $25.2 million was recorded in the income statement as a result of these transactions.

Note 12 – Restricted cash

Restricted cash includes:

(In millions of US dollar)	December 31, 2009		December 31, 2008

CIRR deposits (see Note below)		411.4		387.4
Margin calls related to share forward agreements		71.5		206.2
Cash collateral of performance guarantees issued by bank		-		5.9
Restricted deposit related to loan facility		10.0		10.0
Tax withholding deposits		20.2		17.1
Total restricted cash		513.1		626.6
Long-term restricted cash (related to CIRR deposits and loan facility)		371.0		345.9
Short-term restricted cash		142.1		280.7

Note: CIRR deposits are cash deposited with commercial banks, which match Commercial Interest Reference Rate ("CIRR") loans from Exportfinans ASA, the Norwegian export credit agency (see Note 22). The deposits are used to make repayments of the CIRR loans.

Note 13 – Marketable securities

Marketable securities held by the Company are equity securities considered to be available-for-sale securities.

(In millions of US dollar)	December 31, 2009		December 31, 2008

Original cost		425.2		282.1
Unrealized holding gain/(loss)		317.1		(147.4	)
Carrying value		742.3		134.7

The unrealized holding gain of $317.1 as of December 31, 2009 was recorded in accumulated other comprehensive income. The unrealized holding loss of $147.4 as of December 31, 2008 was recorded as an impairment charge in 2008.

F-25

Note 14 – Accounts receivable

Accounts receivable are presented net of allowances for doubtful accounts. The allowance for doubtful accounts receivables at December 31, 2009 was $13.0 million (2008: $13.0 million).

The Company has a disputed receivable with Gazprom relating to drilling operation in 2005 and 2006 (see legal proceedings in Note 32). Apart from this, at December 31, 2009 the Company does not have any material receivables more than 90 days overdue.

The Company did not recognize any bad debt expense in 2009 or 2008.

Note 15 – Other current assets

Other current assets include:

(In millions of US dollar)	December 31, 2009		December 31, 2008

Unbilled revenue		108.8		34.3
Prepaid expenses/accrued revenue		31.2		160.2
Deferred charges – short term portion		23.2		17.2
Receivable for margin calls *		-		159.9
Unrealized gain on total return swap agreements		40.9		-
Other		123.0		44.3
Total other current assets		327.1		415.9

* Receivable for margin calls relates to share forward purchase contracts. The related liability for the share forward purchase contracts is recorded in other current liabilities (see note 23).

F-26

Note 16 – Investment in associated companies

The Company has the following investments that are recorded using the equity method:

	December 31, 2009			December 31, 2008			December 31, 2007

Scorpion Offshore Limited ("Scorpion")		38.6	%		39.6	%		-
SapuraCrest Bhd ("SapuraCrest")		23.6	%		24.3	%		-
Varia Perdana Sdn Bhd ("Varia Perdana")		49.0	%		49.0	%		49.0	%
Tioman Drilling Company Sdn Bhd ("Tioman")		49.0	%		49.0	%		49.0	%
PT Apexindo Pratama Duta Tbk ("Apexindo")		-			-			31.7	%

Summarized balance sheet information of the Company's equity method investees is as follows:

	As of December 31 2009
(in US$millions)	Current assets		Non-current assets		Current liabilities		Non-current liabilities
Scorpion		187.1		1,134.0		225.8		589.6
SapuraCrest		791.6		352.5		612.2		124.7
Varia Perdana		116.7		162.1		21.4		45.0
Tioman		86.6		0.3		73.0		0.4
TOTAL		1,182.0		1,648.9		932.4		759.7

	As of December 31 2008
(in US$millions)	Current assets		Non-current assets		Current liabilities		Non-current liabilities
Scorpion		103.6		916.6		97.4		550.4
SapuraCrest		684.5		339.0		505.8		134.2
Varia Perdana		109.3		177.1		37.5		57.4
Tioman		104.5		1.1		92.9		-
TOTAL		1,001.9		1,433.8		733.6		742.0

Summarized statement of operations information for the Company's equity method investees is as follows:

	Year ended December 31 2009
(in US$millions)	Operating revenues		Net operating income		Net income
Scorpion		345.4		109.1		60.6
SapuraCrest		1,062.9		116.9		98.5
Varia Perdana		144.7		93.3		92.0
Tioman		239.4		8.6		6.9
TOTAL		1,792.4		327.9		258.0

	Year ended December 31 2008
(in US$millions)	Operating revenues		Net operating income			Net income
Scorpion		161.0		(12.0	)		(30.1	)
SapuraCrest		1,039.7		115.8			75.2
Varia Perdana		157.4		72.8			69.9
Tioman		255.0		(0.1	)		0.3
Apexindo		41.2		13.4			6.5
TOTAL		1,654.3		189.9			121.8

F-27

	Year ended December 31 2007
(in US$millions)	Operating revenues		Net operating income		Net income
Scorpion		-		-		-
SapuraCrest		-		-		-
Varia Perdana		108.7		34.4		31.4
Tioman		190.2		8.5		6.2
Apexindo		200.0		100.9		34.4
TOTAL		498.9		143.8		72.0

Scorpion Offshore Limited is a company incorporated in Bermuda and listed on the Oslo Stock Exchange, which operates a fleet of jack-up drilling rigs.

SapuraCrest Bhd is a company incorporated and listed on the stock exchange in Malaysia, which provides drilling and related services to offshore oil and gas industries in Malaysia and other countries.

Varia Perdana Sdn Bhd is a company incorporated in Malaysia, which operates a fleet of tender rigs. It is a subsidiary of SapuraCrest Bhd.

Tioman Drilling Company Sdn Bhd is a company incorporated in Malaysia, which provides well services. It is a subsidiary of SapuraCrest Bhd.

Apexindo is a company incorporated in Indonesia, which provides drilling and related services in Indonesia and other countries.

At the year-end the book values of the Company's investment in associated companies are as follows:

(In millions of US dollar)	December 31, 2009		December 31, 2008

Scorpion		103.9		53.1
SapuraCrest		86.2		62.8
Apexindo		-		-
Tioman		6.7		6.2
Varia Perdana		124.2		118.0
Total		321.0		240.1

In 2008, the Company recorded impairment charges of $247.5 and $62.2 relating to the investments in Scorpion and SapuraCrest, respectively, (see note 9). The book value at December 31, 2008 has been determined using the quoted market price of the Company's shares in these two companies. There are no quoted market values for Varia Perdana or Tioman.

At year-end the share of recorded equity in the statutory accounts of the Company's associated companies are as follows:

(In millions of US dollar)	December 31, 2009		December 31, 2008		December 31, 2007

Scorpion		200.3		149.8		-
SapuraCrest		98.9		62.4		-
Apexindo		-		-		68.4
Tioman		6.7		6.2		6.2
Varia Perdana		104.1		89.4		62.9
Total		410.0		307.8		137.5

The difference between the book value and the recorded equity is due to the surplus values and goodwill related to the rig fleet at the time of acquisition (Varia Perdana/Tioman Drilling), and due to uncertainty in the market relating to the financing and market conditions for the jack-up fleet (SapuraCrest and Scorpion).

Note 17 – Newbuildings

(In millions of US dollar)	December 31, 2009			December 31, 2008
Opening balance		3,660.5			3,339.8
Additions		1,072.9			2,439.9
Capitalized interest and loan related costs		80.3			151.3
Re-classified as Drilling Units		(3,382.8	)		(2,270.5	)
Closing balance		1,430.9			3,660.5

F-28

Note 18 – Drilling units

(In millions of US dollar)	December 31, 2009			December 31, 2008
Cost		8,251.7			5,056.2
Accumulated depreciation		(737.4	)		(410.7	)
Net book value		7,514.3			4,645.5

Depreciation and amortization expense was $368.9 million, $208.5 million and $169.8 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Note 19 – Goodwill and other intangible assets

In the years ended December 31, 2008 and 2007 the Company acquired several entities which have been consolidated into its financial statements since their acquisition dates – see Note 25 "Acquisitions". The assets and liabilities of the acquired entities were measured at fair value at their date of acquisition, and the purchase price paid in excess of the net fair value of the identifiable assets and liabilities acquired was allocated to goodwill. Goodwill relates to human capital, synergies and expected market opportunities. All of the goodwill acquired in the years ended December 31, 2008 and 2007 was assigned to the Well Services operating segment, apart from $209.8 million arising in 2007 on the step-up acquisition of Eastern Drilling AS which was assigned to the Mobile Units operating segment. There were no acquisitions in 2009.

As described in Note 2 "Accounting policies", the Company tests the value of goodwill at the end of each financial year and if the book value exceeds the fair value then an impairment loss is taken. In the years ended December 31, 2009 and 2008 no impairment losses were necessary. Also in these years, there was no goodwill included in disposals.

Goodwill:

(In millions of US dollar)	December 31, 2009		December 31, 2008
Net book balance at January 1		1,547.3		1,509.5
Goodwill acquired during the year		-		112.2
Impairment losses		-		-
Currency adjustments		48.7		(74.4	)
Net book balance at December 31		1,596.0		1,547.3

Other intangible assets:

(In millions of US dollar)	December 31, 2009			December 31, 2008
Net book balance at January 1		20.1			-
Intangible assets acquired during the year		-			23.7
Depreciation		(4.1	)		(2.2	)
Currency adjustments		7.5			(1.4	)
Net book balance at December 31		23.5			20.1

Note 20– Equipment

Equipment consists of office equipment, furniture and fittings.

(In millions of US dollar)	December 31, 2009			December 31, 2008
Cost		210.6			164.4
Accumulated depreciation		(95.5	)		(81.3	)
Net book value		115.1			83.1

Depreciation and amortization expense was $27.0 million, $24.7 million, and $13.1 million for the years ended December 31, 2009, 2008 and 2007, respectively.

F-29

Note 21 - Other non-current assets

(In millions of US dollar)	December 31, 2009		December 31, 2008
Other non-current assets consists of:
Long-term part of deferred charges		57.8		43.8
Non-current receivables		1.3		1.3
Other		36.1		43.4
Total other non-current assets		95.2		88.5

Deferred charges represent debt arrangement fees that are capitalized and amortized to interest expense over the life of the debt instrument.

(In millions of US dollar)	December 31, 2009			December 31, 2008

Debt arrangement fees		119.6			76.3
Accumulated amortization		(38.6	)		(15.3	)
Total book value		81.0			61.0
Less: Short-term portion		(23.2	)		(17.2	)
Long-term portion		57.8			43.8
Amortization for the period		23.3			12.7

Note 22 – Long-term interest bearing debt and interest expenses

As of December 31, 2009 and 2008, the Company had the following debt facilities:

(inUS$millions)	2009			2008
Credit facilities
US$1,500 facility		1,140.7			1,339.3
US$1,500 facility		658.8			-
US$185 facility		45.0			71.6
US$100 facility		41.7			91.6
US$800 facility		724.8			668.3
US$585 facility		436.3			485.9
US$100 facility		86.1			96.9
US$1000 facility		-			792.1
NOK 1,500 facility (Seawell)		210.6			203.4
NOK other loans and leasing		5.6			3.3
Total Bank Loans + other		3,349.6			3,752.4
Ship Finance International Loans
US$1,500 facility
US$165 facility		-			106.7
US$170 facility		110.8			120.8
US$700 facility		618.7			688.5
US$1,400 facility		1,255.3			1,142.8
Total Ship Finance Facilities		1,984.8			2,058.8
Bonds and convertible bonds
Bonds		250.9			245.4
Convertible bonds		1,399.2			1,000.0
Total Bonds		1,650.1			1,245.4
Other credit facilities with corresponding restricted cash deposit		411.4			380.2

Total interest bearing debt		7,395.9			7,436.8
Less: current portion		(774.1	)		(746.1	)
Long-term portion of interest bearing debt		6,621.8			6,690.7

F-30

The outstanding debt as of December 31, 2009 is repayable as follows:

(inUS$millions) Year ending December 31
2010	774.1
2011	834.7
2012	2126.3
2013	2,028.1
2014 amd therafter	1,733.5
Effect of amortization of convertible bond	(100.8	)
Total debt	7,395.9

Credit facilities

$1,500 million secured credit facilities

In June 2007 the Company entered into a $1,500 million senior secured loan facility with a syndicate of banks to partly fund the acquisition of four drilling units, West Epsilon, West Navigator, West Alpha and West Venture, which have been pledged as security. The net book value at December 31, 2009 of the units pledged as security is $1,349.8 million. At December 31 2009 the outstanding balance was $1,141 million, and in addition an undrawn but committed and available amount of $70 million. The facility bears interest at LIBOR plus a margin of between 0.90% and 1.35% per annum depending on the ratio of net debt to EBITDA, and is repayable over a term of seven years. At maturity a balloon payment of $600 million is due.

$1,500 million secured credit facilities

In June 2009 the Company established a $1,500 million senior secured loan facility with a syndicate of banks and export credit facility agents, to partly fund the acquisition of the jack-up rigs West Capella, West Sirius, West Ariel and West Aquarius, which have been pledged as security. The net book value at December 31, 2009 of the units pledged as security is $1,935.3 million. The facility bears interest at LIBOR plus 3.25% per annum and is repayable over a term of five years. At maturity a balloon payment of $288.2 million is due. The outstanding balance at December 31 2009 was $659 million, and in addition an undrawn but committed amount of $753 million, though in part available only subject to the delivery of West Orion ($150 million) and West Gemini ($150 million).

$185 million secured term loan

In July 2005 the Company entered into a $185 million secured term loan facility with a bank to partly fund the acquisition of the jack-up rigs West Larissa and West Janus, which have been pledged as security. The net book value at December 31, 2009 of the units pledged as security is $69.1 million. The facility bears interest at LIBOR plus 1.25% per annum and is repayable over a term of five years. At maturity a balloon payment of $25 million is due.

$100 million secured term loan

In October 2005 the Company entered into a $100 million secured term loan facility with a bank to partly fund the acquisition of the jack-up rigs West Atlas and West Triton, which have been pledged as security. Pursuant to the incident at the Montana field the West Atlas was declared a Total Loss (as defined in the Loan Agreement), and 50 % of the loan was prepaid. The net book value at December 31, 2009 of the unit pledged as security is $143.0 million. The facility bears interest at LIBOR plus 1.25% per annum and is repayable over a term of five years. At maturity a balloon payment of $37.5 million is due.

$800 million secured term loan

In August 2005 the Company entered into a $300 million secured term loan facility with a syndicate of banks to partly fund the acquisition of two semi-submersible rigs, West Eminence and West Phoenix, which have been pledged as security. The facility was amended and increased in 2006 to $800 million. The net book value at December 31, 2009 of the units pledged as security is $1,481.4. The facility consists of two tranches, and bears interest at LIBOR plus 1.70% and 3.25%per annum. The final repayment of $367.5 million is due in 2013.

F-31

$585 million secured term loan

In December 2006 the Company entered into a $585 million secured term loan facility with a syndicate of banks to partly fund the acquisition of eight tender rigs, which have been pledged as security. The net book value at December 31, 2009 of the units pledged as security is $424.0 million. The facility bears interest at LIBOR plus between 0.70% and 1.00% per annum depending on the ratio of net debt to EBITDA, and is repayable over a term of six years. At maturity a balloon payment of $300 million is due.

$100 million secured term loan

In April 2008 the Company entered into a $100 million secured term loan facility with a two banks to partly fund the acquisition of the tender rig T-11, which has been pledged as security. The net book value at December 31, 2009 of the unit pledged as security is $89.7 million. The facility bears interest at a fixed rate of 3.025% per annum and is repayable over a term of six years. At maturity a balloon payment of $60 million is due.

NOK1,500 million Senior Debt facility

In December 2007 the Company's 73.79% subsidiary Seawell entered into a five year $260.2 million (NOK1,500 million) multi-tranche Senior Debt facility with a syndicate of banks to finance working capital. The facility bears interest at NIBOR plus 1.50% per annum.

Other Seawell NOK loans

Two Seawell subsidiaries acquired in 2008, Seawell Oiltools AS (formerly Peak Well Solutions AS) and Tecwel AS, have loans totaling $5.6 million (NOK32.5 million).

Ship Finance International Loans

In February 2007 the Company entered into a sale and leaseback agreement for the jack-up rig West Prospero with Rig Finance II Ltd, a subsidiary of Ship Finance. Rig Finance II Ltd is consolidated as a VIE by the Company. In February 2007 Rig Finance II Ltd entered into a US$170 million secured term loan facility with a syndicate of banks to partly fund the acquisition of West Prospero, which has been pledged as security. The net book value at December 31, 2009 of the unit pledged as security is $195.8 million. The facility bears interest at LIBOR plus 0.90 % to 1.20% per annum depending on the ratio of market value to loan, and is repayable over a term of six years.

In May 2008 the Company entered into a sale and leaseback agreement for the drillship West Polaris with SFL West Polaris Limited, a subsidiary of Ship Finance. SFL West Polaris Limited is consolidated as a VIE by the Company. In July 2008 SFL West Polaris Limited entered into a US$700 million secured term loan facility with a syndicate of banks to partly fund the acquisition of West Polaris, which has been pledged as security. The net book value at December 31, 2009 of the unit pledged as security is $662.0 million. The facility bears interest at LIBOR plus 1.25% per annum and is repayable over a term of five years.

In September 2008 the Company entered into a sale and leaseback agreement for the two semi-submersible rigs West Taurus and West Hercules with SFL Deepwater Ltd, a subsidiary of Ship Finance. SFL Deepwater Ltd is consolidated as a VIE by the Company. In September 2008 SFL Deepwater Ltd entered into a $1,400 million secured term loan facility with a syndicate of banks to partly fund the acquisition of West Taurus and West Hercules, which have been pledged as security. The net book value at December 31, 2009 of the units pledged as security is $1,120.3 million. The facility bears interest at LIBOR plus 1.40% per annum and is repayable over a term of five years.

Bonds and convertible bonds

$30 million floating rate bond

In February 2005 the Company's acquired subsidiary Smedvig raised $30.0 million through the issue of a seven year bond which matures in February 2012. The bond bears quarterly interest of LIBOR plus 2.03%.

F-32

NOK500 million floating rate bonds

In September 2005 the Company raised $86.7 million (NOK500 million) through the issue of a seven year bond. The bond bears quarterly interest of NIBOR plus 1.60% per annum.

NOK800 million floating rate bonds

In November 2009, the Company raised $134.2 million (NOK800 million) trough the issue of a two year bond. The bond bears quarterly interest at NIBOR plus 2.75% per annum.

3.625% Convertible Bonds due 2012

In November 2007 the Company issued at par $1,000 million of convertible bonds. Interest on the bonds is fixed at 3.625% per annum, payable semi-annually in arrears. The bonds may be converted into Seadrill Limited common shares by the holders at any time up to 10 banking days prior to November 8, 2012. The conversion price set at the time of issuance was $34.474 per share, representing a 45% premium to the share price at the time. Since then, dividend distributions have reduced the conversion price to $31.58. The bond contains covenants, the principle one requiring the Company to maintain a market adjusted equity ratio of at least 30%.

The Company has a right to redeem the bonds at par plus accrued interest at any time following November 29, 2010, if the Company's share price is greater than 130% of the prevailing conversion price on at least 20 trading days during a period of 30 consecutive days, or at any time provided that 90% or more of the principal issued has been redeemed or converted to shares. The convertible bonds are tradable, and their market price on April 08, 2010 was 103.00 percent of nominal value. If the bonds were converted into shares at the current conversion price of $31.58, a further 31,665,661 new shares would be issued.

4.875% Convertible Bonds due 2014

In September 2009 the Company issued at par $500 million of convertible bonds. Interest on the bonds is fixed at 4.875% per annum, payable semi-annually in arrears. The bonds may be converted into Seadrill Limited common shares by the holders at any time up to 10 banking days prior to September 29, 2014. The conversion price set at the time of issuance was $25.18 per share, representing a 35% premium to the share price at the time. Since then, dividend distributions have reduced the conversion price to $24.59. The bond contains covenants, the principle one requiring the Company to maintain a market adjusted equity ratio of at least 30%.

The Company has a right to redeem the bonds at par plus accrued interest at any time following October 20, 2012, if the Company's share price is greater than 130% of the prevailing conversion price on at least 20 trading days during a period of 30 consecutive days, or at any time provided that 90% or more of the principal issued has been redeemed or converted to shares. The obligation of the Company to issue shares on the exercise of any bondholder's conversion rights may, at the sole discretion of the Company, be settled, in whole or in part, by cash payment.The convertible bonds are tradable, and their market price on April 08, 2010 was 120.75 percent of nominal value. If the bonds were converted into shares at the current conversion price of $24.59, a further 20,333,468 new shares would be issued.

Commercial Interest Reference Rate (CIRR) Credit Facilities

In April 2008 the Company entered into a CIRR term loan for NOK850 million with Eksportfinans ASA, the Norwegian export credit agency. The loan bears fixed interest at 4.56% per annum and is repayable over a term of eight years. The outstanding balance at December 31, 2009 was $121.5 million (NOK699.8 million).

In June 2008 the Company entered into a CIRR term loan for NOK904 million with Eksportfinans ASA. The loan bears fixed interest at 4.15% per annum and is repayable over a term of eight years. The outstanding balance at December 31, 2009 was $129.1 million (NOK744.4 million).

In July 2008 the Company entered into a CIRR term loan for NOK1,011 million with Eksportfinans ASA. The loan bears fixed interest at 4.15% per annum and is repayable over a term of twelve years. The outstanding balance at December 31, 2009 was $160.8 million (NOK927.0 million).

F-33

In connection with the above three CIRR fixed interest term loans totalling $411.4 million (NOK2,371.2 million), interest rate swaps and collateral cash deposits equal to the total outstanding loan balances have been established with commercial banks. The collateral cash deposits are reduced in parallel with repayments of the CIRR loans and receive fixed interest at the same rates as those paid on the CIRR loans. The collateral cash deposits are classified as "restricted cash" in the balance sheet, and the effect of these arrangements is that the CIRR loans have no effect on net interest bearing debt.

Covenants on loans and bonds

In addition to security provided to lenders in the form of pledged assets, agreements relating to long-term debt generally contain financial covenants, the main ones being as follows:

·	Minimum liquidity requirements: to maintain cash and cash equivalents of at least $100 million within the group.

·	Interest coverage ratio: to maintain an EBITDA to interest expense ratio of at least 2.5:1.

Current ratio: to maintain current assets to current liabilities ratio of at least 1:1. Current assets are defined as book value less minimum liquidity, but including up to 20% of shares in listed companies owned 20% or more. Current liabilities are defined as book value less the current portion of long term debt.

·	Equity ratio: to maintain total equity to total assets ratio of at least 30%. Both equity and total assets are adjusted for the difference between book and market values of drilling units.

·	Leverage ratio: to maintain a ratio of net debt to EBITDA no greater than 4.5:1. Net debt is calculated as all interest bearing debt less cash and cash equivalents excluding minimum liquidity requirements.

The main covenants for the Company's bonds are to maintain adjusted shareholders' equity of at least $1,500 million and a ratio of adjusted shareholders' equity to total liabilities of at least 30% to 40%. Adjusted shareholder's equity is book value of equity adjusted for the difference between book and market values of drilling units.

As of December 31, 2009, the Company is in compliance with all of the covenants under its long-term debt facilities.

Note 23 – Other current liabilities

Other current liabilities are comprised of the following:

(In millions of US dollar)	December 31, 2009		December 31, 2008

Taxes payable		45.4		61.1
Employee withheld taxes, social security and vacation payment		64.1		53.3
Short-term portion of unfavorable contract values		39.5		43.0
Accrued interest expense		36.7		33.4
Liabilities relating to investment in shares (1)		498.7		336.5
Unrealized loss on forward contracts not classified as derivatives (2)		-		157.9
Short term portion of deferred mobilization revenues		65.6		21.6
Derivative financial instruments (3)		101.5		168.8
Other current liabilities		323.8		316.3
Total other current liabilities		1,175.3		1,191.9

(1) Liabilities relating to the Company's share forward contracts are recorded as short-term debt.

(2) Accrual for loss relating to forward share contracts where the contracts were not defined as derivative, while the loss was expensed as of December 31, 2008.

(3) Derivative financial instruments consist of unrealized losses on interest rate swap agreements, currency forward contracts and total return swap agreements (see Note 31).

F-34

Note 24 – Other non-current liabilities

Other non-current liabilities are comprised of the following:

(In millions of US dollar)	December 31, 2009		December 31, 2008

Accrued pension liabilities		37.7		55.8
Long-term portion of unfavorable contract values		23.4		62.8
Long term portion of deferred mobilization revenues		138.9		56.2
Other non-current liabilities		38.1		34.2
Total other non-current liabilities		238.1		209.0

Note 25 – Acquisitions

Acquisitions in 2009

There have been no acquisitions in 2009.

Acquisitions in 2008

Noble Drilling

In April 2008 the Company acquired the entire issued share capital of Noble Drilling UK Limited ("Noble Drilling"), a well services company incorporated in the United Kingdom. Noble Drilling was the North Sea Platform Division of Noble Corporation, a company incorporated in Switzerland and listed on the NYSE. The purchase price was $53.9 million, including working capital.

Peak Well

In March 2008 the Company acquired the entire issued share capital of Peak Well Solutions AS ("Peak Well"), a well services company incorporated in Norway. The purchase price was $85.0 million, including working capital.

Tecwel

In May 2008 the Company acquired the entire issued share capital of Tecwel AS ("Tecwel"), a well services company incorporated in Norway. The purchase price was $34.3 million, including working capital.

The purchase price of the acquired companies has been allocated as follows:

(in US dollar million)	Noble Drilling		Peak Well		Tecwel		Total
Assets:
Intangible assets		8.5		14.1		12.2		34.9
Goodwill		30.5		61.0		20.7		112.2
Fixed assets		-		6.3		3.7		10.0
Receivables and other current assets		17.6		14.8		5.2		37.6
Total assets		56.6		96.2		41.9		194.7

Liabilities:
Deferred tax		2.4		0.4		3.4		6.2
Payables and other current liabilities		0.3		10.8		4.2		15.3
Total liabilities		2.7		11.2		7.6		21.5

Purchase Price		53.9		85.0		34.3		173.2

F-35

Acquisition in 2007

Eastern Drilling

At December 31, 2006 the Company owned approximately 60.4% of the shares in Eastern Drilling.AS ("Eastern Drilling") -see below. On April 18, 2007 the Company made a mandatory offer for all of the outstanding shares in Eastern Drilling at a price of NOK135 per share. The offer price was determined by a ruling of the Oslo Stock Exchange Appeals Committee following a disagreement between the Company and the Oslo Stock Exchange relating to the Company's use in 2006 of Total Return Swap Agreements linked to Eastern Drilling shares. Following the mandatory offer, Eastern Drilling becoming a wholly-owned subsidiary of the Company and the total cost of increasing the Company's shareholding from 60.4% to 100% amounted to $401.8 million.

Wellbore

In November 2007 the Company acquired a controlling interest in Wellbore Solutions AS ("Wellbore"), a well services company incorporated in Norway. The purchase price was $4.6 million, including working capital.

The purchase price of Wellbore and Eastern Drilling has been allocated as follows:

(in US dollar million)	Wellbore		Eastern Drilling		Total
Assets
Goodwill		2.9		213.6		216.5
Settlement of non-controlling interest		-		209.8		209.8
Deferred tax assets (on Unfavorable Contracts)		-		8.4		8.4
Other non current assets		1.1		-		1.1
Receivables and other current assets		0.6		-		0.6
Total assets		4.6		431.8		436.4

Liabilities: unfavorable contracts		-		30.0		30.0

Purchase price		4.6		401.8		406.4

Note 26 – Non-controlling interest

The Company's consolidated Statement of Operations, Balance Sheet and Statement of Cash Flows include Seawell, whose issued share capital is 73.79% owned by the Company. The part of Seawell's total shareholders' equity not attributable to the Company is included in non-controlling interest.

In 2007 and 2008 the Company entered into five sale and leaseback arrangements for drilling rigs with Ship Finance, who incorporated subsidiary companies for the sole purpose of owning and leasing the rigs. The Company has recognised these subsidiary companies as VIEs and concluded that the Company is their primary beneficiary. Accordingly, these subsidiary companies are included in the Company's consolidated accounts, with the Ship Finance equity in these companies included in non-controlling interest.

For the years ended December 31, 2008 and 2007, the Other Comprehensive Income in these VIEs is not included in non-controlling interest, as it represents fair value adjustments to interest rate swaps designated as hedges on variable interest rate loans taken out by the VIEs, these swaps having been requirements of the lease contracts between the VIEs and Seadrill. Due to new accounting rules effective from January 1, 2009, the Other Comprehensive Income generated after this date has been allocated to non-controlling Interest.

Changes in non-controlling interest in 2009, 2008 and 2007 are as follows:

(in US dollar million)	Eastern Drilling			Seawell		Ship Finance			Total
January 1, 2007		162.1			-		49.9			212.0
Changes in 2007		(162.1	)		1.2		40.5			(120.4	)
2007 net income		-			1.2		11.8			13.0
January 1, 2008		-			2.4		102.2			104.6
Changes in 2008		-			6.5		440.0			446.5
2008 net income		-			5.1		36.6			41.7
December 31, 2008		-			14.0		578.8			592.8
Changes in 2009		-			8.7		(59.5	)		(50.8	)
2009 net income		-			7.5		84.4			91.9
December 31, 2009		-			30.2		603.7			633.9

F-36

Note 27 – Share capital

	2009						2008						2007
All shares are common shares of $2.00 par value each	Shares			$millions			Shares			$millions			Shares			$millions
Authorized share capital		800,000,000			1,600.0			800,000,000			1,600.0			800,000,000			1,600.0

Issued and fully paid share capital		399,133,216			798.3			399,133,216			798.3			399,133,216			798.3
Treasury shares held by Company		(110,200	)		(0.3	)		(717,800	)		(1.4	)		(608,700	)		(1.2	)
Outstanding shares in issue		399,023,016			798.0			398,415,416			796.9			398,524,516			797.1

As of December 31, 2009, the Company's shares are listed on the Oslo Stock Exchange. In April 2010, the Company was also listed on the New York Stock Exchange (refer note 34 subsequent events).

The Company was incorporated on May 10, 2005 and 6,000 ordinary shares of par value $2.00 each were issued. Since incorporation the number of issued shares has increased from 6,000 to 399,133,216 of par value $2.00 each at December 31, 2009. No shares were issued in 2009.

A share repurchase program was approved by the Board in 2007 giving the Company the authorization to buy back shares. Shares bought back under the authorization may be cancelled or held as treasury shares. Treasury shares may be held to meet the Company's obligations relating to the share option scheme (see Note 28). As at December 31, 2009 the Company holds 110,200 treasury shares and net shares outstanding at December 31, 2009 were 399,023,016.

In September 2008, the shareholders in the annual general meeting approved the reduction of the share premium account from US $1,955.4 to nil and the transfer of the balance of $1,955.4 to the Company's Contributed Surplus

Note 28 – Share option plans

Seadrill Scheme:

In May 2005, a general meeting of the Company approved authorizing the Board of Directors to establish and maintain an option scheme (the "Seadrill Scheme") for encouraging the holding of shares in the Company. The Seadrill Scheme will expire in May 2016. The Seadrill Scheme permits the board of directors, at its discretion, to grant options to acquire shares in the Company to employees and directors of the Company or its subsidiaries. The options are not transferable. The subscription price is at the discretion of the board of directors provided the subscription price is never reduced below the par value of the share. The subscription price for certain options granted under the scheme will be reduced by the amount of all dividends declared by the Company in the period from the date of grant until the date the option is exercised. Options granted under the scheme will vest at a date determined by the board at the date of the grant. The options granted under the plan to date vest over a period of one to three years. There is no maximum number of shares authorised for awards of equity share options and authorised, unissued or treasury shares of the Company may be used to satisfy exercised options.

F-37

In May 2009, 214 employees still holding valid 2008 granted share options were offered a repricing of these options and an extention of their maturity date to May 2014. The new strike was NOK90.833 ($14.09) for non-American employees and NOK104.64 ($16.23) for the American employees. The repricing created an additional cost of $4 million, recognized as expenses of $1.4 million in 2009, $1.7 million 2010 and $0.9 million in 2011/12. The fair value of each option was estimated on the date of the grant using a Black Scholes option valuation model, with the following assumptions: risk-free interest rate of 3.8%, volatility of 40%, a dividend yield of 0% and an expected option term of 5 years. The risk-free interest rates were estimated using the published Norwegian treasury yield curve in effect at the time of grant for instruments with a similar life. The dividend yield has been estimated at 0% as the exercise price is reduced by all dividends declared by the Company from the date of grant to the exercise date. It was assumed that 90% of options granted under the plan will vest. The expected term is based on historical information of past employee behavior regarding exercises and forfeiture of options. The Company uses a blended volatility for the volatility assumption, to reflect the expectation of how the share price will react to the future cyclicality of the Company's industry. The blended volatility is calculated using two components. The first component is derived from volatility computed from historical data for a period of time approximately equal to the expected term of the stock option, starting from the date of grant. The second component is the implied volatility derived from the Company's "at-the-money" long-term call options. The two components are equally weighted to create a blended volatility.

The fair value of share options granted is recognized as personnel expenses, and in the year ended December 31, 2009, $14.9 million were expensed in the income statement. There were no effects on taxes in the financial statements. However if the option is exercised a tax benefit will be recorded, as the gain is recorded as deductible for tax purposes. If the Company has to expense social security taxes related to the benefit of options exercised such expenses will be recorded at the exercise date.

The following summarizes share option transactions related to the Seadrill Scheme in 2009, 2008 and 2007:

	2009					2008					2007
	Options			Weighted average exercise price US$		Options			Weighted average exercise price US$		Options			Weighted average exercise price US$

Outstanding at beginning of year		5,978,100			18.11		4,088,700			13.30		3,916,667			12.17
Granted		1,026,000			14.45		2,658,000			25.38		700,000			18.17
Exercised		(607,600	)		14.84		(490,900	)		14.86		(427,967	)		11.47
Forfeited		(196,667	)		19.42		(277,700	)		18.59		(100,000	)		14.07
Outstanding at end of year		6,199,833			13.87		5,978,100			18.11		4,088,700			13.30
Exercisable at end of year		2,682,811			12.20		1,839,133			11.90		922,033			11.75

Options granted in 2006 had initial exercise prices between $2.23 and NOK102 ($16.28) per share, may be exercised one third each year beginning 12 months after they were granted, and expire between May 2010 and September 2011. Options granted in 2007 had initial exercise prices between NOK98.63 ($15.23) and NOK129.63 ($22.35) per share, may be exercised one third each year beginning 12 months after they were granted, and expire in September 2011. Options granted in 2008 had been repriced with exercise prices now being NOK 90.83 ($14.09) and NOK104.64 ($16.24) per share; they may be exercised one third each year beginning 12 months after they were granted, and expire in May 2014. These same prices and dates apply to the options granted in 2009.

The weighted average grant-date fair value of options granted during 2009 is $5.63 per share (2008: $12.59 per share, 2007: $6.70 per share). The exercise price of all options is reduced by the amount of any dividends declared.

As of December 31, 2009 there was $12.4 million in unrecognized compensation costs relating to non-vested options granted under the Options Schemes (2008: $19.4 million). This amount will be recognized as expenses of $8.7 million in 2010, $3.3 million in 2011 and $0.5 million in 2012.

There were 6,199,833 options outstanding at December 31, 2009 (2008: 5,978,100). Their weighted average remaining contractual life was 38 months (2008: 38 months) and their weighted average fair value was $10.35 per option (2008: $10.49 per option). The weighted average parameters used in calculating these weighted average fair values are as follows: risk-free interest rate 4.02% (2008: 4.69%), volatility 37% (2008: 35%), dividend yield 0% (2008: 0%), option holder retirement rate 6% (2008: 5%) and expected term 5 years (2008: 5 years).

During 2009 the total intrinsic value of options exercised was $5.3 million on the day of exercise. The intrinsic value of options full vested but not exercised at December 31, 2009 was $35.6 million and their average remaining term was 19 months.

F-38

Seawell Scheme:

In addition to the Seadrill Scheme, in 2007 the Company's 73.79% owned subsidiary Seawell introduced an option scheme under which its senior management and directors may be granted options to subscribe for new shares. In 2007 options for 4,097,000 shares in Seawell were granted, which may be exercised by one third per year, first time on January 1, 2009. Therefore as at December 31, 2009, one third of the options granted under program 1 are exercisable. The options are not transferable and may be withdrawn upon termination of employment. The exercise price was initially NOK13.75 ($1.96) per share increasing by 6 percent on each anniversary date. Options issued under the 2007 Program may be exercised up to October 5, 2012.

No options were granted in 2008, but in 2009 options for 1,600,000 shares were issued under a new program. Options issued under the 2009 program may be exercised up to December 31, 2015. The exercise price is NOK 10 per share. They may be exercised by one third per year, first time on January 1, 2010.

The fair value of share options granted is recognized as personnel expenses, and in the year ended December 31, 2009, $1.1 million were expensed in the income statement.

As in the Seadrill Scheme, Seawell has used the Black & Scholes pricing model to estimate the fair value of the options granted. The following table summarizes the information of share options outstanding as of December 31, 2009:

Option program	2007 Program			2009 Program

Number of shares		4,097,000			1,600,000
Exercise price		14.80-18.40			10.00
Remaining contractual life (months)		45			72

Pricing model assumptions:

Risk free interest rate (percent)		5.55			3.65
Expected life (years)		5			6.92
Volatility		37	%		41	%
Expected retirement of option holders		10	%		10	%
Expected dividend		0			0

Average fair value of grants		4.50			3.39

As of December 31, 2009, total unrecognized compensation costs related to all unvested share-based awards totaled NOK 3.3 million, which is expected to be recognized as expenses in 2010 and 2011 by, NOK 2.8 million and NOK 0.5 million, respectively. When any options are exercised, employers' national insurance contributions will be payable by Seawell, while the option holders will be charged for their individual income taxes.

Note 29 - Pension benefits

The Company has a defined benefit pension plan covering substantially all Norwegian employees. A significant part of this plan is administered by a life insurance company.

The primary benefits for the onshore employees in Norway are a retirement pension of approximately 66 percent of salary at retirement age of 67 years, together with a long-term disability pension. The retirement pension per employee is capped at an annual payment of 66 percent of the total of 12 times the Norwegian Social Security Base. Most employees in this group may choose to retire at 62 years of age on a pre-retirement pension. Offshore employees in Norway have retirement and long-term disability pension of approximately 60 percent of salary at retirement age of 67. Offshore employees on mobile units may choose to retire at 60 years of age on a pre-retirement pension. Offshore employees on fixed installations have the same pre-retirement pension, but the employees may not retire until they are 62 years of age.

On December 31, 2006, Seadrill adopted the recognition and disclosure provisions of ASC Topic 715 Compensation – Retirement Benefits (formerly SFAS No.158, Employer's Accounting for Defined Benefit Pension and other Postretirement Plans, an amendment of formerly FASB Statements No. 87, 88 and 123(R)). ASC Topic 715 requires the recognition of the funded status of the Defined Benefit and Postretirement Benefits Other Than Pensions ("OPEB") plans on the December 31, 2006 balance sheet with a corresponding adjustment to accumulated other comprehensive income. The adjustment to accumulated other comprehensive income at adoption represents the net unrecognized actuarial losses, unrecognized prior service costs, and unrecognized transition obligation remaining from the initial application of ASC Topic 715, all of which were previously netted against the plans' funded status on the balance sheet. These amounts will be subsequently recognized as net periodic pension cost pursuant to our historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension cost in the same periods will be recognized as a component of other comprehensive income. Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income.

F-39

Effect of formerly SFAS No. 158 on the consolidated balance sheet

(in US dollar million)	2009			2008

Non-current liabilities		(23.7	)		(1.7	)
Deferred tax		6.6			0.5
Shareholders equity		(17.1	)		(1.3	)

Annual pension cost

(in US dollar million)	2009			2008			2007

Benefits earned during the year		18.0			19.3			20.4
Interest cost on prior years' benefit obligation		9.2			7.7			6.3
Gross pension cost for the year		27.2			27.0			26.7
Expected return on plan assets		(7.3	)		(6.0	)		(4.9	)
Administration charges		0.5			0.4			0.2
Net pension cost for the year		20.3			21.4			22.0
Social security cost		2.9			3.0			3.1
Amortization of actuarial gains/losses		(0.5	)		(0.7	)		(0.1	)
Amortization of prior service cost		-			-			-
Amortization of net transition assets		-			-			0.1
Total net pension cost		22.6			23.7			25.1

The funded status of the defined benefit plan

(in US dollar million)	December 31, 2009			December 31, 2008
Projected benefit obligations		171.5			141.8
Plan assets at market value		(138.9	)		(92.9	)
Accrued pension liability exclusive social security		32.6			48.9
Social security related to pension obligations		5.1			6.9
Accrued pension liabilities		37.7			55.8

Change in benefit obligations

(in US dollar million)	2009			2008

Benefit obligations at beginning of year		141.7			158.3
Interest cost		9.2			7.7
Current service cost		18.0			19.3
Benefits paid		(1.4	)		(1.2	)
Change in unrecognized actuarial gain		(26.4	)		(1.9	)
Foreign currency translations		30.3			(40.4	)
Benefit obligations at end of year		171.5			141.8

Change in pension plan assets

(in US dollar million)	2009			2008

Fair value of plan assets at beginning of year		92.9			108.1
Estimated return		7.3			6.0
Contribution by employer		27.2			10.3
Administration charges		(0.5	)		(0.4	)
Benefits paid		(1.2	)		(1.0	)
Change in unrecognized actuarial loss		(8.4	)		(3.3	)
Foreign currency translations		21.6			(26.8	)
Fair value of plan assets at end of year		138.9			92.9

Pension obligations are actuarially determined and are critically affected by the assumptions used, including the expected return on plan assets, discount rates, compensation increases and employee turnover rates. The Company periodically reviews the assumptions used, and adjusts them and the recorded liabilities as necessary.

F-40

The expected rate of return on plan assets and the discount rate applied to projected benefits are particularly important factors in calculating the Company's pension expense and liabilities. The Company evaluates assumptions regarding the estimated rate of return on plan assets based on historical experience and future expectations on investment returns, which are calculated by a third party investment advisor utilizing the asset allocation classes held by the plan's portfolios. The discount rate is based on the Norwegian government 10 year-bond effective yield. Changes in these and other assumptions used in the actuarial computations could impact the projected benefit obligations, pension liabilities, pension expense and other comprehensive income.

Assumptions used in calculation of pension obligations	2009			2008			2007

Rate of compensation increase at the end of year		4.25	%		4.50	%		4.50	%
Discount rate at the end of year		5.40	%		5.80	%		5.30	%
Prescribed pension index factor		2.50	%		2.50	%		2.75	%
Expected return on plan assets for the year		5.60	%		6.30	%		5.75	%
Employee turnover		4.00	%		4.00	%		4.00	%
Expected increases in Social Security Base		4.00	%		4.25	%		4.25	%
Expected annual early retirement from age 60/62:
Offshore personnel fixed installations		30.0	%		30.0	%		30.0	%
Offshore personnel Mobile units and onshore employees		50.0	%		50.0	%		50.0	%

The weighted-average asset allocation of funds related to the Company's defined benefit plan at December 31, 2009 was as follows:

Pension benefit plan assets	2009			2008

Equity securities		13.5	%		3.8	%
Debt securities		59.0	%		58.7	%
Real estate		16.6	%		16.8	%
Money market		8.5	%		14.0	%
Other		2.4	%		6.7	%
Total		100.0	%		100.0	%

The investment policies and strategies for the pension benefit plan funds do not use target allocations for the individual asset categories. The investment objectives are to maximize returns subject to specific risk management policies. The Company diversifies its allocation of plan assets by investing in both domestic and international fixed income securities and domestic and international equity securities. These investments are readily marketable and can be sold to fund benefit payment obligations as they become payable. The estimated yearly return on pension assets was 5.6 percent in 2009 and 2.2 percent in 2008.

Cash flows - Contributions expected to be paid

The table below shows the Company's expected annual pension plan contributions under defined benefit plans for the years 2010-2019. The expected payments are based on the assumptions used to measure the Company's obligations at December 31, 2009 and include estimated future employee services.

(in US dollar million)	December 31 2009

2010		18.0
2011		19.4
2012		20.8
2013		22.4
2014		24.0
2015-2019		150.1
Total payments expected during the next 10 years		254.6

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Note 30 – Related party transactions

The Company transacts business with the following related parties, being companies in which our principal shareholders Hemen Holding Ltd and Farahead Investments Inc (hereafter jointly referred to as "Hemen") and companies associated with Hemen have a significant interest:

- Ship Finance International Limited ("Ship Finance")

- Scorpion Offshore Ltd ("Scorpion")

- Metrogas Holdings Inc ("Metrogas")

- Frontline Management (Bermuda) Limited ("Frontline")

- Aktiv Kapital ASA ("Aktiv")

The Company has entered into sale and lease back contracts for several drilling units with Ship Finance, a company in which our principal shareholders Hemen and companies associated with Hemen have a significant interest. Hemen is controlled by trusts established by the Company's President and Chairman Mr. John Fredriksen for the benefit of his immediate family. The company has determined that the Ship Finance subsidiaries, which own the units, are variable interest entities (VIEs), and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company's consolidated accounts. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in the Company's consolidated accounts (See also note 33).

In the 12 months ended December 31, 2009, the Company incurred the following lease costs on units leased back from Ship Finance subsidiaries.

Rig
West Ceres	20.4
West Prospero	29.8
West Polaris	127.3
West Hercules	122.3
West Taurus	102.1
Total	401.9

In July 2009 the Company exercised its option to repurchase the jack-up rig West Ceres from Rig Finance Ltd, the Ship Finance subsidiary which owned the unit, at the option price of $135.5 million. Accordingly, Rig Finance Ltd will no longer be consolidated as a VIE by the Company.

In November 2008, the Company granted Ship Finance an unsecured credit facility of $115.0 million, to be repaid in full by December 31, 2009. This facility is shown in the balance sheet as short- term "Amount due from related party" as of December 31, 2008. Ship Finance repaid $25.0 million in the first quarter of 2009, and the balance of $90.0 million was sold to Metrogas, a company indirectly controlled by trusts established by Mr. John Fredriksen for the benefit of his immediate family. The balance of $90.0 million was purchased back from Metrogas in the fourth quarter of 2009. At the same time the repayment schedule was amended to provide a maturity date of January 31, 2011. Consequently this facility is shown in the balance sheet as long term "Amount due from related party" as of December 31, 2009. The agreed interest payable by Ship Finance is based upon arms-length principles and is paid monthly. Interest of $8.8 and $2.1 million was received from Ship Finance in the twelve months ended December 31, 2009 and 2008 respectively.

In April 2009, the Company obtained an unsecured credit facility loan of $60.0 million from Metrogas. The amount was repaid in June 2009. Interest payable in accordance with the arms-length principles amounted to $0.7 million in the twelve months ended December 31, 2009.

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In November 2009, the Company provided a short-term unsecured loan of $27.7 million to Scorpion, increased to $79.7 million in December 2009. This facility is shown in the balance sheet as short- term "Amount due from related party" as of December 31, 2009. Interest payable in accordance with the arms-length principles amounted to $1.0 million in the twelve months ended December 31, 2009 (See also note 34 "Subsequent Events").

Frontline provides management support and administrative services for the Company, and charged the Company fees of $0.2 million, $0.2 million and $0.1 million for these services in the years 2009, 2008 and 2007, respectively. These amounts are included in "General and administrative expenses", as they do not merit separate disclosure.

In 2007 the Company sold the FPSOs Crystal Sea and Crystal Ocean. Aktiv was entitled to a 5% share of the gain on the sales and at December 31, 2007 the Company recorded a provision of $7.3 million payable to Aktiv, included in "Other current liabilities". This was settled in the first quarter of 2008.

Note 31 – Risk management and financial instruments

The majority of the Company's gross earnings from rigs and vessels are receivable in US dollars and the majority its other transactions, assets and liabilities are denominated in US dollars, the functional currency of the Company. However, the Company has operations and assets in a number of countries worldwide and incurs expenditures in other currencies, causing its results from operations to be affected by fluctuations in currency exchange rates, primarily relative to the US dollar. The Company is also exposed to changes in interest rates on variable interest rate debt, and to the impact of changes in currency exchange rates on NOK denominated debt. There is thus a risk that currency and interest rate fluctuations will have a negative effect on the value of the Company's cash flows.

Interest rate risk management

The Company's exposure to interest rate risk relates mainly to its variable interest rate debt and balances of surplus funds placed with financial institutions. This exposure is managed through the use of interest rate swaps and other derivative arrangements. The Company's policy is to obtain the most favourable interest rate borrowings available without increasing its foreign currency exposure. Surplus funds are generally placed in fixed deposits with reputable financial institutions, yielding higher returns than are available on cash at bank. Such deposits generally have short-term maturities, in order to provide the Company with flexibility to meet all requirements for working capital and capital investments.

The extent to which the Company utilizes interest rate swaps and other derivatives to manage its interest rate risk is determined by reference to its net debt exposure and its views regarding future interest rates. At December 31, 2009, the Company had interest rate swap agreements with an outstanding prcincipal of $2,854 million(2008: 1,740 million). In addition, the Company had outstanding cross currency interest rate swaps at December 31, 2009 with a principal amount of USD 174.4(2008: 34.3 million) These agreements do not qualify for hedge accounting, and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Statement of Operations under "Gain/(loss) on derivative financial instruments". The combined total fair value of the interest rate swaps and cross currency interest swaps outstanding December 31, 2009 amounted to minus $ 67.4 million.

The Company's interest rate swap and cross currency interest rate swap agreements as at December 31, 2009, were as follows:

Oustanding principal	Receive rate	Pay rate	Length of contract
(In US$millions)
50	3 month LIBOR	4.6300%	May 2005 - May 2015
34 (NOK 220 mill)	3 month NIBOR+1.2%	3 month LIBOR+1.3%	Sept 2005 - Sept 2012
124	6 month LIBOR	3.8250%	April 2008 - Sept 2016
350	3 month LIBOR	4.1030%	June 2008 - June 2013
300	3 month LIBOR	4.1450%	June 2008 - June 2013
350	3 month LIBOR	4.4600%	Sept 2008 - Sept 2013
500	3 month LIBOR	2.0550%	Mar 2009 - Mar 2014
250	3 month LIBOR	2.7075%	May 2009 - May 2014
250	3 month LIBOR	2.6210%	May 2009 - May 2014
250	3 month LIBOR	3.6400%	Dec 2008 - Dec 2011
300	3 month LIBOR	3.1600%	Dec 2008 - Dec 2018
140 (NOK 800 mill)	3 month NIBOR +2.75%	3 month LIBOR + 2.9475 %	Nov 2009 – Nov 2011
130 (NOK 750 mill)	1 month NIBOR	3.355%	April 2009 - October 2012

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The counterparties to the above contracts are DnB NOR Bank ASA, Swedbank AB, Fokus Bank, and ING Bank N.V. Credit risk exists to the extent that the counterparties are unable to perform under the contracts, but this risk is considered remote as the counterparties are all banks which have provided the Company with loan finance and the interest rate swaps are related to those financing arrangements.

Interest rate hedge accounting

Two of the subsidiaries of Ship Finance consolidated by the Company as VIE's have entered into interest rate swaps in order to mitigate the Company's exposure to variability in cash flows for future interest payments on the loans taken out to finance the acquisition of West Polaris and West Taurus. These interest rate swaps qualify for hedge accounting and any changes in their fair value are included in "Other comprehensive income/loss". Below is a summary of the notional amounts, fixed interest rates payable and durations of these interest rate swaps.

Outstanding principal	Receive rate	Pay rate			Length of contract
In US$million)
19 (West Polaris )	1 month LIBOR		3.8945	%	July 2008 - Oct 2012
649 (West Taurus)	1 month LIBOR		2.1900	%	Dec 2008 - Aug 2013

In the year ended December 31, 2009 the above two VIE Ship Finance subsidiaries recorded fair value gains of $15.1 million on their interest rate swaps. These gains were recorded by those VIEs as "Other comprehensive income" but due to their ownership by Ship Finance these gains are included in "Non-controlling interest" on consolidation.

Any change in fair value resulting from hedge ineffectiveness is recognized immediately in earnings. The two VIEs, and therefore the Company, did not recognize any gain or loss due to hedge ineffectiveness in the consolidated financial statements during the years ended December 31, 2009, 2008 and 2007 relating to derivative financial instruments.

Foreign currency risk management

The Company uses foreign currency forward contracts to manage its exposure to foreign currency risk on certain assets, liabilities and future anticipated transactions. Such derivative contracts do not qualify for hedge accounting treatment and are recorded in the balance sheet under receivables if the forward contracts have a net positive fair value, and under other short-term liabilities if the forward contracts have a net negative fair value. At December 31, 2009, the Company had forward contracts and cross currency interest rate swaps to sell approximately $504 million between January 2010 and September 2012 at exchange rates ranging from NOK5.71 to NOK6.40 per US dollar and from SGD1.39 to SGD1.42 per US dollar. The total fair value of currency forward contracts December 31, 2009 amounted to $10.6 million.

Total Return SWAP Agreements

In June and July 2008, the Company entered into Total Return Swap ("TRS") agreements with a total of 4,500,000 shares in Seadrill as underlying security. The agreements were scheduled to expire in December 2008 and the initially agreed reference prices were in a range of NOK141.2 to NOK157.8 per share. In November 2008, these contracts were terminated and simultaneously the Company entered into a new TRS agreement with 4,500,000 shares in Seadrill as underlying security. This agreement was scheduled to expire in February 2009 and the agreed reference price was NOK56.7 per share. In February 2009, the contract was extended to August 2009 and the new reference price was NOK61.3 per share. In August 2009, the contract was settled and simultaneously the Company entered into a new TRS agreement with 4,500,000 in Seadrill as underlying security. This agreement expires in February 2010 and the agreed reference price was NOK98.44 per share. The total fair value gain relating to TRS agreements in 2009 amounted to $69.4 million.

Credit risk

The Company has financial assets, including cash and cash equivalents, marketable securities, other receivables and certain amounts receivable on derivative instruments, mainly forward exchange contracts and interest rate swaps. These assets expose the Company to credit risk arising from possible default by the counterparty. The Company considers the counterparties to be creditworthy financial institutions and does not expect any significant loss to result from non-performance by such counterparties. The Company, in the normal course of business, does not demand collateral. The credit exposure of interest rate swap agreements, currency option contracts and foreign currency contracts is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements. It is the Company's policy to enter into master netting agreements with the counterparties to derivative financial instrument contracts, which give the Company the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes to the Company.

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Fair values

Financial instruments that are measured at fair value on a recurring basis:

	Fair value		Fair value measurements at reporting date using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
(in millions of $)	December 31, 2009		(Level 1)		(Level 2)		(Level 3)
Assets:
Marketable securities		742.3		551.3				191.0
Currency forward contracts – short term receivable		10.6				10.6
TRS equity swap contracts		40.9				40.9
Total assets		793.8		551.3		51.5		191.0
Liabilities:
Interest rate swap contracts – short term payables		101.5				101.5
Total liabilities		101.5		-		101.5		-

ASC Topic 820 Fair Value Measurement and Disclosures (formerly FAS 157) emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, ASC Topic 820 establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within levels one and two of the hierarchy) and the reporting entity's own assumptions about market participant assumptions (unobservable inputs classified within level three of the hierarchy).

Level one inputs utilize unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Level two inputs are inputs other than quoted prices included in level one that are observable for the asset or liability, either directly or indirectly. Level two inputs may include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability, other than quoted prices, such as interest rates, foreign exchange rates and yield curves that are observable at commonly quoted intervals. Level three inputs are unobservable inputs for the asset or liability, which are typically based on an entity's own assumptions, as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability.

Quoted market prices are used to estimate the fair value of marketable securities, which are valued at fair value on a recurring basis.

The fair value of total return equity swaps is calculated using the closing prices of the underlying listed shares, dividends paid since inception and the interest rate charged by the counterparty.

The fair values of interest rate swaps and forward exchange contracts are calculated using well-established independent valuation techniques applied to contracted cash flows and LIBOR and NIBOR interest rates as at December 31, 2009.

Retained Risk

a) Physical Damage Insurance

The Company retains the risk, through self-insurance, for the deductibles relating to physical damage insurance on the Company's rig fleet, currently a maximum of $2 million per occurrence.

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b) Loss of Hire Insurance

The Company purchases insurance to cover loss of revenue on the rig fleet following extensive downtime caused by physical damage, where such damage is covered under the Company's physical damage insurance. The Company's self-insured retentions under the loss of hire insurance are up to 60 days after the occurrence of the physical damage. Thereafter, under the terms of the insurance, the Company is compensated for between 100 days and 290 days of lost revenue. The Company retains the risk that the repair of physical damage takes longer than the total number of days in the loss of hire policy.

Concentration of risk

The Company has financial assets, including cash and cash equivalents, marketable securities, other receivables and certain derivative instrument receivable amounts. These other assets expose the Company to credit risk arising from possible default by the counterparty. There is also a concentration of credit risk with respect to cash and cash equivalents to the extent that most of the amounts are carried with DnB NOR Bank ASA, Nordea Bank Finland Plc, Fokus Bank, and ING Bank N.V. The Company considers these risks to be remote.

In the year ended December, 31, 2009 16.6% of the Company's contract revenues were received from Statoil ASA ("Statoil") (2008: 31.9%), 13.0% from Total S.A. Group ("Total") (2008:4.5%), 11.9% from Exxon Mobil Corp ("Exxon") (2008:4.9%) and 10.1% were received from Royal Dutch Shell Group ("Shell") (2008: 6.5%). There is thus a concentration of revenue risk with Statoil, Total, Exxon and Shell.

Note 32 – Commitments and contingencies

Pledged assets

The book value of assets pledged under mortgages at December 31, 2009 was $7,514 million (2008: $7,569 million).

Purchase Commitments

At December 31, 2009, the Company had contractual commitments under nine newbuilding contracts totaling $1,678 million (2008: $2,891 million). The contracts are for the construction of two semi-submersible rigs, three jack-up rigs, a drillship and three tender rigs. The Company has an option not to take delivery of one of the jack-up rigs and if this option is exercised the commitments will be reduced by $184 million.

The maturity schedule for the contractual commitments as of December 31, 2009 is as follows:

	2010		2011		2012		2013		2014		2015 and thereafter
Newbuildings		1,175.0		503.0		-		-		-		-
Total		1,175.0		503.0		-		-		-		-

Guarantees

The Company has issued guarantees in favor of third parties as follows, which is the maximum potential future payment for each type of guarantee:

(In millions of US dollar)	December 31, 2009		December 31, 2008
Guarantees to customers of the Company's own performance		257		630
Guarantee in favor of banks		830		45
Guarantee in favor of suppliers		1,548		1,673
Guarantee in favor of Variable Interest Entities		2,479		2,793
Total		5,114		5,141

Legal Proceedings:

The Company is a party, as plaintiff or defendant, to several lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the operation of its drilling units, in the ordinary course of business or in connection with its acquisition activities. The Company believes that the resolution of such claims will not have a material adverse effect on the Company's operations or financial condition. The Company's best estimate of the outcome of the various disputes has been reflected in the financial statements of the Company as of December 31, 2009.

F-46

Gazprom dispute

At the end of 2005 and the beginning of 2006, the Company had a dispute with Gazprom in connection with the operations of the jack-up rig West Larissa, which was named Ekha at that time.

In May 2009, legal hearings took place in the High Court of Justice, London, and the Court has issued a decision with the following main conclusions:

The Company was awarded charter hire for the period November 23, 2005, to January 9, 2006, being the date up to when the incident occurred. Including interest this amounted to approximately $6.8 million.

The Company was not awarded hire for the time after the incident, nor was the Company awarded any reimbursement for uninsured costs related to its claim.

It is not possible at this stage to quantify the net outcome of this ruling. The amount of Gazprom's counter-claim, as well as responsibility for incurred legal costs, will be decided in a separate hearing at a later stage. The Court's decision has been appealed by the Company, and appeal hearings are scheduled to take place during first half of 2010. The Company does not expect the final outcome to have a significant effect on its financial results.

Note 33 – Variable Interest Entities (VIEs)

As at December 31, 2009, the Company leased one drillship, jack-up rig, and two semi-submersible rigs from VIEs under finance leases. Each of the units had been sold by the Company to single purpose subsidiaries of Ship Finance Ltd and simultaneously leased back by the Company on bareboat charter contracts for a term of 15 years. The Company has several options to repurchase the units during the charter periods, and obligations to purchase three of the assets at the end of the 15 year lease terms. The following table gives a summary of the sale and leaseback arrangements, as at December 31, 2009:

Unit	Effective from	Sale value (US$millions)	First repurchase option (US$millions)	Month of first repurchase option	Last repurchase option * (US$millions)	Month of last repurchase Option *
West Prospero	July 2007	210.0	142.0	June 2010	60.0	June 2022
West Polaris	July 2008	850.0	548.0	September 2012	177.5	June 2023
West Taurus	Nov 2008	850.0	418.0	February 2015	149.0	November 2023
West Hercules	Oct 2008	850.0	579.5	August 2011	135.0	August 2023

* For the units West Taurus and West Hercules repurchase obligations after 15 years have been agreed, at $149.0 and $135.0, respectively. For the unit West Polaris, a put option after 15 years has been agreed at $75.0.

The Company has determined that the Ship Finance subsidiaries, which own the units, are variable interest entities (VIEs), and that the Company is the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in the Company's consolidated accounts. The Company did not record any gains from the sale of the units, as they continued to be reported as assets at their original cost in the Company's balance sheet at the time of each transaction. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in the Company's consolidated accounts. At December 31, 2009 the units are reported under drilling units in the Company's balance sheet.

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The bareboat charter rates are set on the basis of a Base LIBOR Interest Rate for each bareboat charter contract, and thereafter are adjusted for differences between the LIBOR fixing each month and the Base LIBOR Interest Rate for each contract. A summary of the bareboat charter rates per day for each unit is given below. The amounts shown are based on the Base LIBOR Interest Rate shown, and reflect average rates for the year.

				2010			2011			2012			2013			2014
	Base LIBOR Interest Rate			(US$thousands)			(US$thousands)			(US$thousands)			(US$thousands)			(US$thousands)
West Prospero		5.10	%		67.5			53.9			52.9			51.5			46.1
West Polaris		2.85	%		346.5	*		344.5	*		323.5	*		222.3			176.5
West Taurus		4.25	%		304.0	*		307.8	*		311.9	*		316.2	*		320.7
West Hercules		4.25	%		404.5			378.8			250.0			250.0			238.3

* For a period the interest rates for West Polaris and West Taurus have been fixed at 3.894% and 2.174%, respectively, and the bareboat charter rate for these two units is fixed regardless of movements in LIBOR interest rates. These fixed charter rates are reflected in the above table.

The assets and liabilities in the statutory accounts of the VIEs are as follows:

In US dollar millions	Rig Finance II Ltd.		SFL West Polaris Limited		SFL Deepwater Ltd.
Name of unit	West Prospero		West Polaris		West Taurus West Hercules

Investment in finance lease		144.3		763.6		1,548.3
Other assets		23.4		41.1		66.1
Total assets		167.7		804.7		1,614.4
Long term debt		110.8		546.5		1,099.4
Other liabilities		0.1		109.0		165.9
Total liabilities		110.9		655.5		1,265.3
Equity		56.8		149.2		349.1
Book value of units in the Company's consolidated accounts		195.7		662.0		1,120.3

Note 34 – Subsequent Events

On February 25, 2010, the Company declared a dividend of $0.55 per share to be paid on or about March 26, 2010.

On February 25, 2010, the Company provided a short term secured loan of $49.5 million to Scorpion Offshore Limited, an associated company. The loan has duration of two months and bears interest at 12% per annum.

In March 2010, Seadrill registered their common shares under the Securities and Exchange Act of 1934 and became a reporting issuer in the United States. Seadrill was subsequently approved for the listing of its common shares with the New York Stock Exchange (NYSE).

In April 2010, the common shares were listed on the NYSE under the symbol "SDRL".

In April 2010, the Company announced that it will exercise its option to purchase a drilling unit from the Jurong shipyard for approximately US$350 million, excluding owner furnished equipment, loose drilling equipment, capitalized interest and project management. The jack-up rig of the Gusto MSC CJ70 150A design is currently under construction at the Jurong shipyard in Singapore. The rig is scheduled to be completed at the end of the first quarter 2011.

In April 2010, the Company completed a private placement of a total of 12.5 million shares, representing approximately 3.1% of the issued capital, to a price of NOK151.50 per share. Gross proceeds amounted to NOK1,894 million (approximately US$322 million). The share capital of Seadrill, following the completion of the equity issue in relation to the private placement, amounts to US$824,576,432 represented by 412,288,216 ordinary shares of US$2.00 par value. The net proceeds from the private placement will be used to part finance the mandatory offer for Scorpion Offshore, for equity in the potential acquisition of the CJ70 design jack-up rig, and for further opportunistic expansion of the Company.

In April 2010, the Company acquired 1.3 million shares in Scorpion Offshore Limited ("Scorpion"). The shares have been acquired at a price of NOK36.00 per share. Seadrill is, following this acquisition, the owner of 35,938,903 shares in Scorpion representing a total of 40.0% of Scorpion's issued shares. The acquisition triggers an obligation on Seadrill to make a mandatory cash offer for Scorpion's remaining shares or to reduce its holding below the 40% threshold within four weeks from today. Seadrill has decided to make a cash offer for the remaining shares in Scorpion. Seadrill is prepared, subsequent to the offer, to be owner of anything between 40.0% and 100% of Scorpion.

In April 2010 the Company provided Scorpion a secured loan of $240 million. The loan will partly be used to repay Scorpions' exiting obligations to Seadrill, leaving the total outstanding loan provided to Scorpion at $240 million. The loan matures in 5 years and bears interest at 10% per annum.

On April 30, 2010, the Company received a partial repayment of the Petromena bond amounting to $165 million.

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SIGNATURES

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

Seadrill Limited

(Registrant)

Date: May 5, 2010
	By:	/s/ Alf C. Thorkildsen
	Name: Title:	Alf C. Thorkildsen Chief Executive Officer of Seadrill Management AS

SK 25542 0005 1095567

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Seadrill (SDRLF) Inactive 20-F2009 FY Annual report (foreign)

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