Archer Limited (ARHVF) 20-F 2011 FY Annual report (foreign)

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 20-F

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

for the fiscal year ended December 31, 2010

Commission file number 333-171724

SEAWELL LIMITED

(Exact Name of Registrant as Specified in Its Charter)

BERMUDA

(Jurisdiction of Incorporation or Organization)

Par-la-Ville Place, 14 Par-La-Ville Road

Hamilton HM 08

Bermuda

(Address of Principal Executive Offices)

Max Bouthillette

Archer Management (US) LLC

11125 Equity Drive

Suite 200

Houston, TX 77041

United States

+1 713 856 2394

 (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:

Title of each class	Name of each exchange on which registered
None

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

Common Shares, par value $2.00 per share

(Title of Class)

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.

225,400,050

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

Yes () No (X)

If this report is an annual 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 () No (X)

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes () No ()

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer () Accelerated filer () Non-accelerated filer (X)

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

U.S. GAAP (X) 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 checkmark 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 () No (X)

Name and address of person authorized to receive notices and communications from the Securities and Exchange Commission:

Richard A. Ely

Skadden, Arps, Slate, Meagher & Flom (UK) LLP

40 Bank Street, Canary Wharf

London E14 5DS England

Contents

Part I

Item 1 Identity of Directors, Senior Management and Advisors

Item 2 Offer Statistics and Expected Timetable

Item 3 Key Information

A. Selected Financial Data

B. Capitalization and Indebtedness

C. Reasons for the Offer and Use of Proceeds

D. Risk Factors

Item 4 Information on the Company

A. History and Development of the Company

B. Business Overview

C. Organizational Structure

D. Property, Plant and Equipment

Item 4A Unresolved Staff Comments

Item 5 Operating and Financial Review and Prospects

A. Operating Results

B. Liquidity and Capital Resources

C. Research and Development, Patents and Licenses, etc

D. Trend Information

E. Off-Balance Sheet Arrangements

F. Tabular Disclosure of Contractual Obligations

G. Safe Harbor

Item 6 Directors, Senior Management and Employees

A. Directors and Senior Management

B. Compensation

C. Board Practices

D. Employees

E. Share Ownership

Item 7 Major Shareholders and Related Party Transactions

A. Major Shareholders

B. Related Party Transactions

C. Interests of Experts & Counsel

Item 8 Financial Information

A. Consolidated Statements and Other Financial Information

B. Significant Changes

Item 9 The Offer and Listing

A. Offer and Listing Details

B. Plan of Distribution

C. Markets

D. Selling Shareholders

E. Dilution

F. Expenses of the Issue

Item 10 Additional Information

A. Share Capital

B. Memorandum and Articles of Association

C. Material Contracts

D. Exchange Controls

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E. Taxation

F. Dividends and Paying Agents

G. Statement by Experts

H. Documents on Display

I. Subsidiary Information

Item 11 Quantitative and Qualitative Disclosures About Market Risk

Item 12 Description of Securities Other Than Equity Securities

Part II

Item 13 Defaults, Dividend Arrearages and Delinquencies

Item 14 Material Modifications to the Rights of Security Holders and Use of Proceeds

Item 15 Controls and Procedures

Item 16

A. Audit Committee Financial Expert

B. Code of Ethics

C. Principal Accountant Fees and Services

D. Exemptions from the Listing Standards for Audit Committees

E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

F. Change in Registrant’s Certifying Accountant

G. Corporate Governance

Part III

Item 17 Financial Statements

Item 18 Financial Statements

Item 19 Exhibits

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Part I

Cautionary Statement Regarding Forward-Looking Statements

In addition to historical information, this annual report on Form 20-F contains statements relating to our future business and/or results. These statements include certain projections and business trends that are “forward-looking” within the meaning of the Private Securities Litigation Reform Act of 1995. Seawell Limited, or the Company, desires to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and is including this cautionary statement in connection with this safe harbor legislation. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, including statements preceded by, followed by or that include the words “estimate,” “plan,” project,” “forecast,” “intend,” “expect,” “anticipate,” “believe,” “think,” “view,” “seek,” “target,” “goal,” or similar expressions; any projections of earnings, revenues, expenses, synergies, margins or other financial items; any statements of the plans, strategies and objectives of management for future operations, including integration and any potential restructuring plans relating to the merger; any statements concerning proposed new products, services, developments or industry rankings; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements do not guarantee future performance and involve risks and uncertainties. Actual results may differ materially from projected results as a result of certain risks and uncertainties. These risks and uncertainties include, without limitation, those described under Item 3.D. “Risk Factors” and those detailed from time to time in our other filings with the United States Securities and Exchange Commission (the “Commission” or the “SEC”). These forward-looking statements are made only as of the date of this annual report on Form 20-F. We do not undertake to update or revise the forward-looking statements, whether as a result of new information, future events or otherwise.

The forward-looking statements in this report 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 impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections.

Item 1      Identity of Directors, Senior Management and Advisors

Not applicable.

Item 2      Offer Statistics and Expected Timetable

Not applicable.

Item 3      Key Information

Throughout this annual report, the “Company,” “Seawell,” “we,” “us” and “our” all refer to Seawell Limited and its subsidiaries.

A. Selected Financial Data

The following selected historical consolidated financial data of the Company as of and for the years ended December 31, 2010, 2009 and 2008 have been derived from the Company’s audited financial statements and related notes thereto included in this annual report, which have been audited by PricewaterhouseCoopers AS. The following selected historical combined and consolidated financial data of the Company as of December 31, 2007 has been derived from the Company’s audited combined and consolidated financial statements not included in this annual report. This information is only a summary and you should read this selected historical consolidated financial data in conjunction with Item 5, “Operating and Financial Review and Prospects” and Item 18, “Financial Statements.”

Seawell was incorporated on August 31, 2007 and acquired the shares in the entities comprising Seadrill Limited’s well service division on October 1, 2007. For historical comparison, the Company’s statement of operations data for the year ended December 31, 2007 include the results of operations of Seadrill Limited’s well service division for the period from January 1, 2007 to September 30, 2007, and the Company’s results of operations for the period from October 1, 2007 to December 31, 2007.

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	Years Ended December 31,
	2007	2008	2009	2010	20101
					(Unaudited)
	(NOK in millions, except per share data and weighted average shares)				($ in millions, except per share data and weighted average shares)
Statement of Operations Data:
Operating revenues:
Operating revenues	2,276.4	3,006.2	3,101.2	3,687.5	$        626.1
Reimbursables	451.7	618.5	723.6	641.4	108.9
Total operating revenues	2,728.1	3,624.7	3,824.8	4,328.9	735.0
Operating expenses:
Operating expenses	1,896.3	2,538.8	2,538.3	3,038.0	515.9
Reimbursables expenses	439.0	600.9	692.5	617.1	104.8
Depreciation and amortization	53.6	107.4	131.6	136.2	23.1
General and administrative expenses	88.6	71.9	103.1	152.0	25.8
Total operating expenses	2,477.5	3,319.0	3,465.5	3,943.2	669.6
Operating income	250.6	305.7	359.3	385.7	65.5
Financial items:
Interest income	22.1	25.3	5.6	9.3	1.6
Interest expenses	(33.7)	(148.3)	(96.8)	(132.9)	(22.6)
Share of results in associated company	-	-	-	(1.9)	(0.3)
Other financial items	3.3	(39.0)	(33.1)	(93.8)	(15.9)
Total financial items	(8.3)	(162.0)	(124.3)	(219.4)	(37.3)
Income before income taxes	242.3	143.7	235.0	166.3	28.2
Income taxes	(67.8)	(24.7)	(60.6)	(92.6)	(15.7)
Net income	174.5	119.0	174.4	73.7	12.5
Net income attributable to the parent	175.9	122.5	176.2	74.1	12.6
Net income attributable to the non-controlling interest	(1.4)	(3.5)	(1.8)	(0.4)	(0.1)
Basic earnings per share	2.07	1.14	1.60	0.49	(0.08)
Diluted earnings per share	2.06	1.14	1.59	0.47	(0.08)
Weighted average number of common shares outstanding:
Basic	85,000,050	107,222,272	110,000,050	152,049,913	152,049,913
Diluted	85,371,574	107,222,272	110,567,792	155,930,383	155,930,383
	As of December 31,
	2007	2008	2009	2010	20101
					(Unaudited)
	(NOK in millions, except per share data)				($ in millions, except per share data)
Balance Sheet Data:
Cash and cash equivalents	132.2	224.1	236.7	1,023.6	173.8
Total assets	2,010.3	3,447.4	3,339.8	5,723.1	971.8
Long-term debt classified as:
Current	75.0	218.7	260.8	11.0	1.9
Long-term	1,218.9	1,237.1	987.7	1,128.8	191.7
Total shareholders’ equity	86.9	388.1	627.3	3,273.9	556.0
Book value per common share	0.87	3.53	5.70	14.5	2.5

_______________________
Note:

1 Solely for the convenience of the reader, certain NOK amounts presented as of and for the year ended December 31, 2010 have been translated into U.S. dollars using the noon buying rate in New York City for cable transfers in foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York on December 31, 2010 of NOK 1.00 = $0.1698.

4

Exchange Rate Information

We publish our consolidated financial statements in Norwegian krone. In this Annual Report, references to “krone” or “NOK” are to Norwegian krone, and references to “$,” “U.S. dollar,” “USD,” or “US$” are to United States dollars.

The table below sets forth, for the periods and dates indicated, certain information regarding the exchange rate between the Norwegian krone and the U.S. dollar based on the noon buying rate in New York City for cable transfers in foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York.  Fluctuations in the exchange rates between the Norwegian krone and the U.S. dollar in the past are not necessarily indicative of fluctuations that may occur in the future.

	U.S. dollars per Norwegian krone
	High	Low
October 2010	0.1741	0.1695
November 2010	0.1745	0.1613
December 2010	0.1698	0.1630
January 2011	0.1738	0.1673
February 2011	0.1786	0.1705
March 2011	0.1807	0.1764
April 2011 (through April 22, 2011)	0.1869	0.1819

Years ended December 31,	High	Low	Average1	Period End2
2006	0.1670	0.1460	0.1575	0.1605
2007	0.1900	0.1545	0.1725	0.1841
2008	0.2022	0.1373	0.1789	0.1434
2009	0.1806	0.1374	0.1607	0.1727
2010	0.1781	0.1499	0.1649	0.1698

_______________________
Notes:

1 The average rate for each annual period was calculated by taking the simple average of the historical exchange rates on the last business day of each month during the relevant period.

2 The period-end rate is the historical exchange rate on the last business day of the applicable period, as published by the Federal Reserve Bank of New York.

On April 22, 2011, the last practicable day prior to the date of this Annual Report, the exchange rate was NOK 1.00 = $0.1861.

No representation is made that the Norwegian krone amounts referred to in this document could have been or could be converted into U.S. dollars at the above exchange rates or at any other rate.

B. Capitalization and Indebtedness

Not applicable.

C. Reasons for the Offer and Use of Proceeds

Not applicable.

D. Risk Factors

In conducting our business, we face many risks that may interfere with our business objectives. Some of these risks relate to our operational processes, while others relate to our business environment. It is important to understand the nature of these risks and the impact they may have on our business, financial condition and results of operations. Some of the more relevant risks are described below. These risks are not the only ones that we face. Some risks may not yet be known to us and certain risks that we do not currently believe to be material could become material in the future.

5

Risks Related to our Business

Global political, economic and market conditions could negatively impact our business.

Our operations are affected by global political, economic and market conditions. The recent worldwide economic downturn has reduced the availability of liquidity and credit to fund business operations worldwide and has adversely affected our customers, suppliers and lenders. In addition, as a result of the recent economic downturn, reduced demand for drilling and well services negatively impacted our activity levels and pricing for our services, adversely affecting our financial condition and results of operations. The economic downturn also led to a decline in energy consumption, which has materially and adversely affected our results of operations. Continued hostilities in the Middle East and West Africa and the occurrence or threat of terrorist attacks against the United States or other countries could contribute to the economic downturn in the economies of the United States and other countries in which we operate. A sustained or deeper recession could further limit economic activity and thus result in an additional decrease in energy consumption, which in turn could cause our revenues and margins to further decline and limit our future growth prospects.

Our business depends on the level of activity in the exploration and production industry, which is significantly affected by volatile oil and natural gas prices.

Our business depends on the level of activity of oil and natural gas exploration, development and production in the North Sea and internationally, and in particular, the level of exploration, development and production expenditures of our customers. Demand for our drilling and well services is adversely affected by declines in exploration, development and production activity associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices often causes exploration and production companies to reduce their spending. The worldwide deterioration in the financial and credit markets that began in the second half of 2008 resulted in diminished demand for oil and gas and significantly lower oil and natural gas prices. The significant decline in oil and natural gas prices caused many of our customers to reduce their activities and spending in 2009, and these reduced levels of activity and spending continued through 2010. In addition, higher prices do not necessarily translate into increased drilling activity since our clients’ expectations about future commodity prices typically drive demand for our services. Oil and natural gas prices are extremely volatile. On July 2, 2008 natural gas prices were $13.31 per million British thermal unit, or MMBtu, at the Henry Hub. They subsequently declined sharply, reaching a low of $1.88 per MMBtu at the Henry Hub on September 4, 2009. As of April 20, 2011, the closing price of natural gas at the Henry Hub was $4.33 per MMBtu. The spot price for West Texas intermediate crude has in the last few years ranged from a high of $145.29 per barrel as of July 3, 2008, to a low of $31.41 per barrel as of December 22, 2008, with a closing price of $110.89 per barrel as of April 20, 2011. Oil and natural gas prices are affected by numerous factors, including the following:

· the demand for oil and natural gas in Europe, the United States and elsewhere;

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

· political, economic and weather conditions in Europe, the United States and elsewhere;

· advances in exploration, development and production technology;

· the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain oil production levels and pricing;

· the level of production in non-OPEC countries;

· domestic and international tax policies and governmental regulations;

· the development and exploitation of alternative fuels, and the competitive, social and political position of natural gas as a source of energy compared with other energy sources;

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

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· the worldwide military and political environment and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, West Africa and other significant oil and natural gas producing regions; and

· acts of terrorism or piracy that affect oil and natural gas producing regions, especially in Nigeria, where armed conflict, civil unrest and acts of terrorism have recently increased.

As a result of the recent economic downturn, reduced demand for drilling and well services negatively impacted our activity levels and pricing for our services, adversely affecting our financial condition and results of operations. The economic downturn has led to a decline in energy consumption, which has materially and adversely affected our results of operations. Continued hostilities in the Middle East and West Africa and the occurrence or threat of terrorist attacks against the United States or other countries could contribute to the economic downturn in the economies of the United States and other countries in which we operate. A sustained or deeper recession could further limit economic activity and thus result in an additional decrease in energy consumption, which in turn would cause our revenues and margins to further decline and limit our future growth prospects.

Our industry is highly competitive, with intense price competition. Our inability to compete successfully may reduce our profitability.

Our industry is highly competitive. Our contracts are traditionally awarded on a competitive bid basis, with pricing often being the primary factor in determining which qualified contractor is awarded a job, although each contractor’s technical capability, safety performance record and reputation for quality also can be key factors in the determination.

Several other oilfield services companies are larger than us and have resources that are significantly greater than our resources. These competitors may be able to better withstand industry downturns, compete on the basis of price, and acquire new equipment and technologies, all of which could affect our revenues and profitability. These competitors compete with us both for customers and for acquisitions of other businesses. This competition may cause our business to suffer. Our management believes that competition for contracts will continue to be intense in the foreseeable future.

The oilfield service industry is highly cyclical and lower demand and pricing could result in declines in our profitability.

Historically, the oilfield service industry has been highly cyclical, with periods of high demand and favorable pricing often followed by periods of low demand and sharp reduction in pricing power. Periods of decreased demand or increased supply intensify the competition in the industry. As a result of the cyclicality of our industry, management expects our results of operations to be volatile and to decrease during market declines such as the downturn we are currently experiencing.

A small number of customers account for a significant portion of our total operating revenues, and the loss of, or a decline in the creditworthiness of, one or more of these customers could adversely affect our financial condition and results of operations.

We derive a significant amount of our total operating revenues from a few energy companies. During the year ended December 31, 2010, contracts from Statoil, ConocoPhillips, Shell and BP accounted for 46%, 16%, 6% and 7% of our total operating revenues. In the year ended December 31, 2009, Statoil, BP and Shell accounted for approximately 51%, 16% and 6% of our total operating revenues, respectively. Our financial condition and results of operations will be materially adversely affected if these customers interrupt or curtail their activities, terminate their contracts with us, fail to renew their existing contracts or refuse to award new contracts to us, and we are unable to enter into contracts with new customers at comparable dayrates. The loss of any significant customer could adversely affect our financial condition and results of operations.

Additionally, this concentration of customers may increase our overall exposure to credit risk. Our customers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations will be materially adversely affected if one or more of our significant customers fails to pay us or ceases to contract with us for our services on terms that are favorable to us or at all.

7

We can provide no assurance that our current backlog of platform drilling revenue will be ultimately realized.

As of December 31, 2010, our total platform drilling and well services backlog was approximately NOK 6.6 billion (approximately $1.1 billion). The Norwegian krone amount of our backlog does not necessarily indicate actual future revenue or earnings related to the performance of that work. Management calculates our contract revenue backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization and excluding revenues for contract preparation and customer reimbursables. We may not be able to perform under our contracts due to various operational factors, including unscheduled repairs, maintenance, operational delays, health, safety and environmental incidents, weather events in the North Sea and elsewhere and other factors (some of which are beyond our control), and our customers may seek to cancel or renegotiate our contracts for various reasons, including a financial downturn or falling commodity prices. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice. Our inability or the inability of our customers to perform their respective contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

We will experience reduced profitability if our customers reduce activity levels or terminate or seek to renegotiate their contracts or if we experience downtime, operational difficulties, or safety-related issues.

Currently, our platform drilling contracts with major customers are dayrate contracts, pursuant to which we charge a fixed charge per day regardless of the number of days needed to drill the well. Likewise, under our current well services contracts, we charge a fixed daily fee. During depressed market conditions, a customer may no longer need services that are currently under contract or may be able to obtain comparable services at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing platform drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime, operational problems above the contractual limit or safety-related issues or in other specified circumstances, which include events beyond the control of either party.

Our contracts with our customers usually include terms allowing the customer to terminate the contracts without cause upon written notice specifying the termination date, and without penalty or early termination payments. In addition, under some of our existing contracts, we could be required to pay penalties if the contract is terminated due to downtime, operational problems or failure to perform. Some of our other contracts with customers may be cancelable at the option of the customer upon payment of a penalty, which may not fully compensate us for the loss of the contract. Early termination of a contract may result in our employees being idle for an extended period of time. The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. If our customers cancel or require us to renegotiate some of our significant contracts, and we are unable to secure new contracts on substantially similar terms, or if contracts are suspended for an extended period of time, our revenues and profitability would be materially reduced.

Our growth strategy includes making acquisitions, but we may be unable to complete and finance future acquisitions on acceptable terms. In addition, we may fail to successfully integrate assets or businesses we acquire or may incorrectly predict operating results.

As part of our growth strategy, we may consider future acquisitions which could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt, the issuance of a substantial amount of equity or a combination of the foregoing. If we are restricted from using cash or incurring debt to fund a potential acquisition, we may not be able to issue, on terms we find acceptable, sufficient equity to complete an acquisition or investment.

Management cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our common shares.

Any future acquisitions could present a number of risks, including:

· the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;

8

· the risk of failing to integrate the operations or management of any acquired operations or assets successfully and timely; and

· the risk of diversion of management’s attention from existing operations or other priorities.

If we are unsuccessful in integrating acquisitions in a timely and cost-effective manner, our financial condition and results of operations could be adversely affected.

The loss of the services of key executives or our failure to attract and retain skilled workers and key personnel could hurt our operations.

We are dependent upon the efforts and skills of our executives to manage our business, identify and consummate additional acquisitions and obtain and retain customers. These executives include Chief Executive Officer & President of Seawell Management Limited (entity name change to Archer Management (UK) Limited in process), Jørgen Rasmussen, and the Chief Operating Officer and Executive Vice-President of Archer Management (US) LLC, Thorleif Egeli.

In addition, we and our competitors are dependent upon the available labor pool of skilled employees. Our development and expansion will require additional experienced management and operations personnel. No assurance can be given that we will be able to identify and retain these employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. A shortage of skilled workers, increases in wage rates or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. There can be no assurance that labor costs will not increase. Any increase in operating costs could cause our business to suffer.

Severe weather could have a material adverse impact on our business.

Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

· curtailment of services;

· weather-related damage to facilities and equipment resulting in suspension of operations;

· inability to deliver materials to job sites in accordance with contract schedules; and

· loss of productivity.

A substantial portion of our revenue from operations is generated from work performed in the North Sea. Adverse weather conditions during the winter months in the North Sea usually result in low levels of offshore activity. Further, in Brazil, where we also generate a significant portion of revenue from operations, adverse weather conditions affect our results of operations. Optimal weather conditions offshore Brazil normally exist only from October to April and most offshore operations in this region are scheduled for that period. Additionally, during certain periods of the year, we may encounter adverse weather conditions such as tropical storms. Adverse seasonal weather conditions limit our access to job sites and our ability to service wells in affected areas. During periods of curtailed activity due to adverse weather conditions, we continue to incur expenses, but our revenues could be delayed or reduced.

We have recorded substantial goodwill as the result of our acquisitions, and goodwill is subject to periodic reviews of impairment.

We perform purchase price allocations to intangible assets when we make acquisitions. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. We conduct periodic reviews of goodwill for impairment in value. Any impairments would result in a non-cash charge against earnings in the period reviewed, which may or may not create a tax benefit, and would cause a corresponding decrease in shareholders’ equity. In the event that market conditions deteriorate or there is a prolonged downturn, we may be required to record an impairment of goodwill, and such impairment could be material.

9

We have incurred and will incur transaction, integration and restructuring costs in connection with the merger with Allis-Chalmers.

We have incurred, and expect to continue to incur, significant costs in connection with our merger with Allis-Chalmers, including the fees of our professional advisors. We will also continue to incur integration and restructuring costs as Allis-Chalmers’ operations are integrated with our operations. The efficiencies anticipated to arise from the merger may not be achieved in the near term or at all, and if achieved, may not be sufficient to offset the costs associated with the merger. Unanticipated costs, or the failure to achieve expected efficiencies, may have an adverse impact on the results of operations of the combined company following the completion of the merger.

Any inability to effectively integrate the business and operations of Allis-Chalmers with our own could disrupt operations and force us to incur unanticipated costs.

The merger with Allis-Chalmers significantly increased the size of our operations. Our ability to integrate Allis-Chalmers’ operations with our own will be important to the future success of the combined company. Successful integration is subject to numerous conditions beyond our control, including adverse general and regional economic conditions, general industry trends and competition. The successful integration of Allis-Chalmers’ business will also require us to, among other things, retain key employees from Allis-Chalmers. Our future performance will depend, in part, on our ability to successfully integrate these new employees into our operations. Any failure to retain and successfully integrate these new employees, or otherwise effectively integrate Allis-Chalmers’ operations with our own, could disrupt our ongoing business, force us to incur unanticipated costs and adversely affect the trading price of our common shares. If we are unable to realize the anticipated benefits of the merger due to an inability to address the challenges of integrating Allis-Chalmers’ business or for any other reason, it could have a material adverse effect on our business and financial and operating results and require significant additional time on the part of our senior management dedicated to attempting to resolve integration issues.

If we are unable to retain key Seawell and/or Allis-Chalmers personnel, our business may suffer.

The success of the merger with Allis-Chalmers depends in part on our ability to retain key personnel currently employed by Seawell and Allis-Chalmers. There is no assurance that we will be able to retain key employees of either Seawell or Allis-Chalmers after the merger. This may adversely affect the ability of both companies to attract and retain key personnel. If key employees terminate their employment, or if insufficient numbers of employees are retained to maintain effective operations, management’s attention might be diverted from successfully integrating Allis-Chalmers’ operations to hiring suitable replacements, and our business might suffer. In addition, we might not be able to locate suitable replacements for any key employees that leave Seawell or Allis-Chalmers, or we may not be able to offer employment to potential replacements on terms they find acceptable.

The Deepwater Horizon incident in the U.S. Gulf of Mexico and its consequences, including the potential enactment of further restrictions or regulations on offshore drilling, could have a material adverse effect on our business.

In April 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, owned by Transocean Ltd. and under contract to a subsidiary of BP plc. The accident resulted in the loss of life and a significant oil spill. In response to this incident, the Minerals Management Service of the U.S. Department of the Interior, or MMS, issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. The notice also stated that the MMS would not consider during the six-month moratorium period drilling permits for new wells and related activities for specified water depths. In addition, wells covered by the moratorium that were then being drilled were required to halt drilling and take steps to secure the well. On October 12, 2010, the moratorium was lifted, and deepwater oil and gas drilling in the U.S. Gulf of Mexico was allowed to resume, provided that operators certify compliance with all existing rules and requirements, including those that recently went into effect, and demonstrate the availability of adequate blowout containment resources.

The BOEM is expected to continue to issue new guidelines and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. These may include new or additional bonding and safety requirements, and other requirements regarding certification of equipment.  There is no assurance that operations related to drilling offshore in the United States will reach the same levels that existed prior to the moratorium. The delay in resuming these activities or the failure of these activities to reach levels that existed prior to the moratorium has and could continue to adversely impact our operating results.  

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The enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling or contracting services operations could negatively affect the revenue and operating income of the combined company and/or make it difficult to obtain insurance at commercially reasonable rates, which could materially affect the combined company’s business, financial conditions and results of operations.  We cannot predict how federal and state authorities will further respond to the incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit our customers from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico.

We may not achieve the expected benefits of our merger with Allis-Chalmers.

We entered into the merger with Allis-Chalmers with the expectation that the transaction would result in various benefits. Some of those benefits may not be achieved or, if achieved, may not be achieved in the time frame in which they are expected. Whether we will actually realize these anticipated benefits depends on future events and circumstances, some of which are beyond the parties’ control. For example, future growth in revenues, earnings and cash flow will be partly dependent on future economic conditions and conditions in the oil and gas exploration and production industry. Also, the potential synergies that we anticipate may not be realized. In addition, other risk factors discussed below may prevent the achievement of the expected advantages of the merger.

We do business in international jurisdictions whose political and regulatory environments and compliance regimes differ from those in the U.S.

A significant portion of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 99% of our consolidated revenue in the year ended December 31, 2010 and approximately 98.7% of our consolidated revenue in the year ended December 31, 2009. Risks associated with our operations in foreign areas include, but are not limited to:

· political, social and economic instability, war and acts of terrorism;

· potential seizure, expropriation or nationalization of assets;

· damage to our equipment or violence directed at our employees, including kidnappings and piracy;

· increased operating costs;

· complications associated with repairing and replacing equipment in remote locations;

· repudiation, modification or renegotiation of contracts, disputes and legal proceedings in international jurisdictions;

· limitations on insurance coverage, such as war risk coverage in certain areas;

· import-export quotas;

· confiscatory taxation;

· work stoppages or strikes;

· unexpected changes in regulatory requirements;

· wage and price controls;

· imposition of trade barriers;

· imposition or changes in enforcement of local content laws;

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· the inability to collect or repatriate currency, income, capital or assets;

· foreign currency fluctuations and devaluation; and

· other forms of government regulation and economic conditions that are beyond our control.

Part of our strategy is to prudently and opportunistically acquire businesses and assets that complement our existing products and services, and to expand our geographic footprint. If we make acquisitions in other countries, we may increase our exposure to the risks discussed above.

Our non-U.S. platform drilling and well service operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to currency conversions and repatriation, oil and natural gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of supplies and equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural 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 natural gas companies and may continue to do so. Operations in developing countries can be subject to legal systems which are not as predictable as those in more developed countries, which can lead to greater risk and uncertainty in legal matters and proceedings.

In some jurisdictions we are subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations may adversely affect our ability to compete. Additionally, our operations in some jurisdictions may be significantly affected by union activity and general labor unrest. In Argentina and Brazil labor organizations have substantial support and have considerable political influence. The demands of labor organizations in Argentina have increased in recent years as a result of the general labor unrest and dissatisfaction resulting from the disparity between the cost of living and salaries in Argentina as a result of the devaluation of the Argentine Peso. There can be no assurance that our operations in Argentina will not face labor disruptions in the future or that any such disruptions will not have a material adverse effect on our financial condition or results of operations.

Our results of operations may be adversely affected by currency fluctuations.

Due to our international operations, we may experience currency exchange losses when revenues are received and expenses are paid in nonconvertible currencies or when we do not hedge an exposure to a foreign currency. 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. We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment of a percentage of the contract indexed to the U.S. dollar exchange rate. To the extent possible, we seek to limit our exposure to local currencies by matching the acceptance of local currencies to local expense requirements in those currencies. We may not be able to take these actions in the future, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate materially.

Limitations on our ability to protect intellectual property rights, including trade secrets, could cause a loss in revenue and a reduction in any competitive advantage that we hold.

Some of our products or services, and the processes we use to produce or provide them, have been granted patent protection, have patent applications pending or are trade secrets. Our business may be adversely affected if our patents are unenforceable, the claims allowed under our patents are not sufficient to protect the technology, our patent applications are denied, or our trade secrets are not adequately protected. In addition, our competitors may be able to develop technology independently that is very similar to ours without infringing on our patents or gaining access to our trade secrets.

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We may be subject to litigation if another party claims that we have infringed upon its intellectual property rights.

Third parties could assert that the tools, techniques, methodologies, programs and components we use to provide our services infringe upon the intellectual property rights of others. Infringement claims generally result in significant legal and other costs and may distract management from running our core business. Additionally, if any of these claims were to be successful, developing non-infringing technologies and/or making royalty payments under licenses from third parties, if available, would increase our costs. If a license were not available we might not be able to continue to provide a particular service or product, which could adversely affect our financial condition, results of operations and cash flows.

We could be adversely affected if we fail to keep pace with technological changes and changes in technology could have a negative result on our market share.

We provide platform drilling and well services in increasingly challenging offshore environments. To meet our clients’ needs, we must continually develop new, and update existing, technology for the services it provides. In addition, rapid and frequent technology and market demand changes can render existing technologies obsolete, requiring substantial new capital expenditures, and could have a negative impact on our market share. Any failure by us to anticipate or to respond adequately to changing technology, market demands and client requirements could adversely affect our business and financial results.

We are subject to numerous governmental laws and regulations, some of which may impose significant liability on us for environmental and natural resource damages.

We are subject to various federal, state, local and foreign laws and regulations, including those relating to the energy industry in general and the environment in particular, and may be required to make significant capital expenditures to comply with laws and the applicable regulations and standards of governmental authorities and organizations. Moreover, the cost of compliance could be higher than anticipated. Our operations are subject to compliance with one or more of the U.S. Foreign Corrupt Practices Act, legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations and the laws, regulations and standards of other foreign countries in which we operate. It is also possible that existing and proposed governmental conventions, laws, regulations and standards, including those related to climate and emissions of “greenhouse gases,” may in the future add significantly to our operating costs or limit our activities or the activities and levels of capital spending by our customers.

In addition, many aspects of our operations are subject to laws and regulations that relate, directly or indirectly, to the oilfield services industry, including laws requiring us to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit our operations. Laws and regulations protecting the environment have become more stringent in recent years and may, in certain circumstances, impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. 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 the acts were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploration and production activity could materially limit our future contract opportunities, materially increase our costs or both.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.

Substantially all of our operations are subject to hazards that are customary for exploration and production activity, including blowouts, reservoir damage, loss of well control, cratering, oil and gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage. We may also be subject to property, environmental and other damage claims by oil and natural gas companies and other businesses operating offshore and in coastal areas. Litigation arising from an accident at a location where our products or services are used or provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. Generally, our contracts provide for the division of responsibilities between us and our customer, and consistent with standard industry practice, our clients generally assume, and indemnify us against, some of these risks. In particular, contract terms generally provide that our customer, the operator,

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will retain liability and indemnify us for (i) environmental pollution caused by any oil, gas, water or other fluids and pollutants originating from below the seabed, (ii) damage to customer and third-party equipment and property including any damage to the sub-surface and reservoir and (iii) personal injury to or death of customer personnel. There can be no assurance, however, that these clients will necessarily be financially able to indemnify us against all risks. Also, we may be effectively prevented from enforcing these indemnities because of the nature of our relationship with some of our larger clients. Additionally, from time to time we may not be able to obtain agreement from our customers to indemnify us for such damages and risks.

To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through customary insurance to protect our business against these potential losses. However, we have a significant amount of self-insured retention or deductible for certain losses relating to general liability and property damage. There is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event for which we are not fully insured or indemnified against, or the failure of a customer or insurer to meet our indemnification or insurance obligations, could result in substantial losses.

Our insurance coverage has become more expensive, may become unavailable in the future, and may be inadequate to cover our losses.

Our insurance coverage is subject to certain significant deductibles and levels of self-insurance, does not cover all types of losses and, in some situations, may not provide full coverage for losses or liabilities resulting from our operations. In addition, we are likely to continue experiencing increased costs for available insurance coverage, which may impose higher deductibles and limit maximum aggregated recoveries. For example, the Deepwater Horizon rig explosion in the Gulf of Mexico may lead to further tightening of an increasingly difficult market for insurance coverage. Insurers may not continue to offer the type and level of coverage which we currently maintain, and our costs may increase substantially as a result of increased premiums, potentially to the point where coverage is not available on economically manageable terms. Should liability limits be increased via legislative or regulatory action, it is possible that we may not be able to insure certain activities to a desirable level. If liability limits are increased and/or the insurance market becomes more restricted, our business, financial condition and results of operations could be materially adversely affected.

Insurance costs may also increase in the event of ongoing patterns of adverse changes in weather or climate. We may not be able to obtain customary insurance coverage in the future, thus putting us at a greater risk of loss due to severe weather conditions and other hazards. Moreover, we may not be able to maintain adequate insurance in the future at rates management considers reasonable or be able to obtain insurance against certain risks.

A significant portion of our business is conducted in the North Sea. The mature nature of this region could result in less drilling activity in the area, thereby reducing demand for our services.

The North Sea is a mature oil and natural gas production region that has experienced substantial seismic survey and exploration activity for many years. Because a large number of oil and natural gas prospects in this region have already been drilled, additional prospects of sufficient size and quality could be more difficult to identify. Oil and natural gas companies may be unable to obtain financing necessary to drill prospects in this region. The decrease in the size of oil and natural gas prospects, the decrease in production or the failure to obtain such financing may result in reduced drilling activity in the North Sea and reduced demand for our services.

We are a holding company, and as a result are dependent on dividends from our subsidiaries to meet our obligations.

We are a holding company and do not conduct any business operations of our own. Our principal assets are the equity interests we own in our operating subsidiaries, either directly or indirectly. As a result, we are dependent upon cash dividends, distributions or other transfers we receive from our subsidiaries to repay any debt we may incur, and to meet our other obligations. The ability of our subsidiaries to pay dividends and make payments to us will depend on their operating results and may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements of those subsidiaries. For example, the corporate laws of some jurisdictions prohibit the payment of dividends by any subsidiary unless the subsidiary has a capital surplus or net profits in the current or immediately preceding fiscal year. Payments or distributions from our subsidiaries also could be subject to restrictions on dividends or repatriation of earnings under applicable local law, and monetary transfer restrictions in the jurisdictions in which our subsidiaries operate. Our subsidiaries are separate and distinct legal entities. Any right that we have to receive any assets of or distributions from any subsidiary upon the bankruptcy, dissolution, liquidation or reorganization of such subsidiary, or to realize proceeds from the sale of the assets of any subsidiary, will be junior to the claims of that subsidiary’s creditors, including trade creditors.

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We have a significant level of debt, and could incur additional debt in the future, which could have significant consequences for our business and future prospects.

As of December 31, 2010, we had total outstanding debt of approximately NOK 1,139.8 million. This debt represented approximately 19.9% of our total book capitalization. In addition, we assumed a substantial amount of Allis-Chalmers debt in the recently completed merger. Our debt and the limitations imposed on us by our existing or future debt agreements could have significant consequences for our business and future prospects, including the following:

· we may not be able to obtain necessary financing in the future for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;

· we will be required to dedicate a substantial portion of our cash flow from operations to payments of principal and interest on our debt;

· we could be more vulnerable during downturns in our business and be less able to take advantage of significant business opportunities and to react to changes in our business and in market or industry conditions; and

· we may have a competitive disadvantage relative to our competitors that have less debt.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash in the future, which is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our earnings and cash flow may vary significantly from year to year due to the cyclical nature of the oilfield services industry. As a result, our future cash flows may be insufficient to meet all of our debt obligations and other commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay indebtedness as it becomes due or at maturity with cash on hand, we will need to refinance 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.

Our credit facility imposes restrictions on us that may limit the discretion of management in operating our business and that, in turn, could impair our ability to meet our obligations.

Our credit facility contains various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things:

· make certain types of loans and investments;

· incur or guarantee additional indebtedness;

· pay dividends, redeem or repurchase stock, prepay, redeem or repurchase other debt or make other restricted payments;

· use proceeds from asset sales, new indebtedness or equity issuances for general corporate purposes or investment into our business;

· place restrictions on our subsidiaries’ ability to make dividends or other payments to us;

· invest in joint ventures;

· create or incur liens;

· enter into transactions with affiliates;

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· sell assets or consolidate or merge with or into other companies; and

· enter into new lines of business.

The credit facility also imposes additional covenants and restrictions, including the imposition of a requirement to maintain a minimum equity ratio at all times. Our ability to comply with these financial covenants and restrictions may be affected by events beyond our control. Our credit facility requires that we meet certain financial ratios and tests and there can be no assurance that we will be able to comply with the financial covenants. Our failure to comply with such covenants, as a result of reduced activity in the exploration and production industry or otherwise, would result in an event of default under the credit facility, which could result in us having to immediately repay all amounts outstanding under the credit facility, and in foreclosure of liens on our assets.

These covenants could materially and adversely affect our ability to finance any future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue business strategies and otherwise to conduct our business. A breach of these covenants could result in a default under our credit facility. If there were to be an event of default under the credit facility, the affected creditors could cause all amounts borrowed under the facility to be due and payable immediately. Additionally, if we fail to repay indebtedness under our credit facility when it becomes due, the lender under the credit facility could proceed against the assets which we have pledged as security. Our assets and cash flow might not be sufficient to repay any outstanding debt in the event of a default.

Our operations are subject to a significant number of tax regimes, and changes in legislation or regulations in any one of the countries in which we operate could negatively and adversely affect our results of operations.

Our operations are carried out in several countries across the world, and our tax filings are therefore subject to the jurisdiction of a significant number of tax authorities and tax regimes, as well as cross-border tax treaties between governments. Furthermore, the nature of our operations means that we routinely have to deal with complex tax issues (such as transfer pricing, permanent establishment or similar issues) as well as competing and developing tax systems where tax treaties may not exist or where the legislative framework is unclear. In addition, our international operations are taxed on different bases that vary from country to country, including net profit, deemed net profit (generally based on turnover) and revenue-based withholding taxes based on turnover.

Our management determines our tax provision based on our interpretation of enacted local tax laws and existing practices and uses assumptions regarding the tax deductibility of items and recognition of revenue. Changes in these assumptions and practices could impact the amount of income taxes that we provide for in any given year and could negatively and adversely affect the result of our operations.

Our tax liabilities could increase as a result of adverse tax audits, inquiries or settlements.

Our operations are, and may in the future become, subject to audit, inquiry and possible re-assessment by different tax authorities. In accordance with applicable accounting rules relating to contingencies, management provides for taxes in the amounts that we consider probable of being payable as a result of these audits and for which a reasonable estimate may be made. Management also separately considers if taxes payable in relation to filings not yet subject to audit may be higher than the amounts stated in our filed tax return, and makes additional provisions for probable risks if appropriate. As forecasting the ultimate outcome includes some uncertainty, the risk exists that adjustments will be recognized to our tax provisions in later years as and when these and other matters are finalized with the appropriate tax authorities.

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

We are from time to time involved in litigation. The numerous operating hazards inherent in our business increase our exposure to litigation, which may involve, among other things, contract disputes, personal injury, environmental, employment, tax and securities litigation, and litigation that arises in the ordinary course of business. Management cannot predict with certainty the outcome or effect of any claim or other litigation matter. Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of our management’s resources and other factors.

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Our reputation and ability to do business may be impaired by corrupt behavior by any of our employees or agents or those of our affiliates.

We operate in countries known to experience governmental corruption. While we are committed to conducting business in a legal and ethical manner, there is a risk that our employees or agents or those of our affiliates may take actions that violate either the U.S. Foreign Corrupt Practices Act or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations. These actions could result in monetary penalties against us or our affiliates and could damage our reputation and, therefore, our ability to do business.

In addition to the risks that arise in countries that have experienced governmental corruption, there is also a risk that we will not be able to ensure that our internal control policies and procedures will protect us from fraud or other criminal acts committed by our employees or agents or those of our affiliates.

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

One of our principal shareholders is Hemen Holding Ltd., which is indirectly controlled by trusts established by Mr. John Fredriksen for the benefit of his immediate family. Hemen also has significant shareholdings in Seadrill Limited, or Seadrill, which is our principal shareholder, and in Frontline Limited, or Seadrill, with whom we have management agreements. Currently, one of our directors, Kate Blankenship, is also a director of Frontline and Seadrill and another of our directors, Cecilie A. Fredriksen, the daughter of Mr. John Fredriksen, is also a director of Frontline. These directors owe fiduciary duties to the shareholders of each company and may have conflicts of interest in matters involving or affecting us and our shareholders. In addition, due to any ownership they may have in common shares of Frontline or Seadrill, they may have conflicts of interest when faced with decisions that could have different implications for Frontline or Seadrill than they do for us. Whilst we have procedures in place to deal with conflicts of interest, we cannot assure you that any of these conflicts of interest will be resolved in our favor.

Risks Related to our Common Shares

An active public market for our common shares may not develop, or our common shares may trade at low volumes, both of which could have an adverse effect on the resale price, if any, of our common shares.

Although our common shares were listed for trading on the Oslo Stock Exchange in November 2010, an active trading market may not develop or be sustained. Moreover, our common shares are not listed on a U.S. stock exchange, which makes it more difficult for investors located in the U.S. to trade in those shares. Active, liquid trading markets generally result in lower price volatility and more efficient execution of buy and sell orders for investors. If an active trading market for our common shares does not develop, the price of the shares may be more volatile and it may be more difficult to complete a buy or sell order for our common shares.

In addition, holders of our common shares may incur brokerage charges in connection with the resale of our common shares, which in some cases could exceed the proceeds realized by the holder from the resale of our shares. We cannot predict the price, if any, at which our common shares will trade in the future.

The price of our common shares has been, and may continue to be, volatile.

The trading price of our common shares has historically fluctuated significantly. For example, during the twelve months ended December 31, 2010, the high sales price per share of our common shares as reported by the Norwegian over-the-counter system and the Oslo Børs was NOK 37.00 and the low sales price per share was NOK 15.00. The volatility of the price of our common shares depends upon many factors including:

· decreases in prices for oil and natural gas resulting in decreased demand for our services;

· variations in our operating results and failure to meet expectations of investors and analysts;

· increases in interest rates;

· illiquidity of the market for our common shares;

· sales of common shares by existing shareholders;

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· our substantial indebtedness; and

· other developments affecting us or the financial markets.

A reduced share price may result in a loss to investors and will adversely affect our ability to issue common shares to fund our activities.

Because we are organized under the laws of Bermuda, U.S. investors may face difficulties in protecting their interests, and their ability to protect their rights through the U.S. federal courts may be limited.

It may be difficult to bring and enforce suits against us because we are organized under the laws of Bermuda. Some of our directors reside in various jurisdictions outside the United States. As a result, it may be difficult for investors to effect service of process within the United States upon our non-U.S. directors, or enforce judgments obtained in the United States courts against us or our non-U.S. directors. In addition, there is some doubt as to whether the courts of Bermuda and other countries would recognize or enforce judgments of United States courts obtained against us or our directors or officers based on the civil liabilities provisions of the federal or state securities laws of the United States or would hear actions against us or those persons based on those laws. We have been advised by our legal advisors in Bermuda that the United States and Bermuda do not currently have a treaty providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. Some remedies available under the laws of U.S. jurisdictions, including some remedies available under the U.S. federal securities laws, may not be allowed in Bermuda courts as contrary to that jurisdiction’s public policy. Therefore, a final judgment for the payment of money rendered by any federal or state court in the United States based on civil liability, whether or not based solely on United States federal or state securities laws, would not automatically be enforceable in Bermuda. Similarly, those judgments may not be enforceable in countries other than the United States.

We may not have sufficient capital in the future to meet our needs. Future financings to provide this capital may dilute shareholders’ ownership in the company.

We may raise additional capital in the future through public or private debt or equity financings by issuing additional common shares or other preferred financing shares, debt or equity securities convertible into common or preferred shares, or rights to acquire these securities. We may need to raise this additional capital in order to (among other things):

· take advantage of expansion or acquisition opportunities;

· acquire, form joint ventures with or make investments in complementary businesses, technologies or products;

· develop new products or services;

· respond to competitive pressures;

· repay debt; or

· respond to a difficult market climate.

Our management expects to issue additional equity securities to fund the acquisition of additional businesses and pursuant to employee benefit plans. We may also issue additional equity securities for other purposes. These securities may have the same rights as our common shares or, alternatively, may have dividend, liquidation, or other preferences to our common shares. The issuance of additional equity securities will dilute the holdings of existing shareholders and may reduce the price of our common shares.

Seadrill Limited and Lime Rock Partners control substantial ownership stakes in us and their interests could conflict with those of our other shareholders.

As of April 19, 2011, our largest shareholders, Seadrill and Lime Rock Partners V, L.P., or Lime Rock, own and are entitled to vote up to 36.43% and 13.37%, respectively, of our common shares. As a result of these substantial ownership interests in us, Seadrill and Lime Rock have the ability to exert significant influence over certain actions requiring shareholder approval, including, but not limited to, increasing or decreasing our authorized share capital (and disapplying pre-emptive rights), the election of directors, declaration of dividends, the appointment of management and other policy decisions.

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While transactions with a shareholder could benefit us, the interests of these significant shareholders could at times conflict with the interests of other holders of our common shares. Although we have in the past sought and continue to seek to conclude all related party transactions on an arm’s-length basis, and we have adopted procedures for entering into transactions with related parties, conflicts of interest may arise between us and our principal shareholders or their respective affiliates, resulting in the conclusion of transactions on terms not determined by market forces. Any such conflicts of interest could adversely affect our business, financial condition and results of operations, and therefore the value of our shares.

One of our major shareholders, Hemen, may be able to influence us, including the outcome of shareholder votes with interests that may be different from yours.

As of April 19, 2011, Hemen owned approximately 8.7% of our outstanding common shares. Hemen also owns approximately 30% of our principal shareholder, Seadrill Limited, and is indirectly controlled by trusts formed for the benefit of the immediate family of John Fredriksen, who is also a Director of Seadrill. As a result of this, Hemen may influence our business, including the outcome of any vote of our shareholders. Hemen also currently beneficially owns substantial stakes in Frontline Limited, with whom we have management agreements. The interests of Hemen may be different from your interests.

Item 4     Information on the Company

A. History and Development of the Company

Seawell Limited is organized as a “Company Limited by Shares” under the laws of Bermuda. We were established in August 2007 following the spin off of Seadrill’s well service division. The Company, together with its wholly owned subsidiary, Seawell Holding UK, acquired the shares in the entities comprising Seadrill’s well service division in October 2007. The following entities represented Seadrill’s well services division prior to its acquisition by us: Seawell AS, Seawell Engineering AS, Seawell Management Services Ltd (UK), Seawell Ltd. (UK), Seawell Offshore Denmark AS (DK) and Seawell Services Ltd (Hong Kong). As of April 19, 2011, Seadrill owned 36.43% of our common shares.

As a company incorporated in Bermuda, we are subject to Bermuda laws and regulations with respect to corporate governance. In addition, certain aspects of Norwegian securities law apply as a result of the listing of our common shares on the Oslo Stock Exchange.

Our registered office and principal executive offices are at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda, +1 441 295 69 35. The Company’s website address is www.seawellcorp.com. None of the contents of our website are incorporated by reference herein.

Recent Developments

· On January 27, 2011, we completed the acquisition of Universal Wireline, Inc., or Universal, for total consideration of $25.5 million on a debt-free and cash-free basis. Universal is a provider of a full range of cased-hole wireline services in unconventional plays such as the Barnett, Marcellus, Haynesville, Bakken, Eagle Ford and Woodford shales and in the Permian Basin. The Universal acquisition contributes 26 wireline units -- including 22 Artex built hydraulic units with an average age of less than 3 years and 4 mechanical units specific to work in Appalachia; 17 crane trucks with an average age of less than 3 years; and a wide assortment of logging and wireline tools. Universal also expands our area of operation by adding new districts in Rosharon and Alice in Texas; Dunbar and Buckhannon in West Virginia; and Tioga in North Dakota. For the fiscal year ended December 31, 2010, Universal reported revenues of approximately $5.7 million and losses before taxes of approximately $1.5 million and, at December 31, 2010, Universal had total assets of approximately $27.5 million.

· On February 23, 2011, Wellco Sub Company, or Wellco, a wholly owned subsidiary of the Company, completed the acquisition of Allis-Chalmers Energy Inc., or Allis-Chalmers, for total value of  $600.9 million, with approximately 95% of Allis-Chalmers stockholders electing to receive 97,071,710 common shares in the merger and the remainder receiving an aggregate of approximately $18 million in cash. The acquisition combined our leading drilling and well services businesses with Allis-Chalmers’ drilling, rental and oilfield service business to create a global oilfield service company with operations in more than 30 countries.

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· On February 28, 2011, our board of directors adopted a resolution to change the name of the Company to “Archer Limited.” The Company expects to adopt the name change in the second quarter of 2011, following approval of the change at a special general meeting of our shareholders on May 16, 2011 and the making of the appropriate filings with the Bermuda Registrar of Companies.

· On March 24, 2011, Allis-Chalmers notified holders of its 9.0% Senior Notes, due 2014, and 8.5% Senior Notes, due 2017 (together, the “Notes”), that a change in control occurred on February 23, 2011 as a result of the merger between the Company and Allis-Chalmers. Pursuant to the terms of the Notes and the notice, holders have the right to require Allis-Chalmers to purchase, on the third business day following the expiration of the offer, all or a portion of such holders’ Notes by way of tendering such Notes  to the depositary and paying agent, Global Bondholder Services Corporation, at a price equal to $1,010 per $1,000 principal amount of the Notes, plus any accrued and unpaid interest and Liquidated Damages (as defined in the indentures governing the Notes), if any, up to but not including the third business day following the expiration of the offer. The aggregate principal amount of the Notes is $430.2 million. Note holders’ opportunity to accept the change in control purchase offer commenced on March 24, 2011, and will terminate at 5:00 p.m., New York City time, on May 17, 2011. Holders may withdraw any previously tendered Notes pursuant to the terms of the change in control purchase offer at any time prior to 5:00 p.m., New York City time, on May 17, 2011.

Capital Expenditures

Capital Expenditures

Capital expenditures for property, plant and equipment for operations in the year ended December 31, 2010 were approximately NOK 168.5 million compared to capital expenditures of approximately NOK 195.8 million for in the year ended December 31, 2009 and NOK 265.5 million in the year ended December 31, 2008.

The table below sets forth information on our capital expenditures by business segment during the last three fiscal years:

	Year ended December 31,
	2008	2009	2010
	(NOK in millions)
Drilling Services	207.5	121.2	99.5
Well Services	58.0	74.6	69.0
Total	265.5	195.8	168.5

The four largest capital expenditure projects during fiscal year 2010 are set out in the table below.

Assets	Description of capital expenditure project	(NOK in millions)
Rental drilling equipment	Drilling Services/Platform Drilling	36
Tools & equipment	Wireline logging	29
Wireline equipment	Well Services/Wireline operations	15
Tools & equipment	Oilfield technology	15
Total		95

The four largest capital expenditure projects during fiscal year 2009 are set out in the table below:

Assets	Description of capital expenditure project	(NOK in millions)
Tools & equipment	Wireline logging and Oilfield technology	47
Real Estate building	Bergen office	45
Rental drilling equipment	Drilling Services/Platform Drilling	34
Wireline equipment	Well Services/Wireline operations	32
Total		158

The four largest capital expenditure projects during fiscal year 2008 are set out in the table below:

Assets	Description of capital expenditure project	(NOK in millions)
Drilling equipment	Drilling Services/Platform Drilling	160
Wireline equipment	Well Services/Wireline operations	45
Tools & equipment	Oilfield technology	36
Tools & equipment	Wireline logging	22
Total		263

Capital Expenditures for Fiscal Year 2011

Estimated capital expenditures on property, plant and equipment for fiscal year 2011 is approximately NOK 120 million, including drilling equipment and tools and equipment within Seawell Oiltools and TecWel.

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Divestitures

In July 2010, we completed the sale of Sandsliåsen 59 AS, a property company owning our engineering facility in Bergen, Norway. The net proceeds from the sale amounted to approximately NOK 51.3 million.

Since our formation in 2007, we have had no other significant divestitures.

B. Business Overview

We are a global oilfield service company providing drilling and well services to the oil and natural gas exploration and production industry. Our core businesses include platform drilling, drilling facility engineering, modular rigs, well intervention and oilfield technology. We are capable of providing a variety of services such as oil and gas exploration and development drilling, well service, platform inspection maintenance and de-commissioning operations. We provide drilling and well services to national oil and gas companies, major integrated energy companies and independent oil and natural gas operators by delivering innovative technologies, engineering expertise and operational excellence in the most cost-efficient manner. With operations in thirteen countries on six continents, our operations are supported by a skilled and experienced multinational workforce of approximately 3,200 employees.

Our total operating revenues and reimbursables, which are items purchased on behalf of customers for which we are reimbursed, for fiscal year 2010 were NOK 4,328.9 million, compared to NOK 3,824.8 million for fiscal year 2009 and NOK 3,624.7 million for 2008. Our backlog was NOK 6.6 billion on December 31, 2010, compared to NOK 8 billion on December 31, 2009 and NOK 4.7 billion on December 31, 2008. Of the December 31, 2010 backlog amount, management expects that approximately NOK 2.4 billion will be recognized as revenue in fiscal year 2011, approximately NOK 2.0 billion will be recognized as revenue in fiscal year 2012 and approximately NOK 2.2 billion will be recognized in later years. Although our backlog represents business that management believes to be firm, these figures are subject to change due to factors outside our control.

Strategy

Our strategic objective is to build a profitable and high growth oilfield service company focused on offering a differentiated portfolio of products and services through our two business segments, Drilling Services and Well Services. The key strategies to achieve this objective are:

· Developing and maintaining a solid footprint in each of the world’s significant oil producing regions through good customer relationships, strong local presence and superior personnel;

· Developing and providing packaged, integrated services across our operating divisions in response to customer requirements; and

· Exploiting opportunities to strengthen our service offering by acquiring unique technologies and skills within the drilling and well services market.

Competitive Strengths

Our management believes the following competitive strengths will enable us to capitalize on future opportunities:

· Strategic position in existing fields. We focus on providing services in existing oil producing fields. The high decline rates in these fields combined with global energy demand and the inability of new fields to provide sufficient additional production capacity provide a good foundation for long-term further growth.

· Relationships with diversified customer base across various geographic regions. We have relationships with many of the major and independent oil and natural gas producers and service companies in Norway, Denmark, the United Kingdom, Malaysia and Brazil. Our largest customers include Statoil, ConocoPhillips, Shell, BP, Chevron, Apache and Maersk Oil. We have broadened our customer base and geographic footprint as a result of our acquisitions, technical expertise and customer service and by providing customers with advanced technology and highly skilled operating personnel.

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· Successful execution of growth strategy. Since our inception, we have grown both organically and through successful acquisitions of competing businesses. These acquisitions and organic growth have expanded our geographic presence and customer base and, in turn, have enabled us to offer our technology to a large number of international exploration and production operators.

· Diversified and increased cash flow sources. We operate as a diversified oilfield service company through our two business segments. Management believes that our diverse product and service offerings and geographical presence through our two business segments provide us with stable cash flow and the opportunity for continued further growth.

· Experienced management team. Our executive management team has extensive experience in the energy sector, and consequently has developed strong and longstanding relationships with many of the major and independent exploration and production companies.

Business Segments

Our operations are managed through two business segments, Drilling Services and Well Services.

Drilling Services

Our largest business segment by revenue is the Drilling Services business, which generated total revenues of NOK 3,577.6 million, or 82.6% of total revenues, for the year ended December 31, 2010, compared to NOK 3,199.4 million, or 83.6% of total revenues, for the year ended December 31, 2009 and NOK 3,053.3 million, or 84.2% of total revenues, in the year ended December 31, 2008. Our Drilling Services operations include platform drilling and drilling facility engineering on several fixed installations in the North Sea and offshore Brazil.

Platform Drilling

Our core business is the provision of offshore drilling services, which we conduct on client-owned fixed oil and gas installations, referred to as “platforms.” We supply experienced personnel for drilling and technical operations on fixed production platforms. The scope of services we provide is detailed in client-specific contracts, which are also used to govern the relationship between us and our clients. Our business requires a high volume of personnel who are employed offshore to provide the services on a structured work rotation cycle.

Beginning with our inception as a division of Seadrill’s predecessor, Smedvig ASA, we have more than 30 years of experience drilling production wells on fixed platforms, including managing the operation, maintenance and provision and installation of spare parts of client-owned drilling equipment. We have been a key provider of platform drilling services in the North Sea since 1977, when Smedvig ASA was awarded the Unocal platform drilling contract for the Heather field. We currently operate on approximately 33 fixed installations in the North Sea. Approximately 2,200 experienced employees are trained to deliver quality services and performance.

The primary services that our Platform Drilling segment provides are management of clients’ drilling facilities and the provision of drilling and maintenance services.

· Rig management. Our electronic management system, COMPASS, provides a resource in our efforts to increase rig uptime and ensure operational safety on clients’ drilling facilities. We strive to provide the highest quality, most efficient and safest drilling services to its clients.

· Drilling crews. We supply drill crews to support all phases of its clients’ drilling operations. We provide our clients with highly competent drilling crews, helping to ensure clients have the best workforce in the market place. In addition, our multi-skilled drill crews are able to undertake additional tasks such as plug setting and cutting and cleaning operations. This reduces costs and personnel on board for our clients’ facilities.

· Maintenance crews. Our maintenance crews maintain the drilling facility on board clients’ platforms in prime condition. Our crews conduct preventive and corrective maintenance, helping to minimize non-productive time on the drilling facilities.

In addition to providing core drilling services, we are also able to provide integrated services. By offering a combination of multi-skilled personnel, innovative technology and intelligently-designed systems, we are able to provide clients with effective integration of drilling and well services.

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This integrated services approach enables well cost reductions by utilizing and combining drilling and maintenance crews for additional tasks such as crane and deck operations, cutting and cleaning operations, scaffolding and plug setting, applying new technology to transfer data onshore, thus reducing the requirement for third party involvement, developing and applying innovative technology and equipment to reduce personnel on board and integrating drilling and engineering personnel.

The following table lists the fixed offshore installations where we currently conduct Platform Drilling operations:

Customer	Platform	Location	Contract Start Date	Duration	Renewal Option	Options Exercised
Statoil Petroleum	Statfjord A, B, C	Norway	September 30, 2004	4 years	3 x 2 years	Yes; 1 x 2 years remaining
Statoil Petroleum	Gulfaks A, B, C	Norway	September 30, 2004	4 years	3 x 2 years	Yes; 1 x 2 years remaining
Statoil Petroleum	Veslefrikk	Norway	October 25, 1996	Field lifetime	N/A	N/A
BP	Ula & Valhall	Norway	May 1, 2008	5 years	2 x 3 years	No, 2 x 3 years remaining
Talisman Energy	Gyda	Norway	January 1, 2009	1 year	Options of 1 year each	Yes
ConocoPhillips	Ekofisk / Eldfisk A, B, E, X	Norway	July 1, 2010	5 years	Consecutive periods	No, up to 5 years remaining
Apache	Forties A, B, C, D, E	UK	July 1, 2009	3 years	2 x 1 year	No, 2 x 1 year remaining
Chevron	Alba-Captain	UK	April 1, 2004	5 years	3 x 1 year	Yes, 1 x 1 year remaining
Fairfield	Dunlin	UK	January 3, 2008	Field lifetime	N/A	N/A
Marathon	Brae A, B and East Brae	UK	July 27, 1994	Field lifetime	N/A	N/A
Shell	Brent A, B, C, D	UK	May 3, 2004	4 years	2 x 2 years	Yes, 1 x 2 years remaining
Taqa	Cormorant A, North Cormorant, Eider, Tern	UK	April 1, 2009	2 years	1 x 1 year	No
Statoil Petroleum	Peregrino A, B	Brazil	March 20, 2009	5 years	2 x 3 years	No, 2 x 3 years remaining

Drilling Facility Engineering

Our engineering division offers services covering conceptual engineering, front-end engineering design studies, detailed engineering and design, project management, planning and cost control, procurement and logistics management, construction follow-up, integration, installation, testing and commissioning for the modification and upgrade of projects for drilling facilities and related systems on fixed platforms. We also offer full technical support services for mobile drilling units. Our drilling facility engineering services are provided out of our facilities in: Bergen, Norway; Stavanger, Norway; Aberdeen, Scotland; Newcastle, England; and Houston, Texas.

Our engineering services cover a wide array of engineering disciplines key to the offshore oil and gas exploration and production industry, including drilling equipment, electrical engineering, well construction designs, drilling operations, instrumentation, automation, structural engineering, mechanical engineering, piping, materials and marine engineering. We provide specialist engineering services, including classification of mobile units, cranes and material handling, risk assessment and graphic inspection. In addition, our drilling facility engineering division also supplies consultants to major oil companies for long- or short-term assignments, with qualified and experienced personnel capable of providing top quality technical expertise.

Our engineering experience and expertise cover fixed installations, mobile drilling units and marine services.

· Fixed installations. We are able to provide facility engineering for fixed installation projects of all sizes. Our fixed installation engineering services include compliance assessments, front-end engineering design, 3D design and drafting of fixed installation projects, offshore installation and demolition work, commissioning of offshore facilities, meeting clients’ documentation requirements and project management from concept to closeout.

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· Mobile drilling units (“MODU”). We provide facility engineering for mobile drilling projects from initial study to project hand-over to operation of the unit. We are able to provide modifications of all sizes of MODU and offshore vessels and can perform the entire project from inspection and concept through to procurement, engineering and installation, testing and as built update. In addition, we provide planning and support for MODU five-year Classification Special Survey through planning, preparation, survey support and remediation.

· Marine services. We provide operation engineering services for offshore drilling rigs, providing practical solutions for challenges facing drilling contractors in deep and ultra-deep water. Our marine services include vessel weight control services, riser analysis, dynamic position analysis, mooring system design and vessel stability assessments.

Modular Rigs

We have developed a 400 ton offshore modular drilling and workover rig concept in conjunction with Max Streicher GmbH & Co. KG, a German mechanical engineering and construction company. The modular rig is in the final stages of commissioning and acceptance testing and the rig is scheduled to be delivered in the second half of 2011. The modular rig’s design is based on a rack-and-pinion concept, which provides both pull (400 tons) and push (100 tons) capability. The 400 ton modular rig is capable of performing conventional drilling/sidetrack operations, snubbing services, workover services, through tubing rotary drilling, managed-pressure drilling and plug and abandon activities. Our modular rig design is flexible, and can be delivered with or without a mud system and power generation. In addition, the modular rig’s design allows it to replace all or a portion of conventional drilling facilities, snubbing units and hydraulic workover units.

Well Services

Our Well Services business segment generated total operating revenues of NOK 751.3 million, or 17.4% of total operating revenues, for the year ended December 31, 2010, compared to NOK 625.4 million, or 16.4% of total operating revenues, for the year ended December 31, 2009 and NOK 571.5 million, or 15.8% of total operating revenues, for the year ended December 31, 2008. Our Well Services operations encompass various well intervention and oilfield technology services, including, but not limited, to the offering of (i) advanced multi-line units, which are wireline winches capable of performing either mechanical or electrical interventions from the same unit; (ii) specialized intervention tools, including fishing tools used for removing lost items in the wellbore; (iii) cased hole investigation services, which utilize tools to measure the integrity of the wellbore, leaks in the casing and thickness of the wellbore; and (iv) delivery of well barrier technology, which include removable downhole mechanical isolation plugs.

Wireline Intervention

We are a major player in the North Sea well intervention market and offer a full range of wireline and investigation services through the well life cycle, from drilling to abandonment. Intervention by wireline allows for the maintenance and repair of oil and natural gas wells and is the most efficient and frequently used well-intervention method. Wireline intervention is applied in all phases of a well’s life: in drilling, workover, completion, production, stimulation, repair and maintenance and abandonment.

Our wireline intervention team provides packages of multi-skilled personnel and state-of-the-art conveying equipment for slick, braided and electric-line services, spanning the full range of mechanical and electrical wireline operations.

Our wireline intervention capabilities include operations planning and well intervention modeling, subsea well intervention, horizontal and extended-reach intervention, downhole video cameras, wireline tractors, heavy duty fishing and multi-lateral well intervention. In addition, our special services group provides specialized wireline services to solve complex downhole challenges.

Wireline Logging

We provide oil and gas exploration and production companies with wireline logging services capable of providing detailed records of the conditions of the wellbore through the use of ultrasonic investigation tools that determine well integrity and optimize well production. Our ultrasonic investigation tool capabilities include leak detection, annular flow detection and sand detection. In addition, in 2010, we began operating the well performance eye, or WPE, a camera that can image the well in opaque fluids, providing operators with a visualization of conditions downhole, both inside and outside the well bore. The WPE is unique in that it serves a need no tool was previously able to serve.

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Our well intervention services are further supported by TecWel AS, a company we acquired in 2008. TecWel develops and manufactures proprietary high frequency cased hole investigation tools, an effective and powerful diagnostic resource utilizing the properties of ultrasonic energy to facilitate well production optimization and ensure well integrity for the oil and gas industry worldwide.

Oilfield Technologies

In order to enhance oil and gas recovery for our clients, we acquire and/or develop technologies to optimize drilling and well service activities. Our research and development departments offer products in ultrasonic technologies, well construction and well intervention.

Seawell Oil Tools (former Peak Well Solutions) was acquired by us in 2008 and partners with oil and gas exploration and production companies to enhance their casing and liner performance. Seawell Oil Tools provides clients with the following mechanical tools: VMB barrier plug, a retrievable gas-tight plug providing reduced deployment cycles, increased flexibility and greater security, C-Flex cementing valve, a gas-tight solution for precision primary or contingency staged cementing, and remote controlled cement heads.

The following table sets forth the fixed offshore installations where we currently conduct Well Services operations:

Customer	Platform	Location	Contract Start Date	Duration	Renewal Option	Options exercised
Statoil Petroleum	Kvitebjørn	Norway	March 1, 2002	8 years	N/A	N/A
Statoil Petroleum	Tyrihans	Norway	December 1, 2009	2 years	N/A	N/A
Statoil Petroleum	Morvin	Norway	December 1, 2009	2 years	N/A	N/A
ConocoPhillips	Ekofisk Area	Norway	December 31, 2009	5 years	2 x 2 years	No, 2 x 2 years remaining
Maersk	All fixed platforms in Denmark	Denmark	November 1, 2010	3 years	3 x 1 years	No, 3 x 1 years remaining
Total	Victoria / Hild	Norway	March 1, 2009	3 years	2 x 2 years	No, 2 x 2 years remaining
Shell	Draugen	Norway	September 1, 2008	3 years	Rebid in process	N/A

Principal Markets

The principal markets for our services are Norway, the United Kingdom, Denmark, Malaysia, Brazil and the United States.

The following table sets forth our total revenues by geographic market for the years ended December 31, 2008, 2009 and 2010.

	Year ended December 31,
	2008	2009	2010
	(NOK in millions)
Norway	2,599.2	2,745.8	3,198.6
United Kingdom	967.3	930.4	839.3
Other	58.2	148.6	291.0
Total	3,624.7	3,824.8	4,328.9

Competition

We experience significant competition in all areas of our business. In general, the markets in which we compete are highly fragmented, and a large number of companies offer services that overlap and are competitive with our services and products. Our management believes that the principal competitive factors are technical and mechanical capabilities, management experience, past performance and price. While we have considerable experience, there are many other companies that have comparable skills. Many of our competitors are larger and have greater financial resources than we do.

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Our primary competitors in the North Sea for drilling services are KCA Deutag and Odfjell Drilling, both of which provide similar products and services. Our largest competitors for well intervention services are Aker Solutions and Deepwell.

Seasonality

A significant portion of our revenue is generated from work performed in the North Sea, where adverse weather conditions during the winter months usually result in low levels of activity, although this is less apparent than in the past due to technological advances. Further, in Brazil, where we also generate revenue from operations, adverse weather conditions affect our results of operations. Optimal weather conditions offshore Brazil normally exist only from October to April and most offshore operations in this region are scheduled for that period. Therefore full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters. Additionally, during certain periods of the year, our business may be affected by delays caused by adverse weather conditions such as hurricanes or tropical storms. During periods of curtailed activity due to adverse weather conditions, we continue to incur operating expenses.

Equipment

The equipment utilized in our business is generally available new from manufacturers or at auction. However, the cost of acquiring new equipment to expand our business could increase as demand for equipment in the industry increases.

Marketing

Marketing of our services is performed through regional offices. Our marketing strategy is focused on ensuring that we are invited to bid on all proposed projects that are consistent with our strategy, and where we have a competitive advantage on the basis of our capabilities, engineering excellence or technological specialization. We use our industry know-how and relationships with clients to ensure we are aware of all projects in our markets that fit these criteria.

Most of our work is obtained through a competitive tendering process. When a target project, or “tender,” is identified by our marketing team, the decision to prepare and submit a competitive bid is taken by management in accordance with delegated authority limits. Cost estimates are prepared on the basis of a detailed standard cost manual, and the selling price and contract terms are based on our commercial standards and market conditions. Before the tender package is submitted to the client, it is subject to a detailed review process by senior management.

The implementation of our tendering policies has resulted in the information contained in tender review packages being uniform across our organization, allowing us to weigh the risks and benefits of tendering for various projects. A larger proportion of tenders are reviewed centrally by management and we continue to place great emphasis on our standard contractual terms and conditions. With these policies in place, we devote significant management time to the tendering process and are selective with respect to the initiation of new projects.

Once we have been awarded a project to provide drilling services or well services, we will enter into a project contract with our client. Typically, we enter into day-rate contracts; however, on rare occasions, lump-sum contracts may be entered into. Currently, all of our Drilling Services and Well Services contracts are day-rate contracts.

Where services are to be performed pursuant to a day-rate contract, we will enter into a framework agreement outlining the terms of the project, with individual project call-offs being utilized to provide the details of the specific work we are to conduct. Under the terms of our day-rate contracts, we receive payment based on the days our services are utilized. Our day-rate contracts typically include provisions for a reduced day-rate due to weather or equipment downtime.

Under the terms of our contracts, our clients usually have the right to terminate without cause upon written notification specifying the termination date. Where the client terminates without cause, we are entitled to payment for work performed in accordance with the contract, including our reasonable costs.

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Intellectual Property

We own or have a right to use a number of patents and trademarks, as well as software and other intellectual property to support its operational activities. A limited number of our patents are held in common with other industrial partners. We also conduct some of our operations under licensing agreements allowing us to make use of specific techniques or equipment patented by third parties. However, no one patent or technology is responsible for a significant percentage of revenue.

Environmental Regulations

Our operations are subject to federal, state and local laws and regulations of the jurisdictions in which it operates relating to the energy industry in general and the environment in particular. Environmental laws have in recent years become more stringent and have generally sought to impose greater liability on a larger number of potentially responsible parties. Because we provide services to companies producing oil and natural gas, which may cause damage to the environment, we may become subject to claims relating to the release of such substances into the environment. We strive to conduct our business activities in an environmentally sustainable manner that is achieved through the use of written processes and risk management procedures focused on the proactive assessment of environmental risks associated with our operations. These risk assessments help facilitate a reduction of the environmental impact of our activities and help prevent the accidental release of oil and natural gas into the environment. While management is not currently aware of any situation involving an environmental claim that would likely have a material adverse effect on us, it is possible that an environmental claim could arise that could cause our business to suffer. Management does not anticipate any material expenditure to comply with environmental regulations affecting our operations.

Other Matters

Health, Safety and Environmental Management

We conduct business in accordance with a well-defined set of processes. Our Health, Safety and Environmental, or HSE, philosophy is to establish and maintain a culture where there are no accidents, injuries or losses. Management believes that a good working environment is a prerequisite for achieving good safety results and that sincere commitment from senior management is a key factor in reaching the goal of no accidents, injuries or losses. Line management is responsible for the implementation of systematic and preventive HSE work, as well as encouraging and promoting a sound health, environment and safety culture. In addition, we have implemented a program to encourage and stress each individual’s responsibility for and commitment to HSE matters. This program includes seminars, on-the-job training, best practice campaigns and a focus on leadership.

Our management system meets the relevant requirements of authorities, customers and partners. The management system has certified according to ISO 9001:2008, Quality Management. In addition, the management system has met the requirements of ISO 14001:2006, Environmental Management Standards, for several years and management is currently in the process of certifying Seawell according to these standards. In addition, relevant authorities such as the Petroleum Safety Authority Norway and the UK Health & Safety Executive have accepted the management system through the Acknowledgement of Compliance and the Safety Case certification, respectively.

As a result of our systematic and focused safety management program, improvements have been shown in most safety statistics. In addition, the majority of incidents still taking place have a very low potential for serious personal injuries, spills or emissions to the environment or economic losses. In addition, we are actively working to prevent damage to the environment as a result of our operations. This includes the systematic registration of emissions and discharges and pre-emptive action in selecting chemicals that cause minimum harm to the environment.

Risks and Insurance

Our operations are subject to all the risks normally associated with offshore development and operations and could result in damage to, or loss of, property, suspension of operations or injury or death to employees or third parties. Our operations are conducted in hazardous environments where accidents involving catastrophic damage or loss of life could result, and litigation arising from such an event may result in us being named a defendant in lawsuits asserting large claims. As is customary in the oilfield services industry, we attempt to mitigate our exposure to some of these risks through indemnification arrangements and insurance policies.

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Our platform drilling well services contracts are identified above. Generally, such contracts contain contractual indemnities against liability for pollution, well and environmental damages, damages to equipment and property, and personal injury, consistent with industry practices. These indemnities provide that our customer, the operator, will retain liability and indemnify us for:

· environmental pollution caused by any oil, gas, water or other fluids and pollutants originating from below the seabed;

· damage to customer and third-party equipment and property including any damage to the sub-surface and reservoir; and

· personal injury to or death of customer personnel.

The allocation of risk described above is not unique to our business and is generally accepted in the oil and gas industry by and between service companies like us, on the one hand, and operators and exploration and production companies, on the other. This allocation reflects the risk-reward model as defined in the industry for several decades.

We also carry insurance coverage for our operations and are partially self-insured for certain claims in amounts that management believes to be customary and reasonable. In line with industry practice, we maintain insurance worldwide for liability arising from our operations, and our insurance covers all of our material assets, including all capital items such as major equipment and real property. Among the risks insured are loss of, or damage to, third-party property, consequential interruptions in business, death or injury to employees and/or third parties, statutory workers’ compensation protection and pollution.

Our insurance coverage is consistent with industry practices, including a policy for general third party and product liability insurance with If Property & Casualty Insurance NUF, Norway. The current policy expires on May 31, 2011, and management currently anticipates that we will be able to renew our policy on commercially reasonable terms. The policy includes coverage of NOK 250 million per occurrence for contractual liability for damage caused to a third party (any party other than the insured, its affiliates and co-licensees and their respective employees). The policy also has extended coverage of up to $700,000 per occurrence with an annual aggregate limit of $3.5 million for professional liability as a result of faulty product design, feasibility studies, procurement, supervision, license agreements or sales of electronic data processing software and reservoir monitoring system. This policy has a deductible of NOK 500,000 (in the U.S., Canada and Australia, local policies will be taken out with a minimum limit of USD/CAD/AUD 1,000,000, which applies as the deductible).

Our general third party and product liability insurance policy does, however, expressly exclude coverage for certain types of environmental damages. In all locations except North America the policy covers only environmental damages that are the direct and unavoidable consequences of a sudden, unforeseen and identifiable event and, in the case of recoverable pollution damage, the policy also covers clean-up related expenses imposed by public authorities. In North America, the policy includes what is known as “Named Perils Coverage”, which covers claims for personal injury or damage to soil, air, water or other property damage, provided that such loss is a direct and unavoidable consequence of any of the following perils:

· unintended and unforeseen fire, lightning or explosion;

· collision or overturning of road vehicles; and

· explosion of piping or pressure vessels within the insured’s premises that are not caused by insufficient maintenance or monitoring.

The Named Perils Coverage expressly excludes the following:

· loss of or damage to or loss of use of property or indirectly resulting from sub-surface operations or installations of the insured;

· costs for removal of, loss of or damage to substances stored or handled under ground, such as oil, gas or any other substance;

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· losses emanating from any site or location used in whole or in part for handling, processing, treating, storing, disposing or dumping of any waste material or similar substance;

· costs for evaluation, monitoring, or controlling of suspect or known seeping, polluting or contaminating substances; and

· costs of removing or cleaning up seeping, polluting or contaminating substances on property at any time owned or leased by the insured or under control of the insured.

Such insurance would cover claims made against us by or on behalf of individuals who are not our employees regardless of whether we held indemnity rights from our customer or another third party.

We have not previously, and do not now, own an offshore rig. We do have a contract for the purchase of a modular rig currently under construction in Germany and such modular rig will be insured upon transfer of title under our existing insurance coverage above. In addition, we may procure a hull and marine policy for such modular rig.

Management considers our level of insurance coverage to be appropriate for the risks inherent in our business. The determination of the appropriate level of insurance coverage is made on an individual asset basis taking into account several factors, including the age, market value, cash flow value and replacement value of the asset in hand. However, there can be no assurance that the amount of insurance we carry is sufficient to protect us fully in all events, and a successful liability claim for which we are under-insured or uninsured could have a material adverse effect on our business. Additionally, insurance rates have in the past been subject to wide fluctuations, and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. See “Risk Factors—Risks Related to our Business—Our insurance coverage has become more expensive, may become unavailable in the future, and may be inadequate to cover our losses.”

The acquired business of Allis-Chalmers includes providing services and rental equipment to owners and operators of offshore rigs in the Gulf of Mexico. Allis-Chalmers is a party to various master service agreements establishing the terms and conditions under which it provides oilfield services to its customers. These master service agreements generally require customers to indemnify Allis-Chalmers against claims relating to pollution or other environmental liabilities arising from subsurface conditions or resulting from drilling activities of the customers or its operators. However, pursuant to these agreements, Allis-Chalmers retains potential liability for any gross negligence or willful misconduct on its part. The master services agreements are designed to allocate potential liabilities relating to the services provided by Allis-Chalmers and the activities of its customers between Allis-Chalmers, on the one hand, and its customers, on the other. Generally, the customers agree to indemnify Allis-Chalmers against claims arising from their employees’ personal injury or death, unless resulting from Allis-Chalmers’ gross negligence or willful misconduct. Similarly, Allis-Chalmers generally agrees to indemnify its customers for liabilities arising from personal injury to, or death of, any of Allis-Chalmers’ employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, the customers generally agree to indemnify Allis-Chalmers for loss or destruction of customer-owned property or equipment, and in turn, Allis-Chalmers generally agrees to indemnify our customers for loss or destruction of property or equipment it owns. However, for equipment Allis-Chalmers rents to its customers, the contracts generally provide that the customer is responsible for the replacement of any damaged or lost equipment in their care. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer.

Allis-Chalmers’ general liability insurance policy generally covers third-party bodily injury and property damage, subject to policy exclusions. The limits and deductibles for this policy are as follows:

· General Aggregate $2,000,000

· Products/Completed Operations Aggregate $2,000,000

· Occurrence Limit $1,000,000

· Personal / Advertising Injury Limit $1,000,000

· Deductible (Bodily Injury & Property Damage Combined) Per Claim $100,000

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In addition, this general liability insurance policy is scheduled under Allis-Chalmers’ umbrella / excess liability insurance policy, which provides $30 million in coverage. Allis-Chalmers also has workers’ compensation insurance coverage up to $1,000,000 and a contractor’s pollution liability insurance policy of $10 million with a $200,000 deductible.

Allis-Chalmers does not own or operate offshore rigs in the Gulf of Mexico or elsewhere. We expect to renew Allis-Chalmers’ existing insurance policies to extend through 2011 as the combined businesses are integrated, after which we plan to re-assess coverage in light of the new scope of the combined business. Any revised insurance coverage would cover the acquired business of Allis-Chalmers.

Emergency Response Protocol

Although, as discussed above, as is customary for a provider of oilfield services, we are generally protected from responsibility for oil spills and leaks by our insurance policies and indemnification arrangements with our customers, we also have in place an emergency preparedness protocol that is designed to address these and other emergencies. We employ emergency call receivers who are on duty or on call 24 hours a day to receive initial calls regarding any emergency, conduct an initial assessment of the extent of the emergency and notify the appropriate persons and authorities according to an established communication matrix. In the case of emergencies that occur on the facilities operated by our customers, the customer/operator leads the emergency response. We work with customers to insure that all employees on the facility in question have received the training specified in the Guidelines for Safety and Emergency Training as required by the Petroleum Safety Authority Norway. We also maintain onshore response teams at each of our workshop and office sites. These teams number between six and fifteen individuals, depending on the size of the location. Each team includes a fire protection leader and a floor warden and at least one deputy. The teams conduct drills at least twice a year and are regularly provided with first aid training. We have dedicated a room in all of our locations for the emergency response teams to meet and manage the situations that arise. Once the necessary persons have been notified, our onshore emergency response team first prepares an emergency response room, based on both a company-wide protocol as well as specific instructions depending on the location and type of emergency. The onshore emergency response team is also responsible for determining at an early stage whether an offshore response is needed and whether further third-party assistance is required. The emergency response team then proceeds to work with the applicable authorities and third parties to normalize the situation. In all cases of an emergency, our emergency response protocol does not permit normal activity to resume without the approval of the highest authority involved.

C. Organizational Structure

We were incorporated on August 31, 2007, under the laws of Bermuda. We are engaged, with our subsidiaries and consolidated companies, in the provision of drilling and well services to the oil and natural gas exploration and production industry. Our operations are split into two reporting segments—drilling services and well services.

Overall responsibility for the management of the Company and its subsidiaries rests with our board of directors. Our board of directors has determined that the Company shall not directly employ any individuals and that all of our management requirements shall be contracted with subsidiaries and third parties. Our board of directors, however, retains sole authority on all issues, including:

· defining our business;

· setting goals in relation to our business; and

· approving all strategic plans to achieve the goals set.

The following table sets forth our significant subsidiaries.

Subsidiary	Jurisdiction of Incorporation	Principal Activities	% Owned
Allis-Chalmers Energy Inc.	United States	Holding company	100
Archer Management (US) LLC	United States	Management company	100
Seawell Management AS	Norway	Management company	100
Seawell Management Ltd	United Kingdom	Management company	100
Seawell Management (Bermuda) Ltd	Bermuda	Management company	100

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Subsidiary Jurisdiction of Incorporation Principal Activities % Owned

Seawell Management (Hong Kong) Limited	Hong Kong	Management company	100
Seawell Norge AS	Norway	Onshore administration and holding company	100
Seawell AS	Norway	Drilling, engineering and well services	100
Seawell Offshore Denmark AS	Denmark	Well services	100
Seawell Services Ltd.	Hong Kong	Drilling services	100
Seawell Overseas Contracting Ltd.	Hong Kong	Drilling services	100
Seawell Ltd. (UK)	United Kingdom	Drilling, engineering and well services	100
Seawell Consulting  Services Ltd.	United Kingdom	Onshore administration and management	100
Archer Assets UK Limited	United Kingdom	Holding company	100
Seawell Drilling Ltd.	United Kingdom	Drilling services	100
Archer Well Company Inc.	United States	Drilling, engineering and well services	100
Seawell Emerald Ltd.	Bermuda	Owner of modular rig	100
Seawell Oil Tools Ltd.	Bermuda	Rental services	100
Seawell do Brasil Servicos de Petroleo Ltda	Brazil	Drilling and engineering services	100
Seawell Oil Tools AS	Norway	Well services	100
Peak Well Solutions AS	Norway	Well services	100
TecWel AS	Norway	Well services	100
TecWel Telemetri AS	Norway	Well services	100
TecWel Inc.	United States	Well services	100
TecWel Ltd.	United Kingdom	Well services	100
C6 Technologies AS	Norway	Oilfield equipment	50
Viking Intervention Technology AS	Norway	Oilfield equipment	501
Wellbore Solutions AS	Norway	Oilfield equipment	42.6
Rig Inspection Services Pte. Ltd	Singapore	Inspection Services	100
Romeg Holdings Pty. Ltd.	Australia	Inspection Services	100
Gray Holdco, Inc.	United States	Holding company	100
Gray Parent Inc.	United States	Holding company	100
Gray Wireline Service Inc.	United States	Well services	100
Universal Wireline, Inc.	United States	Well services	100

_______________________
Note:

1 Viking Intervention Technology AS is 100% owned by C6 Technologies AS.

D. Property, Plant and Equipment

As of December 31, 2010 we owned or held under long-term leases the real estate property described below.

Location	Function	Status
Hamilton, Bermuda	Principal executive offices	Leased
Stavanger, Norway	Offices and warehouses	Leased
Bergen, Norway	Offices and warehouses	Leased
Aberdeen, Scotland, UK	Offices and warehouses	Leased
Newcastle, England, UK	Offices and warehouses	Leased
Houston, Texas, USA	Offices and warehouses	Leased
Fort Worth, Texas, USA	Offices and warehouses	Leased
Esbjerg, Denmark	Offices and warehouses	Leased
Rio, Brazil	Offices and warehouses	Leased

In addition to the leases listed above, as of December 31, 2010, we have a modular rig under construction.

In addition to the above assets and leases, we hold a substantial amount of wireline, tooling and rental drilling assets, none of which are individually significant.

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Item 4A  Unresolved Staff Comments

Not applicable.

Item 5     Operating and Financial Review and Prospects

A. Operating Results

Overview

We are a leading global oilfield service company providing drilling and well services to the oil and natural gas exploration and production industry. Our core businesses include platform drilling, drilling facility engineering, modular rigs, well intervention and oilfield technology. We are capable of providing a variety of services such as oil and gas exploration and development drilling, well services, platform inspection maintenance and de-commissioning operations. We provide drilling and well services to national oil and gas companies, major integrated energy companies and independent oil and natural gas operators by delivering innovative technologies, engineering expertise and operational excellence in the most cost-efficient manner. With operations in thirteen countries on six continents, our operations are supported by a skilled and experienced multinational workforce of approximately 3,200 employees.

Our total operating revenues and reimbursables for the year ended December 31, 2010 were NOK 4,328.9 million, compared to NOK 3,824.8 million for the year ended December 31, 2009 and NOK 3,624.7 million for the year ended December 31, 2008. Our backlog was NOK 6.6 billion on December 31, 2010, compared to NOK 8 billion on December 31, 2009 and NOK 4.7 billion on December 31, 2008. Of the December 31, 2010 backlog amount, we expect that approximately NOK 2.4 billion will be recognized as revenue in fiscal year 2011, approximately NOK 2.0 billion will be recognized as revenue in fiscal year 2012 and approximately NOK 2.2 billion will be recognized in later years. Although our backlog represents business that management believes to be firm, these figures are subject to change due to factors outside our control. See Item 3.D. “Risk Factors—Risks Related to our Business—We can provide no assurance that our current backlog of platform drilling revenue will be ultimately realized.”

Our operations are managed through our two business segments, Drilling Services and Well Services.

· Drilling Services. Our Drilling Services segment provides platform drilling services, drilling facility engineering and modular rigs to support the offshore oil and gas exploration and production industry from well construction to plug and abandonment. Our drilling teams secure the production of oil and gas on more than 40 platforms globally.

· Well Services. Our Well Services segment conducts wireline intervention and wireline logging and provides well barrier technology to improve the integrity and performance of our clients’ wells.

Material Factors Affecting Our Results of Operations

Business Environment

The oilfield services industry is cyclical and volatile. Our business depends on the level of activity in oil and gas production in offshore areas worldwide. Given that our customers are oil and gas companies, the strength of the market in which we operate is dependent on the level of exploration, development and production activities for oil and gas. The level of activity in the oilfield services industry and, consequently, its profitability are directly related to factors such as:

· the prevailing prices of oil and gas;

· expectations about future prices;

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

· the sale and expiration dates of offshore leases;

· the discovery rate of new oil and gas reserves in offshore areas;

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· local and international political and economic conditions;

· technological advances;

· the ability of oil and gas companies to generate funds for capital expenditures; and

· the level of competition in the marine construction sector.

Utilization of Personnel and Equipment

The majority of our contracts for the provision of drilling services and well services are day-rate contracts, the revenues of which depend on the utilization rate of our personnel and equipment. We do not generate revenue under these contracts unless our personnel and/or equipment are being utilized and many of these contracts do not require a minimum level of utilization by our customers.

Acquisitions

We have developed our current business through several strategic acquisitions. Some of these acquisitions have had a significant effect on our financial condition and results of operations since our inception. Our business primarily comprises the following acquisitions:

Universal Wireline

On January 27, 2011, we completed the acquisition of Universal Wireline, Inc., or Universal, for total consideration of $25.5 million on a debt-free and cash-free basis. Universal is a provider of a full range of cased-hole wireline services in unconventional plays such as the Barnett, Marcellus, Haynesville, Bakken, Eagle Ford and Woodford shales and in the Permian Basin. The Universal acquisition contributes 26 wireline units -- including 22 Artex built hydraulic units with an average age of less than 3 years and 4 mechanical units specific to work in Appalachia; 17 crane trucks with an average age of less than 3 years; and a wide assortment of logging and wireline tools. Universal also expands our area of operation by adding new districts in Rosharon and Alice in Texas; Dunbar and Buckhannon in West Virginia; and Tioga in North Dakota. For the fiscal year ended December 31, 2010, Universal reported revenues of approximately $5.7 million and losses before taxes of approximately $1.5 million and, at December 31, 2010, Universal had total assets of approximately $27.5 million.

Allis-Chalmers Energy

On February 23, 2011, Wellco Sub Company, or Wellco, a wholly owned subsidiary of the Company, completed the acquisition of Allis-Chalmers Energy Inc., or Allis-Chalmers, for total value of $600.9 million, with approximately 95% of Allis-Chalmers stockholders electing to receive 97,071,710 common shares in the merger and the remainder receiving an aggregate of approximately $18 million in cash. The acquisition combined our leading drilling and well services businesses with Allis-Chalmers’ drilling, rental and oilfield service business to create a global oilfield service company with operations in more than 30 countries.

Gray Wireline

On December 16, 2010, Seawell Americas, Inc., one of our subsidiaries, completed the acquisition of Gray Holdco, Inc. and its subsidiaries, including Gray Wireline Service, Inc., or Gray, for total consideration of $160.5 million on a debt-free basis. Gray is a provider of a full range of cased-hole wireline services in the Permian basin in Texas and in unconventional plays such as the Barnett, Marcellus, Haynesville, Bakken, Eagle Ford and Woodford oil and natural gas shales, located throughout the U.S. Gray has a total of 110 wireline units and operates in 18 district locations, providing access to approximately 85% of all active U.S. drilling rigs and generating a balanced revenue stream from liquids and gas. For the fiscal year ended June 30, 2010, Gray reported revenues of approximately $72.1 million and losses before taxes of approximately $(16.6) million and, at June 30, 2010, Gray had total assets of approximately $90.0 million.

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Joint Venture with IKM

In November 2010, we entered into an agreement with the IKM Group, or IKM, pursuant to which IKM acquired 50% of the shares in C6 Technologies AS through an equity issue, and C6 Technologies AS simultaneously acquired 100% of the shares in Viking Intervention Technology AS.

Following the loss of control in C6 Technologies AS and Viking Intervention Technology AS, we deconsolidated C6 Technologies AS, and have accounted for our interest in C6 Technologies AS as an investment in associates in the balance sheet as of December 31, 2010.

Rig Inspection Services Pte. Ltd and Romeg Holdings Pty. Ltd

In August 2010, we acquired Rig Inspection Services Pte. Ltd, or RIS, and Romeg Holdings Pty. Ltd for a consideration of SGD 7.5 million (approximately NOK 30 million) plus a contingent consideration of up to SGD 7.5 million (approximately NOK 30 million). RIS offers specialized industry knowledge and experience with broad inspection expertise. RIS surveyors and inspectors are on call 24 hours a day, seven days a week, specifically to provide a wide range of services within the oil and gas industry, including Rig Acceptance & Safety Surveys, Rig Condition & Benchmark Surveys, Subsea & Surface Well Control Equipment Inspection and Oil Country Tubular Goods (OCTG) services.

Viking Intervention Technology AS

In May 2010, we acquired Viking Intervention Technology AS for consideration of NOK 50 million plus an earn-out of up to NOK 25 million. Viking Intervention Technology is a company developing an integrated carbon cable intervention system.

Sandsliåsen 59 AS

In April 2009, we exercised an option to purchase Sandsliåsen 59 AS, a property company located in Bergen, Norway that owns an operational support office in Bergen. The purchase price for the acquisition was NOK 33.3 million. This transaction was accounted for as a purchase of asset under Accounting Standards Codification 805, and all surplus value has been allocated to the property owned by us. We subsequently sold Sandsliåsen 59 AS in July 2010 for approximately NOK 51.3 million.

Noble Corporation’s North Sea Platform Division

In April 2008, we purchased Noble Corporation’s North Sea Platform division by acquiring all shares in Noble Drilling UK Limited for a purchase price of approximately US$ 51 million (approximately NOK 268.3 million). The acquisition included platform drilling contracts on 11 fixed installations covering five different fields on the UK continental shelf. The purchase closed on April 1, 2008, and the North Sea Platform division’s results of operations have been included in our consolidated results from such date.

Peak Well Solutions AS (previously Seawell Oilservice AS)

In May 2008, we acquired Peak Well Solutions AS for a purchase price of NOK 412.3 million. Peak Well Solutions is a Norwegian-based oil service company offering products and services for the upstream offshore oil and gas industry. Peak Well Solutions performs development, engineering, assembly, testing, sales and operations of casing, plugs, and liner technologies and services, employing approximately 60 people. The purchase closed on May 1, 2008, and Peak Well Solutions’ results of operations have been included in our consolidated results from such date. In 2009, an adjustment of NOK 2.4 million to the purchase price of Peak Well Solutions AS was made, reducing the total purchase price to NOK 409.9 million. The reduction has been booked as a reduction in goodwill in the consolidated accounts.

TecWel AS

In July 2008, we acquired TecWel AS for a purchase price of NOK 172.7 million. TecWel develops and manufactures proprietary high frequency ultrasound investigation tools and provides cased-hole services for production optimization and well integrity to the oil and gas industry worldwide. The purchase closed on July 1, 2008, and TecWel’s results of operations have been included in our consolidated results from such date.

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Wellbore Solutions AS

On November 7, 2007, Seawell Norge AS completed the purchase of 33.7% of the shares in Wellbore Solutions AS, or Wellbore, a company developing equipment to be used in the oil service industry, for a purchase price of NOK 20 million. Simultaneously with the purchase, Wellbore issued shares to us for total consideration of NOK 5 million, increasing our ownership interest to 40.3%. Wellbore’s results have been consolidated from the date of acquisition as we are considered to have control over Wellbore through a shareholder agreement that gives us the power to vote 50.1% of Wellbore’s shares. In 2009, we increased our ownership in Wellbore to 42.6% at a cost of NOK 2.0 million.

Seadrill’s Well Service Division

On October 1, 2007, together with our wholly owned subsidiary Seawell Holding UK, we acquired the shares in the entities comprising Seadrill’s Well Services division for total consideration of NOK 2,413.1 million. The following entities represented Seadrill’s Well Services division prior to its transfer to us: Seawell AS, Seawell Engineering AS, Seawell Management Services Ltd (UK), Seawell Ltd (UK), Seawell Offshore Denmark AS (DK) and Seawell Services Ltd (Hong Kong). These entities were acquired in a common control transaction between us and our parent company, Seadrill. The net assets acquired were settled through issuances of an equity stake in the Company of 73.8% and the proceeds of a subordinated loan of NOK 515 million.

Results of Operations

2009 Compared to 2010 – Consolidated Results

		Years ended December 31,
		2009	2010	% Change
		(NOK in millions)
Operating revenues		3,101.2	3,687.5	18.9
Reimbursables		723.6	641.4	(11.4)
Total operating revenues		3,824.8	4,328.9	13.2
Operating expenses		2,538.3	3,038.0	19.7
Reimbursable expenses		692.5	617.1	(10.9)
Depreciation and amortization		131.6	136.2	3.5
General and administrative expenses		103.1	152.0	47.4
Total operating expenses		3,465.5	3,943.2	13.8
Operating income		359.3	385.7	7.3
Interest income		5.6	9.3	66.1
Interest expenses		(96.8)	(132.9)	39.2
Share of results in associated company	��	—	(1.9)	—
Other financial items		(33.1)	(93.8)	172.7
Total financial items		(124.3)	(219.4)	76.5
Income before income taxes		235.0	166.3	(29.2)
Income taxes		(60.6)	(92.6)	52.8
Net income		174.4	73.7	(57.7)
Net income attributable to the parent		176.2	74.1	(57.9)
Net income attributable to the non-controlling interest		(1.8)	(0.4)	(77.8)

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Total operating revenues

	Years ended December 31,
	2009	2010	% Change
	(in NOK millions)
Drilling Services:
Operating revenues	2,514.6	2,959.3	17.7
Reimbursables	684.8	618.3	(9.7)
Total operating revenues	3,199.4	3,577.6	11.8
Well Services:
Operating revenues	586.6	736.0	25.5
Reimbursables	38.8	15.3	(60.6)
Total operating revenues	625.4	751.3	20.1

Total operating revenues increased from NOK 3,824.8 million in the year ended December 31, 2009 to NOK 4,328.9 million in the year ended December 31, 2010, reflecting an increase of NOK 378.2 million in total operating revenues for our Drilling Services segment, and a NOK 125.9 million increase in total operating revenues in our Well Services segment.

Our Drilling Services segment’s total operating revenues increased from NOK 3,199.4 million in the year ended December 31, 2009 to NOK 3,577.6 million in the year ended December 31, 2010. The increase in total operating revenues in our Drilling Services segment reflects a NOK 444.7 million increase in operating revenues partially offset by a decline in reimbursables of NOK 66.5 million. The increase in operating revenues was due to an increase in our platform drilling operating revenues associated with the start up of the Statoil-Peregrino drilling services contract in Brazil and the ConocoPhillips Ekofisk contract in the North Sea. Reimbursables declined from NOK 684.8 million to NOK 618.3 million consistent with the decline in reimbursables expenses described below.

Total operating revenues for our Well Services segment increased from NOK 625.4 million in the year ended December 31, 2009 to NOK 751.3 million in the year ended December 31, 2010. The increase in total operating revenues in our Well Services segment reflects a NOK 149.4 million increase in operating revenues offset by a decline in reimbursables of NOK 23.5 million. The increase in operating revenues for our Well Services segment was due to an increase in operating revenues for both the well intervention services and oilfield technology divisions. The increase in well intervention services operating revenues reflects an increase of NOK 69.9 million in wireline services operating revenues associated with high utilization under a newly awarded five year contract for all of ConocoPhillips’ wireline work and the acquisition of Gray Wireline Services in December 2010 as well as an increase of NOK 52.4 million in cased hole investigation services revenues associated with the completion of jobs utilizing our new Well Performance Eye tool and its new caliper job capabilities. The increase in oilfield technology operating revenues of NOK 27.1 million reflects an increase in the provision of Peak C-Flex smart cementing completion services and in VMB plug operations. Reimbursables declined from NOK 38.8 million to NOK 15.3 million consistent with the decline in reimbursables expenses described below.

Total operating expenses

	Years ended December 31,
	2009	2010	% Change
	(in NOK millions)
Drilling Services:
Operating expenses	2,134.0	2,532.9	18.7
Reimbursables expenses	654.9	601.8	(8.1)
Depreciation and amortization	53.7	53.6	0.0
General and administrative expenses	72.2	106.4	47.4
Total operating expenses	2,914.8	3,294.7	13.0
Well Services:
Operating expenses	404.3	505.1	24.9
Reimbursables expenses	37.6	15.3	(59.3)
Depreciation and amortization	77.9	82.5	5.9
General and administrative expenses	30.9	45.6	47.6
Total operating expenses	550.6	648.5	17.8

Total operating expenses increased from NOK 3,465.5 million for the year ended December 31, 2009 to NOK 3,943.2 million for the year ended December 31, 2010, reflecting a NOK 379.9 million increase in total operating expenses for our Drilling Services segment, and a NOK 97.9 million increase in total operating expenses for our Well Services segment.

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Our Drilling Services segment’s total operating expenses increased from NOK 2,914.8 million in the year ended December 31, 2009 to NOK 3,294.7 million in the year ended December 31, 2010. The increase in total operating expenses in the Drilling Services segment reflects a NOK 398.8 million increase in operating expenses and a NOK 34.2 million increase in general and administrative expenses partially offset by a NOK 53.1 million decline in reimbursables expenses and a NOK 0.1 million decline in depreciation and amortization. The decline in our Drilling Services segment’s reimbursables expenses reflects a higher level of modification work on the Statfjord field as well as completion of the Gullfaks minimum pressure drilling project in 2009 and the loss of the BP Clair platform drilling contract in the UK. Operating expenses consist primarily of onshore and offshore personnel expenses, and repair and maintenance expenses. Operating expenses increased from NOK 2,134.0 million in the year ended December 31, 2009 to NOK 2,532.9 million in the year ended December 31, 2010 consistent with the increase in Drilling Services operating revenues described above.

Total operating expenses for our Well Services segment increased from NOK 550.6 million in the year ended December 31, 2009 to NOK 648.5 million in the year ended December 31, 2010. The increase in total operating expenses in the Well Services segment reflects a NOK 100.8 million increase in operating expenses, a NOK 4.6 million increase in depreciation and amortization and a NOK 14.7 million increase in general and administrative expenses offset by a NOK 22.3 million decline in reimbursables expenses. Operating expenses increased from NOK 404.3 million in the year ended December 31, 2009 to NOK 505.1 million in the year ended December 31, 2010 consistent with the increase in Well Services operating revenues described above. The decline in depreciation and amortization was primarily due to investment in new VMB plugs. The decline in reimbursables expenses was primarily due to completion of the Statoil contract at the end of 2009.

Total Financial Items

Interest income for the year ended December 31, 2010 was NOK 9.3 million compared to NOK 5.6 million for 2009. The increase in interest income reflects an increase in our consolidated cash balances due to a private placement made in August 2010.

Interest expenses increased from NOK 96.8 million in the year ended December 31, 2009 to NOK 132.9 million in the year ended December 31, 2010. The increase in interest expense was primarily due to the payment of arrangement fees related to funding expensed in 2010 offset by a decrease in the amount outstanding under the Credit Facility with Fokus Bank as well as the settlement of the subordinated loan from Seadrill.

Share of result in associated company was a net loss of NOK 1.9 million in the year ended December 31, 2010, compared to no share of result in associated company in the year ended December 31, 2009. The loss of NOK 1.9 million in 2010 is related to our share of result in the C6 joint venture.

In the year ended December 31, 2010, we recorded a loss of NOK 93.8 million related to other financial items. The loss was primarily due to unrealized foreign exchange losses based on an ending FX rate of NOK 5.85 to USD 1.00.

Income Taxes

Income taxes for the year ended December 31, 2010 were NOK 92.6 million compared to NOK 60.6 million for the year ended December 31, 2009. The effective tax rate increased from 25.8% in the year ended December 31, 2009 to 55.7% in the year ended December 31, 2010, principally reflecting an increase in operations in countries with higher corporate tax rates, in particular, the start up of our Brazilian operations, which are subject to a tax rate of 34%, an unrealized foreign exchange loss on Bermuda which has a statutory tax rate of 0% and a tax loss in the United States that was not recognized.

2008 Compared to 2009 – Consolidated Results

	Years ended December 31,
	2008	2009	% Change
	(NOK in millions)
Operating revenues	3,006.2	3,101.2	3.2
Reimbursables	618.5	723.6	17.0
Total operating revenues	3,624.7	3,824.8	5.5
Operating expenses	2,610.7	2,641.4	1.2
Reimbursable expenses	600.9	692.5	15.2

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Years ended December 31,
2008	2009	% Change
(NOK in millions)

Depreciation and amortization	107.4	131.6	22.5
Total operating expenses	3,319.0	3,465.5	4.4
Operating income	305.7	359.3	17.5
Interest income	25.3	5.6	(77.9)
Interest expenses	(148.3)	(96.8)	(35.6)
Other financial items	(39.0)	(33.1)	(11.8)
Total financial items	(162.0)	(124.3)	(23.3)
Income before income taxes	143.7	235.0	63.5
Income taxes	(24.7)	(60.6)	145.3
Net income	119.0	174.4	46.6
Net income attributable to the parent	122.5	176.2	40.9
Net income attributable to the non-controlling interest	(3.5)	(1.8)	(48.6)

Total operating revenues

	Years ended December 31,
	2008	2009	% Change
	(in NOK millions)
Drilling Services:
Operating revenues	2,521.5	2,514.6	(0.3)
Reimbursables	531.8	684.8	28.8
Total operating revenues	3,053.2	3,199.4	4.8
Well Services:
Operating revenues	484.7	586.6	21.0
Reimbursables	86.7	38.8	(55.2)
Total operating revenues	571.5	625.4	9.5

Total operating revenues increased from NOK 3,624.7 million in the year ended December 31, 2008 to NOK 3,824.8 million in the year ended December 31, 2009, reflecting an increase of NOK 146.2 million in total operating revenues for our Drilling Services segment and an increase of NOK 53.9 million in total operating revenues for our Well Services segment.

Our Drilling Services segment’s total operating revenues increased from NOK 3,053.3 million in the year ended December 31, 2008 to NOK 3,199.4 million in the year ended December 31, 2009. The increase in total operating revenues in the Drilling Services segment reflects a NOK 153.0 million increase in reimbursables offset by a decline in operating revenues of NOK 6.9 million. Reimbursables increased from NOK 531.8 million in 2008 to NOK 684.8 million in 2009 consistent with the increase in reimbursables expenses described below. The decline in operating revenues was due to decreased activity in the UK resulting from the loss of the BP Clair platform drilling contract and a decrease in the number of Shell’s operating rigs.

Total operating revenues for our Well Services segment increased from NOK 571.5 million in the year ended December 31, 2008 to NOK 625.4 million in the year ended December 31, 2009. The increase in total operating revenues in the Well Services segment reflects a NOK 101.9 million increase in operating revenues offset by a decline in reimbursables of NOK 47.9 million. The increase in operating revenues for our Well Services segment was due to the acquisition of Peak Well Solutions in May 2008 and the acquisition of TecWel in July 2008. Reimbursables declined from NOK 86.7 million in 2008 to NOK 38.8 million in 2009 consistent with the decrease in reimbursables expenses described below.

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Total operating expenses

	Years ended December 31,
	2008	2009	% Change
	(in NOK millions)
Drilling Services:
Operating expenses	2,268.9	2,206.2	(2.8)
Reimbursables expenses	516.9	654.9	26.7
Depreciation and amortization	42.8	53.7	25.5
Total operating expenses	2,828.6	2,914.8	3.0
Well Services
Operating expenses	341.8	435.2	27.3
Reimbursables expenses	84.0	37.6	(55.2)
Depreciation and amortization	64.6	77.9	20.6
Total operating expenses	490.4	550.6	12.3

Total operating expenses increased from NOK 3,319.0 million for the year ended December 31, 2008 to NOK 3,465.5 million for the year ended December 31, 2009, reflecting a NOK 86.2 million increase in total operating expenses for our Drilling Services segment and a NOK 60.2 million increase in total operating expenses for our Well Services segment.

Our Drilling Services segment’s total operating expenses increased from NOK 2,828.6 million in the year ended December 31, 2008 to NOK 2,914.8 million in the year ended December 31, 2009. The increase in total operating expenses in the Drilling Services segment reflects a NOK 138.0 million increase in reimbursables expenses and a NOK 10.9 million increase in depreciation and amortization offset by a NOK 62.7 million decrease in operating expenses. The increase in the Drilling Services segment’s reimbursables expenses reflects a higher level of modification work on the Statfjord field as well as work on the Gullfaks minimum pressure drilling project and a full accounting year in 2009 for Noble’s UK operations, which the Company acquired in April 2008, compared to only nine months in 2008. The increase in depreciation and amortization in 2009 resulted in part from the acquisition of Noble Corporation’s North Sea platform drilling division in April 2008 and its results not being consolidated for the entire year. Operating expenses consist primarily of onshore and offshore personnel expenses, and repair and maintenance expenses. Operating expenses declined from NOK 2,268.9 million in 2008 to NOK 2,206.2 million in 2009 consistent with the decrease in Drilling Services operating revenues described above.

Total operating expenses for our Well Services segment increased from NOK 490.4 million in the year ended December 31, 2008 to NOK 550.6 million in the year ended December 31, 2009. The increase in total operating expenses in the Well Services segment reflects a NOK 93.4 million increase in operating expenses and a NOK 13.3 million increase in depreciation and amortization offset by a NOK 46.4 million decrease in reimbursables expenses. Operating expenses increased from NOK 341.8 million in 2008 to NOK 435.2 million in 2009. Due to difficult economic conditions existing between 2008 and mid-2010, we had to make some one-time decisions in respect of economic pricing of material contracts. This had the effect of decreasing margins on certain commercial arrangements during this period but is not reflective of our long-term pricing and is not expected to be a recurring factor. The increase in depreciation and amortization in 2009 resulted from the acquisition of Peak Well Solutions and TecWel in May and June 2008, respectively, and their results not being consolidated for the entire year. The decline in reimbursables expenses was primarily due to a decrease in purchases on behalf of customers, and was linked to the decrease in reimbursable revenue.

Total financial items

Interest income for the year ended December 31, 2009 was NOK 5.6 million compared to NOK 25.3 million in 2008. The decrease in interest income reflects a decline in interest rates between 2008 and 2009.

Interest expenses decreased from NOK 148.3 million in 2008 to NOK 96.8 million in 2009. The decline in interest expense was primarily due to a decline in interest rates on our Fokus Bank credit facility and its subordinated loan from Seadrill. The weighted average interest rate for the loans was 4.55% in 2009 compared to 7.24% in 2008. The decrease in interest rates was partially offset by increased borrowings under the Fokus Bank credit facility in 2009.

In the year ended December 31, 2009, we recorded a loss of NOK 33.1 million related to other financial items. The loss was due to a weakening of the British pound against the Norwegian krone resulting in a gain related to an intra-group loan denominated in British pounds.

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Income taxes

Income taxes for the year ended December 31, 2009 were NOK 60.6 million compared to NOK 24.7 million for the year ended December 31, 2008. The effective tax rate increased from 17.2% in 2008 to 25.8% in 2009, principally reflecting increases in taxable income in tax jurisdictions with higher tax rates.

Inflation

Our business transactions are denominated primarily in NOK. Management believes that inflation has not had a material effect on our results of operations.

B. Liquidity and Capital Resources

Overview

Our historical sources of liquidity have been cash generated from operations, credit facilities provided by major financial institutions, equity issuances and shareholder loans. Cash generated from operations continues to be our primary source of funds to finance operating needs, capital expenditures and debt service. We had cash and cash equivalents of NOK 1,023.6 million as of December 31, 2010, compared to NOK 236.7 million at December 31, 2009.

Management believes that our ability to obtain funding from the sources described above will continue to provide the cash flows necessary to satisfy our present working capital requirements and capital expenditure requirements, as well as meet our debt repayments and other financial commitments for the next 12 months.

Cash Flows from Operating Activities

Net cash provided by operating activities during the year ended December 31, 2010 was NOK 305.2 million, compared to NOK 343.7 million for the year ended December 31, 2009 and NOK 372.6 million for the year ended December 31, 2008. Operating cash flows are affected primarily by net income and movement in working capital. In particular, during 2008, our first full year of operations, both trade accounts receivable and trade accounts payable grew significantly by NOK 215.5 million and NOK 356.9 million, respectively. These numbers were significantly reduced in 2009 as a result of enhancements of our accounts receivable and accounts payable management function. In addition, in 2008, our customers took longer to pay outstanding invoices, which management believes was largely due to the effect of the credit crisis and the corresponding slowdown in the oil and gas exploration and production industry. Operating cash flow performance in the year ended December 31, 2010 principally reflects an increase in net working capital.

Cash Flows from Investing Activities

Net cash used in investing activities was NOK 1,148.2 million for the year ended December 31, 2010, compared to NOK 168.0 million for the year ended December 31, 2009 and NOK 1,104.9 million for the year ended December 31, 2008. The cash outflow for the year ended December 31, 2010 was substantially higher than that for the year ended December 31, 2009, mainly due to the acquisitions of Rig Inspection Services, Romeg Holdings and Gray Wireline. In 2009, the net cash outflows were primarily related to routine purchases of drilling equipment. In 2008, investing cash flows included the acquisition of subsidiaries referred to in “Acquisitions” above as well as payments for the construction of our modular rig, which we anticipate will be delivered in the second half of 2011.

Cash Flows from Financing Activities

In the year ended December 31, 2010, net cash provided by financing activities was NOK 1,630 million, as compared to net cash used in financing activities of NOK 194.1 million in the year ended December 31, 2009. This increase in cash received from financing activities is attributable to the proceeds from issuance of equity. Net cash provided by financing activities was NOK 856.0 million in 2008. Cash flows from financing activities principally reflect our acquisition of Seadrill’s well services division, which was financed through a combination of an equity issuance of NOK 1,148 million (net of issuance costs) and a long-term bank facility of NOK 750 million. In addition, in 2008, we received NOK 191.6 million from a private placement of shares to external investors, which was used to partially finance the acquisition of subsidiaries.

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Description of Indebtedness

Our debt facilities comprise a revolving credit facility and a shareholder loan.

Revolving Credit Facility Agreement

On September 7, 2010, we entered into a NOK 1,500 million Revolving Credit Facility with Fokus Bank, the Norwegian branch of Danske Bank AS, replacing the NOK 1,500 million Senior Bank Debt Facility outstanding as at June 30, 2010, the proceeds of which will be used for general corporate purposes, capital expenditures, working capital and the issuance of guarantees to support contract performance obligations and other operating requirements. The facility is divided into two tranches. The first tranche, Tranche A, is for NOK 1,215 million, while the second tranche, Tranche B, is for NOK 285 million. Both tranches have a final maturity date of 12 months from the date of signing of the agreement. The interest rate of the tranches is the aggregate of LIBOR, NIBOR or EURIBOR, plus 2.50%, plus mandatory costs, if any. The facility can be drawn in several currencies, including NOK.

The NOK 1,500 million Revolving Credit Facility Agreement contains events of default which include payment defaults, breach of financial covenants, breach of other obligations, breach of representations and warranties, insolvency, illegality, unenforceability, conditions subsequent, curtailment of business, claims against an obligor’s assets, appropriation of an obligor’s assets, cross-defaults to other indebtedness in excess of NOK 5 million, material adverse effect, and material litigation. As of December 31, 2010, approximately NOK 1,000 million and EUR 14 million (approximately $185 million) of the facility had been drawn.

Our Revolving Credit Facility Agreement contains certain financial covenants, including, among others:

· our ratio of consolidated total net debt to consolidated EBITDA cannot exceed 3.0;

· our ratio of equity to total assets must be at least 25%.

Multicurrency Term and Revolving Facility Agreement

In November 2010, we entered into a $550 million (approximately NOK 3,263 million) Multicurrency Term and Revolving Facility Agreement with Danske Bank AS, DnB NOR Bank AS, Swedbank AB and Nordea Bank Norge ASA as original lenders. The purpose of the facility is to refinance our existing NOK 1,500 Revolving Credit Facility Agreement described above, to finance general corporate purposes, to partially finance the cash option payable to Allis-Chalmers’ shareholders as part of the merger, and to refinance existing indebtedness in Allis-Chalmers and its subsidiaries.

The facility is divided into three tranches. The first tranche, Tranche A, is for $250 million, the second tranche, Tranche B, is for $85 million and the third tranche, Tranche C, is for $215 million. The final maturity date of all three tranches is five years from the signing date of the agreement.

The interest rate of the tranches is the aggregate of LIBOR, NIBOR or EURIBOR, plus between 2.00% and 3.00% per annum, depending on the ratio of Net Interest Bearing Debt to EBITDA, plus mandatory costs, if any.

Loans made under the Multicurrency Term and Revolving Facility Agreement will be secured by (i) pledges of our shares in Seawell Norge AS, Seawell AS, Seawell Ltd. UK, Seawell Oil Tools AS, Allis-Chalmers Energy Inc. and Gray Wireline Services Inc., (ii) guarantees provided by certain of these same subsidiaries and (iii) assignment of various intercompany loans. As at December 31, 2010, the assets of these material subsidiaries comprised NOK 3,270.8 million, or 56% of our total assets.

Our Multicurrency Term and Revolving Facility Agreement contains certain financial covenants, including, among others:

· our total consolidated net interest bearing debt cannot exceed 3.0x EBITDA;

· our ratio of equity to total assets must be at least 30.0%;

· we must maintain the higher of $30 million and 5% of interest bearing debt in freely available cash (including undrawn committed credit lines); and

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· our capital expenditure for each year cannot exceed $175,000,000, plus any capital expenditure for the newbuilding modular rig to be delivered in the second half of 2011.

The Revolving Credit Facility Agreement contains events of default which include payment defaults, breach of financial covenants, breach of other obligations, breach of representations and warranties, insolvency, illegality, unenforceability, curtailment of business, claims against an obligor’s assets, appropriation of an obligor’s assets, failure to maintain listing of our shares on an exchange, material adverse effect, repudiation and material litigation.

As of April 25, 2011, we were in compliance with all of the covenants under its Multicurrency Term and Revolving Credit Facility Agreement.

Management believes that our cash balances of NOK 1,023.6 million as of December 31, 2010, should provide sufficient liquid resources and working capital to meet our present and future operating requirements. The Multicurrency Term and Revolving Credit Facility, with up to $550 million (approximately NOK 3,263 million) available for drawing will provide additional liquid resources and working capital.

Application of Critical Accounting Policies, Estimates and Judgments

Significant accounting policies are described in Note 2 to the Financial Statements. The preparation of financial statements requires management to make judgments, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and on various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimate is revised if the revision affects only that period or in the period of revision and future periods if the revision affects both current and future periods.

Management has identified the policies below as critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations are discussed throughout “Operating and Financial Review and Prospects” where such policies affect our reported and expected financial results. For a detailed discussion on the application of these and other accounting policies, see Note 2 to the Consolidated Financial Statements included elsewhere in this document. Management’s preparation of the information in this section requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amounts of revenue and expenses during the reporting period. There can be no assurance that actual results will not differ from those estimates.

Receivables

Receivables, including accounts receivable and unbilled revenue, are recorded in the balance sheet at their full amount less allowance for doubtful receivables. We establish reserves for doubtful receivables on a case-by-case basis. In establishing these reserves, management considers changes in the financial position of the customer. Uncollectible trade accounts receivable are written off when a settlement is reached for an amount that is less than the outstanding historical balance.

Revenue Recognition

We recognize revenue for services and products when purchase orders, contracts or other persuasive evidence of an arrangement with the customer exist, the price is fixed or determinable, collectability is reasonably assured and services have been performed. Revenue from contract services performed on an hourly, daily or monthly rate basis is recognized as the service is performed.

All known or anticipated losses on contracts are provided for when they become evident.

Reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement are recorded as revenue when incurred. The related costs are recorded as reimbursable expenses when incurred.

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Impairment of long-lived assets, including fixed asset and intangible asset

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 disposal. If the 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.

Goodwill

We allocate the cost of acquired businesses to the identifiable tangible and intangible assets and liabilities acquired, with any remaining amount being capitalized as goodwill. Goodwill is tested for impairment at least annually 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. We have determined that our 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 us 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, we must perform an exercise similar to a purchase price allocation in a business combination in order to determine the amount of the impairment charge.

We perform our annual test of goodwill impairment as of December 31 for each reporting segment, based on a discounted cash flow model. When testing for impairment management has 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. We had no impairment of goodwill for the years ended December 31, 2010, 2009 and 2008 as the net present value of the estimated future cash flows justify the book value of goodwill. Management has also performed a 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.

Purchase Price Allocation of Acquired Businesses

Management allocates the purchase price of acquired businesses to the identifiable assets and liabilities of the businesses, post acquisition, based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We may engage third-party appraisal firms and valuation experts to assist in the determination of the estimated fair value of identifiable assets and liabilities. Management’s judgments and estimates for the allocation of purchase price are based on information available during the measurement period. These judgments and estimates can materially impact our financial position as well as our results of operations.

Income taxes

Seawell Limited is a Bermuda company. Under current Bermuda law, we are not required to pay taxes in Bermuda on either income or capital gains. We have received written assurance from the Minister of Finance in Bermuda (the “Minister of Finance”) under the Exempted Undertakings Tax Protection Act 1966 of Bermuda (the “Exempted Undertakings Act”) that, in the event of any such taxes being imposed, the Company will be exempted from taxation until March 28, 2016. The Government of Bermuda has recently amended the Exempted Undertakings Act to extend the period for which the Minister of Finance may grant an assurance from March 28, 2016 to March 31, 2035. The existing assurance received by us remains valid until March 28, 2016; however, we can now apply to the Minister of Finance for an assurance pursuant to the Exempted Undertakings Act lasting until March 31, 2035. We intend to apply to the Minister of Financefor such an extended assurance. Certain of our subsidiaries operate in other jurisdictions where taxes are imposed, mainly Norway and the UK. Consequently income taxes have been provided in respect of taxes in such jurisdictions.

Significant judgment is involved in determining the provision for income taxes across the Company and its subsidiaries. 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 estimates of whether additional taxes will 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.

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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.

Defined benefit pension plans

We have several defined benefit plans which provide retirement, death and termination benefits. Our 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.

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. We record our pension costs in the period during which the services are rendered by the employees. Actuarial gains and losses are recognized in the income statement when the net cumulative unrecognized actuarial gains or losses for each individual plan at the end of the previous reporting year exceed 10% of the higher of the present value of the defined benefit obligation and the fair value of plan assets at that date. These gains and losses are recognized over the expected remaining working lives of the employees participating in the plans. Otherwise, recognition of actuarial gains and losses is not recognized in the income statement. On December 31, 2006, we adopted amended recognition and disclosures provisions, which require the recognition of the funded status of the plan in the balance sheet with a corresponding adjustment to accumulated other comprehensive income. The adjustment to other comprehensive income represents the net unrecognized actuarial losses and unrecognized prior service costs, all of which were previously netted against the plans’ funded status on the balance sheet. These amounts will continue to be 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.

C. Research and Development, Patents and Licenses, etc.

Research and Development

Our research and development programs have concentrated on the requirements of our clients, who are constantly seeking to develop oil and gas reserves in more demanding environments, and on increasing the efficiency of our equipment and operations. We have research and development programs aimed at developing new technologies and extending existing technologies for the provision of platform drilling and well intervention services. Our research and development activities are typically carried out internally using both dedicated research personnel and as part of specific projects. External research and development is performed either through strategic technological alliances or via joint industry collaborative projects, where appropriate.

The table below sets forth information on our research and development expenditures during the years ended December 31, 2008, 2009 and 2010.

Years ended December 31,
2008	2009	2010
(in NOK millions)
25.6	29.1	33.2

Intellectual Property

We own or have a right to use a number of patents and trademarks, as well as software and other intellectual property to support its operational activities. A limited number of our patents are held in common with other industrial partners. We also conduct some of our operations under licensing agreements allowing us to make use of specific techniques or equipment patented by third parties. However, no one patent or technology is responsible for a significant percentage of revenue.

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D. Trend Information

The oilfield services industry is highly cyclical. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and natural gas. The peaks and valleys of demand are further apart than those of many other cyclical industries. This is primarily a result of the industry being driven by commodity demand and corresponding price increases. As demand increases, producers raise their prices. The price escalation enables producers to increase their capital expenditures. The increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. The increased capital expenditures also ultimately result in greater production which historically has resulted in increased supplies and reduced prices.

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 2010, 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.

We experience significant competition in all areas of our business. In general, the markets in which we compete are highly fragmented, and a large number of companies offer services that overlap and are competitive with our services and products. Our management believes that the principal competitive factors are technical and mechanical capabilities, management experience, past performance and price. While we have considerable experience, there are many other companies that have comparable skills. Many of our competitors are larger and have greater financial resources than we do.

A significant portion of our revenue is generated from work performed in the North Sea, where adverse weather conditions during the winter months usually result in low levels of activity, although this is less apparent than in the past due to technological advances. Further, in Brazil, where we also generate revenue from operations, adverse weather conditions affect our results of operations.

The trends discussed in this Item 5.D. “Trend Information” are subject to risks and uncertainties. See “Part I – Special Note Regarding Forward-Looking Statements.”

E. Off-Balance Sheet Arrangements

Historically, we have not used special-purpose vehicles or similar financing arrangements. In addition, we do not have any off-balance sheet arrangements with any of our affiliates or with any unconsolidated entities.

F. Tabular Disclosure of Contractual Obligations

As of December 31, 2010, our contractual cash obligations for future periods were as follows:

	Payments Due
	Less than 1 year	1-3 Years	3-5 Years	After 5 Years	Total
	(NOK in millions)
Debt Obligations(1)	1.6	—	1,109.2	—	1,110.8
Interest Expenses(2)	64.8	129.7	108.1	—	302.6
Finance Lease Obligations	9.6	14.7	4.7	—	29.0
Operating Lease Obligations	72.8	113.7	83.2	76.2	345.9
Purchase Obligations	235.4	—	—	—	235.4
Total	384.2	258.1	1,305.2	76.2	2,023.7

_______________________
Notes:

(1) In November 2010, we entered into a $550 million Multicurrency Term and Revolving Facility Agreement in order to refinance our NOK 1,500 million Revolving Credit Facility entered into on September 7, 2010. The amounts outstanding under the Revolving Credit Facility represented all of our debt obligations as at December 31, 2010. As at December 31, 2010, NOK 1,000 million at an annual interest rate of 5.37% and EUR 14 million at an annual interest rate of 3.796% were outstanding under the Multicurrency Term and Revolving Facility Agreement.

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(2) Estimated based on currently applicable interest rate.

G. Safe Harbor

See Part I “Cautionary Statement Regarding Forward-Looking Statements.”

Item 6    Directors, Senior Management and Employees

A. Directors and Senior Management

Directors

Overall responsibility for our management and the management of our subsidiaries rests with our board of directors. Our Bye-Laws provide that our board of directors consist of at least two directors, with the board currently consisting of nine members, four of whom were appointed in February 2011. The following table sets forth the members of our board of directors as of the date of this annual report:

Name	Age	Position
Saad Bargach(1)	53	Chairman of the Board
Frederick Halvorsen	37	Deputy Chairman of the Board
Tor Olav Trøim	47	Director
John Reynolds(1)(2)	40	Director
Alejandro P. Bulgheroni(1)	67	Director
Giovanni Dell’Orto(1)	66	Director
Cecilie Fredriksen	27	Director
Kate Blankenship(2)	45	Director
Jørgen Rasmussen	52	Director

_______________________

Note:

(1)        Appointed in February 2011 as a result of the merger with Allis-Chalmers

(2)        Audit committee member

Saad Bargach has served as Chairman of the Board since February 2011, following the merger with Allis-Chalmers. Prior to the merger, Mr. Bargach served as a director of Allis-Chalmers from June 2009 to February 2011. Mr. Bargach is a Managing Director at Lime Rock Partners, or Lime Rock. Prior to joining Lime Rock, Mr. Bargach worked for more than 25 years at Schlumberger Inc., or Schlumberger. Most recently, he served as Schlumberger’s Chief Information Officer and, from July 2004 to March 2006, as President, Well Completions & Productivity Group, which included Artificial Lift, Completions, Testing, Subsea and Sand Management Services. During his career at Schlumberger, Mr. Bargach also served as President of Consulting & Systems Integration for Schlumberger Sema in several European locations; as President of the Drilling & Measurements division with worldwide responsibility for drill bits, directional drilling, measurements-while-drilling, and logging-while-drilling services; and as the Cairo-based President, Oilfield Services for Africa and Near East. Mr. Bargach has a bachelor’s degree in electrical engineering and a master’s degree in control systems. He is also a member of the Board of the American Productivity and Quality Center and currently serves on the board of directors of Gas2 Limited, an Aberdeen-based oil service technology company, Tiway Oil, a Dubai-based oil and gas producing company, Expert Petroleum, a Bucharest-based production enhancement company, ITS International Tubular Services, an Aberdeen-based oilfield services global company, Omni Oil Technology Holdings Limited, a Dubai-based oilfield services technology company, and Xtreme Oil Drilling, an Alberta-based oil services technology provider.

Fredrik Halvorsen has served as Deputy Chairman of the Company since February 2011 and as a director of the Company since October 2010. Mr. Halvorsen is a director of Deep Sea Supply Plc, where he has served since October 2010. Mr. Halvorsen is currently employed by Frontline Corporate Services Ltd. Prior to joining Frontline, Mr. Halvorsen served as CEO of Tandberg ASA, as Senior Vice President of Cisco Systems Inc. and as the leader of McKinsey & Company’s Southeast Asia Corporate Finance Practice. Mr. Halvorsen graduated from the Norwegian School of Economics and Business Administration with a degree in business administration and from the J.L. Kellogg Graduate School of Management with a master's degree in finance.

Tor Olav Trøim has served as a director of the Company since its incorporation in August 2007. From August 2007 to February 2011, Mr. Trøim also served as Deputy Chairman of the Company. Mr. Trøim is Vice-President and a director of Seadrill, where he has served since May 2005. Mr. Trøim graduated as M.Sc. Naval Architect from the University of Trondheim, Norway in 1985. From 1987 to 1990, Mr. Trøim served as Portfolio Manager Equity for Storebrand ASA and, from 1992 to 1995, he was Chief Executive Officer of Norwegian Oil Company DNO AS. Mr. Trøim serves as a director of four Oslo Stock Exchange listed companies, Golden Ocean Group Limited, Golar LNG Energy Limited, Aktiv Kapital ASA and Marine Harvest ASA.

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Mr. Trøim served as a director of Frontline Ltd from November 1997 until February 2008. 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.

John Reynolds has served as a director of the Company since February 2011, following the merger with Allis-Chalmers. Prior to the merger, Mr. Reynolds was a director of Allis-Chalmers from June 2009 to February 2011. Mr. Reynolds co-founded Lime Rock Partners in 1998, where he is currently a Managing Director. Mr. Reynolds remains an active member of the Lime Rock investment team, investigating and executing primarily energy service investment opportunities worldwide. Prior to co-founding Lime Rock, Mr. Reynolds worked at Goldman Sachs where he spent six years in the Investment Research Department and had senior analyst responsibility for global oil service sector research and was one of the top-rated analysts in the sector. He currently serves on the board of directors of Tesco Corporation, EnerMech, Ltd., Revelation Energy Holdings, LLC, Omni Oil Technology Holdings Limited and VEDCO Holdings, Inc. He previously served on the board of directors of Hercules Offshore, Inc., Eastern Drilling ASA, IPEC, Ltd., Noble Rochford Drilling, Ltd., Patriot Drilling, Roxar ASA, Sensa, Ltd., and Torch Offshore Inc. Mr. Reynolds is a graduate of Bucknell University, where he received his B.A.

Alejandro P. Bulgheroni has served as a director of the Company since February 2011, following the merger with Allis-Chalmers. Prior to the merger, Mr. Bulgheroni was a director of Allis-Chalmers from August 2006 to February 2011. Mr. Bulgheroni has served as the Chairman of the Management Committee of Pan American Energy LLC, an oil and gas company, since November 1997. He also served as the Chairman of Bridas SAPIC from 1988 until 1997. Mr. Bulgheroni has served as Vice-Chairman and Executive Vice-President of Bridas Corporation since 1993, where he is also a director. He also serves as Chairman, President and CEO of Associated Petroleum Investors Ltd., an international oil and gas holding company, as Chairman and President of Global Oilfield Holdings Ltd., as Chairman of Beusa Energy, Inc. and as President and CEO of Nuevo Manantial S.A. and Agroland S.A. Mr. Bulgheroni is a member of the Petroleum and Gas Argentine Institute and of the Society of Petroleum Engineers (USA), Vice-President of the Argentine Chamber of Hydrocarbons Producers, Vice-President of the Argentine-Uruguayan Chamber of Commerce, Counselor of the Argentine Business Council for Sustainable Development and Vice-President of the Educando Foundation (Argentina). Mr. Bulgheroni is a graduate of the University of Buenos Aires with a degree in industrial engineering.

Giovanni Dell’Orto has served as a director of the Company since February 2011, following the merger with Allis-Chalmers. Prior to the merger, Mr. Dell’Orto served as a director of Allis-Chalmers from June 2009 to February 2011. Mr. Dell’Orto was President and Chief Executive Officer of DLS Drilling, Logistics & Services Corporation (then a subsidiary of Bridas Corporation) from 1994 to August 2006. Following Allis-Chalmers’ purchase of DLS, he served as Vice Chairman of DLS Argentina Limited. He is a member of the board of directors and the executive committee of Energy Developments and Investments Corporation, or EDIC, supervising EDIC’s gas marketing activities in Europe and other upstream projects in North Africa. He is also a non-executive member of the board of directors of Gas Plus S.p.a., an Italian company listed on the Milan Stock Exchange. Prior to joining Bridas and DLS in 1994, he worked for 23 years with ENI in Italy, holding various positions. Mr. Dell’Orto has also served as the Chairman and CEO of Saipem and is a former member of the board of directors of ENI, Agip and Snam.

Cecilie Fredriksen has served as a director of the Company since September 2008. Ms. Fredriksen is currently employed by Frontline Corporate Services in London, where she has served as an investment director since 2007. Her responsibilities include providing the group with strategic and investment advice in addition to administrative day-to-day services. Ms. Fredriksen has been a director of Aktiv Kapital ASA since 2006, Golden Ocean Group Limited, an affiliated company of Seadrill, since September 2008 and Ship Finance International Limited, an affiliated company of Seadrill, since November 2008 and Frontline Ltd since September 2010. Ms. Fredriksen also serves as a director of Marine Harvest ASA and Marine Harvest Ireland and has been a director of Northern Offshore Ltd. since February 2010. She received a BA in Business and Spanish from the London Metropolitan University in 2006.

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

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Jørgen Rasmussen has served as a director of the Company since its incorporation in August 2007. From August 2007 to February 2011, Mr. Rasmussen also served as the Chairman of the Board of the Company. Prior to joining the Company, Mr. Rasmussen was employed by Schlumberger Limited for 25 years. From 1998 to 2001, Mr. Rasmussen served as General Manager of Schlumberger’s Scandinavian office. From 2001 to 2003, he served a President and Chief Executive Officer of Schlumberger Smart Cards. From 2003 to 2005, he was Chief Executive Officer of Atos Origin Northern Europe and from 2005 to 2007, he served as Vice President of WesternGeco. He has held various board positions in industry associations and oilfield companies and holds a M.Sc. in Geology and Geophysics from the University of Aarhus, Denmark.

Management and Executive Officers

The individuals in the Seawell group’s executive management team with major areas of responsibility for our day-to-day management requirements are:

Name	Age	Position
Jørgen Rasmussen	52	Chief Executive Officer & President, Seawell Management Limited
Thorleif Egeli	47	Chief Operating Officer and Executive Vice-President, Archer Management (US) LLC
Lars Bethuelsen	47	Chief Financial Officer, Seawell Management AS
Max Bouthillette	42	Executive Vice President and General Counsel, Archer Management (US) LLC
Gunnar Lemvik	45	Senior Vice President, Human Resources, Seawell Management AS

Thorleif Egeli served as Chief Executive Officer of Seawell Management AS from October 2009 to December 2010, and has served as Chief Operating Officer of Archer Management (US) LLC since January 1, 2011. Prior to joining Seawell Management AS, Mr. Egeli was employed by Schlumberger Limited, where he served in a variety of positions since 1993. From 2007 to 2009, Mr. Egeli served as Vice President, Schlumberger North America and from 2004 to 2007, he served as Marketing Director North Sea. Prior to 2004, Mr. Egeli held management positions within Schlumberger as Managing Director Dowell Norge A.S., QHSE Manager East Asia and as country manager in Well Services and Drilling Fluids. Mr. Egeli holds a degree in mechanical engineering from the Norwegian Technical University and an MBA from Erasmus School of Management in Rotterdam.

Lars Bethuelsen has served as the Chief Financial Officer of Seawell Management AS since 2007. In addition, he currently serves on the board of directors of several of our subsidiaries. Prior to joining Seawell Management AS, Mr. Bethuelsen held several senior positions at Smedvig and Seadrill, including finance manager for Smedvig Asia and, most recently, commercial manager of Seadrill. Mr. Bethuelsen has a degree in finance from the University of Stavanger.

Max Bouthillette has been Executive Vice President and General Counsel of Archer Management (US) LLC since August 6, 2010. Prior to this, Mr. Bouthillette was employed for the last 16 years by BJ Services, Schlumberger Limited and the U.S. national law firm of Baker Hostetler LLP. His professional experience includes serving as Chief Compliance Officer and Associate General Counsel for BJ Services from 2006 to 2010, as a partner with Baker Hostetler LLP from January 2004 to 2006, and in several positions with Schlumberger in North America, Asia, and Europe from 1998 to December 2003. Mr. Bouthillette holds a degree in Accounting from Texas A&M University and a Juris Doctorate from the University of Houston Law Center.

Gunnar Lemvik has served as the Senior Vice President, Human Resources of Seawell Management AS since January 2009. From 2005 to 2009, Mr. Lemvik served as HR director, North Europe & Canada for Acergy S.A. Mr. Lemvik has served as an officer in the Norwegian armed forces and has a degree in law with specialization in labor and company law from the University of Oslo awarded in 1993.

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B. Compensation

Compensation for our directors is generally determined by the affirmative vote of a majority of our shareholders. However, any director who, by request, goes or resides abroad for any purposes related to the Seawell group or who performs services which in the opinion of our board of directors go beyond the ordinary duties of a director may be paid such extra remuneration (whether by way of salary, commission, participation in profits or otherwise) as our board of directors may determine.

The table below sets forth remuneration paid to our directors, executive officers and other key personnel for the year ended December 31, 2010.

	Year ended December 31, 2010
	Salary and bonus payment	Income from exercised options	Total
	(NOK in thousands)
Board of Directors	2,750.0	—	2,750.0
Chief Executive Officer of Seawell Management AS	3,491.6	—	3,491.6
Other key personnel(1)	5,190.3	1,719.2	6,909.5
Total	11,431.9	1,719.2	13,151.1

_______________________
Note:

(1) Other key personnel consists of the Chief Financial Officer—Seawell Management AS, Director Human Resources—Seawell Management AS and Executive Vice President and General Counsel.

The total amount of compensation accrued by our directors and executive officers was NOK 13.2 million in 2010 compared to NOK 10.3 million in 2009 and NOK 9.7 million in 2008. In addition, in 2010, we paid premiums totaling NOK 285,000 in respect of pension arrangements for certain members of our management.

The Chief Executive Officer has a bonus arrangement based on achieving specific targets. The maximum amount of the bonus is limited to 50% of the CEO’s annual salary. Other key personnel have similar bonus arrangements with various limits.

Pursuant to the Chief Executive Officer’s employment contract, in the event the Chief Executive Officer resigns at the request of our board of directors, he will receive compensation equal to 18 months salary.

For a description of share options granted to our senior management and directors see Item 6.E. “Share Ownership.”

C. Board Practices

Audit Committee

The audit committee, which is comprised of two directors, Kate Blankenship and John Reynolds, is responsible for ensuring that we have an independent and effective internal and external audit system. The audit committee supports our board of directors in the administration and exercise of our responsibility for supervisory oversight of financial reporting and internal control matters and to maintain appropriate relationships with our auditors. The audit committee charter details the terms of reference for the audit committee. The company’s auditor meets the audit committee annually regarding the preparation of the annual accounts. The audit committee holds separate discussions with our external auditor on a quarterly basis without executive management being present. The scope, resources and the level of fees proposed by the external auditor in relation to the group’s audit are approved by the audit committee.

The audit committee recognizes that it is occasionally in our interests to engage our auditor to undertake certain other non-audit assignments. The appointment of the Company’s auditor is approved at our annual general meeting. Fees paid to the auditor for audit services are approved by our board of directors.

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Corporate Governance Requirements

As a company incorporated in Bermuda, we are subject to Bermuda laws and regulations with respect to corporate governance. Bermuda corporate law is to a great extent based on English law. In addition, the listing of our common shares on the Oslo Stock Exchange subjects the Company to certain aspects of Norwegian securities law, which include the requirement to adhere to the Norwegian Code of Practice for Corporate Governance, or the Code.

We are committed to ensuring that high standards of corporate governance are maintained and support the principles set out in the Code. Our corporate governance policies and procedures are explained below in the format of how it currently addresses the principles of corporate governance as set out in the sections identified in the Code.

We endeavor to comply with the Code and generally to maintain high standards of corporate governance and are committed to ensure that all shareholders of the company are treated equally.

It is the opinion of our board of directors that we in all material respects comply with the Code, subject to the following:

1.	The board’s mandate to increase our issued share capital is limited to the extent of our authorized share capital in accordance with our Memorandum of Association and Bye-Laws. This is in accordance with Bermuda law. Our authorized capital is currently $1,200,000,000, divided into 600,000,000 shares of a par value of $2.00 each, of which 225,400,050 shares were issued and outstanding at December 31, 2010.
2.	The appointment of a nomination committee is not a requirement under Bermuda law, and we have so far not seen sufficient reason to appoint such a committee. However, prior to proposing candidates to the annual general meeting for election to the board, the board seeks to consult with our major shareholders. The board further endeavors to ensure that it is constituted by directors with a varied background and with the necessary expertise and capacity. We do not have a corporate assembly.
3.	The directors are elected by our shareholders at the annual general meeting and each director holds office until the next annual general meeting following his or her election or until a successor is elected. The directors serving on the board are encouraged to hold our shares as the board believes it encourages a common financial interest between the members of the board and our shareholders. However, there is no requirement at law or in our Bye-Laws that our directors own our shares.
4.	Our chief executive officer, Mr. Jørgen Rasmussen, has also been appointed a director.
5.	Our Bye-Laws permit the board to approve the granting of share options to employees. A total of 6,507,000 share options (including the 2010 program and excluding forfeited options) have been granted to employees since October 1, 2007.
6.	Where it is considered beneficial for us that any of our directors, by request, go or reside abroad for any purposes related to our business or perform services which go beyond the ordinary duties of a director (e.g., in situations where the director has special expertise), the director may receive extra remuneration for such services (whether by way of salary, commission, participation in profits or otherwise). In accordance with the Code, such matters are approved by the board and all directors must be kept informed.
7.	Our Bye-Laws permit general meetings to be convened on not less than 7 days’ notice.
8.	Pursuant to our Memorandum of Association, the objects for which we were formed and incorporated are unrestricted.

Our board of directors annually sets a plan for its work in December for the following year which includes a review of strategy, objectives and their implementation, the review and approval of the annual budget and review and monitoring of our current year financial performance. The board is scheduled to meet in person approximately four times a year, with further meetings being held by telephone conference as required to react to operational or strategic changes in the market and company circumstances.

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Our board of directors receives appropriate, precise and timely information on our operations and financial performance from the executive management team, which is imperative for the board to perform its duties.

Our board of directors has established an audit committee, which has formal terms of reference approved by the board. Matters are delegated to committees as appropriate.

In the event that the chairman of our board of directors cannot attend or is conflicted in leading the work of the board, the deputy chairman will lead.

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

Indemnification of Our Officers and Directors

The Bermuda Companies Act 1981 (the “Companies Act”) permits a company to indemnify its directors, officers and auditor with respect to any loss arising or liability attaching to such person by virtue of any rule of law concerning any negligence, default, breach of duty, or breach of trust of which the director, officer or auditor may be guilty in relation to the company or any of its subsidiaries; provided that the company may not indemnify a director, officer or auditor against any liability arising out of his or her fraud or dishonesty. The Companies Act also permits a company to indemnify a director, officer or auditor against liability incurred in defending any civil or criminal proceedings in which judgment is given in his or her favor or in which he or she is acquitted, or when the Bermuda Supreme Court, or the Court, grants relief to such director, officer or auditor. The Companies Act permits a company to advance moneys to a director, officer or auditor to defend civil or criminal proceedings against them on condition that these moneys are repaid if the allegation of fraud or dishonesty is proved against them. The Court may relieve a director, officer or auditor from liability for negligence, default, breach of duty or breach of trust if it appears to the Court that such director, officer or auditor has acted honestly and reasonably and, in all the circumstances, ought fairly to be excused.

Our Bye-Laws provide that our current and former directors, officers and members of board committees as well as current and former directors and officers of our subsidiaries, shall be indemnified out of the funds of the Company from and against all civil liabilities, loss, damage or expense incurred or suffered in the capacity as a director, officer or committee member of the Company, or as a director or officer of any of our subsidiaries, and the indemnity extends to any person acting as a director, officer or committee member of the Company, or as a director or officer of any of our subsidiaries in the reasonable belief that he or she has been so appointed or elected notwithstanding any defect in such appointment or election. Such indemnity shall not extend to any matter which would render it void pursuant to the Companies Act.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors or officers of, or persons controlling, the Company pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

D. Employees

As of December 31, 2010, we employed approximately 3,600 employees in nine countries.

The following table sets forth the number of our employees as at December 31, 2008, 2009 and 2010:

	Years ended December 31,
	2008	2009	2010
Employees	2,300	2,600	3,600

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E. Share Ownership

The following table sets forth share ownership in the Company of our directors, executive officers and other key personnel as of April 19, 2010.

	Beneficial interest in Common Shares, par value $2.00 each		Interest in Options
	Number of shares	%	Number of options outstanding	Number of options vested	Exercise price	Expiry date
Jørgen Rasmussen	223,000	(1)	725,000	483,333	(2)	October 5, 2012
			200,000	66,667	NOK 10	December 31, 2015
Thorleif Egeli	31,500	(1)	500,000	166,667	NOK 12	December 31, 2015
Kate Blankenship	30,000	(1)	50,000	33,333	(2)	October 5, 2012
			50,000	16,667	NOK 10	December 31, 2015
Tor Olav Trøim	200,000	(1)	50,000	33,333	(2)	October 5, 2012
			50,000	16,667	NOK 10	December 31, 2015
Alf C. Thorkildsen	100,000	(1)	50,000	33,333	(2)	October 5, 2012
Alf Ragnar Løvdal	70,000	(1)	725,000	483,333	(2)	October 5, 2012
Cecilie Fredriksen	—	—	50,000	16,667	NOK 10	December 31, 2015
Max Bouthillette	—	—	150,000	—	NOK 22	December 31, 2015
Lars Bethuelsen	30,000	(1)	435,000	290,000	(2)	October 5, 2012
			100,000	33,333	NOK 10	December 31, 2015
Gunnar Lemvik	—	—	250,000	83,333	NOK 10	December 31, 2015
Total	684,500	(1)	3,385,000	1,756,666

_______________________
Notes:

(1) Less than one percent.

(2) The exercise price is initially NOK 13.75 per share, increasing by 6% on the anniversary of the option grant. As of December 31, 2010, the exercise price was NOK 16.38.

Options

Options on Seawell shares

We have granted options to our senior management and directors of the Company, which provide the employee with the right to subscribe for new shares. The options are not transferable and may be withdrawn upon termination of employment under certain conditions. Options granted under the scheme will vest at a date determined by the board of directors.

As of December 31, 2010 we had seven grants under the option programs—one that began in 2007, two that began in 2009 and four that began in 2010.

Accounting for share-based compensation

The fair value of the share options in respect of Seadrill shares is recognized as personnel expenses. During 2010, NOK 4.4 million was expensed in the income statement (NOK 7.0 million in 2009). There were no effects on taxes in the financial statements. Social security expenses related to the exercise of an option are expensed on the exercise date.

	2008		2009		2010
	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)
Outstanding as at January 1	4,097,000	13.75	4,097,000	14.58	6,147,000	13.76
Granted	—	—	2,100,000	10.48	460,000	19.30
Forfeited	—	—	(50,000)	14.58	(100,000)	10.00
Outstanding as at December 31	4,097,000	14.58	6,147,000	13.76	6,507,000	14.79
Exercisable as at December 31	—	—	1,349,000	15.45	3,398,000	15.16

Options issued under the 2007 Program may be exercised up to October 5, 2012. The exercise price is initially NOK 13.75 per share increasing by 6 percent per anniversary. One third of the options issued under the 2007 Program become exercisable each year, commencing January 1, 2009. As at December 31, 2010, two thirds of the options granted under the 2007 Program were exercisable.

Options issued under the 2009 Programs may be exercised up to December 31, 2015. The exercise price is between NOK 10 and NOK 12 per share. One third of the options issued under the 2009 Programs become exercisable each year, beginning twelve months after the date the options were granted. As at December 31, 2010, one third of the options granted under the 2009 Programs were exercisable.

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Options issued under the 2010 Programs have exercise prices between NOK 18 and NOK 22. One third of the options issued under the 2010 Programs become exercisable each year, beginning twelve months after the options were granted. Options issued under the 2010 Programs expire on December 31, 2015. As at December 31, 2010, none of the options granted under any of the 2010 Programs are exercisable.

The weighted average grant date fair value of options granted during 2010 was NOK 7.56 per share (2009: NOK 3.99 per share, 2008: NOK 4.50 per share).

As of December 31, 2010, total unrecognized compensation costs related to all unvested share based awards totaled NOK 3.2 million, which is expected to be recognized as expenses of NOK 2.3 million, NOK 0.7 million and NOK 0.2 million in 2011, 2012 and 2013, respectively.

There were 6,507,000 options outstanding as at December 31, 2010 (2009: 6,147,000). The weighted average remaining contractual life of outstanding options was 36 months (2009: 46 months) and their weighted average fair value was NOK 4.56 per option (2009: NOK 4.33 per option). Management used the Black & Scholes pricing model in its fair value estimation. The weighted average parameters used in calculating these weighted fair values are as follows: risk-free interest rate 4.8% (2009: 5.0%), volatility 38.7% (2009: 38.6%), dividend yield 0% (2009: 0%), option holder retirement rate 10% (2009: 10%) and expected term 5.62 years (2009: 5.64 years).

We pay employer’s national insurance contributions related to the options, while the option holders are responsible for paying individual income taxes related to the options.

During 2010, the total intrinsic value of vested Seawell options was NOK 123.8 million (NOK 4.7 million in 2009 and NOK 0 in 2008 as no options were vested in 2008).

Options on Seadrill shares

Some of our senior management and directors also have options in Seadrill Limited. The option agreement provides the option holder with the right to subscribe for new shares in Seadrill Limited. The options are not transferable and may be withdrawn upon termination of employment under certain conditions. The subscription price under the options is fixed at the date of grant.

Accounting for share-based compensation

The fair value of the share options is recognized as personnel expenses. During 2010, NOK 0.5 million has been expensed in the income statement, compared to NOK 0.1 million in 2009 and NOK 3.9 million in 2008. There were no effects on taxes in the financial statements; however, if the option is exercised, a tax benefit would be recorded as the gains are recorded as deductible for tax purposes. Social security expenses related to the exercise of an option are expensed on the exercise date.

	2007		2008		2009		2010
	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)
Outstanding as at January 1	860,000	—	706,700	92.34	577,100	99.96	162,100	89.48
Granted	—	—	105,000	132.12	—	—	—	—
Transferred	—	—	—	—	—	—	125,000	89.48
Exercised	(73,300)	88.13	(204,600)	83.74-88.13	(40,000)	88.13	(148,700)	88.13
Forfeited	(80,000)	88.13	(30,000)	88.13	(375,000)	106.33	—	—
Outstanding as at December 31	706,700	92.34	577,100	99.96	162,100	89.48	138,400	90.89
Exercisable as at December 31					162,100	89.48	98,400	90.91

The options under the 2006 Programs for Seadrill shares may be exercised up to May-September 2011. The exercise price for 2006 Programs 1 to 4 ranges between $2.23 and NOK 102 per share. One third of the options issued under the 2006 Programs may be exercised each year, beginning one year after they were granted. As at December 31, 2010, all of the options granted under 2006 Programs 1 to 4 are exercisable.

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In 2010, 125,000 options under 2006 Program 4 and 2009 Program 7 were transferred from Seadrill to the Company due to employee transfers. The exercise price for options issued under these programs ranges from NOK 88.12 to NOK 90.83. One third of the options issued under these Programs may be exercised each year, beginning one year after they were granted.  As at December 31, 2010 all of the options under Program 4 are exercisable and one third of the options under Program 7 are exercisable.

Management has used the Black & Scholes pricing model in its fair value estimation. The weighted average parameters used in calculating these weighted fair values are as follows: risk-free interest rate 4.06% (2009: 4.14%), volatility 36.2% (2009: 34.0 %), dividend yield 0% (2009: 0%), option holder retirement rate 0% (2009: 0%) and expected term 5 years (2009: 4 years).

During 2010, the total intrinsic value of vested Seadrill options at the day of exercise amounted to NOK 14.1 million (MNOK 2.4 million in 2009 and NOK 12.8 million in 2008).

Valuation

For the options plans in both Seawell and Seadrill management uses the Black-Scholes pricing model to value stock options granted under SFAS 123(R). The fair value of options granted is determined based on the expected term, risk-free interest rate, dividend yield and expected volatility. The expected term is based on historical information of past employee behavior regarding exercises and forfeiture of options. The risk-free interest rate assumption is based upon the published Norwegian treasury yield curve in effect at the time of grant for instruments with a similar life. The dividend yield assumption is based on the Company’s history and expectation of dividend payouts.

Management uses a blended volatility for the volatility assumption, to reflect the expectation of how the share price will react to the future cyclicality of our 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 our “at-the-money” long-term call options. The two components are equally weighted to create a blended volatility.

Item 7    Major Shareholders and Related Party Transactions

A. Major Shareholders

Principal Shareholders

The following table sets forth information as at April 19, 2011 with respect to the beneficial ownership of our common shares by each person who is known to be the beneficial owner of more than 10% of the common shares, and all directors and senior management as a group.

Shareholder	Number of Shares	Percentage
Seadrill Limited	117,798,650	36.43%
Lime Rock Partners V, L.P.	43,227,867	13.37%
Hemen Holding Ltd.(1)	28,036,010	8.67%
All directors and senior management as a group	13,131,738	4.06%
Total	202,194,265	62.53%

_______________________

 (1) Hemen Holding Ltd, or Hemen, is a Cyprus holding company, which is indirectly controlled by trusts established by Mr. John Fredriksen for the benefit of his immediate family. Mr. Fredriksen disclaims beneficial ownership of the 28,721,000 Seawell common shares held by Hemen, except to the extent of his voting and dispositive interest in such common shares. Mr. Fredriksen has no pecuniary interest in the common shares held by Hemen.

Voting Rights

We have one class of common shares. Each share carries equal rights including an equal voting right at annual or special general meetings of our shareholders. Every Seawell shareholder who is present in person or by proxy has one vote for every Seawell share of which he is the holder. However, our Bye-Laws establish a right to divide the share capital into different classes of shares with varied rights attached to the shares. An ordinary resolution passed by a simple majority of votes cast at a general meeting of our shareholders is required for such alteration of the share capital.

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Control of Seawell by Other Corporations

We were established in August 2007 as a wholly owned subsidiary of Seadrill Limited, as a result of the spin off of Seadrill’s well service division. As of April 19, 2011, Seadrill owned 36.43% of the Company.  Hemen Holding Ltd. owns approximately 30% of Seadrill and 8.9% of Seawell, and is indirectly controlled by trusts established by John Fredriksen for the benefit of his immediate family.  Mr. Fredriksen is also a director of Seadrill.  Several of our directors also serve on other affiliated companies, including Seadrill.

B. Related Party Transactions

Establishment of Seawell

We were established at the end of the third quarter of 2007 as a spin-off of Seadrill’s Well Service division. The Company, together with its wholly owned subsidiary, Seawell Holding UK, acquired the shares in the Seadrill Well Service division entities on October 1, 2007 for total consideration of NOK 2,413.1 million. The acquisition was accounted for as a common control transaction with the asset and liabilities acquired recorded by us at historical carrying value of Seadrill.

Non-Current Liabilities –Intercompany debt

On October 1, 2007, we entered into a NOK 515 million subordinated loan with Seadrill as part of our acquisition of Seadrill’s Well Service division. The subordinated loan has an interest rate of 6 months NIBOR plus 3.5%, with the interest of the loan added to the loan. On August 17, 2010, the full amount of the loan and accrued interest together with short-term indebtedness owed to Seadrill aggregating to NOK 831.5 million were repaid in connection with a private placement of shares. As part of this transaction, NOK 802.1 million of the loan was extinguished in exchange for 34.9 million shares of our common stock with the remainder owed (NOK 29.5 million) to Seadrill repaid with a portion of the cash proceeds of the private placement.

Other Current Intercompany Debt and Liabilities

As of December 31, 2010, none of other current assets stated in the balance sheet is related to short-term loans to Seadrill, compared to NOK 2.8 million stated in the balance sheet as at December 31, 2009 as a part of other current liabilities.

Performance Guarantees

Our shareholder, Seadrill, has provided performance guarantees for the obligations of members of the Seawell group. These performance guarantees were provided due to the Company having been a subsidiary of Seadrill. The following performance guarantees have been provided by Seadrill:

· NOK 75 million performance guarantee in favor of Statoil ASA, dated August 24, 2004;

· NOK 33 million performance guarantee in favor of ConocoPhilips Skandianvia AS effective January 1, 2010; and

· NOK 33 million performance guarantee in favor of ConocoPhilips Skandianvia AS effective January 1, 2010.

C. Interests of Experts & Counsel

Not applicable.

Item 8    Financial Information

A. Consolidated Statements and Other Financial Information

Consolidated Statements

See Item 18, “Financial Statements.”

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Legal Proceedings

Other than litigation arising in connection with the merger as described below, neither we nor any of our subsidiaries is involved in any legal proceedings. See also “Risk Factors—Risks Related to our Business—Seawell may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations” in Item 3.D. for a discussion of the possible effects of litigation on our business.

Texas State Court

Beginning on August 16, 2010, seven putative stockholder class action petitions were filed against various combinations of Allis-Chalmers, members of the Allis-Chalmers board of directors, the Company, and Wellco in the District Court of Harris County, Texas, challenging the proposed merger and seeking, among other things, compensatory damages, attorneys’ and experts’ fees, declaratory and injunctive relief concerning the alleged breaches of fiduciary duties and injunctive relief prohibiting the defendants from consummating the merger.

The lawsuits generally allege, among other things, that the Agreement and Plan of Merger, dated as of August 12, 2010, by and among Allis-Chalmers, the Company and Wellco Sub Company (the “Merger Agreement”) was reached through an unfair process and that the consideration upon which the Merger Agreement is premised is inadequate, that the transaction was timed to take advantage of an overall decline in the market price of Allis-Chalmers stock and that the Merger Agreement unfairly caps the price of Allis-Chalmers stock, that the Merger Agreement’s “no shop” provision unreasonably dissuades potential suitors from making competing offers and that the Merger Agreement otherwise unduly restricts Allis-Chalmers from considering competing offers.

Beginning on August 26, 2010, various plaintiffs in these lawsuits filed competing motions to consolidate the suits, to appoint their counsel as interim class counsel and to compel expedited discovery. On September 16, 2010, the defendants filed joint motions to stay the Texas lawsuits in favor of a first-filed Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set for these motions. The parties to the Texas State Court actions have agreed that the various defendants need not respond to the petitions until after lead counsel is appointed, a consolidated amended petition is filed and served or, alternatively, an active petition is designated by lead counsel.

Delaware Chancery Court

Beginning on August 16, 2010, three putative stockholder class action suits were filed against various combinations of Allis-Chalmers, members of the Allis-Chalmers board of directors, the Company, and Wellco in the Court of Chancery of the State of Delaware, challenging the proposed merger and seeking, among other things, compensatory and rescissory damages, attorneys’ and experts’ fees and injunctive relief concerning the alleged breaches of fiduciary duties and prohibiting the defendants from consummating the merger.

The lawsuits generally allege, among other things, that the Merger Agreement was reached through an unfair process and that the consideration upon which the Merger Agreement is premised is inadequate, that the transaction was timed to take advantage of an overall decline in the market price of Allis-Chalmers stock, that the transaction unfairly favors the Company, that the Merger Agreement’s “no shop” provision unreasonably dissuades potential suitors from making competing offers and that the Merger Agreement otherwise unduly restricts Allis-Chalmers from considering competing offers.

On September 21, 2010, the plaintiffs in the three actions wrote the Court seeking consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position regarding lead plaintiff. On September 29, 2010, the Court granted the Motion to Consolidate. On September 16, 2010, the Company and Wellco answered the first-filed Girard Complaint (designated as the operative complaint post-consolidation). Allis-Chalmers and the members of the Allis-Chalmers board of directors answered the consolidated complaint on October 4, 2010.

On January 26, 2011, plaintiffs in the consolidated Delaware actions filed an Amended Verified Class Action Complaint For Breach Of Fiduciary Duty (the “Amended Complaint”) along with a motion to expedite proceedings.  The Amended Complaint generally alleges, among other things, that the Merger Agreement was reached through an unfair process and that the consideration upon which the Merger Agreement is premised is inadequate, that the Allis-Chalmers board failed to inform itself adequately of the highest price reasonably available, that the Allis-Chalmers board was conflicted and thus unable to fulfill its duties, that the transaction was timed to take advantage of an overall decline in the market price of Allis-Chalmers stock, that the transaction unfairly favors the Company, that the Merger Agreement’s “no solicitation” provision unreasonably dissuades potential suitors from making competing offers, that the Merger Agreement otherwise unduly restricts Allis-Chalmers from considering competing offers and that a voting agreement between the Company and Lime Rock Partners GP V, L.P. improperly restrains Allis-Chalmers from engaging with third parties regarding an alternative proposal. The amended complaint alleges that Allis-Chalmers, the Company, and Wellco aided and abetted the alleged breaches of fiduciary duty.

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 In addition, the Amended Complaint contains allegations that the Registration Statement filed on Form F-4 filed with the SEC on January 14, 2011, and amended on January 21, 2011, failed to properly disclose all material facts in connection with the proposed merger, in violation of Delaware law.

At a February 3, 2011 hearing Vice Chancellor John W. Noble, of the Delaware Court of Chancery, denied plaintiffs’ motion to expedite proceedings.  On February 9, 2011, the Company filed a motion to dismiss the Amended Complaint under Court of Chancery Rule 12(b)(6) for failure to state a claim upon which relief may be granted.

We believe these lawsuits are without merit and intend to defend them vigorously.

We are involved in various other legal proceedings, including labor contract litigation, in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceedings is remote.

Dividend Policy

Our board of directors may from time to time declare cash dividends (including interim dividends) or distributions. The timing and amount of dividends, if any, is at the sole discretion of our board of directors and will depend upon our operating results, financial condition, cash requirements, restrictions in terms of financing arrangements and other relevant factors. Our board of directors is prohibited by the Companies Act from declaring or paying a dividend, or making a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) we are, or would after the payment be, unable to pay our liabilities as they become due; or (b) the realizable value of our assets would thereby be less than the aggregate of our liabilities and our issued share capital and share premium accounts.

We have never paid or declared any dividends on our common shares.

B. Significant Changes

Universal Wireline Acquisition

On January 27, 2011, we completed the acquisition of Universal Wireline, Inc., or Universal, for total consideration of $25.5 million on a debt-free and cash-free basis. Universal is a provider of a full range of cased-hole wireline services in unconventional plays such as the Barnett, Marcellus, Haynesville, Bakken, Eagle Ford and Woodford shales and in the Permian Basin. The Universal acquisition contributes 26 wireline units -- including 22 Artex built hydraulic units with an average age of less than 3 years and 4 mechanical units specific to work in Appalachia; 17 crane trucks with an average age of less than 3 years; and a wide assortment of logging and wireline tools. Universal also expands our area of operation by adding new districts in Rosharon and Alice in Texas; Dunbar and Buckhannon in West Virginia; and Tioga, in North Dakota. For the fiscal year ended December 31, 2010, Universal reported revenues of approximately $5.7 million and losses before taxes of approximately $1.5 million and, at December 31, 2010, Universal had total assets of approximately $27.5 million.

Allis-Chalmers Merger

On February 23, 2011, Wellco Sub Company, or Wellco, a wholly owned subsidiary of the Company, completed the acquisition of Allis-Chalmers Energy Inc., or Allis-Chalmers, for total value of  $600.9 million, with approximately 95% of Allis-Chalmers stockholders electing to receive 97,071,710 common shares in the merger and the remainder receiving an aggregated of $18 million in cash. The acquisition combined our leading drilling and well services businesses with Allis-Chalmers’ drilling, rental and oilfield service business to create a global oilfield service company with operations in more than 30 countries.

Other than the Universal Wireline acquisition and the merger with Allis-Chalmers, no significant changes have occurred since the date of our consolidated financial statements. See Item 5.D., “Trend Information.”

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Item 9    The Offer and Listing

A. Offer and Listing Details

Our common shares are traded on the Oslo Stock Exchange under the symbol “SEAW.” The following table sets forth, for the periods indicated, the high and low sale prices per common share as reported on the Norwegian over-the-counter system through November 25, 2010 and thereafter on the Oslo Stock Exchange. However, it is important to note that, due to reduced liquidity associated with the Norwegian over-the-counter market, sale prices prior to the listing of our common shares on the Oslo Stock Exchange, as reported on the Norwegian over-the-counter system, may not be strictly comparable to those prices reported on the Oslo Stock Exchange after the listing of our common shares.

	Seawell Common Stock (NOK)		Seawell Common Stock (USD)(1)
	High	Low	High	Low
2007	NOK   22.00	NOK   14.00	$  3.74	$  2.38
2008	26.00	6.00	4.41	1.02
2009	17.00	6.00	2.89	1.02
2010	37.00	15.00	6.28	2.55
2009 First Quarter	10.00	6.50	1.70	1.10
Second Quarter	11.00	6.00	1.87	1.02
Third Quarter	13.00	9.25	2.21	1.57
Fourth Quarter	17.00	12.00	2.89	2.04
2010 First Quarter	22.00	15.00	3.74	2.55
Second Quarter	20.00	16.25	3.40	2.76
Third Quarter	23.90	22.70	4.06	3.85
Fourth Quarter	37.00	27.25	6.28	4.63
October 2010	27.50	23.60	4.67	4.01
November 2010	37.00	27.25	6.28	4.63
December 2010	38.00	29.30	6.45	4.98
January 2011	43.00	34.90	7.30	5.93
February 2011	40.00	31.80	6.79	5.40
March 2011	38.60	32.00	6.55	5.43
April 2011 (through April 25, 2011)	38.60	33.70	6.55	5.72

_______________________
Note:

(1) Solely for the convenience of the reader, certain NOK amounts presented for the year ended December 31, 2010 have been translated into U.S. dollars using the noon buying rate in New York City for cable transfers in foreign countries as certified for customs purposes by the Federal Reserve Bank of New York on December 31, 2010 of NOK 1.00 = $0.1698.

B. Plan of Distribution

Not applicable.

C. Markets

See Item 9.A. “Offer and Listing Details”.

D. Selling Shareholders

Not applicable.

E. Dilution

Not applicable.

F. Expenses of the Issue

Not applicable.

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Item 10   Additional Information

A. Share Capital

Not applicable.

B. Memorandum and Articles of Association

The information required by Item 10.B. is incorporated by reference to the Company’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011.

C. Material Contracts

Allis-Chalmers Merger

On February 23, 2011, Wellco Sub Company, or Wellco, a wholly owned subsidiary of the Company, completed the acquisition of Allis-Chalmers Energy Inc., or Allis-Chalmers, for total value of  $600.9 million, with approximately 95% of Allis-Chalmers stockholders electing to receive 97,071,710 common shares in the merger and the remainder receiving an aggregated of $18 million in cash. The acquisition combined our leading drilling and well services businesses with Allis-Chalmers’ drilling, rental and oilfield service business to create a global oilfield service company with operations in more than 30 countries.

D. Exchange Controls

Specific permission is required from the Bermuda Monetary Authority (the “BMA”) pursuant to the provisions of the Bermuda Exchange Control Act 1972 and related regulations, for all issuances and transfers of securities of Bermuda exempted companies like ours, other than in cases where the BMA has granted a general permission. On June 1, 2005, the BMA granted a general permission for the issue and subsequent transfer of any equity securities of a Bermuda company listed on an “appointed stock exchange” from and/or to a non-resident, for as long as any equity securities of such company remain so listed. Our common shares are listed on the Oslo Stock Exchange, which is an appointed stock exchange under Bermuda law.

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 Business Development and Tourism of Bermuda; (iii) the acquisition of any bonds or debentures secured on any land in Bermuda except bonds or debentures issued by the Government of Bermuda or by a public authority in Bermuda; or (iv) the carrying on of business of any kind in Bermuda, except in so far as may be necessary for the carrying on of its business outside Bermuda or under a license granted by the Minister of Business Development and Tourism of Bermuda.

The Bermuda government actively encourages foreign investment in “exempted” entities like us that are based in Bermuda but do not operate in competition with local business. In addition to having no restrictions on the degree of foreign ownership, we are subject neither to taxes on our income or dividends 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.

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E. Taxation

The following discussion of material United States and Bermuda federal income tax consequences of an investment in our common shares is based upon laws and relevant interpretations thereof as of the date of this report, all of which are subject to change.  This discussion does not deal with all possible tax consequences relating to an investment in our common shares, such as the tax consequences under state, local and other tax laws.

United States Federal Income Taxation

General

The following is a discussion of the United States federal income tax considerations relating to the acquisition, ownership, and disposition of our common shares that are anticipated to be material to a U.S. Holder (as defined below) that will hold common shares as “capital assets” (generally, property held for investment) under the United States Internal Revenue Code of 1986, as amended. This discussion is based upon existing United States federal income tax law, which is subject to differing interpretations or change, possibly with retroactive effect.

The following is a discussion of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of Seawell common shares that are anticipated to be material to a U.S. holder (as defined below) that holds Seawell common shares as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.  A U.S. holder is a beneficial owner of our common shares that is, for U.S. federal income tax purposes:

· an individual citizen or resident of the United States;

· a corporation or other entity taxable as a corporation created in or organized under the laws of the United States or any political subdivision thereof;

· an estate the income of which is subject to U.S. federal income tax without regard to its source; or

· a trust (A) if a court within the United States is able to exercise primary supervision over its administration and one or more U.S. persons have the authority to control all of the substantial decisions of such trust or (B) that has otherwise validly elected to be treated as a United States person under the Internal Revenue Code.

This discussion is not intended to be a complete analysis and does not address all potential tax consequences that may be relevant to you. Moreover, this discussion does not apply to you if you are subject to special treatment under the Internal Revenue Code, including, without limitation, because you are:

· a foreign person or entity;

· a U.S. expatriate;

· a tax-exempt organization, financial institution, mutual fund, dealer or broker in a securities or insurance company;

· an owner (directly, indirectly, or constructively) of 10% or more of our common shares;

· a trader who elects to mark its securities to market for U.S. federal income tax purposes;

· an investor that will hold our common shares as part of a straddle, hedge, conversion, constructive sale, or other integrated transaction for United States federal income tax purposes;

· a person whose functional currency is not the U.S. dollar;

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· an individual who acquires Seawell common shares, pursuant to the exercise of employee stock options or otherwise as compensation or in connection with the performance of services;

· a partnership or other flow-through entity (including an S corporation or a limited liability company treated as a partnership or disregarded entity for U.S. federal income tax purposes) and persons who hold an interest in such entities; or

· a person subject to the alternative minimum tax.

If a partnership is a beneficial owner of our common shares, the tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. Partners of a partnership holding our common shares are urged to consult their tax advisors regarding an investment in our common shares.

In addition, this discussion does not address any non-United States, state, or local tax considerations. This description, moreover, does not address the U.S. federal estate and gift tax or alternative minimum tax consequences of the acquisition or ownership our common shares. Each U.S. holder is urged to consult their tax advisors regarding the United States federal, state, local, and non-United States income and other tax considerations of an investment in common shares.

Dividends

Any cash distributions paid on Seawell common shares out of its current or accumulated earnings and profits, as determined under United States federal income tax principles, will generally be includible in the gross income of a U.S. holder as dividend income. Because the Company does not intend to determine its earnings and profits on the basis of United States federal income tax principles, U.S. holders should expect that any distribution paid will generally be reported to them as a “dividend” for United States federal income tax purposes. Dividends received on Seawell common shares will not be eligible for the dividends received deduction allowed to corporations.

Dividends will generally be treated as income from foreign sources for United States foreign tax credit purposes. The rules with respect to foreign tax credits are complex and U.S. holders are urged to consult their independent tax advisors regarding the availability of the foreign tax credit under their particular circumstances.

Sale or Other Disposition of Seawell Common Shares

A U.S. holder will generally recognize capital gain or loss upon the sale or other disposition of our common shares in an amount equal to the difference between the amount realized upon the disposition and the holder’s adjusted tax basis in such common shares. The ability to deduct any loss may be subject to limitations. If you are an individual, capital gain or loss generally will be long-term if your holding period in our common shares is more than one year and will generally be United States source gain or loss for United States foreign tax credit purposes.

Passive Foreign Investment Company Considerations

A non-United States corporation, such as us, will be classified as a passive foreign investment company, or PFIC, for United States federal income tax purposes, if either (i) 75% or more of its gross income consists of certain types of “passive” income or (ii) 50% or more of the fair market value of its assets (determined on the basis of a quarterly average) produce or are held for the production of passive income. For this purpose, cash is categorized as a passive asset and unbooked intangibles will be taken into account and generally treated as nonpassive assets. The corporation will be treated as owning its proportionate share of the assets and earning its proportionate share of the income of any other corporation in which it owns, directly or indirectly, more than 25% (by value) of the stock. While we do not anticipate becoming a PFIC in the current or future taxable years, there can be no assurance that it will not be a PFIC for any taxable year, as PFIC status is tested each taxable year and depends on the composition of its assets and income in such taxable year. If we are classified as a PFIC for any year during which a U.S. holder holds our common shares, we will generally continue to be treated as a PFIC for all succeeding years during which such U.S. holder holds our common shares. Because PFIC status is a fact-intensive determination made on an annual basis and depends on the composition of our assets and income at such time, no assurance can be given that we are not or will not become classified as a PFIC.

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If we are classified as a PFIC for any taxable year during which a U.S. holder holds our common shares, unless a U.S. holder makes a mark-to-market election (as described below), a U.S. holder will generally be subject to imputed interest charges, characterization of a portion of any gain from the sale or exchange of our common shares as ordinary income, and other disadvantageous tax treatment with respect to our common shares.

As an alternative to the foregoing rules, a U.S. holder of “marketable stock” in a PFIC may make a mark-to-market election, provided that our common shares are actively traded. No assurances may be given that our common shares should qualify as being actively traded. If you make this election, you will generally (i) include as income for each taxable year the excess, if any, of the fair market value of our common shares held at the end of the taxable year over the adjusted tax basis of such shares and (ii) deduct as a loss the excess, if any, of the adjusted tax basis of our common shares over the fair market value of such shares held at the end of the taxable year, but only to the extent of the amount previously included in income as a result of the mark-to-market election. Your adjusted tax basis in our common shares would be adjusted to reflect any income or loss resulting from the mark-to-market election. If a U.S. holder makes a mark-to-market election in respect of a corporation classified as a PFIC and such corporation ceases to be classified as a PFIC, the U.S. holder will not be required to take into account the gain or loss described above during any period that such corporation is not classified as a PFIC.

A qualified electing fund election, or QEF election, could also alleviate certain of the tax consequences referred to above. However, it is expected that the conditions necessary for making a QEF election will not apply in the case of our common shares, because we do not make available the information necessary for U.S. holders to report income and certain losses in a manner consistent with the requirements for such elections.

If you own our common shares during any taxable year in which we are a PFIC, you may be subject to certain reporting obligations with respect to our common shares, including reporting on Internal Revenue Service Form 8621. In the case of a U.S. holder that has held our common shares during any taxable year in respect of which we were classified as a PFIC and continues to hold such common shares (or any portion thereof), and has not previously determined to make a mark-to-market election, and that is now considering making a mark-to-market election, special tax rules may apply relating to purging the PFIC taint of such common shares. Each U.S. holder is urged to consult its tax advisor concerning the United States federal income tax consequences of holding and disposing of our common shares if we are or become classified as a PFIC, including the possibility of making a mark-to-market or other election.

Information Reporting and Back-Up Withholding

Dividends may be subject to backup withholding, currently at a 28% rate, unless a holder (1) is a corporation or other exempt entity or (2) provides a taxpayer identification number, certifies as to no loss of exemption from backup withholding and otherwise complies with the backup withholding rules. Any amounts withheld from payments to a holder under the backup withholding rules are not additional tax and generally will be allowed as a refund or credit against the holder’s U.S. federal income tax liability, provided the required information is timely furnished to the Internal Revenue Service.

Bermuda Tax Consequences

Under current law, Bermuda will not impose on us or any of our operations or the shares, debentures or other of our obligations, any tax computed on profits or income, or computed on any capital asset, gain or appreciation, or any tax in the nature of estate, duty or inheritance tax. We have obtained a written assurance from the Minister of Finance under the Exempted Undertakings Tax to the effect that in the event of the enactment in Bermuda of any legislation imposing any such tax, then the imposition of such tax shall not be applicable to us or to any of our operations or the shares, debentures or other of our obligations until March 28, 2016. The Government of Bermuda has recently amended the Exempted Undertakings Act to extend the period for which the Minister of Finance may grant an assurance from March 28, 2016 to March 31, 2035. The existing assurance received by us remains valid until March 28, 2016, however, we can now apply to the Minister of Finance for an assurance pursuant to the Exempted Undertakings Act lasting until March 31, 2035. We intend to apply to the Minister of Financefor such an extended assurance. The assurances are subject to the proviso that they are not construed so as to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda (we are not currently so designated) or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967 of Bermuda or otherwise payable in relation to the land, if any, leased to us. We are required to pay certain annual Bermuda government fees. Under current rates, we will pay a maximum fixed annual fee of $31,120.

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Under current Bermuda law, there will be no Bermuda income or withholding tax on dividends paid by us to our shareholders. Furthermore, no Bermuda tax or other levy is payable on the sale or other transfer (including by gift or on the death of a shareholder) of our common shares (other than by shareholders resident in Bermuda).

F. Dividends and Paying Agents

Not applicable.

G. Statement by Experts

Not applicable.

H. Documents on Display

We are subject to certain reporting requirements of the US Securities Exchange Act of 1934 (the “Exchange Act”). As a “foreign private issuer,” we are exempt from the rules under the Exchange Act prescribing certain disclosure and procedural requirements for proxy solicitations, and our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions contained in Section 16 of the Exchange Act, with respect to their purchases and sales of shares. In addition, we are not required to file reports and financial statements with the Commission as frequently or as promptly as companies that are not foreign private issuers whose securities are registered under the Exchange Act. However, we are required to file with the Commission, within six months after the end of each fiscal year, an annual report on Form 20-F containing financial statements audited by an independent accounting firm and interactive data comprising financial statements in extensible business reporting language which, with respect to our annual report on Form 20-F for the year ended December 31, 2010, may be filed within 30 days of filing our annual report on Form 20-F. We publish unaudited interim financial information after the end of each quarter. We furnish this quarterly financial information to the Commission under cover of a Form 6-K.

Documents we file with the Commission are publicly available at its public reference facilities at 450 Fifth Street, N.W., Washington, DC 20549, Woolworth Building, 233 Broadway, New York, New York 10048 and Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511. Copies of the documents are available at prescribed rates by writing to the Public Reference Section of the Commission at 450 Fifth Street, N.W., Washington DC 20549. The Commission also maintains a website that contains reports and other information regarding registrants that are required to file electronically with the Commission. The address of this website is http://www.sec.gov. Please call the Commission at 1-800-SEC-0330 for further information on the operation of the public reference facilities.

I. Subsidiary Information

Not applicable.

Item 11   Quantitative and Qualitative Disclosures About Market Risk

Quantitative and Qualitative Disclosure about Market Risk

Financial risk management objectives

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.

Market risk

Our activities expose us primarily to the financial risks of changes in foreign currency exchange rates and interest rates as described below.

Foreign currency risk management

We, along with the majority of our subsidiaries, use the Norwegian krone as our functional currency because the majority of our revenues and expenses are denominated in krone. Accordingly, our reporting currency is also the Norwegian krone. We do, however, earn revenue and incur expenses in other currencies, and there is thus a risk that currency fluctuations could have an adverse effect on the value of our cash flows.

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Our foreign currency risk arises from the measurement of debt and other monetary assets and liabilities denominated in foreign currencies converted to Norwegian krone, with the resulting gain or loss recorded as “Other financial items” and the impact of fluctuations in exchange rates on the reported amounts of our revenues and expenses which are contracted in foreign currencies.

Subsequent to our establishment in October 2007, we have not used any financial instruments to manage these foreign currency risks, but management is constantly monitoring the risks.

Interest rate risk

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

During 2008, 2009 and 2010, a substantial portion of our borrowings were in the form of a loan from our controlling shareholder, Seadrill. Further details of this loan are set out under Item 7, “Major Shareholders and Related Party Transactions” above.

At December 31, 2010, we had a revolving credit facility with Fokus Bank, the Norwegian branch of Danske Bank AS, for NOK 1,500 million for a contractually specified period of time and at an interest rate determined with reference to NIBOR at the time of borrowing.

We had no significant interest bearing assets other than cash and cash equivalents, therefore our income and operating cash flows are substantially independent of changes in market interest rates.

Our management uses 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. In 2009, we entered into an interest rate swap agreement securing the interest rate on NOK 750 million of our then outstanding credit facility for 42 months. The agreement was entered into in mid-March 2009, with the commencement of the hedging period and start of hedging accounting beginning by the end of April 2009. We have interest rate risk arising from long-term borrowings. Borrowings at variable rates expose us to cash flow interest rate risk and borrowings at fixed rates expose us to fair value interest rate risk.

Financial instruments

We use interest rate swaps to manage our interest rate risk and entered into an interest rate swap agreement in March 2009, securing the interest rate on NOK 750 million of the Company’s interest bearing debt for 3.5 years. The following table summarizes the notional amounts and estimated fair values of our financial instruments:

	2010 notional amount	Fair value
	(NOK in millions)
Interest rate swap(1)	715	(11.1)

(1) Relates to interest rate swaps assigned as a hedge to interest bearing debt related to the NOK 1,500 million revolving facility; the fair value of the interest rate swaps includes accrued interest.

Concentration of credit risk

The market for our services is the offshore oil and gas industry, and our 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.

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

	Years ended December 31,
Customer	2008	2009	2010
Statoil	52%	51%	46%
Shell	11%	6%	6%
BP	12%	16%	7%
ConocoPhillips	0%	0%	16%
Other customers	25%	27%	25%
Total	100%	100%	100%

We may also face credit related losses in the event that counterparties to its 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 interest rate swaps. We generally do not require collateral for our financial instrument contracts. In the opinion of management, our counterparties are creditworthy financial institutions, and management does not expect any significant loss to result from their non-performance. The credit exposure of interest rate swap agreements is represented by the fair value of contracts with a positive fair value at the end of each period.

Liquidity and capital risk management

Prudent liquidity risk management includes maintaining sufficient cash and cash equivalents and the availability of funding through an adequate amount of committed credit facilities. We regularly review the efficiency of our capital structure.

As of December 31, 2010, cash and cash equivalents amounted to NOK 1,023.6 million, compared to NOK 236.7 million as of December 31, 2009.

Item 12   Description of Securities Other Than Equity Securities

Not applicable.

Part II

Item 13   Defaults, Dividend Arrearages and Delinquencies

None.

Item 14   Material Modifications to the Rights of Security Holders and Use of Proceeds

None.

Item 15   Controls and Procedures

Disclosure Controls and Procedures

As of the end of the period covered by this report, the management of Seawell conducted an evaluation, under the supervision and with the participation of Seawell’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Seawell’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). Based on such evaluation, Seawell’s Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2010, Seawell’s disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by Seawell in the reports that it files or submits under the Exchange Act and are effective in ensuring that information required to be disclosed by Seawell in the reports that it files or submits under the Exchange Act is accumulated and communicated to Seawell’s management, including Seawell’s Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management's Report on Internal Control 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 Seawell’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

65

Changes in Internal Control over Financial Reporting

During the year ended December 31, 2010, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 16

A. Audit Committee Financial Expert

Our board of directors has determined that Kate Blankenship, an independent director, qualifies as the Audit Committee Financial Expert.

B. Code of Ethics

The Company has adopted its "Code of Conduct," which contains the Company’s ethical principles in relation to various subjects.  The Company’s Code of Conduct applies to all employees.  A copy of the Code of Conduct may be obtained without charge upon written request to our offices at Second Floor, 2 Basil Street, London SW3 1AA, United Kingdom.

C. Principal Accountant Fees and Services

PricewaterhouseCoopers AS has served as our independent registered public accounting firm for each of the three financial years up to December 31, 2010. The following table sets out the aggregate fees for professional audit services by PricewaterhouseCoopers AS in 2009 and 2010:

	Years ended December 31,
	2009	2010
	(NOK in thousands)
Audit fees	2,555.9	4,544.2
Audit-related fees	558.9	1,341.0
Tax fees	1,138.4	809.5
All other fees	—	9.5
Principal accountant fees and services	4,253.2	6,974.2

Audit fees

Audit fees primarily relate to the audit of our annual consolidated financial statements set out in our Annual Report on Form 20-F, our statutory annual report, agreed upon procedures on our quarterly financial results, services related to statutory and regulatory filings of Seawell Limited and its subsidiaries and services in connection with accounting consultations on U.S. GAAP.

Audit-related fees

Audit-related fees mainly related to various audit services not related to the Company’s consolidated financial statements, mainly statutory audits.

Tax fees

The following table sets forth tax fees billed by PricewaterhouseCoopers AS in 2009 and 2010:

	Years ended December 31,
	2009	2010
	(NOK in thousands)
Tax compliance	—	—
Tax advice	1,138.4	809.5
Tax planning	—	—
Total tax fees	1,138.4	809.5

66

The Company’s 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 of directors to approve the appointment of the independent auditor of the Company 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 2010 were approved by the board of directors pursuant to the pre-approval policy.

D. Exemptions from the Listing Standards for Audit Committees

Not applicable.

E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

F. Change in Registrant’s Certifying Accountant

Not applicable.

G. Corporate governance

Not applicable.

Part III

Item 17   Financial Statements

The financial statements and related information specified in Item 18 of this Form are provided in lieu of Item 17.

Item 18   Financial Statements

In response to this item, the Company herein incorporates by reference the consolidated financial statements of the Company set out on pages F-1 through F-41 hereto.

Item 19   Exhibits

Exhibit No.	Description
1.1	Memorandum of Association of Seawell Limited, dated August 31, 2007, as amended by a Certificate of Deposit of Memorandum of Increase of Share Capital, dated September 25, 2007, and, as further amended by a Certificate of Deposit of Memorandum of Increase of Share Capital, dated October 4, 2010 (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
1.2	Amended and Restated Bye-Laws of Seawell Limited, dated September 18, 2007 (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
2.1	The Bank of New York Mellon Sponsored Share Sale Plan (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).

4.1	Agreement and Plan of Merger, dated as of August 12, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.2	Amendment Agreement, dated as of October 1, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.3	Voting Agreement, dated as of August 12, 2010, between Lime Rock Partners V., L.P. and Seawell Limited (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).

67

Exhibit No. Description

4.4	Revolving Credit Facility Agreement, dated as of September 7, 2010, between Seawell Limited and Fokus Bank (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.5	Multicurrency Term and Revolving Credit Facility Agreement, dated as of November 11, 2010, among Danske Bank AS, DnB NOR Bank AS, Swedbank AB, Nordea Bank Norge ASA and Seawell Limited (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.6	Long-Term Incentive Plan of Seawell Limited, approved by Seawell Limited’s board of directors on September 24, 2010 (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.7	Form of Corporate Administrative Services Agreement between Seawell and Frontline Management (Bermuda) Ltd (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.8	Form of General Management Agreement, between Seawell and Seawell Management (Bermuda) Ltd (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
8.1	List of Significant Subsidiaries*
11.1	Code of Ethics*
12.1	Certification of CEO Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934*
12.2	Certification of CFO Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934*
13.1	Certification of CEO Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934*
13.2	Certification of CFO Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934*

_______________________
*           Filed herewith

68

SIGNATURES

Seawell Limited 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.

SEAWELL LIMITED
By:	/s/ Jørgen Rasmussen
Name:	Jørgen Rasmussen
Title:	Chief Executive Officer & President, Seawell Management Limited

Date:  April 26, 2011

69

Index to Consolidated Financial Statements

	Page
Report of Independent Auditors	F-2
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008	F-3
Consolidated Balance Sheets as of December 31, 2010 and 2009	F-4
Consolidated Statement of Cash Flows for the years ended December 31, 2010, 2009 and 2008	F-5
Consolidated Statement of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008	F-6
Consolidated Statement of Changes in Shareholders’ Equity for the years ended December 31, 2010, 2009 and 2008	F-7
Notes to Consolidated Financial Statement for the years ended December 31, 2010, 2009, 2008	F-8

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Seawell 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 Seawell Limited and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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

April 26, 2011

F-2

Consolidated Statement of Operations for the years ended December 31, 2008, 2009 and 2010

(In millions of NOK, except per share data and weighted average shares)

	Year ended December 31,
	2008	2009	2010
Operating revenues
Operating revenues	3,006.2	3,101.2	3,687.5
Reimbursables	618.5	723.6	641.4
Total operating revenues	3,624.7	3,824.8	4,328.9
Operating expenses
Operating expenses	2,538.8	2,538.3	3,038.0
Reimbursable expenses	600.9	692.5	617.1
Depreciation and amortization	107.4	131.6	136.2
General and administrative expenses	71.9	103.1	152.0
Total operating expenses	3,319.0	3,465.5	3,943.2
Operating income	305.7	359.3	385.7
Financial items
Interest income	25.3	5.6	9.3
Interest expenses	(148.3)	(96.8)	(132.9)
Share of results in associated company	—	—	(1.9)
Other financial items	(39.0)	(33.1)	(93.8)
Total financial items	(162.0)	(124.3)	(219.4)
Income before income taxes	143.7	235.0	166.3
Income taxes	(24.7)	(60.6)	(92.6)
Net income	119.0	174.4	73.7
Net income attributable to the parent	122.5	176.2	74.1
Net income attributable to the non-controlling interest	(3.5)	(1.8)	(0.4)
Basic earnings per share (NOK)	1.14	1.60	0.49
Diluted earnings per share (NOK)	1.14	1.59	0.47
Weighted average number of shares outstanding
Basic	107,222,272	110,000,050	152,049,913
Diluted	107,222,272	110,567,792	155,930,383

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

F-3

Consolidated Balance Sheet as of December 31, 2009 and December 31, 2010

(In millions of NOK)

	As of December 31,
	2009	2010
ASSETS
Current assets
Cash and cash equivalents	236.7	1,023.6
Restricted cash (note 8)	51.8	71.5
Accounts receivables, net of allowance for doubtful accounts of NOK 4.5  and NOK 6.5	550.4	889.5
Other current assets	191.0	378.6
Total current assets	1,029.9	2,363.2
Non-current assets
Investments in associates	—	30.9
Drilling equipment and other fixed assets	404.9	650.6
Asset under construction	167.0	184.5
Deferred income tax asset	9.3	31.5
Other intangible assets	135.7	343.9
Goodwill	1,589.8	2,091.3
Deferred charges	3.2	27.3
Total non-current assets	2,309.9	3,359.9
Total assets	3,339.8	5,723.1
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Current portion of long term debt	260.8	11.0
Other current liabilities	509.5	956.0
Amounts due to parent	191.1	0.0
Total current liabilities	961.4	967.1
Non-current liabilities
Subordinated loan from parent	613.6	0.0
Long-term interest bearing debt	987.7	1,128.8
Deferred taxes	—	75.2
Other non-current liabilities	149.8	278.1
Total non current liabilities	1,751.1	1,482.1
Commitments and contingencies
Shareholders’ equity
Common shares of par value $2.00 per share:
600,000,000 shares authorized
152,049,913 outstanding shares at December 31, 2010 (December, 31 2009: 110,000,050)	1,198.4	2,622.4
Additional paid in capital	163.3	1,357.7
Retained earnings	336.9	411.0
Accumulated other comprehensive income / (loss)	30.3	(15.3)
Contributed deficit	(1,102.1)	(1,102.1)
Non-controlling interest	0.5	0.1
Total shareholders’ equity	627.3	3,273.9
Total liabilities and shareholders’ equity	3,339.8	5,723.1

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

F-4

Consolidated Statement of Cash Flows for the years ended December 31, 2008, 2009 and 2010

(In millions of NOK)

	Year ended December 31,
	2008	2009	2010
Cash Flows from Operating Activities
Net income	119.0	174.4	73.7
Adjustment to reconcile net income to net cash   provided by operating activities:
Depreciation and amortization	107.4	131.6	136.2
Share-based compensation expenses	12.9	7.0	(9.4)
Change in pension cost	36.3	(19.3)	(8.5)
Gain on disposal of other investments	—	—	—
Deferred income taxes	(37.3)	(11.3)	16.2
Unrealized foreign currency gain (loss)	(7.0)	59.3	37.0
Change in deferred charges	—	1.1	58.4
Changes in other non current liabilities	—	5.4	52.7
Changes in working capital items:
Trade accounts receivable and other short-term receivables	(215.5)	170.6	(389.7)
Trade accounts payable and other short-term liabilities	200.2	(195.4)	346.1
Amounts due to parent	156.7	20.3	(7.7)
Net cash provided by operating activities	372.6	343.7	305.2
Cash Flows from Investing Activities
Additions to drilling equipment	(105.3)	(138.9)	(150.1)
Additions to assets under construction	(160.2)	(12.0)	(17.5)
Sale of rigs, vessels and equipment	—	—	19.0
Acquisition of subsidiaries	(853.3)	(31.0)	(1,066.4)
Acquisition of shares in associated companies	—	—	(40.0)
Proceeds from sale of shares in subsidiaries	—	—	100.5
Net change in restricted cash	(14.0)	12.6	(19.7)
Cash assumed in the purchase of subsidiaries	27.8	1.3	26.0
Net cash used in investing activities	(1,104.9)	(168.0)	(1,148.2)
Cash Flows from Financing Activities
Proceeds from debt	739.5	39.2	—
Repayment of debt	(75.0)	(233.1)	(113.2)
Debt fees paid	—	(0.2)	(82.5)
Proceeds from issuance of equity	195.0	—	1,852.1
Issuance cost in connection with issuance of equity	(3.4)	—	(26.3)
Net cash provided by (used in) financing activities	856.0	(194.1)	1,630.0
Effect of exchange rate changes on cash and cash equivalents	(31.8)	31.0	(53.4)
Net increase in cash and cash equivalents	91.9	12.6	786.9
Cash and cash equivalents at beginning of the period	132.2	224.1	236.7
Cash and cash equivalents at the end of the period	224.1	236.7	1,023.6
Interest paid	(71.9)	(60.9)	(56.6)
Taxes paid	(83.4)	(68.3)	(35.6)

During the year ended December 31, 2010 the Company converted NOK 638.6 million of subordinated debt due to Seadrill into equity.

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

F-5

Consolidated Statement of Comprehensive Income for the years ended December 31, 2008, 2009 and 2010

(In millions of NOK)

	Year ended December 31,
	2008	2009	2010
Net income (loss)	119.0	174.4	73.7
Change in unrealized loss/gain related to pension	(7.0)	45.1	(67.3)
Change in unrealized foreign exchange differences	(19.8)	13.5	27.3
Interest swap gain (loss)	–	(2.1)	(5.6)
Total comprehensive Income (net of tax)	92.2	230.9	28.1
Comprehensive income attributable to the parent	95.7	232.7	28.5
Comprehensive income attributable to the non controlling interest	(3.5)	(1.8)	(0.4)

	Pension – unrecognized gains/losses	Change in unrealized foreign exchange differences	Other comprehensive gains/losses	Total
Balance at December 31, 2007	3.7	(3.1)	–	0.6
Net change in gains and losses and prior service cost	(7.0)	–	–	(7.0)
Foreign exchange differences	–	(19.8)	–	(19.8)
Balance at December 31, 2008	(3.3)	(22.9)	–	(26.2)
Net change in gains and losses and prior service cost	45.1	–	–	45.1
Interest swap gain (loss)	–	–	(2.1)	(2.1)
Foreign exchange differences	–	13.5	–	13.5
Balance at December 31, 2009	41.8	(9.4)	(2.1)	30.3
Net change in gains and losses and prior service cost	(67.3)	–	–	(67.3)
Interest swap gain (loss)	–	–	(5.6)	(5.6)
Foreign exchange differences	–	27.3	–	27.3
Balance at December 31, 2010	(25.5)	17.9	(7.7)	(15.3)

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

F-6

Consolidated Statement of Changes in Shareholders’ Equity for the years ended December 31, 2008, 2009 and 2010

(In millions of NOK)

	Share capital	Additional paid in capital	Accumulated other comprehensive income	Retained earnings	Contributed deficit	Non-controlling interest	Total shareholders’ equity
Consolidated Balance at December 31, 2007	1,098.4	51.8	0.6	38.2	(1,102.1)	4.5	91.4
Issued shares April 2008, net of issuance cost of NOK 3.4	100.0	91.6	–	–	–	–	191.6
Translation adjustment	–	–	(19.8)	–	–	–	(19.8)
Pension  - unrecognized gain (loss)	–	–	(7.0)	–	–	–	(7.0)
Options issued	–	12.9	–	–	–	–	12.9
Net income	–	–	–	122.5	–	(3.5)	119.0
Consolidated Balance at December 31, 2008	1,198.4	156.3	(26.2)	160.7	(1,102.1)	1.0	388.1
Translation adjustment	–	–	13.5	–	–	–	13.5
Interest swap gain (loss)	–	–	(2.1)	–	–	–	(2.1)
Pension  - unrecognized gain (loss)	–	–	45.1	–	–	–	45.1
Options issued	–	7.0	–	–	–	–	7.0
Share issue	–	–	–	–	–	1.3	1.3
Net income	–	–	–	176.2	–	(1.8)	174.4
Consolidated Balance at December 31, 2009	1,198.4	163.3	30.3	336.9	(1,102.1)	0.5	627.3
Private placement	1,424.0	1,203.8	–	–	–	–	2,627.8
Translation adjustment	–	–	27.3	–	–	–	27.3
Interest swap gain (loss)	–	–	(5.6)	–	–	–	(5.6)
Pension – unrecognized gain (loss)	–	–	(67.3)	–	–	–	(67.3)
Options issued	–	(9.4)	–	–	–	–	(9.4)
Net income	–	–	–	74.1	–	(0.4)	73.7
Consolidated Balance at December 31, 2010	2,622.4	1,357.7	(15.3)	411.0	(1,102.1)	0.1	3,273,9

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

F-7

Note 1 - General information

Seawell Limited (the “Company” or “Seawell”) is a global oilfield service company providing drilling services and well services, including platform drilling, drilling facility engineering, modular rigs, well intervention and oilfield technology. The Company employs approximately 3,600 skilled and experienced people.

Seawell was incorporated in Bermuda on August 31, 2007 as a wholly owned subsidiary of Seadrill Limited (“Seadrill”). Seawell, together with its wholly owned subsidiary Seawell Holding UK, acquired the shares in the entities comprising Seadrill’s Well Service division on October 1, 2007. The consideration for the shares was NOK 2,413.1 million and has been accounted for as a common control transaction. As of December 31, 2010, Seadrill owned 52.26% of the outstanding common shares of Seawell. As described in Note 27, subsequent to the year end, Seawell Limited acquired Allis-Chalmers Energy Inc. On February 28, 2011, the Company’s board of directors adopted a resolution to change the name of the Company to “Archer Limited”. The Company expects to adopt the name change in the second quarter of 2011, following approval of the change at a special general meeting of the Company’s shareholders and the making of the appropriate filings with the Bermuda Registrar of Companies.

Seawell’s shares are traded on the Oslo Börs under the symbol “SEAW.”

As used herein, unless otherwise required by the context, the term “Seawell” refers to Seawell Limited and the terms “Company,” “we,” “Group,” “our” and words of similar import refer to Seawell and its consolidated subsidiaries for the periods that are consolidated and the combined group for the period that are combined.  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 Norwegian krone (NOK) rounded to the nearest hundred thousand, unless otherwise stated.

In accordance with US GAAP, Seawell’s acquisition of the Noble Corporation North Sea Platform division (“Noble”), Peak Well Solutions AS (“Peak”), TecWel AS (“TecWel”) in 2008 have been accounted for as purchases in accordance with Statement of Financial Standards No. 141 and Gray Wireline Co (“Gray”), Rig Inspection Services Limited (“RIS”) and Romeg Holdings Pty. Ltd (“Romeg”) in 2010 have been accounted for as purchases in accordance with Statement of Financial Accounting Standards No. 141R “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.

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

Basis of consolidation

Seawell consolidated:

The consolidated financial statements include controlled entities, which for the Company are those where its voting interests exceed 50 percent or the Company otherwise considers that it controls an entity. Wellbore Solutions AS which is owned 42.6% at December 31, 2010, is consolidated as Seawell is considered to have control over the company through a shareholder agreement which gives Seawell the power to vote 50.1% of the shares. Intercompany transactions and internal sales have been eliminated on consolidation.

Note 2 - Accounting Policies

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

F-8

Future events and their effects cannot be perceived with certainty. Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts, recoverability of long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

Revenue recognition

The Company recognizes revenue for services and products when purchase orders, contracts or other persuasive evidence of an arrangement with the customer exist, the price is fixed or determinable, collectability is reasonable assured and services have been performed. Revenue from contract services performed on an hourly, daily or monthly rate basis is recognized as the service is performed.

All known or anticipated losses on contracts are provided for when they become evident.

Reimbursements for the purchase of supplies, equipment, 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 when incurred. The related costs are recorded as reimbursable expenses when incurred.

Repairs and maintenance

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

Foreign currencies

The Company’s functional currency is the Norwegian krone (NOK) as the majority of revenues are received in NOK and a majority of the Company’s expenditures and financing are in NOK.

Most of the Company’s subsidiaries have functional currency in NOK. For subsidiaries that have functional currencies other than NOK, the Company uses the current method of translation whereby the statements of operations are translated using the average exchange rate for the month and the assets and liabilities are translated using the year end exchange rate. Foreign currency translation gains or losses are recorded as a separate component of other comprehensive income in shareholders’ equity.

Transactions in foreign currencies during the year are translated into functional currency at the specific entity at the rates of exchange in effect at the date of the transaction. Foreign currency monetary assets and liabilities are translated using rates of exchange at the balance sheet date. Foreign currency non-monetary assets and liabilities are translated using historical rates of exchange. Foreign currency transaction gains or losses 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. Receivables and liabilities not maturing within one year are classified as long-term assets and long-term liabilities respectively.

Cash and cash equivalents

Cash and cash equivalents consist of cash, demand deposits and highly liquid financial instruments purchased with maturity of three months or less, and exclude restricted cash.

Restricted cash

Restricted cash consists of bank deposits arising from advance employee tax withholdings.

F-9

Receivables

Receivables, including accounts receivables and unbilled revenue, are recorded in the balance sheet at their full amount less allowance for doubtful receivables. The Company establishes reserves for doubtful receivables on a case-by-case basis. In establishing these reserves, the Company considers changes in the financial position of the customer. Uncollectible trade accounts receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance.

Drilling equipment and other fixed assets

Drilling equipment and other fixed assets 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 drilling equipment ranges from 3 years to 8 years, and 3 years to 10 years for other fixed assets. Seawell evaluates the remaining useful life of its drilling equipment and other fixed assets on a periodic basis to determine whether events and circumstances warrant a revision

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.

Assets under construction

The carrying value of assets under construction (“newbuildings”) represents the accumulated costs at the balance sheet date. Cost components include payments for 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.

Intangible assets

Intangible assets are recorded at historical cost less accumulated amortization. The cost of these assets is amortized on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of the Company’s intangible asset ranges from 4 years to 10 years. Seawell evaluates the remaining useful life of its intangible assets on a periodic basis to determine whether events and circumstances warrant a revision of the remaining amortization period.

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.

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.

F-10

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, 2008, 2009 and 2010, 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.

Impairment of long-lived assets and intangible assets

The carrying values of long-lived assets and intangible 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 disposal. If the 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.

Research and Development

All research and development expenditures are expensed as incurred. In process research and development acquired, that meets the definition of an intangible asset and where fair value can be measured reliably, is immediately expensed for historical acquisitions performed prior to the provisions of SFAS 141R (now ASC 805, ‘Business Combinations’). For acquired in-process R&D in the future, amounts that meet the definition of an intangible asset will be capitalized and amortized.

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.

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 income statement when the net cumulative unrecognized actuarial gains or losses for each individual plan at the end of the previous reporting year exceed 10% of the higher of the present value of the defined benefit obligation and the fair value of plan assets at that date. These gains and losses are recognized over the expected remaining working lives of the employees participating in the plans. Otherwise, recognition of actuarial gains and losses is not recognized in the income statement. On December 31, 2006, the Company adopted amended recognition and disclosures provisions, which requires the recognition of the funded status of the plan in the balance sheet with a corresponding adjustment to accumulated other comprehensive income.  The adjustment to other comprehensive income represents the net unrecognized actuarial losses and unrecognized prior service costs, all of which were previously netted against the plans’ funded status on the balance sheet. These amounts will continue to be 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-11

Income taxes

Seawell Limited is a Bermuda company. Under current Bermuda law, Seawell is not required to pay taxes in Bermuda on either income or capital gains. The Company has received written assurance from the Minister of Finance in Bermuda (the “Minister of Finance”) under the Exempted Undertakings Tax Protection Act 1966 of Bermuda (the “Exempted Undertakings Act”) that, in the event of any such taxes being imposed, the Company will be exempted from taxation until year 2016. The Government of Bermuda has recently amended the Exempted Undertakings Act to extend the period for which the Minister of Finance may grant an assurance from March 28, 2016 to March 31, 2035. The existing assurance received by us remains valid until March 28, 2016; however, we can now apply to the Minister of Finance for an assurance pursuant to the Exempted Undertakings Act lasting until March 31, 2035. We intend to apply to the Minister of Financefor such an extended assurance. Certain of its subsidiaries operate in other jurisdictions where taxes are imposed, mainly Norway and the UK. Consequently income taxes have been provided in respect of taxes in such jurisdictions.

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 estimates of whether additional taxes will 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.

Earnings per share

Basic earnings per share (“EPS”) is calculated based on the income for the period available to common shareholders 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.  The determination of dilutive earnings per share requires the Company to potentially make certain adjustments to net income and to the weighted average shares outstanding used to compute basic earnings per share unless anti-dilutive.

Deferred charges

Loan related costs, including debt arrangement fees, are capitalized and amortized over the tenor of the related loan using the straight-line method, which approximates the interest method. Amortization of loan related costs is included in interest expense.

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 Seawell Limited. In addition, some of the Company’s senior management and directors may also be allocated options to subscribe for new shares in Seadrill Limited.

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.

F-12

Financial Instruments

The Company enters into interest rate swaps in order to manage floating interest rates on debt. The Company’s interest-rate swap agreements are recorded at fair value in the balance sheet. 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 may be designated as a cash flow hedge.

When the interest swap qualifies for hedge accounting, the Company formally designates the swap instrument as a hedge of cash flows to be paid on the underlying loan, and when the hedge is effective, the change in the fair value of the swap for each period is recognized in the “Accumulated other comprehensive loss” line of the Consolidated Balance Sheet. Any ineffective portion of the hedges is charged to the income statement in “Other Financial Items.” Changes in the fair value of interest-rate swaps are otherwise recorded as a gain or loss under “Other Financial Items” in the statement of operations where those hedges are not designated as cash flow hedges.

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.

Inventories

Inventories are stated at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method or the average cost method, which approximates FIFO. Inventory is included within the balance sheet line item “Other current assets.”

Segment reporting

A segment is a distinguishable component of the Company that is engaged in business activities from which it earns revenues and incur expenses whose operating results are regularly reviewed by the chief operating decision maker, in which is subject to risks and rewards that are different from those of other segments. The Company has identified two reportable industry segments; drilling services and well services. The Company provides services geographically to the North Sea (UK, Norwegian and Danish sector) but views this as one geographical area.

Related party transactions

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).

Recently issued accounting pronouncements

In June 2009, the Financial Accounting Standards Board, or FASB, issued amended guidance requiring companies to qualitatively assess the determination of the primary beneficiary of a variable-interest entities (or VIEs) based on whether the entity (1) has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.  It also requires additional disclosures for any enterprise that holds a variable interest in a VIE.  The new accounting and disclosure requirements became effective for us from January 1, 2010.  The adoption of this amended guidance did not have a material effect on our consolidated financial statements.

F-13

In October 2009, the FASB issued authoritative guidance that amends earlier guidance addressing the accounting for contractual arrangements in which an entity provides multiple products or services (deliverables) to a customer.  The amendments address the unit of accounting for arrangements involving multiple deliverables and how arrangement consideration should be allocated to the separate units of accounting, when applicable, by establishing a selling price hierarchy for determining the selling price of a deliverable.  The selling price used for each deliverable will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific nor third-party evidence is available.  The amendments also require that arrangement consideration be allocated at the inception of an arrangement to all deliverables using the relative selling price method.  We will adopt this guidance in the first quarter 2011, and we do not believe that adoption of this guidance will have a material effect on the consolidated financial statements.

In January 2010, the FASB issued authoritative guidance that changes the disclosure requirements for fair value measurements.  Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers.  The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements.  We adopted the guidance in the first quarter 2010, which did not have a material impact on our consolidated financial statements.

In January 2010, the FASB issued authoritative guidance in order to eliminate diversity in the way different enterprises reflect new shares issued as part of a distribution in their calculation of Earnings Per Share (“EPS”). The provisions of this new guidance are effective on a retrospective basis and their adoption had no impact on the Company’s reported EPS.

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

In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements.  Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements.  This guidance was effective immediately and we adopted these new requirements in the first quarter 2010.  The adoption of this guidance did not have an impact on our financial statements.

In July 2010, the FASB issued authoritative guidance which requires expanded disclosures about the credit quality of an entity’s financing receivables and its allowance for credit losses on a disaggregated basis. The adoption of this guidance by the Company with effect from January 1, 2010 did not have any material effect on the Company’s consolidated financial statements.

In December 2010, the FASB issued authoritative guidance which modifies the requirements of step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. The Company will adopt this guidance in the first quarter of fiscal year 2011. The Company does not believe that adoption of this guidance will have a material effect on the Company’s consolidated financial statements.

In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations,to specify that if a company presents comparative financial statements, it should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current period, occurred at the beginning of the comparable prior annual reporting period only. This guidance is effective prospectively for business combinations for which the acquisition date in, on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. We have early adopted the guidance as of January 1, 2010.

F-14

Note 3 – Supplemental Pro Forma Data (Unaudited)

The unaudited pro forma statement of operations data below gives effect to the Gray Wireline acquisition that was completed in 2010 as if it had occurred at the beginning of 2009. The following data includes the amortization of purchased intangible assets and increased depreciation for fixed asset valuation adjustments, along with the tax effect of each of the above. This pro forma data is presented for informational purposes only and does not purport to be indicative of the results of future operations or of the results that would have occurred had the acquisitions taken place at the beginning of 2009.

	Year ended December 31,
	2009	2010
	(NOK in millions, except per share data)
Pro forma net revenue	4,267.2	4,907.9
Pro forma net income (loss)	23.2	(70.5)
Pro forma net income (loss) per share (basic)	0.21	(0.46)
Pro forma net income (loss) per share (diluted)	0.21	(0.45)

Note 4 – Segment information

The Company provides drilling services and well services, including platform drilling, drilling facility engineering, modular rigs, well intervention and oilfield technology to the offshore oil and gas industry. Seawell’s reportable segments consist of the primary services it provides. Although Seawell’s segments are generally influenced by the same economic factors, each represents a distinct service to the oil and gas industry. There have not been any intersegment sales during the periods presented. Segment results are evaluated based on operating income. The accounting principles for the segments are the same as for the Company’s combined and consolidated financial statements. Indirect general and administrative expenses are allocated to each segment based on estimated use.

The split of our organization and aggregation of our business into two segments was based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure. As of December 31, 2010, the Company operated in the following two segments:

· Drilling Services: The Company performs platform drilling, drilling facility engineering and modular rig activities on several fixed installations in the North Sea.

· Well Services: The Company performs various well intervention and oilfield technology services, including but not limited to conveying of logging, perforation, zonal isolation, well clean up, leak detection services and fishing.

Revenues from external customers

(NOK in millions)	2008	2009	2010
Drilling Services	3,053.2	3,199.4	3,577.6
Well Services	571.5	625.4	751.3
Total	3,624.7	3,824.8	4,328.9

Depreciation and amortization

(NOK in millions)	2008	2009	2010
Drilling Services	42.8	53.7	53.6
Well Services	64.6	77.9	82.5
Total	107.4	131.6	136.2

F-15

Operating income (loss) - net income (loss)

(NOK in millions)	2008	2009	2010
Drilling Services	224.7	284.6	282.9
Well Services	81.0	74.7	102.8
Operating income (loss)	305.7	359.3	385.7
Unallocated items:
Total financial items	(162.0)	(124.3)	(219.4)
Income taxes	(24.7)	(60.6)	(92.6)
Non-controlling interest	3.5	1.8	0.4
Net income attributable to the parent (loss)	122.5	176.2	74.1

Total assets

(NOK in millions)		2009	2010
Drilling Services		1,924.5	2,660.2
Well Services		1,415.3	3,062.9
Total	��	3,339.8	5,723.1

Total goodwill

(NOK in millions)	Drilling Services	Well Services	Total
Balance at December 31, 2007	650.1	370.0	1,020.1
Acquisition of Noble Corporation’s North Sea Platform Division	156.5	–	156.5
Acquisition of Peak Well Solutions AS	–	309.4	309.4
Acquisition of TecWel AS	–	119.1	119.1
Balance at December 31, 2008	806.6	798.5	1,605.1
Adjustment of purchase price Peak Well Solutions AS	–	(2.3)	(2.3)
Exchange rate fluctuations on goodwill measured in foreign currency	(13.0)	–	(13.0)
Balance at December 31, 2009	793.6	796.2	1,589.8
Acquisition of RIS and ROMEG	26.9	–	26.9
Final Settlement Peak Well Solutions	–	3.8	3.8
Acquisition of Gray Wireline	–	466.3	466.3
Exchange rate fluctuations on goodwill measured in foreign currency	(3.1)	7.6	4.5
Balance at December 31, 2010	817.4	1,273.9	2,091.3

F-16

Capital expenditures – fixed assets

(NOK in millions)	2008	2009	2010
Drilling Services	207.5	121.2	99.5
Well Services	58.0	74.6	69.0
Total	265.5	195.8	168.5

Geographic information by country

Revenue

(NOK in millions)	2008	2009	2010
Norway	2,599.2	2,745.8	3,198.6
United Kingdom	967.3	930.4	839.3
Other	58.2	148.6	291.0
Total	3,624.7	3,824.8	4,328.9

Long lived assets

(NOK in millions)	2009	2010
Norway	383.2	366.5
United States	8.7	268.1
Bermuda	167.0	184.5
Other	13.0	16.0
Total	571.9	835.1

Note 5 –Other financial items

(NOK in millions)	2008	2009	2010
Foreign exchange differences	(37.9)	(28.4)	(91.1)
Other items	(1.1)	(4.7)	(2.7)
Total other financial items	(39.0)	(33.1)	(93.8)

Note 6 – Taxes

The income taxes consist of the following:

(NOK in millions)	2008	2009	2010
Current tax expense:
Bermuda	–	–	–
Foreign	62.0	71.9	93.4
Deferred tax expense:
Bermuda	–	–	–
Foreign	(37.3)	(11.3)	(0.8)
Total provision	24.7	60.6	92.6

F-17

The income taxes for the period ended December 31, 2010 differed from the amount computed by applying the statutory income tax rate of 0% as follows:

(NOK in millions)	2008	2009	2010
Income taxes at statutory rate	–	–	–
Income taxes related to other countries
Norway	12.3	48.0	74.5
United Kingdom	13.2	11.1	8.5
Other	(0.8)	1.5	9.6
Total	24.7	60.6	92.6

In the consolidated financial statements for 2010 the Company has recognized NOK 4.4 million as general and administrative expenses related to stock options (NOK 7.1 million in 2009), which is not deductible for tax purposes.

The Company’s operations in the United Kingdom, United States, Brazil, Norway, Denmark, Singapore and Australia are taxable.

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:

(NOK in millions)	December 31, 2009	December 31, 2010
Pension	34.9	58.7
Tax loss carry forward	19.5	59.5
Provisions	17.6	19.7
Other	–	–
Gross deferred tax asset	72.0	137.9

The loss of NOK 59.5 million at December 31, 2010 originates in the United States and expires in 20 years.

Deferred Tax Liability:

(NOK in millions)	December 31, 2009	December 31, 2010
Drilling equipment and other fixed assets	4.6	51.2
Deferred tax on excess values	47.3	130.0
Other	3.9	3.8
Gross deferred tax liability	55.8	185.0
Net deferred tax asset/(liability)	16.2	(47.1)

Included in gross deferred tax liability at December 31, 2010 is NOK 130.0 million related to surplus value recognized in the purchase price allocations of purchase of Noble Corporation’s North Sea Platform Division, Peak Well Solutions AS, TecWel AS, Rig Inspection Services Ltd., Romeg Holding Pty. and Gray Wireline Inc.

F-18

Deferred taxes are classified as follows:

(NOK in millions)	December 31, 2009	December 31, 2010
Short-term deferred tax asset	6.9	10.1
Long-term deferred tax asset	9.3	31.5
Short-term deferred tax liability	–	(13.5)
Long-term deferred tax liability	–	(75.2)
Net deferred tax asset	16.2	(47.1)

At December 31, 2010, 2009 and 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. The Company believes that no provision for tax exposures is required.

The parent company, Seawell Limited, is headquartered and incorporated 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
Norway	2009
United Kingdom	2009

Note 7 – Earnings per share

The components of the numerator for the calculation of basic EPS and diluted EPS for net income from continuing operations and net income are shown below.

The components of the denominator for the calculation of basic EPS and diluted EPS are as follows:

	Net income allocated to majority shareholders	Weighted average shares outstanding	Earnings per share (in NOK)
2008
Earnings per share	122.5	107,222,272	1.14
Effect of dilution:
Options, not in the money		–
Diluted earnings per share		107,222,272	1.14

	Net income allocated to majority shareholders	Weighted average shares outstanding	Earnings per share (in NOK)
2009
Earnings per share	176.2	110,000,050	1.60
Effect of dilution:
Options, in the money		567,742
Diluted earnings per share		110,567,792	1.59

	Net income allocated to majority shareholders	Weighted average shares outstanding	Earnings per share (in NOK)
2010
Earnings per share	74.1	152,049,913	0.49

F-19

Effect of dilution:
Options, in the money	3,880,470
Diluted earnings per share	155,930,383	0.47

Note 8 – Restricted cash

Restricted cash of NOK 71.5 million at December 31, 2010 (NOK 51.8 million at December 31, 2009) are bank deposits arising from advance employee tax withholdings.

Note 9 – Receivables, net

Accounts receivables are presented net of allowances for doubtful accounts receivables as follows:

(NOK in millions)	December 31, 2008	December 31, 2009	December 31, 2010
Accounts receivables gross	576.6	554.9	893.7
Allowance for doubtful accounts receivable	5.0	4.5	4.2
Accounts receivables net	571.6	550.4	889.5

Bad debt expense for 2010 and 2009 was NOK 0 million and (0.5) million, respectively.

Note 10 – Other current assets

Other current assets include:

(NOK in millions)	December 31, 2009	December 31, 2010
Unbilled revenue	31.3	64.4
Prepaid expenses	50.3	168.0
Inventory	21.5	0.4
VAT receivable	17.4	23.5
Deferred tax assets	6.9	10.1
Other short term receivables	63.6	112.2
Total other current assets	191.0	378.6

Other short term receivables are interest free.

Note 11 – Equity in net assets of non-controlled investees

At December 31, 2010, the Company had the following participation in investments that are recorded using the equity method:

	2009	2010
C6 Technologies AS	—	50.00%

The carrying amounts of the Company’s investments in its equity method investment as at December 31, 2010 and 2009 are as follows:

(NOK in millions)	2009	2010
	—	30.9

Equity in net assets of non-consolidated investees — 30.9

F-20

The components of equity in net assets of non-consolidated investees are as follows:

(NOK in millions)	2009	2010
Cost	—	32.8
Equity in net earnings of investees	—	(1.9)
Equity in net assets of non-consolidated investees	-	30.9

Quoted market prices for C6 Technologies AS are not available because shares are not publicly traded.

C6/VIT

On April 30, 2010 Seawell announced the acquisition of Viking Intervention Technology AS (VIT). VIT is a company developing an integrated carbon cable intervention system and was acquired for its complimentary product portfolio. In November 2010, Seawell closed an agreement with the IKM Group, pursuant to which IKM Group acquired 50% of the shares in C6 Technologies AS through an equity issue, and C6 Technologies AS simultaneously purchased 100% of the shares in Viking Intervention Technology AS. These transactions were completed under the same terms as the initial share purchase agreement.

Following the loss of control in C6 Technologies AS and Viking Intervention Technology AS, Seawell deconsolidated C6 Technologies AS, and has accounted for the investment in C6 Technologies AS as an investment in associates in the balance sheet as of December 31, 2010.

Note 12 – Drilling equipment and other fixed assets and Assets under construction

The following table discloses cost and accumulated depreciation of the Company’s operating drilling units and other fixed assets:

(NOK in millions)	December 31, 2008	December 31, 2009	December 31, 2010
Drilling equipment:
Cost	570.6	745.1	1,019.8
Accumulated depreciation and amortization	(325.9)	(449.0)	(583.1)
Net book value drilling equipment	244.7	296.1	436.7
Depreciation and amortization for the period	61.4	87.5	86.9

(NOK in millions)	December 31, 2008	December 31, 2009	December 31, 2010
Other fixed assets:
Cost - office equipment, furniture, fittings and motor vehicles	91.8	137.1	358.8
Accumulated depreciation and amortization	(22.5)	(28.3)	(144.9)
Net book value	69.3	108.8	213.9
Depreciation and amortization for the period	15.5	11.2	23.2
Total Drilling equipment and other fixed assets	314.0	404.9	650.6

In February 2008, Seawell ordered a modularized drilling rig (Well Service Unit). The estimated capital expenditure for the unit is EUR 34 million (NOK 265 million).

F-21

(NOK in millions)	December 31, 2008	December 31, 2009	December 31, 2010
Asset under construction – Modular Rig:
Cost	160.2	167.0	184.5
Accumulated depreciation and amortization	-	–	–
Net book value	160.2	167.0	184.5
Depreciation and amortization for the period	–	–	–

Included in capitalized cost of asset under construction are interest expenses and loan related cost of NOK 6.5 million for the year ended December 31, 2010 (NOK 5.3 million for the year ended December 31, 2009 and NOK 2.9 million for the year ended December 31, 2008).

Note 13 – Intangible assets

The following table discloses the Company’s intangible assets:

(NOK in millions)	December 31, 2008	December 31, 2009	December 31, 2010
Intangible assets
Cost	174.9	174.9	396.5
Accumulated depreciation and amortization	(15.7)	(39.2)	(64.9)
Currency adjustments	-	–	12.3
Net book value	159.2	135.7	343.9
Depreciation and amortization for the period	15.7	23.5	25.8

The cost at December 31, 2010 of NOK 396.5 million consists of identified technology of NOK 84.6 million, and customer relationships of NOK 311.9 million (including NOK 221.7 million acquired during the year). The remaining average amortization period as of December 31, 2010 for the intangible assets is 103 months (85 months for technology and 107 months for customer relationship).

Future amortization of intangible assets as of December 31, 2010 is as follows:

(NOK in millions)	2011	2012	2013	2014	2015 and thereafter
Intangible assets
Customer relationship	31.3	23.2	20.5	20.4	109.0
Technology	6.8	6.8	6.8	6.8	19.7
Total intangible amortizations	38.1	30.0	27.3	27.2	128.7

Note 14 - Goodwill

In the years ended December 31, 2010, 2009 and 2008, Seawell acquired several entities which have been consolidated into its financial statement since their acquisitions dates – see Note 22, “Acquisitions and non-controlling interests.” In addition, in the year ended December 31, 2006, Seadrill acquired Smedvig AS. Seawell records the excess of purchase price over the fair value of tangible and identifiable intangible assets acquired as goodwill, which represents primarily intangible assets which are not separately identifiable.

The consolidated financial statements of the Seawell group are based on group carrying values for group consolidation purposes. As such, the consolidated financial statements of the Seawell group include goodwill and excess values related to fixed assets recorded in the Seadrill group consolidated financial statement for the entities included in “Seawell combined.”

F-22

The goodwill in the balance sheet relates to the following transactions:

(NOK in millions)	Total
Seadrill’s acquisition of Smedvig	1,004.9
Net book balance at December 31, 2006	1,004.9
Acquisition of Wellbore Solutions AS	15.2
Net book balance at December 31, 2007	1,020.1
Acquisition of Noble Corporation’s North Sea Platform Division	156.5
Acquisition of Peak Well Solutions AS	309.4
Acquisition of TecWel AS	119.1
Net book balance at December 31, 2008	1,605.2
Adjustment of purchase price Peak Well Solutions AS	(2.3)
Exchange rate fluctuations	(13.0)
Net book balance at December 31, 2009	1,589.8
Final settlement Peak Well Solutions AS	3.8
Acquisition of Rig Inspection Services Ltd. and Romeg Holdings Pte. Ltd.	26.9
Acquisition of Gray Holdco Inc.	466.3
Exchange rate fluctuations	4.5
Net book balance at December 31, 2010	2,091.3

All of the entities have been combined or consolidated into our financial statements since their respective acquisition dates. The acquired entities assets and liabilities were recorded in the consolidated accounts at their fair values on the acquisition date. The purchase price paid in excess of the fair value of the net identifiable assets acquired (excess purchase price) was allocated to goodwill (see Note 22, “Acquisitions and non-controlling interest”). The goodwill is related to human capital and expected future increase in market conditions among others.

We perform 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 budgets and forecasts regularly reviewed by management. For periods after expiry of the contract period, revenue has been forecasted based on conservative assumptions regarding future market conditions. The estimated cash flows have been discounted using a WACC. We had no impairment of goodwill for the years ended December 31, 2010, 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, asset maintenance investment and discount rates, showing an acceptable tolerance to changes in underlying assumptions in the impairment model before changes in assumptions would result in impairment.

The goodwill balance and changes in the carrying amount of goodwill are as follows:

(NOK in millions)	December 31, 2009	December 31, 2010
The aggregated amount of goodwill acquired	1,589.8	2,091.3

F-23

The aggregated amount of impairment losses	—	—
Net book balance at December 31	1,589.8	2,091.3

Note 15 – Operating leases

The Company has signed operating leases for certain premises. The most significant lease agreements are related to offices in Stavanger, Bergen and Aberdeen. Rental expenses amounted to NOK 51.8 million for 2010 (NOK 42.3 million for 2009 and NOK 34.1 million for 2008).

 Estimated future minimum rental payments for the period 2011 to 2015, and thereafter, are as follows:

Year	Amount (NOK in millions)
2011	72.8
2012	62.0
2013	51.7
2014	43.1
2015	40.1
Thereafter	76.2
Total	345.9

Note 16 – Deferred charges

Deferred charges represent debt arrangement fees that are capitalized and amortized to interest expense over the life of the debt instrument. The deferred charges are comprised of the following amounts:

(NOK in millions)	December 31, 2008	December 31, 2009	December 31, 2010
Debt arrangement fees	5.5	5.5	35.7
Accumulated amortization	(1.2)	(2.3)	(1.2)
Total book value	4.3	3.2	34.5

Amortization for the period 1.1 1.1 4.4

In addition, we have charged MNOK 46.1 to the profit and loss statement related to financial support and arrangement fees on funding settled in 2010. See also Note 17, “Long term interest bearing debt and subordinated loan,” for additional information.

Note 17 – Long-term interest bearing debt and subordinated loan

(NOK in millions)	2009	2010
Long-term debt:
MNOK 1,500 Revolving Credit Facility	1,214.1	—
MUSD 550 Multicurrency Term and Revolving Facility	—	1,109.2
Other loans and capital lease liability	34.4	30.6
Subordinated loan from Seadrill Limited	613.6	—
	1,862.1	1,139.8
Less: current portion	(260.8)	(11.0)
Long-term portion of interest bearing debt	1,601.3	1,128.8

The weighted average interest rate for the loans was 4.96% in 2010. In 2009, the weighted average interest rate for the loans was 4.55%. The effective interest rate for the loans was 8.33% in 2010 (this includes costs related to extinguishment loss of NOK 50.5 million).

F-24

On September 7, 2010, Seawell entered into a NOK 1,500 million Revolving Credit Facility Agreement with Fokus Bank, the Norwegian branch of Danske Bank AS, replacing the December 2007 NOK 1,500 million Senior Bank Debt Facility Agreement outstanding as of the second quarter of 2010. The purpose of the Revolving Credit Facilty was to fund general corporate purposes, capital expenditures, working capital and the issuance of guarantees to support contract performance obligations and other operating requirements.

As of the end of the fourth quarter, NOK 1,000 million and EUR 14 million of the facility had been drawn.

On November 11, 2010, Seawell entered into a USD 550 million Multicurrency Term and Revolving Facility Agreement with a syndicate of banks. The purpose of the facility was to replace Seawell’s existing NOK 1,500 million Revolving Credit Facility Agreement entered into on September 7, 2010, to fund general corporate purposes, to partially finance the cash option of Allis-Chalmers’ shareholders if exercised as part of Seawell’s acquisition of Allis-Chalmers and to refinance existing indebtedness of Allis –Chalmers and its subsidiaries.

The USD 550 million facility is divided into three tranches. The first tranche, Tranche A, is for USD 250 million, the second tranche, Tranche B, is for USD 85 million, while the third tranche, Tranche C, is for USD 215 million. The final maturity date of all three tranches is five years from the signing date of the agreement. The interest rate of the tranches is the aggregate of LIBOR, NIBOR or EURIBOR, plus between 2.00% and 3.00% per annum, depending on the ratio of Net Interest Bearing Debt to EBITDA, plus mandatory costs, if any.

The three Tranches made under the USD 550 million Multicurrency Term and Revolving Facility Agreement shall be secured by pledges over shares in Material Subsidiaries, assignments over certain intercompany debt and Guarantees issued by certain Material Subsidiaries.

Repayment of subordinated loan to parent

In August 2010, Seawell completed a private placement of shares, the proceeds of which were used by Seawell to repay the subordinated loan and short term loan to Seadrill Limited.

Seawell’s outstanding debt as of December 31, 2010 is repayable as follows:

(NOK in millions)
Year ending December 31
2011	11.0
2012	8.7
2013	6.2
2014	3.0
2015	1,110.9
Total debt	1,139.8

The Company’s Multicurrency Term and Revolving Facility Agreement contains certain financial covenants, including, among others:

· the Company’s total consolidated Net Interest Bearing Debt shall not exceed 3.0x EBITDA;

· the Company’s minimum ratio of equity to total assets shall equal at least 30.0%; and

· the Company is to maintain the greater of USD 30 million and 5% of Interest Bearing Debt in freely available cash (including undrawn committed credit lines).

The Multicurrency Term and Revolving Facility Agreement contains events of default, which include payment defaults, breach of financial covenants, breach of other obligations, breach of representations and warranties, insolvency, illegality, unenforceability, curtailment of business, claims against an obligor’s assets, appropriation of an obligor’s assets, failure to maintain exchange listing, material adverse effect, repudiation and material litigation.

As of December 31, 2010, the Company was in compliance with all of the covenants under its Multicurrency Term and Revolving Facility Agreement.

Loans made under the Multicurrency Term and Revolving Facility Agreement will be secured by (i) pledges of the Company’s shares in Seawell Norge AS, Seawell AS, Seawell Ltd. UK and Seawell Oil Tools AS; (ii) guarantees provided by these same subsidiaries; and (iii) assignment of various intercompany loans. At December 31, 2010, the assets of these material subsidiaries comprised NOK 3,270.8 million, or 56% of Seawell's total assets.

F-25

Interest rate swap agreement

The Company has entered into an interest rate swap agreement, securing the interest rate on NOK 750 million of the the Company’s interest bearing debt 3.5 years. The agreement was entered into in mid-March 2009, with the commencement of the hedging period and start up of hedging accounting by end of April 2009. The fair value of the swaps as of December 31, 2010 was a liability of NOK 11.1 million (2009: NOK 5.6 million) and is included within other non-current liabilities.

Note 18 – Share capital

	2009		2010
All shares are common shares of par value $2.00 each	Shares	NOK million	Shares	NOK million
Authorized share capital	300,000,000	3,241.0	600,000,000	7,012.8
Issued, outstanding and fully paid share capital	110,000,050	1,198.35	225,400,050	2,622.4

The authorized share capital has been translated at the rate in effect on October 1, 2007, the date of incorporation.

The Company’s shares are traded on the Oslo Börs under the symbol “SEAW”.

The Company was incorporated on August 31, 2007 and 50 ordinary shares of par value $2.00 each were issued. In October 2007, there was one share issue of 80,000,000 shares at NOK 13.75 per share and one issue of 20,000,000 shares at NOK 13.75 per share. At the end of December 2007, a total of 100,000,050 shares of par value $2.00 each were issued and outstanding.

In April 2008, there was an equity issue of 10,000,000 shares at NOK 19.50 per share.

There were no new shares issued in 2009.

In August 2010, Seawell completed a private placement of 115.4 million shares at a share price of NOK 23 per share, amounting to proceeds of NOK 2,627.9 million net of brokers' fees of NOK 26.3 million.

Note 19 – Share option plans

Options on Seawell shares

Seawell has granted options to senior management and directors of the Company, which provide the employee with the right to subscribe for new shares. The options are not transferable and may be withdrawn upon termination of employment under certain conditions. Options granted under the scheme will vest at a date determined by the board of directors. The options granted under the plan to date vest over a period of one to three years.

As of December 31, 2010, there were seven grants under the option programs: one in 2007, two in 2009 and four in 2010.

Accounting for share-based compensation

The fair value of the share options on Seawell shares granted is recognized as personnel expenses. During 2010, NOK 4.4 million was expensed in the income statement (NOK 7.0 million in 2009). There were no effects on taxes in the financial statements. If the option are exercised, social security related to the exercise will be expensed at the exercise date.

F-26

The following summarizes share option transactions related to the Seawell programs in 2008, 2009 and 2010:

	2008		2009		2010
	options	weighted average exercise price (NOK)	options	weighted average  exercise price (NOK)	options	weighted average exercise price (NOK)
Outstanding at beginning of year	4,097,000	13.75	4,097,000	14.58	6,147,000	13.76
Granted	—	—	2,100,000	10.48	460,000	19.30
Forfeited	—	—	(50,000)	14.58	(100,000)	10.00
Outstanding at end of year	4,097,000	14.58	6,147,000	13.76	6,507,000	14.79
Exercisable at end of year	—	—	1,349,000	15.45	3,398,000	15.16

Options issued under the 2007 Program may be exercised up to October 5, 2012. The exercise price is initially NOK 13.75 per share increasing by 6 percent per anniversary. Options issued under the 2007 Program may be exercised by one third per year, first time on January 1, 2009. As at December 31, 2010, two thirds of the options granted under Program 1 are exercisable.

Options issued in 2009 may be exercised up to December 31, 2015. The exercise price is between NOK 10 and NOK 12 per share, and may be exercised one third each year beginning twelve months after they were granted. As at December 31, 2010, one-third of the options granted in 2009 are exercisable.

Options issued in 2010 have exercise prices between NOK 18 and NOK 22. They may be exercised by one third each year beginning twelve months after they were granted, and expire December 31, 2015. As of December 31, 2010, none of the options granted under any of the 2010 Programs are exercisable.

The weighted average grant-date fair value of options granted during 2010 is NOK 7.56 per share (2009: NOK 3.99 per share, 2008: NOK 4.50 per share).

As of December 31, 2010, total unrecognized compensation costs related to all unvested share-based awards totaled NOK 3.2 million, which is expected to be recognized as expenses in 2011, 2012 and 2013 by NOK 2.3 million, NOK 0.7 million and NOK 0.2 million, respectively.

There were 6,507,000 options outstanding at December 31, 2010 (2009: 6,147,000). Their weighted average remaining contractual life are 36 months (2009: 46 months), and their weighted average fair value was NOK 4.56 per option (2009: NOK 4.33 per option). The Company has used the Black & Scholes pricing model in its fair value estimation. The weighted average parameters used in calculating these weighted fair values are as follow: risk-free interest rate 4.8% (2009: 5.0%) volatility 38.7% (2009: 38.6 %), dividend yield 0% (2009: 0%), option holder retirement rate 10% (2009: 10%) and expected term 5.62 years (2009: 5.64 years).

The Company will pay employers' national insurance contributions related to the options, while the option holders will be charged for the individual income taxes.

During 2010, the total intrinsic value of vested Seawell options was NOK 123.8 million (NOK 4.7 million in 2009 and NOK 0 in 2008 as no options were vested in 2008).

Options on Seadrill shares

Some of our senior management and directors also have options in Seadrill Limited. The option agreement provides the option holder with the right to subscribe for new shares in Seadrill Limited. The options are not transferable and may be withdrawn upon termination of employment under certain conditions. The subscription price under the options is fixed at the date of grant.

Accounting for share-based compensation

The fair value of the share options on Seadrill shares is recognized as personnel expenses. During 2010, NOK 0.5 million has been expensed in the income statement, compared to NOK 0.1 million in 2009 and NOK 3.9 million in 2008. There were no effects on taxes in the financial statements, however if the option is exercised, a tax benefit would be recorded as the gains are recorded as deductible for tax purposes. Social security expenses related to the exercise of an option are expensed on the exercise date.

F-27

	2007		2008		2009		2010
	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)	Options	Weighted average exercise price (NOK)
Outstanding as at January 1	860,000	—	706,700	92.34	577,100	99.96	162,100	89.48
Granted	—	—	105,000	132.12	—	—	—	—
Transferred	—	—	—	—	—	—	125,000	89.48
Exercised	(73,300)	88.13	(204,600)	83.74-88.13	(40,000)	88.13	(148,700)	88.13
Forfeited	(80,000)	88.13	(30,000)	88.13	(375,000)	106.33	—	—
Outstanding as at December 31	706,700	92.34	577,100	99.96	162,100	89.48	138,400	90.89
Exercisable as at December 31					162,100	89.48	98,400	90.91

The options under the 2006 Programs may be exercised up to May-September 2011. The exercise price for 2006 Programs 1 to 4 ranges between $2.23 and NOK 102 per share. One third of the options issued under the 2006 Programs may be exercised each year, beginning one year after they were granted. As at December 31, 2010, all of the options granted under 2006 Programs 1-4 are exercisable.

In 2010, 125,000 options under 2006 Program 4 and 2009 Program 7 were transferred from Seadrill to Seawell due to employee transfers. The exercise price for options issued under these programs ranges from NOK 88.12 to NOK 90.83. One third of the options issued under these Programs may be exercised each year, beginning one year after they were granted.  As at December 31, 2010 all of the options under Program 4 are exercisable and one third of the options under Program 7 are exercisable.

The Company has used the Black & Scholes pricing model in its fair value estimation. The weighted average parameters used in calculating these weighted fair values are as follow: risk-free interest rate 4.06% (2009: 4.14%) volatility 36.2% (2009: 34.0 %), dividend yield 0% (2009: 0%), option holder retirement rate 0% (2009: 0%) and expected term 5 years (2009: 4 years).

During 2010, the total intrinsic value of vested Seadrill options at the day of exercise amounted to NOK 14.1 million (MNOK 2.4 million in 2009 and NOK 12.8 million in 2008).

Valuation

For the options plans in both Seawell and Seadrill, the Company uses the Black-Scholes pricing model to value stock options granted. The fair value of options granted is determined based on the expected term, risk-free interest rate, dividend yield and expected volatility. The expected term is based on historical information of past employee behavior regarding exercises and forfeiture of options. The risk-free interest rate assumption is based upon the published Norwegian treasury yield curve in effect at the time of grant for instruments with a similar life. The dividend yield assumption is based on the Company’s history and expectation of dividend payouts.

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.

Note 20 – Pension benefits

The Company has a defined benefit pension plan covering substantially all Norwegian employees as of December 31, 2010. A significant part of this plan is administered by a life insurance company.

F-28

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.

The pension obligations were transferred from the Seadrill group to the Seawell group in connection with the spin-off and transfer of Seadrill Well Service companies from Seadrill in 2007. One pension contract was split between Seadrill and Seawell, as only some of the participants in the pension contract were transferred to Seawell. The obligations related to retired persons as of October 1, 2007 participating in this contract were not transferred and are a Seadrill obligation.

On December 31, 2006, Seawell adopted new recognition and disclosure provisions which require 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 SFAS No. 87, Employers’ Accounting for Pension (“SFAS 87”), 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.

The incremental effect of adopting this new standard on the consolidated balance sheet at December 31, 2006 was an increase in Other non-current liabilities of NOK 26.5 million, an increase in Deferred tax assets of NOK 7.4 million and a decrease in Shareholders equity of NOK 19.1 million. The adoption of the new standard did not affect the consolidated statement of operations for the year ended December 31, 2006, or any prior period presented, and it will not have any affect on our operating results in future periods.

Annual pension cost

(NOK  in millions)	2008	2009	2010
Benefits earned during the year	53.5	50.1	50.0
Interest cost on prior years’ benefit obligation	18.4	25.8	22.2
Gross pension cost for the year	71.9	75.9	72.2
Expected return on plan assets	(12.5)	(18.9)	(18.6)
Administration charges	1.0	1.2	1.5
Net pension cost for the year	60.4	58.2	55.1
Social security cost	8.5	8.2	7.7
Amortization of actuarial gains/losses	(0.6)	(0.8)	(0.2)
Amortization of prior service cost	–	–	(10.6)
Amortization of net transition assets	–	–	(6.9)
Total net pension cost	68.3	65.6	45.0

The funded status of the defined benefit plan

	December 31,
(NOK  in millions)	2008	2009	2010
Projected benefit obligations	445.1	421.9	528.1
Plan assets at market value	(264.1)	(312.7)	(344.5)
Accrued pension liability exclusive social security	181.0	109.2	183.6
Social security related to pension obligations	25.5	15.4	25.9
Accrued pension liabilities	206.5	124.6	209.5

F-29

Change in benefit obligations

(NOK  in millions)	2008	2009	2010
Benefit obligations at beginning of year	349.3	445.1	421.9
Interest cost	18.4	25.8	22.2
Current service cost	53.5	50.1	50.0
Acquisitions	—	—	(9.3)
Benefits paid	(4.3)	(2.8)	(5.2)
Change in unrecognized actuarial gain	28.2	(96.2)	48.5
Benefit obligations at end of year	445.1	421.9	528.1

Change in pension plan assets

(NOK  in millions)	2008	2009	2010
Fair value of plan assets at beginning of year	208.5	264.1	312.7
Estimated return	12.6	18.8	18.6
Contribution by employer	25.4	73.7	44.0
Administration charges	(1.0)	(1.2)	(1.5)
Benefits paid	(1.8)	(2.0)	(2.3)
Change in unrecognized actuarial gain	20.4	(40.7)	(27.1)
Fair value of plan assets at end of year	264.1	312.7	344.5

Pension obligations are actuarially determined and are affected by assumptions including expected return on plan assets, discount rates, compensation increases and employee turnover rates. The Company evaluates the assumptions periodically and makes adjustments to these assumptions and the recorded liabilities as necessary.

Two of the most critical assumptions used in calculating the Company’s pension expense and liabilities are the expected rate of return on plan assets and the assumed discount rate. 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. In determining the discount rate, Seawell utilized the Norwegian government 10 year-bond effective yield plus 0.3-0.5%. 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	2008	2009	2010
Rate of compensation increase at the end of year	4.50%	4.25%	4.00%
Discount rate at the end of year	5.80%	5.40%	4.60%
Prescribed pension index factor	2.50%	2.50%	2.50%
Expected return on plan assets for the year	6.30%	5.60%	5.40%
Turnover	4.00%	4.00%	4.00%
Expected increases in Social Security Base	4.25%	4.00%	3.75%

Expected annual early retirement from age 60/62:

Offshore personnel fixed installations	30.0%	30.0%	30.0%
Offshore personnel and onshore employees	50.0%	50.0%	50.0%

The asset allocation of funds related to the Company’s defined benefit plan at December 31, 2010 was as follows:

Pension benefit plan assets	2008	2009	2010
Equity securities	11.5%	3.8%	15.6%
Debt securities	59.4%	58.7%	49.1%
Real estate	16.8%	16.8%	16.1%

F-30

Money market	8.3%	14.0%	13.2%
Other	4.0%	6.7%	6.0%
Total	100.0%	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 addresses diversification by the use of 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 5.4% in 2010.

Cash flows - Benefits expected to be paid

The table below shows the Company’s expected annual pension plan payments under defined benefit plans for the years 2011-2020. The expected payments are based on the assumptions used to measure the Company’s obligations at December 31, 2010 and include estimated future employee services.

(NOK  in millions)
2011	70.9
2012	78.2
2013	85.5
2014	93.3
2015	100.0
2016-2020	609.1
Total payments expected during the next 10 years	1,037.0

Note 21 – Related party transactions

The Company transacts business with the following related parties, being companies in which our parent company’s principal shareholders Hemen Holding Ltd and Farahead Investments Inc (hereafter jointly referred to as “Hemen”) and companies associated with Hemen have a significant interest:

o Seadrill

o Frontline Management (Bermuda) Limited (“Frontline”)

Seawell was established at the end of the third quarter of 2007, as a spin-off of Seadrill’s Well Service division. Seawell, together with its wholly owned subsidiary Seawell Holding UK, acquired the shares in the Seadrill Well Service division entities on October 1, 2007. The consideration for the shares was NOK 2,413.1 million. The acquisition has been accounted for as a common control transaction with the asset and liabilities acquired recorded by Seawell at historical carrying value of Seadrill. The excess of consideration of the net asset and liabilities acquired has been recorded as adjustment to equity of NOK 1,102.1 million. The Company’s acquisition of companies comprising the previous Seadrill well service division was financed with a subordinated loan from Seadrill. As of December 31, 2010, the subordinated loan was paid off in full. Interest accrued during 2010, 2009 and 2008 was NOK 25.0 million, NOK 32.4 million and NOK 48.9 million, respectively.

As of December 31, 2010, NOK 2.8 million of the current liabilities stated in the balance sheet is related to short term loans to Seadrill (NOK 191.1 million at December 31, 2009). The interest rate on the short term loans is 3 months NIBOR + 1.25% margin, and interest accrued during 2010, 2009 and 2008 was NOK 4.5 million, NOK 6.3 million and  NOK 8.1 million, respectively.

Seadrill Management AS, a company within the Seadrill group charged the Company a fee of NOK 1.6 million for providing management support and administrative services in 2010 (in 2009, the fee charged was NOK 11.3 million and in 2008, the fee charged was NOK 33.0 million). Frontline provides management support and administrative services for the Company, and charged the Company fees of NOK 0.0 million, NOK 0.8 million and NOK 1.0 million for these services in the years 2008, 2009 and 2010, respectively.

F-31

These amounts are included in “General and administrative expenses”, as they do not merit separate disclosure.

Note 22 – Acquisitions and non-controlling interest

Acquisitions in 2008:

Noble North Sea Platform division:

On January 16, 2008, Seawell Limited announced the purchase of Noble Corporation North Sea Platform division (ND UK), by acquiring all shares in Noble Drilling UK Limited. The purchase price was approximately $51 million (NOK 268.4 million).

The acquisition included platform drilling contracts on 11 fixed installations covering five different fields on the UK continental shelf.

The purchase was closed on April 1, 2008, and results of operations are included in the consolidated entity from this date.

Peak Well Solution AS:

On March 25, 2008, Seawell Limited announced the purchase of Peak Well Solutions AS. The purchase price was NOK 412.3 million.

Peak Well Solutions is a Norwegian owned oil service company offering products and services for the upstream offshore oil and gas industry. Peak Well Solutions performs development, engineering, assembly, testing, sales and operations of casing, plugs, and liner technologies and services. The company employs approximately 60 people.

The purchase was closed on May 1, 2008, and results of operations are included in the consolidated entity from this date.

In 2009,  there has been an adjustment of the purchase price of Peak Well Solutions AS of NOK 2.4 million. This brings the total purchase price of Peak Well Solutions AS down to NOK 409.9 million. The reduction has been booked as a reduction in goodwill in the consolidated accounts.

TecWel AS:

On May 27, 2008, Seawell Limited announced the purchase of TecWel AS. TecWel develops and manufactures proprietary high frequency ultrasound investigation tools and provides cased-hole services within production optimization and well integrity to the oil and gas industry world wide.

The purchase was closed on July 1, 2008, and results of operations are included in the consolidated entity from this date. The purchase price was NOK 172.7 million.

In addition the purchase price is subject to two earn out considerations:

· NOK 25 million, related to successfully completing a binding contract for minimum one commercial job based on the well observation tool under development (WPE) before June 30, 2009, and

· Up to NOK 50 million, based on aggregated EBITDA for financial years 2008 and 2009, where aggregated EBITDA on or above NOK 100 million gives a full payment. The payment is reduced on a linear basis down to NOK 0 million for aggregated EBITDA results of NOK 60 million or less.

The earn out considerations is not reflected in the purchase price allocation. The earn out consideration was not achieved, and as such has lapsed.

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The purchase price of these acquisitions have been allocated as follows:

(NOK  in millions)	Noble Drilling UK Ltd	Peak Well Solutions AS	TecWel AS	Total
Current assets
Cash and cash equivalents	-	21.5	6.3	27.8
Accounts receivable	82.2	17.4	14.1	113.7
Other current assets	-	36.6	5.7	42.3
Total current assets	82.2	75.5	26.1	183.8
Non-current assets
Drilling equipment and other fixed asset	-	31.5	19.3	50.8
Other intangible asset	43.3	72.5	57.7	173.5
Goodwill	156.5	307.2	119.1	582.8
Total non-current assets	199.8	411.2	196.1	807.1
Current liabilities
Other current liabilities	1.5	29.6	14.5	45.6
Total current liabilities	1.5	29.6	14.5	45.6
Deferred taxes	12.1	21.0	17.3	50.4
Other non-current liabilities	-	26.2	27.0	53.1
Total non-current liabilities	12.1	47.2	42.3	103.5
IP R&D (expensed to P&L as depreciation and amortization)	-	-	9.3	9.3
Total purchase price (fair value)	268.4	409.9	172.7	851.1

Acquisitions in 2009:

In April 2009, Seawell Limited utilized an option to purchase Sandsliåsen 59 AS, a property company owning Seawell’s engineering base in Bergen, Norway. The purchase price was NOK 33.3 million. Previously Seawell had leased a building owned by Sandsliåsen for 10 years. The transaction was accounted for as a purchase of an asset, and all surplus value was allocated to the property owned.

In July 2010, Seawell completed the sale of Sandsliåsen 59 AS. The net proceeds from the transaction were approximately NOK 51.3 million.  After the sale, Seawell continues to utilize the premises under a 10 year lease and the building continues to house Seawell’s operational support office in Bergen, Norway. The gain of approximately NOK 13.9 million is amortized over the life of the lease.

Acquisitions and divestitures in 2010:

Viking Intervention Technology AS

On April 30, 2010, Seawell announced the acquisition of Viking Intervention Technology AS for a consideration of NOK 50 million. The purchase price has been calculated as NOK 70 million taking into account certain contingent considerations. Viking Intervention Technology is a company developing an integrated carbon cable intervention system and was acquired for its complimentary product portfolio.

Joint Venture with IKM

In November 2010, IKM Group acquired 50% of the shares in Seawell’s subsidiary, C6 Technologies AS, through an equity issue, and C6 Technologies AS simultaneously purchased 100% of the shares in Viking Intervention Technology AS. These transactions were completed under the same terms as the initial share purchase agreement.

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Following the loss of control in C6 Technologies AS and Viking Intervention Technology AS, Seawell deconsolidated C6 Technologies AS, and has accounted for the investment in C6 Technologies AS as an investment in associates in the balance sheet as of December 31, 2010.

Rig Inspection Services Limited and Romeg Holdings Pty.  Ltd

On August 5, 2010, Seawell acquired Rig Inspection Services Limited (“RIS”) and Romeg Holdings Pty. Ltd for a price of NOK 55.3 million, with NOK 20.8 million considered contingent based on financial performance over the next two years. RIS offers specialized industry knowledge and experience with broad inspection expertise. RIS surveyors and inspectors are on call 24 hours a day, seven days a week, specifically to provide a wide range of services within the oil and gas industry, including Rig Acceptance & Safety Surveys, Rig Condition & Benchmark Surveys, Subsea & Surface Well Control Equipment Inspection and Oil Country Tubular Goods (OCTG) services. The addition of RIS to Seawell compliments the Seawell drilling facility engineering capabilities and allows Seawell to offer its clients a very broad range of inspection services on rigs, risers and drilling equipment on a global basis.

Gray Wireline Service, Inc.

On December 16, 2010, Seawell acquired Gray Wireline Service, Inc. for total consideration of NOK 957.1 million. Gray is a provider of a full range of cased-hole wireline services in the Permian basin in Texas and in unconventional plays such as the Barnett, Marcellus, Haynesville, Bakken, Eagle Ford and Woodford oil and natural gas shales, located throughout the U.S. Gray has a total of 110 wireline units and operates in 18 district locations, providing access to approximately 85% of all active U.S. drilling rigs and generating a balanced revenue stream from liquids and gas.

The purchase prices of these acquisitions have been allocated as follows:

(NOK in millions)	Viking Intervention Technology AS	Rig Inspection Services Ltd. and Romeg Holdings Pty.	Gray Wireline Services, Inc.	Total
Current assets
Cash and cash equivalents	0.1	3.6	16.0	19.7
Accounts receivable	2.8	14.8	102.8	120.4
Deferred tax asset	-	-	68.3	68.3
Other current assets	4.8	1.1	21.5	27.4
Total current assets	7.7	19.5	208.6	235.8
Non-current assets
Drilling equipment and other fixed asset	4.7	0.9	259.7	265.3
Other intangible asset	70.1	13.8	208.1	292.0
Goodwill	21.3	26.9	473.9	522.1
Total non-current assets	96.1	41.6	941.7	1,079.4
Current liabilities
Accounts payable	-	3.3	35.5	38.8
Other current liabilities	6.4	2.5	10.5	19.4
Total current liabilities	6.4	5.8	46.0	58.2
Deferred taxes	18.3	-	147.2	165.5
Other non-current liabilities	9.3	-	-	9.3
Total non-current liabilities	27.6	-	147.2	174.8
Total purchase price (fair value)	70.0	55.3	957.1	1,082.4

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Note 23 – Risk management and financial instruments

The majority of the Company’s gross earnings from operations are receivable in Norwegian krone (NOK) and the majority of its other transactions, assets and liabilities are denominated in NOK, the functional currency of the Company. However, the Company has operations and assets in a number of countries worldwide and incurs expenditure in other currencies, causing its results from operations to be affected by fluctuations in currency exchange rates, primarily relative to British pounds. 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 debt denominated in British pounds. 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, and this is managed through the use of interest rate swaps and other derivative arrangements. The Company’s policy is to obtain the most favorable interest rate borrowings available without increasing its foreign currency exposure. Surplus funds are generally placed in fixed deposits with reputable financial institutions, yielding higher returns than are available on cash at bank. Such deposits generally have short-term maturities, in order to provide the Company with flexibility to meet 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, 2010, the Company had outstanding interest rate swap agreements covering NOK 715 million of its NOK interest bearing debt (2009: NOK 750 million), effectively fixing the interest rate on approximately 63% of the debt (2009: 40%). These agreements qualify for hedge accounting, and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Balance Sheet under “Other Comprehensive Income.” The total fair value loss relating to interest rate swaps in 2010 amounted to NOK 5.6 million.

Any change in fair value resulting from hedge ineffectiveness is recognized immediately in earnings. The Company recognized a NOK 3.4 million loss related to the interest swap agreement prior to the start up of the hedging period. Other than this, the Company has not recognized any gain or loss due to hedge ineffectiveness in the consolidated financial statements during the year ended December 31, 2010.

The Company’s interest rate swap agreement as at December 31, 2010, was as follows:

Notional amount	Receive rate	Pay rate	Length of contract
(NOK in millions)
715	3 month NIBOR	3.355%	April 30, 2009 - October 31, 2012

The interest swap agreement is reduced by NOK 225 million on October 31, 2011 and NOK 490 million on October 31, 2012.

The counterparties to the above contract are Fokus Bank. 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.

 Foreign currency risk management

The Company is exposed to foreign currency exchange movements in both transactions that are denominated in currency other than NOK, and in translating consolidated subsidiaries who do not have a functional currency of NOK, which is the presentational currency for the Company. Transaction losses are recognized in Other Financial Items in the period to which they relate. Translation differences are recognized as a component of equity. The total transaction loss relating to foreign exchange movements recognized in the consolidated statement of operations in 2010 amounted to NOK 91.1 million (2009: 34.4 million; 2008:  39.0 million).

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Credit risk

The Company has financial assets, including cash and cash equivalents, other receivables and certain amounts receivable on derivative instruments, mainly 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 is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements. It is the Company’s policy to enter into master netting agreements with the counterparties to derivative financial instrument contracts, which give the Company the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes to the Company.

Fair values

The carrying value and estimated fair value of the Company’s financial instruments at December 31, 2009 and December 31, 2010 are as follows:

	December 31,
	2009		2010
(NOK in millions)	Fair value	Carrying value	Fair value	Carrying value
Non-Derivatives
Cash and cash equivalents	236.7	236.7	1,023.6	1,023..6
Restricted cash	51.8	51.8	71.5	71.5
Current portion of long term floating rate debt	260.8	260.8	11.0	11.0
Long term interest bearing debt	1,601.3	1,601.3	1,128.8	1,128.8
Interest rate swap agreement – long term liability	(5.6)	(5.6)	11.1	11.1

The above financial assets and liabilities are measured at fair value on a recurring basis as follows:

		Fair value measurements at reporting date using
		Quoted Prices in Active Markets for Identical Assets	Significant Other Observable Inputs	Significant Unobservable Inputs
(NOK in millions)	December 31, 2010	(Level 1)	(Level 2)	(Level 3)
Assets:
Cash and cash equivalents	1,023.6	1,023.6
Restricted cash	71.5	71.5
Total assets	1,095.1	1,095.1	—	—
Liabilities:
Current portion of long term debt	11.0	11.0
Long-term portion of floating rate debt	1,128.8	1,128.8
Interest rate swap contracts – long term liability	11.1		11.1
Total liabilities	1,150.9	1,139.8	11.1	—

ASC Topic 820 Fair Value Measurement and Disclosures 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).

F-36

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.

The carrying value of cash and cash equivalents, including restricted cash, which are highly liquid, is a reasonable estimate of fair value.

The fair value of the current portion of long-term debt is estimated to be equal to the carrying value, since it is repayable within twelve months.

The fair value of the long-term portion of floating rate debt is estimated to be equal to the carrying value since it bears variable interest rates, which are reset on a quarterly basis. This debt is not freely tradable and cannot be purchased by the Company at prices other than the outstanding balance plus accrued interest.

The fair value of the subordinated loan is equal to the loan balance plus the fair market value of the interest payable.

The fair values of interest rate swaps are calculated using well-established independent valuation techniques applied to contracted cash flows and LIBOR and NIBOR interest rates as at December 31, 2010.

Retained Risk

Physical Damage Insurance

The Company retains the risk, through self-insurance, for the deductibles relating to physical damage insurance on the Company’s capital equipment, currently a maximum of NOK 0.03 million per occurrence. In the opinion of management, adequate provisions have been made in relation to such exposures, based on known and estimated losses.

Concentration of risk

With respect to credit risk arising from other financial assets of the Seawell group, which comprise cash and cash equivalents and other receivables, the Company’s exposure to credit risk arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments. However, the Company believes this risk is remote as the counterparties are of high credit quality parties.

The following table summarizes revenues from major customers as a percentage of total revenues (revenues in excess of 10 percent for the period):

Customer	2008	2009	2010
StatoilHydro	52%	51%	46%
ConocoPhillips	—	—	16%
Shell	11%	6%	6%
British Petroleum	12%	16%	7%
Customer <10%	25%	27%	25%
Total	100%	100%	100%

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Figures in the table are total operating revenues, and include reimbursables.

The Company has operations and assets in different countries across the world, but the majority in northern Europe. Consequently, the Company’s results from operations are affected by fluctuations in currency exchange rates, primarily relative to the Euro. When the Euro appreciates against other currencies, the Company’s profit from operations in foreign currencies reported in Euro may increase. Likewise, when the Euro depreciates against other currencies, the Company’s profit from operations in foreign currencies reported in Euro may decrease.

The Company is also exposed to changes in interest rates on debt with variable interest rates. In 2009, the Company entered into an interest rate swap agreement, securing the interest rate on NOK 750 million of the Company’s interest bearing debt for 3.5 years.

Before the commencement of the hedging period and start up of hedging accounting, NOK 3.4 million of the difference between fair value and interest swap agreement is recognized in the income statement through other financial items. After commencement of hedging period and start up of hedge accounting NOK 7.7 million in losses related to change in fair value of the interest swap agreement has been recognized as other comprehensive income.

Note 24 – Other current liabilities

Other current liabilities comprise the following:

(NOK in millions)	December 31, 2009	December 31, 2010
Accounts payable	56.5	131.9
Taxes payable	70.2	92.8
Employee withheld taxes, social sec. and vacation payment	206.4	264.1
Accrued expenses and prepaid income	139.3	301.4
Other current liabilities	37.1	165.8
Total other current liabilities	509.5	956.0

Note 25 – Other non-current liabilities

Other non-current liabilities comprise the following:

(NOK in millions)	December 31, 2009	December 31, 2010
Accrued pension and early retirement obligation	124.6	209.5
Other non current liabilities	25.2	68.6
Total other non-current liabilities	149.8	278.1

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Note 26 – Commitments and contingencies

Purchase Commitments

In February 2008, Seawell ordered a modularized drilling rig (Well Service Unit). The estimated capital expenditure for the unit is some EUR 34 million (NOK 265 million) with delivery scheduled in the second half of 2011. As of December 31, 2010, Seawell has paid EUR 17.8 million (NOK 155.8 million) to the builder.

Mortgages and pledged assets

As of December 31, 2010, the Company has a bank loan amounting to NOK 1,139.8 million. The loan is secured in operating cash flows and some of the fixed assets.

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:

(NOK in millions)	December 31, 2009	December 31, 2010
Guarantees to customers of the Company’s own performance	151.8	184.8
Guarantee in favor of banks	47.5	3.0
Other guarantees	2.0	2.0
	201.3	189.8

The guarantees have the following maturities:

Year	(NOK in millions)
2011	-
2012	90.0
2013	-
2014	61.8
2015 and thereafter	38.0
Total	189.8

Legal Proceedings

Other than litigation arising in connection with the merger as described below, neither the Compnay nor any of its subsidiaries is involved in any legal proceedings.

Texas State Court

Beginning on August 16, 2010, seven putative stockholder class action petitions were filed against various combinations of Allis-Chalmers, members of the Allis-Chalmers board of directors, the Company, and Wellco in the District Court of Harris County, Texas, challenging the proposed merger and seeking, among other things, compensatory damages, attorneys’ and experts’ fees, declaratory and injunctive relief concerning the alleged breaches of fiduciary duties and injunctive relief prohibiting the defendants from consummating the merger.

The lawsuits generally allege, among other things, that the Agreement and Plan of Merger, dated as of August 12, 2010, by and among Allis-Chalmers, the Company and Wellco Sub Company (the “Merger Agreement”) was reached through an unfair process and that the consideration upon which the Merger Agreement is premised is inadequate, that the transaction was timed to take advantage of an overall decline in the market price of Allis-Chalmers stock and that the Merger Agreement unfairly caps the price of Allis-Chalmers stock, that the Merger Agreement’s “no shop” provision unreasonably dissuades potential suitors from making competing offers and that the Merger Agreement otherwise unduly restricts Allis-Chalmers from considering competing offers.

F-39

Beginning on August 26, 2010, various plaintiffs in these lawsuits filed competing motions to consolidate the suits, to appoint their counsel as interim class counsel and to compel expedited discovery. On September 16, 2010, the defendants filed joint motions to stay the Texas lawsuits in favor of a first-filed Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set for these motions. The parties to the Texas State Court actions have agreed that the various defendants need not respond to the petitions until after lead counsel is appointed, a consolidated amended petition is filed and served or, alternatively, an active petition is designated by lead counsel.

Delaware Chancery Court

Beginning on August 16, 2010, three putative stockholder class action suits were filed against various combinations of Allis-Chalmers, members of the Allis-Chalmers board of directors, the Company, and Wellco in the Court of Chancery of the State of Delaware, challenging the proposed merger and seeking, among other things, compensatory and rescissory damages, attorneys’ and experts’ fees and injunctive relief concerning the alleged breaches of fiduciary duties and prohibiting the defendants from consummating the merger.

The lawsuits generally allege, among other things, that the Merger Agreement was reached through an unfair process and that the consideration upon which the Merger Agreement is premised is inadequate, that the transaction was timed to take advantage of an overall decline in the market price of Allis-Chalmers stock, that the transaction unfairly favors the Company, that the Merger Agreement’s “no shop” provision unreasonably dissuades potential suitors from making competing offers and that the Merger Agreement otherwise unduly restricts Allis-Chalmers from considering competing offers.

On September 21, 2010, the plaintiffs in the three actions wrote the Court seeking consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position regarding lead plaintiff. On September 29, 2010, the Court granted the Motion to Consolidate. On September 16, 2010, the Company and Wellco answered the first-filed Girard Complaint (designated as the operative complaint post-consolidation). Allis-Chalmers and the members of the Allis-Chalmers board of directors answered the consolidated complaint on October 4, 2010.

On January 26, 2011, plaintiffs in the consolidated Delaware actions filed an Amended Verified Class Action Complaint For Breach Of Fiduciary Duty (the “Amended Complaint”) along with a motion to expedite proceedings.  The Amended Complaint generally alleges, among other things, that the merger agreement was reached through an unfair process and that the consideration upon which the merger agreement is premised is inadequate, that the Allis-Chalmers board failed to inform itself adequately of the highest price reasonably available, that the Allis-Chalmers board was conflicted and thus unable to fulfill its duties, that the transaction was timed to take advantage of an overall decline in the market price of Allis-Chalmers stock, that the transaction unfairly favors the Company, that the merger agreement’s “no solicitation” provision unreasonably dissuades potential suitors from making competing offers, that the merger agreement otherwise unduly restricts Allis Chalmers from considering competing offers and that a voting agreement between the Company and Lime Rock Partners GP V, L.P. improperly restrains Allis-Chalmers from engaging with third parties regarding an alternative proposal. The amended complaint alleges that Allis-Chalmers, the Company, and Wellco aided and abetted the alleged breaches of fiduciary duty.

In addition, the Amended Complaint contains allegations that the Registration Statement filed on Form F-4 filed with the SEC on January 14, 2011, and amended on January 21, 2011, failed to properly disclose all material facts in connection with the proposed merger, in violation of Delaware law.

At a February 3, 2011, hearing Vice Chancellor John W. Noble, of the Delaware Court of Chancery, denied plaintiffs’ motion to expedite proceedings.  On February 9, 2011, the Company filed a motion to dismiss the Amended Complaint under Court of Chancery Rule 12(b)(6) for failure to state a claim upon which relief may be granted.

The Company believes these lawsuits are without merit and intend to defend them vigorously.

The Company is involved in various other legal proceedings, including labor contract litigation, in the ordinary course of business. The legal proceedings are at different stages; however, the Company believes that the likelihood of material loss relating to any such legal proceedings is remote.

F-40

Note 27 – Subsequent Events

Acquisition of Allis- Chalmers Energy Inc.

On August 12, 2010, Seawell announced the approval of a definitive merger agreement with Allis-Chalmers Energy Inc. (“ALY”), a NYSE listed energy company. The transaction involved Seawell’s wholly owned subsidiary, Wellco Sub Company, being the accounting and legal acquirer of ALY. The principal reason for the acquisition was to expand the Company’s drilling services offerings, acquire new rental equipment offerings and to reach new geographic markets.

The preliminary purchase price includes both cash and equity payments to the shareholders of ALY. The acquisition involved Seawell acquiring 100% of the share capital of ALY in exchange for Seawell shares, in a ratio of 1.15 Seawell shares to ALY shares, or a cash settlement of $4.25 per share. Elections from ALY shareholders were finalized on March 4, 2011 and 95.3% of ALY shareholders elected to take Seawell shares in the above ratio, with the remainder receiving cash. The purchase price, which includes an accounting adjustment pertaining to the exchange of ALY share options for options in Seawell, was mNOK 3,375.9 or USD $600.9m.

The Company is however presently unable to disclose the fair value adjustments expected to arise and their effect upon these financial statements as the closing balance sheet valuation and final purchase price allocation exercise is not yet substantially complete.

On March 24, 2011, Allis-Chalmers notified holders of its 9.0% Senior Notes, due 2014, and 8.5% Senior Notes, due 2017 (together, the “Notes”), that a change in control occurred on February 23, 2011 as a result of the merger between the Company and Allis-Chalmers. Pursuant to the terms of the Notes and the notice, holders have the right to require Allis-Chalmers to purchase, on the third business day following the expiration of the offer, all or a portion of such holders’ Notes by way of tendering such Notes  to the depositary and paying agent, Global Bondholder Services Corporation, at a price equal to $1,010 per $1,000 principal amount of the Notes, plus any accrued and unpaid interest and Liquidated Damages (as defined in the indentures governing the Notes), if any, up to but not including the third business day following the expiration of the offer. The aggregate principal amount of the Notes is $430.2 million. Note holders’ opportunity to accept the change in control purchase offer commenced on March 24, 2011, and will terminate at 5:00 p.m., New York City time, on May 17, 2011. Holders may withdraw any previously tendered Notes pursuant to the terms of the change in control purchase offer at any time prior to 5:00 p.m., New York City time, on May 17, 2011.

Acquisition of Universal Wireline

On January 27, 2011, the Company completed the acquisition of Universal Wireline, Inc., or Universal, for total consideration of $25.5 million on a debt-free and cash-free basis. Universal is a provider of a full range of cased-hole wireline services in unconventional plays such as the Barnett, Marcellus, Haynesville, Bakken, Eagle Ford and Woodford shales and in the Permian Basin.

The Universal acquisition contributes 26 wireline units and also expands Seawell’s area of operations. The Company is presently unable to disclose the fair value adjustments expected to arise and their effect upon these financial statements as the closing balance sheet valuation and final purchase price allocation exercise is not yet substantially complete.

Change of name

On February 28, 2011, the Company’s board of directors adopted a resolution to change the name of the Company to “Archer Limited.” The Company expects to adopt the name change in the second quarter of 2011, following approval of the change at a special general meeting of our shareholders on May 16, 2011 and the making of the appropriate filings with the Bermuda Registrar of Companies.

Board restructuring

Pursuant to the merger agreement in connection with the acquisition of ALY, in February 2011, the Company restructured its Board to include 9 members, 4 of which joined pursuant to the acquisition.

F-41

Exhibit No.	Description
1.1	Memorandum of Association of Seawell Limited, dated August 31, 2007, as amended by a Certificate of Deposit of Memorandum of Increase of Share Capital, dated September 25, 2007, and, as further amended by a Certificate of Deposit of Memorandum of Increase of Share Capital, dated October 4, 2010 (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
1.2	Amended and Restated Bye-Laws of Seawell Limited, dated September 18, 2007 (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
2.1	The Bank of New York Mellon Sponsored Share Sale Plan (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.1	Agreement and Plan of Merger, dated as of August 12, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.2	Amendment Agreement, dated as of October 1, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.3	Voting Agreement, dated as of August 12, 2010, between Lime Rock Partners V., L.P. and Seawell Limited (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.4	Revolving Credit Facility Agreement, dated as of September 7, 2010, between Seawell Limited and Fokus Bank (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.5	Multicurrency Term and Revolving Credit Facility Agreement, dated as of November 11, 2010, among Danske Bank AS, DnB NOR Bank AS, Swedbank AB, Nordea Bank Norge ASA and Seawell Limited (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.6	Long-Term Incentive Plan of Seawell Limited, approved by Seawell Limited’s board of directors on September 24, 2010 (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.7	Form of Corporate Administrative Services Agreement between Seawell and Frontline Management (Bermuda) Ltd (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
4.8	Form of General Management Agreement, between Seawell and Seawell Management (Bermuda) Ltd (Incorporated by reference to the Registrant’s Registration Statement on Form F-4 (Registration No. 333-171724), filed with the Commission on January 14, 2011).
8.1	List of Significant Subsidiaries*
11.1	Code of Ethics*
12.1	Certification of CEO Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934*
12.2	Certification of CFO Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934*
13.1	Certification of CEO Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934*
13.2	Certification of CFO Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934*

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*           Filed herewith