Noble Corp - Annual Report: 2010 (Form 10-K)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 000-53604

NOBLE CORPORATION

(Exact name of registrant as specified in its charter)

Switzerland		98-0619597
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)

Dorfstrasse 19A, Baar, Switzerland 6430
(Address of principal executive offices) (Zip Code)

Registrant’s Telephone Number, Including Area Code: 41 (41) 761-65-55

Title of each class		Name of each exchange on which registered
Shares, Par Value 3.80 CHF per Share		New York Stock Exchange

Commission file number: 001-31306

NOBLE CORPORATION

(Exact name of registrant as specified in its charter)

Cayman Islands		98-0366361
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)

Suite 3D Landmark Square, 64 Earth Close, P.O. Box 31327
George Town, Grand Cayman, Cayman Islands KY1-1206
(Address of principal executive offices) (Zip Code)

Registrant’s Telephone Number, Including Area Code: (345) 938-0293

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

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 þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 proceeding 12 months. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Noble-Swiss:		Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o

Noble-Cayman:		Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of June 30, 2010, the aggregate market value of the registered shares of Noble Corporation (Switzerland) held by non-affiliates of the registrant was $7.8 billion based on the closing sale price as reported on the New York Stock Exchange.

Number of shares outstanding and trading at February 14, 2011: Noble Corporation (Switzerland) — 252,336,929.

Number of shares outstanding and trading at February 14, 2011: Noble Corporation (Cayman Islands) — 261,245,693

The proxy statement for the 2011 annual general meeting of the shareholders of Noble Corporation (Switzerland) will be incorporated by reference into Part III of this Form 10-K.

This Form 10-K is a combined annual report being filed separately by two registrants: Noble Corporation, a Swiss corporation (“Noble-Swiss”), and its wholly-owned subsidiary Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Noble-Cayman meets the conditions set forth in General Instructions I (1) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format contemplated by paragraphs (a) and (c) of General Instruction I(2) of Form 10-K.

 

 

TABLE OF CONTENTS

		PAGE
PART I
Item 1. Business			2
Item 1A. Risk Factors			9
Item 1B. Unresolved Staff Comments			17
Item 2. Properties			18
Item 3. Legal Proceedings			22
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			22
Item 6. Selected Financial Data			27
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			50
Item 8. Financial Statements and Supplementary Data			53
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			114
Item 9A. Controls and Procedures			114
Item 9B. Other Information			114
PART III
Item 10. Directors, Executive Officers and Corporate Governance			115
Item 11. Executive Compensation			116
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			116
Item 13. Certain Relationships and Related Transactions, and Director Independence			116
Item 14. Principal Accounting Fees and Services			117
PART IV
Item 15. Exhibits, Financial Statement Schedules			117
SIGNATURES			118
Exhibit 3.1
Exhibit 10.5
Exhibit 10.11
Exhibit 10.16
Exhibit 10.20
Exhibit 10.23
Exhibit 10.24
Exhibit 10.32
Exhibit 21.1
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 31.3
Exhibit 32.1
Exhibit 32.2
Exhibit 32.3
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

This combined Annual Report on Form 10-K is separately filed by Noble Corporation, a Swiss corporation (“Noble-Swiss”), and Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Information in this filing relating to Noble-Cayman is filed by Noble-Swiss and separately by Noble-Cayman on its own behalf. Noble-Cayman makes no representation as to information relating to Noble-Swiss (except as it may relate to Noble-Cayman) or any other affiliate or subsidiary of Noble-Swiss. Since Noble-Cayman meets the conditions specified in General Instructions I(1) to Form 10-K, it is permitted to use the reduced disclosure format for wholly-owned subsidiaries of reporting companies set forth in General Instruction I(2) to Form 10-K.

This report should be read in its entirety as it pertains to each Registrant. Except where indicated, the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements are combined. References in this Annual Report on Form 10-K to “Noble,” the “Company,” “we,” “us,” “our” and words of similar meaning refer collectively to Noble-Swiss and its consolidated subsidiaries, including Noble-Cayman, after March 26, 2009 and to Noble-Cayman and its consolidated subsidiaries for periods through March 26, 2009. Noble-Swiss became a successor registrant to Noble-Cayman under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) pursuant to Rule 12g-3 of the Exchange Act as a result of consummation of the 2009 migration transactions described in Item 1 of Part I of this Annual Report on Form 10-K.

Part I

Item 1.		Business.

General

Noble Corporation, a Swiss corporation, is a leading offshore drilling contractor for the oil and gas industry. We perform contract drilling services with our fleet of 73 mobile offshore drilling units and one floating production storage and offloading unit (“FPSO”) located worldwide. Our fleet consists of 14 semisubmersibles, 12 drillships, 45 jackups and two submersibles. Our fleet includes eight units under construction: two dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillships, two dynamically positioned, ultra-deepwater, harsh environment Bully-class drillships, two heavy-duty, harsh environment jackup rigs announced in December 2010 and two ultra-deepwater drillships announced in January 2011. For additional information on the specifications of the fleet, see “Item 2. Properties. — Drilling Fleet.” As of January 19, 2011, approximately 81 percent of our fleet was located outside the United States in the following areas: Middle East, India, Mexico, the Mediterranean, the North Sea, Brazil, West Africa and Asian Pacific. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.

Acquisition of Frontier Holdings Limited

On July 28, 2010, Noble-Swiss and Noble AM Merger Co., a Cayman Islands company and indirect wholly-owned subsidiary of Noble-Swiss (“Merger Sub”), completed the acquisition of FDR Holdings Limited, a Cayman Islands company (“Frontier”). Under the terms of the Agreement and Plan of Merger with Frontier and certain of Frontier’s shareholders, Merger Sub merged with and into Frontier, with Frontier surviving as an indirect wholly-owned subsidiary of Noble-Swiss and a wholly-owned subsidiary of Noble-Cayman. The Frontier acquisition was for a purchase price of approximately $1.7 billion in cash plus liabilities assumed and strategically expanded and enhanced our global fleet by adding three dynamically positioned drillships (including two Bully-class joint venture-owned drillships under construction), two conventionally moored drillships, including one that is Arctic-class, a conventionally moored deepwater semisubmersible and one dynamically positioned FPSO to our fleet. Frontier’s results of operations were included in our results beginning July 28, 2010. We funded the cash consideration paid at closing of approximately $1.7 billion using proceeds from our July 2010 offering of senior notes and existing cash on hand.

Consummation of 2009 Migration

On March 26, 2009, we completed a series of transactions that effectively changed the place of incorporation of our parent holding company from the Cayman Islands to Switzerland. As a result of these transactions, Noble-Cayman, the previous publicly traded Cayman Islands parent holding company, became a direct, wholly-owned subsidiary of Noble-Swiss, the current parent company. Noble-Swiss’ principal asset is 100 percent of the shares of Noble-Cayman. The consolidated financial statements of Noble-Swiss include the accounts of Noble-Cayman, and Noble-Swiss conducts substantially all of its business through Noble-Cayman and its subsidiaries. In connection with this transaction, we relocated our principal executive offices, executive officers and selected personnel to Geneva, Switzerland.

Business Strategy

Noble’s goal is to be the industry’s preferred drilling contractor based upon the following overarching principles:

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operate in a manner that provides a safe working environment for our employees while protecting the environment and our assets;

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provide an attractive investment vehicle for our shareholders; and

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deliver exceptional customer service via a large, diverse and technically advanced fleet operated by competent personnel.

Our business strategy continues to be the active expansion of our worldwide offshore drilling and deepwater capabilities whereby we move our fleet towards the latest technology while maintaining the highest level of operational integrity with respect to health, safety, and the environment. Historically, we have accomplished this via rig and hull upgrades and modifications, acquisitions, and divestitures of lower specification units. While divestitures of non-competitive assets continue to be a part of the strategy, many of our existing units have been upgraded to their technical limits and our ability to complete acquisitions has been limited by market conditions. As a result, in recent years, we have actively expanded our fleet through the construction of new rigs, including jackups and drillships. In all of our investment decisions we seek to achieve a strong return on capital for the benefit of our shareholders. During 2010, we continued our strategy as indicated by the following activities:

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we completed the acquisition of Frontier, which added a total of five drillships (including two Bully-class joint venture-owned drillships under construction and to be completed in 2011), one semisubmersible and an FPSO to the fleet;

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we completed construction on the Noble Dave Beard, a dynamically positioned ultra-deepwater semisubmersible that left the shipyard during the first quarter of 2010 and began operating under a long-term contract in Brazil;

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we completed construction on the Noble Jim Day, a dynamically positioned ultra-deepwater semisubmersible that left the shipyard during the third quarter of 2010;

•

we continued construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered to our customer in the fourth quarter of 2011;

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we began construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered to our customer in the fourth quarter of 2013; and

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we announced we would construct two high-specification heavy duty, harsh environment jackup rigs, both of which are scheduled to be delivered during 2013.

In addition to the projects listed above, in January 2011, we signed a contract for the construction of two additional newbuild drillships at Hyundai Heavy Industry (“HHI”), increasing the number of floating drilling units in our fleet to 26. The delivered cost of the new ultra-deepwater drillships, to be named at a later date, is expected to be $605 million each, including the turnkey construction contract, Noble-furnished equipment, project management and spares, but excluding capitalized interest. The expected deliveries from the shipyard are the second and fourth quarters of 2013, respectively, after which time the units would be mobilized to their potential drilling locations and undergo customer acceptance testing. We have a letter of intent for one of these units for a five and one-half year contract with a subsidiary of Royal Dutch Shell plc (“Shell”) at a dayrate of $410,000, plus a 15 percent performance bonus opportunity. We have also negotiated options for two additional jackups and two additional HHI drillships.

Excluding the Frontier acquisition, capital expenditures totaled $1.4 billion during 2010.

As of January 31, 2011, shipyards worldwide reportedly had received commitments to construct 55 jackups and 61 deepwater floaters, including our units. These jackups and floaters are expected to be delivered between 2011 and 2014. Of these totals, approximately 21 jackups and 12 floating drilling units have been announced since fourth quarter 2010, signifying that the industry has entered into another new building phase, and more announcements are expected. These totals do not include options for additional units that many companies have negotiated with shipyards and therefore, the number of units which could ultimately come to market could increase significantly. The majority of these jackups and floaters reportedly do not have a contractual commitment from a customer and are being built on speculation without an underlying contract. The introduction of non-contracted rigs into the marketplace will increase the supply of vessels which compete for drilling service contracts, which could negatively impact the dayrates we are able to achieve. Our strategy on new construction has generally been to expand our drilling fleet in connection with a long-term drilling contract that covers a substantial portion of our capital investment and provides an acceptable return on our capital employed. However, with the addition of a significant number of new, technologically advanced units to the global fleet as well as changes in customer requirements and preferences, we believe that in order to maintain the long-term competitiveness of our fleet as well as our significant contract backlog, it has become both necessary and desirable for us to engage in building speculative highly advanced jackups and floating units. Of the units we currently have under construction, one of the ultra-deepwater drillships and both heavy duty, harsh environment jackups are being built on speculation. We will attempt to secure contracts for these units prior to their completion. We may also engage in additional speculative building in the future even in the absence of contracts for units already under construction.

As part of our strategy, we intend to participate in the consolidation of the offshore drilling industry to the extent we believe we can create shareholder value. From time to time, we evaluate other individual rig transactions and business combinations with other parties, and we will continue to consider business opportunities that promote our growth strategy and optimize shareholder value.

In previous years, the drilling industry has experienced significant increases in dayrates for drilling services in most market segments, a tightening market for drilling equipment, and a shortage of personnel. This environment drove operating costs higher and magnified the importance of recruiting, training and retaining skilled personnel. While the global financial turmoil and the governmental actions following the events of the Deepwater Horizon in April 2010 have created an environment of uncertainty and downward pressure on both dayrates and certain types of costs, we are not certain whether this downward pressure will continue in the future.

In recognition of the importance of our offshore operations personnel in achieving a safety record that has consistently outperformed the offshore drilling industry sector and to retain such personnel, we have implemented a number of key operations personnel retention programs. We believe these programs will complement our other short and long-term incentive programs to attract and retain the skilled personnel we need to maintain safe and efficient operations.

Drilling Contracts

We typically employ each drilling unit under an individual contract. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process. Our drilling contracts generally contain the following terms:

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contract duration extending over a specific period of time or a period necessary to drill a defined number wells;

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provisions permitting early termination of the contract by the customer (i) if the unit is lost or destroyed or (ii) if operations are suspended for a specified period of time due to breakdown of equipment;

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provisions allowing the impacted party to terminate the contract if specified “force majeure” events beyond the contracting parties’ control occur for a defined period of time;

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payment of compensation to us (generally in U.S. Dollars although some customers, typically national oil companies, require a part of the compensation to be paid in local currency) on a “daywork” basis, so that we receive a fixed amount for each day (“dayrate”) that the drilling unit is operating under contract (a lower rate or no compensation is payable during periods of equipment breakdown and repair or adverse weather or in the event operations are interrupted by other conditions, some of which may be beyond our control);

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payment by us of the operating expenses of the drilling unit, including labor costs and the cost of incidental supplies; and

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provisions that allow us to recover certain cost increases from certain of our customers.

The terms of some of our drilling contracts permit early termination of the contract by the customer, without cause, generally exercisable upon advance notice to us and in some cases upon the making of an early termination payment to us. Our drilling contracts with Petróleos Mexicanos (“Pemex”) in Mexico, for example, allow early cancellation on 30 days or less notice to us without Pemex making an early termination payment.

Generally, our contracts allow us to recover our mobilization and demobilization costs associated with moving a drilling unit from one regional location to another. When market conditions require us to bear these costs, our operating margins are reduced accordingly. We cannot predict our ability to recover these costs in the future. For shorter moves such as “field moves,” our customers have generally agreed to bear the costs of moving the unit by paying us a reduced dayrate or “move rate” while the unit is being moved.

During times of depressed market conditions, our customers may seek to avoid or reduce their contractual obligations to us under term drilling contracts or letter agreements or letters of intent for drilling contracts. A customer may no longer need a rig due to a reduction in its exploration, development or production program, or it may seek to obtain a comparable rig at a lower dayrate.

For a discussion of our backlog of commitments for contract drilling services, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contract Drilling Services Backlog.”

Offshore Drilling Operations

Contract Drilling Services

We conduct offshore contract drilling operations, which accounted for approximately 99 percent, 99 percent and 98 percent of operating revenues for the years ended December 31, 2010, 2009 and 2008, respectively. We conduct our contract drilling operations principally in the Middle East, India, the U.S. Gulf of Mexico, Mexico, the Mediterranean, the North Sea, Brazil, West Africa and Asian Pacific. Revenues from Pemex accounted for approximately 20 percent, 23 percent and 20 percent of our total operating revenues for the years ended December 31, 2010, 2009 and 2008, respectively. Revenues from Petróleo Brasileiro S.A. (“Petrobras”) accounted for 19 percent of total operating revenue in 2010. Petrobras did not account for more than 10 percent of total operating revenue in 2009 or 2008. Revenues from Shell and its affiliates accounted for 12 percent of total operating revenues during both 2010 and 2009. Shell did not account for more than 10 percent of total operating revenues in 2008. No other single customer accounted for more than 10 percent of our total operating revenues in 2010, 2009 or 2008.

Labor Contracts

We perform services for drilling and workover activities covering two rigs under a labor contract (the “Hibernia Contract”) off the east coast of Canada. We do not own or lease these rigs. Under our labor contracts, we provide the personnel necessary to manage and perform the drilling operations from a drilling platform owned by the operator. The Hibernia Contract extends through January 2013.

Competition

The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and maintenance costs. Some of our competitors may have access to greater financial resources than we do.

In the provision of contract drilling services, competition involves numerous factors, including price, rig availability and suitability, experience of the workforce, efficiency, safety performance record, condition and age of equipment, operating integrity, reputation, industry standing and client relations. We believe that we compete favorably with respect to all of these factors. We follow a policy of keeping our equipment well maintained and technologically competitive. However, our equipment could be made obsolete by the development of new techniques and equipment, regulations or customer preferences.

We compete on a worldwide basis, but competition may vary by region at any particular time. Demand for offshore drilling equipment also depends on the exploration and development programs of oil and gas producers, which in turn are influenced by the financial condition of such producers, by general economic conditions and prices of oil and gas, and by political considerations and policies.

In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business can occur. We cannot assure that any such shortages experienced in the past would not happen again in the future.

Governmental Regulations and Environmental Matters

Political developments and numerous governmental regulations, which may relate directly or indirectly to the contract drilling industry, affect many aspects of our operations. Non-U.S. contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling units, the reduction of greenhouse gas emissions to address climate change, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel and use of local employees and suppliers by foreign contractors. A number of countries actively regulate and control the ownership of concessions and companies holding concessions, the exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government action, including initiatives by the Organization of Petroleum Exporting Countries (“OPEC”), may continue to contribute to oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by oil and gas companies and their need for drilling services and may continue to do so.

The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment or require remediation of contamination under certain circumstances. Many of the other countries in whose waters we operate from time to time also regulate the discharge of oil and other contaminants in connection with drilling operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. We have made and will continue to make expenditures to comply with environmental requirements. To date we have not expended material amounts in order to comply, and we do not believe that our compliance with such requirements will have a material adverse effect upon our results of operations or competitive position or materially increase our capital expenditures. Although these requirements impact the energy and energy services industries, generally they do not appear to affect us in any material respect that is different, or to any materially greater or lesser extent, than other companies in the energy services industry. However, our business and prospects could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts our customers’ exploration and production activities, results in reduced demand for our services or imposes environmental protection requirements that result in increased costs to us, our customers or the oil and natural gas industry in general.

On April 22, 2010, the Nigerian Oil and Gas Industry Content Development Bill was signed into law. The law is designed to create Nigerian content in operations and transactions within the Nigerian oil and gas industry. The law sets forth certain requirements for the utilization of Nigerian human resources and goods and services in oil and gas projects and creates a Nigerian Content Development and Monitoring Board to implement and monitor the law and develop regulations pursuant to the law. The law also establishes a Nigerian Content Development Fund to fund the implementation of the law, and requires that one percent of the value of every contract awarded in the Nigerian oil and gas industry be paid into the fund. We cannot predict what impact the new law may have on our existing or future operations in Nigeria, but the effect on our operations there could be significant.

The following is a summary of some of the existing laws and regulations to which our business operations in the U.S. Gulf of Mexico are subject. However, there are also laws that apply to similar issues in most of the other jurisdictions in which we operate.

Spills and Releases. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws and regulations, impose joint and several liabilities, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” and “operator” of the site where the release occurred, past owners and operators of the site, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” However, we have not to date received notification that we are or may be potentially responsible for cleanup costs under CERCLA.

In addition, the U.S. government has indicated that before any new deepwater drilling resumes, (i) operators must demonstrate that containment resources are available promptly in the event of a deepwater blowout, (ii) the chief executive officer of each operator seeking to perform deepwater drilling must certify that the operator has complied with all applicable regulations and (iii) the Bureau of Ocean Energy Management, Regulation and Enforcement will conduct inspections of each deepwater drilling operation for compliance with the applicable regulations. In addition, regulations regarding blowout preventers are still being developed, but we are proceeding in a manner to help ensure we will be in compliance with any final regulations.

The Oil Pollution Act. The U.S. Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose certain operational requirements on offshore rigs operating in the U.S. Gulf of Mexico and govern liability for leaks, spills and blowouts involving pollutants. The OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities of $350 million, while the liability limit for offshore facilities is equal to all removal costs plus up to $75 million in other damages. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.

Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA, and we believe that compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.

Waste Handling. The U.S. Resource Conservation and Recovery Act (“RCRA”), and analogous state and local laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. However, these wastes may be regulated by the United States Environmental Protection Agency (“EPA”) or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated under RCRA as hazardous waste. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, any repeal or modification of the oil and natural gas exploration and production exemption, or modifications of similar exemptions in analogous state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses with respect to our U.S. operations.

Water Discharges. The U.S. Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and analogous state laws and regulations impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water. We do not anticipate that compliance with these laws will cause a material impact on our operations or financial condition.

Air Emissions. The U.S. Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Except as outlined below regarding climate change issues, we believe that compliance with the Clean Air Act and analogous state laws and regulations will not have a material impact on our operations or financial condition.

Climate Change. There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gas (“GHG”) emissions. On September 22, 2009, the EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule (“Reporting Rule”). The Reporting Rule establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHG’s to inventory and report their GHG emissions annually on a facility-by-facility basis. In addition, on December 15, 2009, the EPA published a Final Rule finding that current and projected concentrations of six key GHG’s in the atmosphere threaten public health and welfare of current and future generations. The EPA also found that the combined emissions of these GHG’s from new motor vehicles and new motor vehicle engines contribute to pollution that threatens public health and welfare. This Final Rule, also known as the EPA’s Endangerment Finding, does not impose any requirements on industry or other entities directly. However, the EPA must now finalize motor vehicle GHG standards, the effect of which could reduce demand for motor fuels refined from crude oil. Finally, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources.

Further, proposed legislation has been introduced in Congress that would establish an economy-wide cap on emissions of GHG’s in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHG’s. Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. While it is not possible at this time to predict how legislation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. Moreover, incentives to conserve energy or use alternative energy sources could have a negative impact on our business if such incentives reduce the worldwide demand for oil and gas.

Safety. The U.S. Occupational Safety and Health Act, or OSHA, and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and analogous state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens. We believe that we are in substantial compliance with these requirements and with other applicable OSHA requirements.

Employees

At December 31, 2010, we had approximately 5,900 employees, including employees engaged through labor contractors or agencies. Approximately 78 percent of our employees were engaged in operations outside of the U.S. and approximately 22 percent were engaged in U.S. operations. We are not a party to any collective bargaining agreements that are material, and we consider our employee relations to be satisfactory.

Financial Information About Segments and Geographic Areas

Information regarding our revenues from external customers, segment profit or loss and total assets attributable to each segment for the last three fiscal years is presented in Note 16 to our consolidated financial statements included in this Annual Report on Form 10-K.

Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operations for the last three fiscal years is presented in Note 16 to our consolidated financial statements included in this Annual Report on Form 10-K.

Available Information

Our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 are available free of charge at our internet website at http://www.noblecorp.com. These filings are also available to the public at the U.S. Securities and Exchange Commission’s (“SEC”) Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC internet website at http://www.sec.gov.

You may also find information related to our corporate governance, board committees and company code of ethics (and any amendments thereto or waivers of compliance therewith) at our website. Among the information you can find there is the following:

	•		Corporate Governance Guidelines;
	•		Audit Committee Charter;
	•		Nominating and Corporate Governance Committee Charter;
	•		Compensation Committee Charter; and
	•		Code of Business Conduct and Ethics.

Item 1A.		Risk Factors.

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could affect our business, operating results and financial condition, as well as affect an investment in our shares.

Risk Factors Relating to Our Business

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

Demand for drilling services depends on a variety of economic and political factors and the level of activity in offshore oil and gas exploration, development and production markets worldwide. Commodity prices, and market expectations of potential changes in these prices, may significantly affect this level of activity. However, higher prices do not necessarily translate into increased drilling activity since our clients’ expectations of future commodity prices typically drive demand for our rigs. Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including:

•

laws and regulations related to environmental or energy security matters, including those addressing alternative energy sources and the risks of global climate change;

•

the political environment of oil-producing regions, including uncertainty or instability resulting from civil disorder, an outbreak or escalation of armed hostilities or acts of war or terrorism;

•

worldwide demand for oil and gas, which is impacted by changes in the rate of economic growth in the U.S. and other non-U.S. economies;

•

the ability of OPEC to set and maintain production levels and pricing;

•

the level of production in non-OPEC countries;

•

the laws and regulations of governments regarding exploration and development of their oil and gas reserves or speculation regarding future laws or regulations;

•

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

•

the discovery rate of new oil and gas reserves;

•

the rate of decline of existing and new oil and gas reserves;

•

available pipeline and other oil and gas transportation capacity;

•

the ability of oil and gas companies to raise capital;

•

adverse weather conditions (such as hurricanes and monsoons) and seas;

•

the development and exploitation of alternative fuels;

•

tax policy;

•

advances in exploration, development and production technology; and

•

availability of, and access to, suitable acreage bearing hydrocarbons for our customers.

Demand for our drilling services may decrease due to events beyond our control and some of our customers could seek to cancel, terminate or renegotiate their contracts.

Our business could be impacted by events beyond our control including changes in our customers’ drilling programs or budgets or their liquidity (including access to capital), changes in, or prolonged reductions of, prices for oil and gas, or shifts in the relative strength of various geographic drilling markets brought on by economic slowdown, or regional or worldwide recession, any of which could result in deterioration in demand for our drilling services. In addition, our customers may cancel drilling contracts or letter agreements or letters of intent for drilling contracts, or exercise early termination rights found in some of our drilling contracts or available under local law, for a variety of reasons, many of which are beyond our control. Depending upon market conditions, our customers may also seek renegotiation of firm drilling contracts to reduce their obligations. If the future level of demand for our drilling services or if future conditions in the offshore contract drilling industry decline, our financial position, results of operations and cash flows could be adversely affected.

We may not be able to renew or replace expiring contracts.

We have a number of contracts that will expire in 2011 and 2012. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions and the condition of our customers. We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the dayrates under any new contracts may be below, perhaps substantially below, the existing dayrates, which could have a material adverse effect on our results of operations and cash flows.

The U.S. governmental, regulatory, and industry response to the Deepwater Horizon drilling rig accident and resulting oil spill has, and could continue to have, a prolonged and material adverse impact on our U.S. Gulf of Mexico operations.

Subsequent to the April 20, 2010 fire and explosion on the Deepwater Horizon, a competitor’s drilling rig in the U.S. Gulf of Mexico, U.S. governmental authorities implemented a moratorium on and suspension of specified types of drilling activities in the U.S. Gulf of Mexico. On October 12, 2010, the U.S. government lifted the moratorium following adoption of new regulations including a drilling safety rule and a workplace safety rule, each of which imposed multiple obligations relating to offshore drilling operations. These obligations relate to, among other things, additional certifications and verifications relating to compliance with applicable regulations; compatibility of blowout preventers with drilling rigs and well design; third-party inspections and design review of blowout preventers; testing of casing installations; minimum requirements for personnel operating blowout preventers; and training in deepwater well control. In January 2011, the government agency charged with reviewing compliance with new regulations determined that it could not yet issue drilling permits under the new regulations.

In addition, the U.S. government has indicated that before any new deepwater drilling resumes, (i) operators must demonstrate that containment resources are available promptly in the event of a deepwater blowout, (ii) the chief executive officer of each operator seeking to perform deepwater drilling must certify that the operator has complied with all applicable regulations and (iii) the Bureau of Ocean Energy Management, Regulation and Enforcement will conduct inspections of each deepwater drilling operation for compliance with the applicable regulations.

There have been and may continue to be judicial and other challenges made with respect to some of the government imposed restrictions on U.S. Gulf of Mexico drilling operations. However, we cannot predict (1) how those challenges will be resolved, (2) how the resolution of those challenges may affect the scope or duration of the government-imposed restrictions or (3) the actions the U.S. government may take, whether in response to those challenges or otherwise. We also cannot predict when the applicable government agency will determine that any deepwater driller is in compliance with the new regulations.

Our existing U.S. Gulf of Mexico operations have been and will continue to be negatively impacted by the events and governmental actions described above. U.S. governmental restrictions and regulations have and may continue to result in a number of our rigs and those of others being moved, or becoming available for moving, to locations outside of the U.S. Gulf of Mexico, which could potentially reduce global dayrates and negatively affect our ability to contract our rigs that are currently uncontracted or coming off contract. In addition, U.S. or other governmental authorities could implement additional regulations concerning licensing, taxation, equipment specifications and training requirements that could increase the costs of our operations. Additionally, increased costs for our customers’ operations, along with permitting delays, could negatively affect the economics of currently planned or future exploration and development activity and result in a reduction in demand for our services. Furthermore, due to the Deepwater Horizon accident and resulting oil spill, insurance costs across the industry could increase, and certain insurance may be less available or not available at all, which could negatively affect us over time.

At this time, we cannot predict for how long or to what extent our operations will be adversely impacted by the governmental, regulatory and industry response to the Deepwater Horizon drilling rig accident and resulting oil spill nor can we predict:

•

the extent of additional or substitute regulations and restrictions that may be imposed on drilling operations in the U.S. Gulf of Mexico;

•

the extent to which drilling operations subsequent to the moratorium period will be impacted or the delay in issuing permits for new or continued drilling;

•

the extent to which customers may seek to terminate existing contracts or the demand by customers for new or renewed drilling contracts;

•

the availability of, or delays in delivery of, equipment required to comply with any new regulations;

•

the effect of the developments described above on demand for our services in the U.S. Gulf of Mexico.

Depending on their duration and extent, these and related developments could continue to have a material adverse effect on our results of operations, cash flows and liquidity relating to the U.S. Gulf of Mexico.

The recent worldwide instability in the financial and credit sectors and economic recession could have a material adverse effect on our financial position, results of operations and cash flows.

The recent worldwide financial and credit situation reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with substantial losses in worldwide equity markets led to a recession in the United States, Europe and Japan. A slowdown in economic activity caused by a worldwide recession, combined with lower prices for oil and gas, reduced worldwide demand for energy and demand for drilling services. If demand for drilling services declines further, we could experience a decline in dayrates for new contracts and a slowing in the pace of new contract activity. Demand for our services depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices. Demand for our services is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies. Any prolonged reduction in oil and natural gas prices or material impairment of our customers’ cash flow or liquidity, including their access to capital, could result in lower levels of exploration, development and production activity. Lower levels of exploration activity could result in a corresponding decline in the demand for our drilling services, which could have a material adverse effect on our financial position, results of operations and cash flows. The financial situation may also adversely affect the ability of shipyards to meet scheduled deliveries of our newbuilds and our ability to renew our fleet through new vessel construction projects and conversion projects.

We are substantially dependent on several of our customers including Shell, Petrobras and Pemex, and the loss of these customers could have a material adverse effect on our financial condition and results of operations.

We estimate Shell and Petrobras represents more than 62 percent and 26 percent, respectively, of our backlog at December 31, 2010 and revenues from Pemex, Petrobras and Shell accounted for 20 percent, 19 percent and 12 percent of our total operating revenues for the year ended December 31, 2010. This concentration of customers increases the risks associated with any possible termination or nonperformance of contracts by either customer in addition to our exposure to credit risk of either customer. If either of these customers were to terminate or fail to perform their obligations under their contracts and we were not able to find other customers for the affected drilling units promptly, our financial condition and results of operations could be materially adversely affected.

Construction, conversion or upgrades of rigs are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.

We currently have significant new construction projects and conversion projects underway and we may undertake additional such projects in the future. In addition, we make significant upgrade, refurbishment and repair expenditures for our fleet from time to time, particularly as our rigs become older. Some of these expenditures are unplanned. These projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:

•

shortages of equipment, materials or skilled labor;

•

work stoppages and labor disputes;

•

unscheduled delays in the delivery of ordered materials and equipment;

•

local customs strikes or related work slowdowns that could delay importation of equipment or materials;

•

weather interferences;

•

difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;

•

design and engineering problems;

•

latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;

•

unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;

•

unanticipated actual or purported change orders;

•

client acceptance delays;

•

disputes with shipyards and suppliers;

•

delays in, or inability to obtain, access to funding;

•

shipyard failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and

•

failure or delay of third-party equipment vendors or service providers.

Failure to complete a rig upgrade or new construction on time, or the inability to complete a rig conversion or new construction in accordance with its design specifications, may, in some circumstances, result in loss of revenues, penalties, or delay, renegotiation or cancellation of a drilling contract or the recognition of an asset impairment. Additionally, capital expenditures for rig upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our rigs undergoing upgrade, refurbishment and repair may not earn a dayrate during the period they are out of service.

We could be adversely affected by violations of applicable anti-corruption laws and our failure to comply with the terms of our settlement agreements with the DOJ and SEC.

We operate in a number of countries throughout the world, including countries known to have a reputation for corruption. We are committed to doing business in accordance with applicable anti-corruption laws and our code of business conduct and ethics. We are subject, however, to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”) and similar laws in other countries. Any violation of the FCPA or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

In 2007, we began an internal investigation of the legality under the FCPA of certain activities in Nigeria. In November 2010, we finalized settlements of this matter with each of the SEC and the DOJ. Under the settlements with the DOJ and SEC, we agreed to, among other things, pay certain fines and interest and disgorge certain profits, cooperate with the DOJ, comply with the FCPA, comply with certain self-reporting and annual reporting obligations and comply with an injunction restraining us from violating the anti-bribery, books and records and internal controls provisions of the FCPA. Our ability to comply with the terms of the settlements is dependent on the success of our ongoing compliance program, including our ability to continue to manage our agents and supervise, train and retain competent employees, and the efforts of our employees to comply with applicable law and our code of business conduct and ethics.

Also, in January 2011, the Nigerian Economic and Financial Crimes Commission and the Nigerian Attorney General Office initiated an investigation into these same activities. A subsidiary of Noble-Swiss resolved this matter through the execution of a non-prosecution agreement dated January 28, 2011. Pursuant to this agreement, the subsidiary paid $2.5 million to resolve all charges and claims of the Nigerian government. Any additional sanctions we may incur as a result of any such investigation could damage our reputation and result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, results of operations or financial condition. Further, resolving any such additional investigations could be expensive and consume significant time and attention of our senior management.

Possible changes in tax laws could affect us and our shareholders.

We are a Swiss company and operate through various subsidiaries in numerous countries throughout the world including the United States. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the U.S., Switzerland or jurisdictions in which we or any of our subsidiaries operate or are resident.

Tax laws and regulations are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, treaties and regulations in and between countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If these laws, treaties or regulations change or if the U.S. Internal Revenue Service or other taxing authorities do not agree with our assessment of the effects of such laws, treaties and regulations, this could have a material adverse effect on us, including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

In addition, the manner in which our shareholders are taxed on distributions on, and dispositions of, our shares could be affected by changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the U.S., Switzerland or other jurisdictions in which our shareholders are resident. Any such changes could affect the trading price of our shares.

Our business involves numerous operating hazards.

Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires and collisions or groundings of offshore equipment, and damage or loss from adverse weather and seas. These hazards could cause personal injury or loss of life, suspend drilling operations or seriously damage or destroy the property and equipment involved, result in claims by employees, customers or third parties and, in addition to causing environmental damage, could cause substantial damage to oil and natural gas producing formations or facilities. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services, or personnel shortages. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to damage claims by oil and gas companies.

The contract drilling industry is a highly competitive and cyclical business with intense price competition. If we are not able to compete successfully, our profitability may be reduced.

The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and maintenance costs. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition, rig availability, location and suitability, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing and client relations are all factors in determining which contractor is awarded a job. Mergers among oil and natural gas exploration and production companies from time to time may reduce the number of available clients, resulting in increased price competition.

Our industry has historically been cyclical. There have been periods of high demand, short rig supply and high dayrates, followed by periods of lower demand, excess rig supply and low dayrates. Periods of excess rig supply intensify the competition in the industry and may result in some of our rigs being idle for long periods of time. Prolonged periods of low utilization and low dayrates could result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

The increase in supply created by the number of rigs being built, as well as changes in our competitors’ drilling rig fleets, could intensify price competition and require higher capital investment to keep our rigs competitive. In addition, the supply attributable to newbuild rigs, especially those being built on speculation, could cause a reduction in future dayrates. In certain markets, for example, we are experiencing competition from newbuild jackups that are scheduled to enter the market in 2011 and beyond. The entry of these newbuild jackups into the market may result in lower marketplace dayrates for jackups. Similarly, there are a number of deepwater newbuilds that are scheduled to enter the market over the next several years, which could also adversely affect the dayrates for these units.

We may have difficulty obtaining or maintaining insurance in the future and we cannot fully insure against all of the risks and hazards we face.

No assurance can be given that we will be able to obtain insurance against all risks or that we will be able to obtain or maintain adequate insurance in the future at rates and with deductibles or retention amounts that we consider commercially reasonable.

The damage sustained to offshore oil and gas assets as a result of hurricanes in 2005 and 2008 caused the insurance market for U.S. named windstorm perils to deteriorate significantly. Consequently, beginning in 2009, we elected to self insure U.S. named windstorm coverage. Currently, our units deployed in the U.S. Gulf of Mexico include eight semisubmersibles, four jackups, two submersibles and one FPSO. We have not yet concluded the March 2011 renewal of our insurance program, but we expect to continue self insuring U.S. named windstorm perils. Our rigs located in the Mexican portion of the Gulf of Mexico remain covered by commercial insurance for windstorm damage up to the declared value of each unit. If one or more future significant weather-related events occur in the Gulf of Mexico, or in any other geographic area in which we operate, we may experience further increases in insurance costs, additional coverage restrictions or unavailability of certain insurance products.

Although we maintain insurance in the geographic areas in which we operate, pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet. Uninsured exposures may include expatriate activities prohibited by U.S. laws and regulations, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position, results of operations or cash flows. Additionally, there can be no assurance that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks.

Governmental laws and regulations, including environmental laws and regulations, may add to our costs or limit our drilling activity.

Our business is affected by public policy and laws and regulations relating to the energy industry and the environment in the geographic areas where we operate.

The drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and accordingly, we are directly affected by the adoption of laws and regulations that for economic, environmental or other policy reasons curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or significantly limit drilling activity. Governments in some foreign countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. Additionally, there is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases. For further discussion, see “Part I, Item 1. Business — Governmental Regulations and Environmental Matters.” The modification of existing laws or regulations or the adoption of new laws or regulations that result in the curtailment of exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs.

Our operations are also subject to numerous laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. As a result, the application of these laws could have a material adverse effect on our results of operations by increasing our cost of doing business, discouraging our customers from drilling for hydrocarbons or subjecting us to liability. For example, we, as an operator of mobile offshore drilling units in navigable U.S. waters and certain offshore areas, including the U.S. Outer Continental Shelf, are liable for damages and for the cost of removing oil spills for which we may be held responsible, subject to certain limitations. Our operations may involve the use or handling of materials that are classified as environmentally hazardous. Laws and regulations protecting the environment have generally become more stringent and in certain circumstances impose “strict liability”, rendering a person liable for environmental damage without regard to negligence or fault. Environmental laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed.

Our global operations involve additional risks.

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

•

terrorist acts, war and civil disturbances;

•

seizure, nationalization or expropriation of property or equipment;

•

monetary policies and foreign currency fluctuations and devaluations;

•

the inability to repatriate income or capital;

•

complications associated with repairing and replacing equipment in remote locations;

•

piracy;

•

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

•

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

•

changing taxation policies.

Our operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:

•

the importing, exporting, equipping and operation of drilling units;

	•		repatriation of foreign earnings;
	•		currency exchange controls;

•

oil and gas exploration and development;

•

taxation of offshore earnings and earnings of expatriate personnel; and

•

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

Our ability to do business in a number of jurisdictions is subject to maintaining required licenses and permits and complying with applicable laws and regulations. We have historically operated our drilling units offshore Nigeria under temporary import permits. We have one jackup rig in Nigeria which is operating under a temporary import permit which expired in November 2008 and we have a pending application to renew this permit. We have received approval from the Nigerian Customs office that we will be allowed to obtain a new temporary import permit for this rig. We recently received a new temporary import permit for another rig in Nigeria that had been waiting for a temporary import permit based on a long-standing application. We continue to seek to avoid material disruption to our Nigerian operations; however, there can be no assurance that we will be able to obtain new permits or further extensions of permits necessary to continue the operation of our rigs in Nigeria. If we cannot obtain a new permit or an extension necessary to continue operations of any rig, we may need to cease operations under the drilling contract for such rig and relocate such rig from Nigerian waters. We cannot predict what impact these events may have on any such contract or our business in Nigeria, and we could face additional fines and sanctions in Nigeria. Furthermore, we cannot predict what changes, if any, relating to temporary import permit policies and procedures may be established or implemented in Nigeria in the future, or how any such changes may impact our business there.

For additional information regarding our internal investigation of our Nigerian operations and the status of our temporary import permits in Nigeria, see “Part II Item 8. Financial Statements and Supplementary Data, Note 14 — Commitments and Contingencies.” Changes in, compliance with, or our failure to comply with the laws and regulations of the countries where we operate, including Nigeria, may negatively impact our operations in those countries and could have a material adverse effect on our results of operations.

The Nigerian Maritime Administration and Safety Agency (“NIMASA”) is seeking to collect a two percent surcharge on contract amounts under contracts performed by “vessels”, within the meaning of Nigeria’s cabotage laws, engaged in the Nigerian coastal shipping trade. We do not believe that our offshore drilling units are engaged in the Nigerian coastal shipping trade nor that our units are “vessels” within the meaning of Nigeria’s cabotage laws. In January 2008 we filed a declaratory judgment action in the Federal High Court of Nigeria seeking relief from NIMASA’s attempt to apply the cabotage laws to our operations. In February 2009, NIMASA filed suit against us in the Federal High Court of Nigeria seeking collection of this surcharge. In August 2009, the court ruled in our favor in our declaratory judgment action. NIMASA has appealed the court’s ruling, but NIMASA’s suit against us was subsequently dismissed. The outcome of any such legal action and the extent to which we may ultimately be responsible for the surcharge is uncertain. We may be required to pay the surcharge and comply with other aspects of the Nigerian cabotage laws, which could adversely affect our operations in Nigerian waters and require us to incur additional costs of compliance. For additional information regarding these actions relating to the application of the cabotage laws, see “Part II, Item 8. Financial Statements and Supplementary Data, Note 14 — Commitments and Contingencies.”

NIMASA has also informed the Nigerian Content Division of its position that we are not in compliance with the cabotage laws. The Nigerian Content Division makes determinations of companies’ compliance with applicable local content regulations for purposes of government contracting, including contracting for services in connection with oil and gas concessions where the Nigerian national oil company is a partner. The Nigerian Content Division had barred us from participating in tenders for new projects as a result of NIMASA’s allegations, but we are currently able to participate based on the court’s ruling in our favor. However, no assurance can be given with respect to our ability to bid for future work in Nigeria until our dispute with NIMASA is resolved.

Governmental action, including initiatives by OPEC, may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.

Failure to attract and retain highly skilled personnel or an increase in personnel costs could hurt our operations.

We require highly skilled personnel to operate and provide technical services and support for our drilling units. As the demand for drilling services and the size of the worldwide industry fleet increases, shortages of qualified personnel have occurred from time to time. These shortages could result in our loss of qualified personnel to competitors, impair our ability to attract and retain qualified personnel for our new or existing drilling units, impair the timeliness and quality of our work and create upward pressure on personnel costs, any of which could adversely affect our operations.

Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.

We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where 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 are subject to litigation that could have an adverse effect on us.

We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, asbestos and other toxic tort claims, environmental claims or proceedings, employment matters, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an adverse effect on us because of potential negative outcomes, costs of attorneys, the allocation of management’s time and attention, and other factors.

Forward-Looking Statements

This report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this report, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will prove to have been correct. We have identified factors that could cause actual plans or results to differ materially from those included in any forward-looking statements. These factors include those described in “Risk Factors” above, or in our other SEC filings, among others. Such risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. You should consider these risks when you are evaluating us.

Item 1B.		Unresolved Staff Comments.

None.

Item 2.		Properties.

Drilling Fleet

Our drilling fleet is composed of the following types of units: semisubmersibles, drillships, jackups and submersibles. Each type of drilling rig is described further below. We also own one FPSO. Several factors determine the type of unit most suitable for a particular job, the most significant of which include the water depth and ocean floor conditions at the proposed drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth.

Semisubmersibles

Semisubmersibles are floating platforms which, by means of a water ballasting system, can be submerged to a predetermined depth so that a substantial portion of the hull is below the water surface during drilling operations. These units maintain their position over the well through the use of either a fixed mooring system or a computer controlled dynamic positioning system and can drill in many areas where jackups cannot drill. However, semisubmersibles normally require water depth of at least 200 feet in order to conduct operations. Our semisubmersibles are capable of drilling in water depths of up to 12,000 feet, depending on the unit. Semisubmersibles are more expensive to construct and operate than jackups.

Our semisubmersible fleet consists of 14 units, including:

•

five units that have been converted to Noble EVA-4000™ semisubmersibles;

•

three Friede & Goldman 9500 Enhanced Pacesetter semisubmersibles;

•

two Pentagone 85 semisubmersibles;

•

two Bingo 9000 design unit submersibles;

•

one Aker H-3 Twin Hull S1289 Column semisubmersible; and

•

one Offshore Co. SCP III Mark 2 semisubmersible.

Drillships

All of our drillships are self-propelled vessels. The dynamically positioned drillships operate through the use of a computer controlled operating system that is used to maintain the vessel’s position. Our conventionally moored drillships drill over the well through a fixed mooring system which keeps the drillship in place over the well. Our drillships vary in maximum drillable water depth ranging from 1,500 to 12,000 feet. The maximum drilling depth of our drillships ranges from 20,000 feet up to 40,000 feet. Like semisubmersibles, drillships are more expensive to construct and operate than standard jackups.

Our drillship fleet consists of 12 units, including:

•

two dynamically positioned harsh environment drillships currently under construction with HHI with scheduled completion dates in the second and fourth quarters of 2013, respectively;

•

two dynamically positioned Globetrotter-class drillships currently under construction with scheduled completion dates of the fourth quarter of 2011 and the third quarter of 2013, respectively;

•

two dynamically positioned Bully-class drillships currently under construction and to be operated by us through a 50 percent joint venture with a subsidiary of Shell with estimated completion dates in the third quarter and fourth quarter of 2011, respectively;

•

one conventionally moored Sonat Discoverer Class drillship capable of drilling in Arctic environments;

•

one dynamically positioned NAM Nedlloyd-C drillship;

•

three dynamically positioned Gusto Engineering Pelican Class drillships; and

•

one conventionally moored conversion class drillship.

Jackups

We currently have 45 jackups in the fleet, including two high-specification heavy duty, harsh environment jackups currently under construction. Jackups are mobile, self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established for support. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. All of our jackups are independent leg (i.e., the legs can be raised or lowered independently of each other) and cantilevered. A cantilevered jackup has a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over pre-existing platforms or structures. Moving a rig to the drill site involves jacking up its legs until the hull is floating on the surface of the water. The hull is then towed to the drill site by tugs and the legs are jacked down to the ocean floor. The jacking operation continues until the hull is raised out of the water, and drilling operations are conducted with the hull in its raised position. Our jackups are capable of drilling to a maximum depth of 30,000 feet in water depths ranging between eight and 400 feet, depending on the jackup.

Submersibles

We have two submersibles in the fleet that are cold-stacked. Submersibles are mobile drilling platforms that are towed to the drill site and submerged to drilling position by flooding the lower hull until it rests on the sea floor, with the upper deck above the water surface. Our submersibles are capable of drilling to a maximum depth of 25,000 feet in water depths ranging between 12 and 70 feet.

Drilling Fleet Table

The following table sets forth certain information concerning our offshore fleet at January 19, 2011. The table does not include any units owned by operators for which we had labor contracts. We operate and own all of the units included in the table.

Water

Drilling

Depth

Depth

Year Built

Rating

Capacity

Name

Make

or Rebuilt (1)

(feet)

(feet)

Location

Status (2)

Semisubmersibles — 14

Noble Amos Runner

Noble EVA-4000™

1999 R/2008 M

8,000

32,500

U.S. Gulf of Mexico

Active

Noble Clyde Boudreaux

F&G 9500 Enhanced Pacesetter

2007 R/M

10,000

35,000

U.S. Gulf of Mexico

Active

Noble Danny Adkins

Bingo 9000 — DP

2009 R

12,000

35,000

U.S. Gulf of Mexico

Active

Noble Dave Beard

F&G 9500 Enhanced Pacesetter — DP

2008 R

10,000

35,000

Brazil

Active

Noble Driller

Aker H-3 Twin Hull S1289 Column

2007 R

5,000

30,000

U.S. Gulf of Mexico

Active

Noble Homer Ferrington

F&G 9500 Enhanced Pacesetter

2004 R

7,200

30,000

Malta

Active

Noble Jim Day

Bingo 9000 — DP

2010 R

12,000

35,000

U.S. Gulf of Mexico

Active

Noble Jim Thompson

Noble EVA-4000™

1999 R/2006 M

6,000

32,500

U.S. Gulf of Mexico

Active

Noble Lorris Bouzigard

Pentagone 85

2003 R

4,000

25,000

U.S. Gulf of Mexico

Active

Noble Max Smith

Noble EVA-4000™

1999 R

7,000

30,000

Mexico

Active

Noble Paul Romano

Noble EVA-4000™

1998 R/2007 M

6,000

32,500

U.S. Gulf of Mexico

Active

Noble Paul Wolff

Noble EVA-4000™ — DP

2006 R

9,200

30,000

Brazil

Active

Noble Therald Martin

Pentagone 85

2004 R

4,000

25,000

Brazil

Active

Noble Ton van Langeveld (3)

Offshore Co. SCP III Mark 2

2000 R

1,500

25,000

U.K.

Active

Drillships — 12

Noble Bully I (3)(6)

GustoMSC Bully PRD 12000

2011 N

8,200

40,000

Singapore

Shipyard

Noble Bully II (3)(6)

GustoMSC Bully PRD 12000

2011 N

8,200

40,000

Singapore

Shipyard

Noble Discoverer (3)

Sonat Discoverer Class

2009 R

2,000

20,000

New Zealand

Active

Noble Duchess

Conversion

1975

1,500

25,000

Nigeria

Active

Noble Globetrotter I (3)

Globetrotter Class

2011 N

10,000

30,000

China

Shipyard

Noble Globetrotter II (3)

Globetrotter Class

2013 N

10,000

30,000

China

Shipyard

Noble Leo Segerius

Gusto Engineering Pelican Class

2002 R

5,600

20,000

Brazil

Active

Noble Muravlenko

Gusto Engineering Pelican Class

1997 R

4,900

20,000

Brazil

Active

Noble Phoenix

Gusto Engineering Pelican Class

2008 R

5,000

25,000

Brunei

Active

Noble Roger Eason

NAM Nedlloyd — C

2005 R

7,200

25,000

Brazil

Active

Noble Newbuild Drillship #1 (3)

Hyundai Gusto P 10000

2013 N

12,000

40,000

South Korea

Shipyard

Noble Newbuild Drillship #2 (3)

Hyundai Gusto P 10000

2013 N

12,000

40,000

South Korea

Shipyard

Independent Leg Cantilevered Jackups — 45 (Continued to next page)

Dhabi II

Baker Marine BMC 150

2006 R

150

20,000

U.A.E.

Active

Noble Al White (3)

CFEM T-2005-C

2005 R

360

30,000

The Netherlands

Active

Noble Alan Hay

Levingston Class 111-C

2005 R

300

25,000

U.A.E.

Active

Noble Bill Jennings

MLT Class 84 — E.R.C.

1997 R

390

25,000

Mexico

Active

Noble Byron Welliver (3)

CFEM T-2005-C

1982

300

30,000

U.K.

Active

Noble Carl Norberg

MLT Class 82-C

2003 R

250

20,000

Mexico

Active

Noble Charles Copeland

MLT Class 82-SD-C

2001 R

280

20,000

U.A.E.

Active

Noble Charlie Yester

MLT Class 116-C

1980

300

25,000

India

Active

Noble Chuck Syring

MLT Class 82-C

1996 R

250

20,000

U.A.E.

Active

Noble David Tinsley

Modec 300C-38

2010 R

300

25,000

U.A.E.

Active

Noble Dick Favor

Baker Marine BMC 150

2004 R

150

20,000

U.A.E.

Active

Noble Don Walker

Baker Marine BMC 150-SD

1992 R

150

20,000

Cameroon

Active

Noble Earl Frederickson

MLT Class 82-SD-C

1999 R

250

20,000

Mexico

Active

Noble Ed Holt

Levingston Class 111-C

2003 R

300

25,000

India

Active

Noble Ed Noble

MLT Class 82-SD-C

2003 R

250

20,000

Nigeria

Active

Noble Eddie Paul

MLT Class 84 — E.R.C.

1995 R

390

25,000

Mexico

Active

Noble Gene House

Modec 300C-38

1998 R

300

25,000

Qatar

Active

Noble Gene Rosser

Levingston Class 111-C

1996 R

300

25,000

Mexico

Active

Noble George McLeod

F&G L-780 MOD II

1995 R

300

25,000

India

Active

Noble George Sauvageau (3)

NAM Nedlloyd-C

1981

250

25,000

The Netherlands

Active

Noble Gus Androes

Levingston Class 111-C

2004 R

300

30,000

Qatar

Active

Noble Hans Deul (3)

F&G JU-2000E

2009 N

400

30,000

The Netherlands

Active

Noble Harvey Duhaney

Levingston Class 111-C

2001 R

300

25,000

Qatar

Active

See footnotes on the following page.

Water

Drilling

Depth

Depth

Year Built

Rating

Capacity

Name

Make

or Rebuilt (1)

(feet)

(feet)

Location

Status (2)

Independent Leg Cantilevered Jackups — 45 (Continued from previous page)

Noble Jimmy Puckett

F&G L-780 MOD II

2002 R

300

25,000

Qatar

Active

Noble Joe Beall

Modec 300C-38

2004 R

300

25,000

Qatar

Active

Noble John Sandifer

Levingston Class 111-C

1995 R

300

25,000

Mexico

Active

Noble Johnnie Hoffman

Baker Marine BMC 300

1993 R

300

25,000

Mexico

Active

Noble Julie Robertson (3) (4)

BMC 300 Harsh Weather Class

2001 R

390

25,000

U.K.

Active

Noble Kenneth Delaney

F&G L-780 MOD II

1998 R

300

25,000

India

Active

Noble Leonard Jones

MLT Class 53 - E.R.C.

1998 R

390

25,000

Mexico

Active

Noble Lewis Dugger

Levingston Class 111-C

1997 R

300

25,000

Mexico

Active

Noble Lloyd Noble

MLT Class 82-SD-C

1990 R

250

20,000

Nigeria

Active

Noble Lynda Bossler (3)

MSC/CJ-46

1982

250

25,000

The Netherlands

Active

Noble Alan Hay

Levingston Class 111-C

2005 R

300

25,000

U.A.E.

Active

Noble Percy Johns

F&G L-780 MOD II

1995 R

300

25,000

Nigeria

Active

Noble Piet van Ede (3)

MSC/CJ-46

1982

250

25,000

The Netherlands

Active

Noble Roger Lewis (3)

F&G JU-2000E

2007

400

30,000

Qatar

Active

Noble Ronald Hoope (3)

MSC/CJ-46

1982

250

25,000

The Netherlands

Active

Noble Roy Butler (5)

F&G L-780 MOD II

1998 R

300

25,000

Mexico

Active

Noble Roy Rhodes

MLT Class 116-C

2009 R

300

25,000

U.A.E.

Active

Noble Sam Noble

Levingston Class 111-C

1982

300

25,000

Mexico

Active

Noble Scott Marks (3)

F&G JU-2000E

2009 N

400

30,000

The Netherlands

Active

Noble Tom Jobe

MLT Class 82-SD-C

1982

250

25,000

Mexico

Active

Noble Tommy Craighead

F&G L-780 MOD II

2003 R

300

25,000

Cameroon

Active

Noble Jackup I- Newbuild (3)

F&G JU-3000N

2013 N

400

30,000

Singapore

Shipyard

Noble Jackup II- Newbuild (3)

F&G JU-3000N

2013 N

400

30,000

Singapore

Shipyard

Submersibles — 2

Noble Joe Alford

Pace Marine 85G

2006 R

70

25,000

U.S. Gulf of Mexico

Stacked

Noble Lester Pettus

Pace Marine 85G

2007 R

70

25,000

U.S. Gulf of Mexico

Stacked

FPSO- 1

Seillean

Harland & Wolf Shipbuilding

2008 R

N/A

N/A

U.S. Gulf of Mexico

Active

Footnotes to Drilling Fleet Table

Facilities

Our corporate office is located in Baar, Switzerland. In addition, we maintain executive offices for executive officers and selected personnel in Geneva, Switzerland. We also maintain office space in Sugar Land, Texas where significant worldwide global support activity occurs. We own and lease administrative and marketing offices, and sites used primarily for storage, maintenance and repairs, and research and development for drilling rigs and equipment in various locations worldwide.

Item 3.		Legal Proceedings.

Information regarding legal proceedings is set forth in Note 14 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.

PART II

Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market for Shares and Related Shareholder Information

Noble-Swiss shares are listed and traded on the New York Stock Exchange under the symbol “NE”. The following table sets forth for the periods indicated the high and low sales prices and dividends or returns of capital declared and paid in U.S. Dollars per share:

										Dividends
										Declared and
		High				Low				Paid
2010
Fourth quarter		$	38.00			$	33.14			$	0.13
Third quarter			35.95				30.36				0.66
Second quarter			43.63				27.04				0.04
First quarter			44.87				38.94				0.05
2009
Fourth quarter		$	44.78			$	36.15			$	0.05
Third quarter			39.39				28.14				0.09
Second quarter			37.03				24.16				—
First quarter			28.48				20.81				0.04

The declaration and payment of dividends or distributions and returns of capital in the future by Noble-Swiss and the making of distributions of capital, including returns of capital in the form of par value reductions, require authorization of the shareholders of Noble-Swiss. The amount of such dividends, distributions and returns of capital will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors and our shareholders.

On February 14, 2011, there were 252,336,929 of our shares outstanding held by 1,598 shareholder accounts of record.

Swiss Tax Consequences to Shareholders of Noble

The tax consequences discussed below are not a complete analysis or listing of all the possible tax consequences that may be relevant to shareholders of Noble. Shareholders should consult their own tax advisors in respect of the tax consequences related to receipt, ownership, purchase or sale or other disposition of our shares and the procedures for claiming a refund of withholding tax.

Swiss Income Tax on Dividends and Similar Distributions

A non-Swiss holder will not be subject to Swiss income taxes on dividend income and similar distributions in respect of our shares, unless the shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder. However, dividends and similar distributions are subject to Swiss withholding tax. See “—Swiss Withholding Tax—Distributions to Shareholders.”

Swiss Wealth Tax

A non-Swiss holder will not be subject to Swiss wealth taxes unless the holder’s shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder.

Swiss Capital Gains Tax upon Disposal of Shares

A non-Swiss holder will not be subject to Swiss income taxes for capital gains unless the holder’s shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder. In such case, the non-Swiss holder is required to recognize capital gains or losses on the sale of such shares, which will be subject to cantonal, communal and federal income tax.

Swiss Withholding Tax—Dividends to Shareholders

A Swiss withholding tax of 35 percent is due on dividends to our shareholders from us, regardless of the place of residency of the shareholder (subject to the exceptions discussed under “—Exemption from Swiss Withholding Tax—Distributions to Shareholders” below). We will be required to withhold at such rate and remit on a net basis any payments made to a holder of our shares and pay such withheld amounts to the Swiss federal tax authorities. Please see “—Refund of Swiss Withholding Tax on Dividends and Other Distributions.”

Exemption from Swiss Withholding Tax—Distributions to Shareholders

Under present Swiss tax law, distributions to shareholders in relation to a reduction of par value are exempt from Swiss withholding tax. Since January 1, 2011, distributions to shareholders out of qualifying additional paid-in capital for Swiss statutory purposes are exempt from the Swiss withholding tax. Consequently, we expect that a substantial amount of any potential future distributions, whether distributed as a reduction of par value or directly out of qualifying additional paid-in capital may be exempt from Swiss withholding tax.

Repurchases of Shares

Under present Swiss tax law, repurchases of shares for the purposes of capital reduction are treated as a partial liquidation subject to the 35 percent Swiss withholding tax. However, for shares repurchased for capital reduction, the portion of the repurchase price attributable to the par value of the shares repurchased will not be subject to the Swiss withholding tax. Since January 1, 2011, the portion of the repurchase price attributable to the qualifying additional paid-in capital for Swiss statutory reporting purposes of the shares repurchased will also not be subject to the Swiss withholding tax. We would be required to withhold at such rate the tax from the difference between the repurchase price and the related amount of par value and the related amount of qualifying additional paid-in capital. We would be required to remit on a net basis the purchase price with the Swiss withholding tax deducted to a holder of our shares and pay the withholding tax to the Swiss federal tax authorities.

With respect to the refund of Swiss withholding tax from the repurchase of shares, see “—Refund of Swiss Withholding Tax on Dividends and Other Distributions” below.

In most instances, Swiss companies listed on the SIX Swiss Exchange (“SIX”), carry out share repurchase programs through a “second trading line” on the SIX. Swiss institutional investors typically purchase shares from shareholders on the open market and then sell the shares on the second trading line back to the company. The Swiss institutional investors are generally able to receive a full refund of the withholding tax. Due to, among other things, the time delay between the sale to the company and the institutional investors’ receipt of the refund, the price companies pay to repurchase their shares has historically been slightly higher (but less than one percent) than the price of such companies’ shares in ordinary trading on the SIX first trading line.

We do not expect to be able to use the SIX second trading line process to repurchase our shares because we do not currently intend to list our shares on the SIX. However, we have in the past and intend to continue to follow an alternative process whereby we expect to be able to repurchase our shares in a manner that should allow Swiss institutional market participants selling the shares to us to receive a refund of the Swiss withholding tax and, therefore, accomplish the same purpose as share repurchases on the second trading line at substantially the same cost to us and such market participants as share repurchases on a second trading line.

The repurchase of shares for purposes other than capital reduction, such as to retain as treasury shares for use in connection with stock incentive plans, convertible debt or other instruments within certain periods, will generally not be subject to Swiss withholding tax.

Refund of Swiss Withholding Tax on Dividends and Other Distributions

Swiss holders — A Swiss tax resident, corporate or individual, can recover the withholding tax in full if such resident is the beneficial owner of our shares at the time the dividend or other distribution becomes due and provided that such resident reports the gross distribution received on such resident’s income tax return, or in the case of an entity, includes the taxable income in such resident’s income statement.

Non-Swiss holders — If the shareholder that receives a distribution from us is not a Swiss tax resident, does not hold our shares in connection with a permanent establishment or a fixed place of business maintained in Switzerland, and resides in a country that has concluded a treaty for the avoidance of double taxation with Switzerland for which the conditions for the application and protection of and by the treaty are met, then the shareholder may be entitled to a full or partial refund of the withholding tax described above. The procedures for claiming treaty refunds (and the time frame required for obtaining a refund) may differ from country to country.

Switzerland has entered into bilateral treaties for the avoidance of double taxation with respect to income taxes with numerous countries, including the U.S., whereby under certain circumstances all or part of the withholding tax may be refunded.

U.S. residents — The Swiss-U.S. tax treaty provides that U.S. residents eligible for benefits under the treaty can seek a refund of the Swiss withholding tax on dividends for the portion exceeding 15 percent (leading to a refund of 20 percent) or a full refund in the case of qualified pension funds.

As a general rule, the refund will be granted under the treaty if the U.S. resident can show evidence of:

•

beneficial ownership,

•

U.S. residency, and

•

meeting the U.S.-Swiss tax treaty’s limitation on benefits requirements.

The claim for refund must be filed with the Swiss federal tax authorities (Eigerstrasse 65, 3003 Berne, Switzerland), no later than December 31 of the third year following the year in which the dividend payments became due. The relevant Swiss tax form is Form 82C for companies, 82E for other entities and 82I for individuals. These forms can be obtained from any Swiss Consulate General in the U.S. or from the Swiss federal tax authorities at the address mentioned above or at www.estv.admin.ch (English, Anticipatory Tax, Services, Domicile abroad). Each form needs to be filled out in triplicate, with each copy duly completed and signed before a notary public in the U.S. Evidence that the withholding tax was withheld at the source must also be included.

Stamp duties in relation to the transfer of shares — The purchase or sale of our shares may be subject to Swiss federal stamp taxes on the transfer of securities irrespective of the place of residency of the purchaser or seller if the transaction takes place through or with a Swiss bank or other Swiss securities dealer, as those terms are defined in the Swiss Federal Stamp Tax Act and no exemption applies in the specific case. If a purchase or sale is not entered into through or with a Swiss bank or other Swiss securities dealer, then no stamp tax will be due. The applicable stamp tax rate is 0.075 percent for each of the two parties to a transaction and is calculated based on the purchase price or sale proceeds. If the transaction does not involve cash consideration, the transfer stamp duty is computed on the basis of the market value of the consideration.

Purchases of Shares

The following table sets forth for the periods indicated certain information with respect to repurchases by Noble-Swiss of its shares:

										Total Number of				Maximum Number
										Shares Purchased				of Shares that May
		Total Number				Average				as Part of Publicly				Yet Be Purchased
		of Shares				Price Paid				Announced Plans				Under the Plans
Period		Purchased				per Share				or Programs				or Programs (1)
October 2010			—			$	0.00				—				6,769,891
November 2010			174			$	34.18	(2)			—				6,769,891
December 2010			4,240			$	34.95	(3)			—				6,769,891

Stock Performance Graph

This graph shows the cumulative total shareholder return of our shares over the five-year period from January 1, 2006 to December 31, 2010. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and the Dow Jones U.S. Oil Equipment & Services Index. The graph assumes that $100 was invested in our shares and the two indices on January 1, 2006 and that all dividends or distributions and returns of capital were reinvested on the date of payment.

		INDEXED RETURNS
		Year Ended December 31,
Company Name / Index		2006				2007				2008				2009				2010
Noble Corporation		$	108.20			$	161.00			$	64.01			$	118.59			$	107.14
S&P 500 Index			115.79				122.16				76.96				97.33				111.99
Dow Jones U.S. Oil Equipment & Services			113.47				164.47				66.94				110.56				140.78

Investors are cautioned against drawing any conclusions from the data contained in the graph, as past results are not necessarily indicative of future performance.

The above graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

Item 6.		Selected Financial Data.

The following table sets forth selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2010, which information is derived from our audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in our financial statements included in Item 8 of this Annual Report on Form 10-K.

		Year Ended December 31,
		2010				2009				2008				2007				2006
		(In thousands, except per share amounts)
Statement of Income Data
Operating revenues		$	2,807,176			$	3,640,784			$	3,446,501			$	2,995,311			$	2,100,239
Net income attributable to Noble Corporation			773,429				1,678,642				1,560,995				1,206,011				731,866
Net income per share:
Basic			3.03				6.44				5.85				4.49				2.68
Diluted			3.02				6.42				5.81				4.45				2.65
Balance Sheet Data (at end of period)
Cash and marketable securities		$	337,871			$	735,493			$	513,311			$	161,058			$	61,710
Property and equipment, net			10,048,087				6,634,452				5,647,017				4,795,916				3,858,393
Total assets			11,221,321				8,396,896				7,106,799				5,876,006				4,585,914
Long-term debt			2,686,484				750,946				750,789				774,182				684,469
Total debt (1)			2,766,697				750,946				923,487				784,516				694,098
Total equity			7,287,634				6,788,432				5,290,715				4,308,322				3,228,993
Other Data
Net cash from operating activities		$	1,654,376			$	2,136,716			$	1,888,192			$	1,414,373			$	988,715
Net cash from investing activities			(2,913,943	)			(1,495,059	)			(1,129,293	)			(1,223,873	)			(349,910	)
Net cash from financing activities			861,945				(419,475	)			(406,646	)			(91,152	)			(698,940	)
Capital expenditures			1,423,484				1,431,498				1,231,321				1,287,043				1,122,061
Working capital			110,347				1,049,243				561,348				367,419				143,720
Cash dividends/par value reduction declared per share (2) (3)			0.88				0.18				0.91				0.12				0.08

Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion is intended to assist you in understanding our financial position at December 31, 2010 and 2009, and our results of operations for each of the years in the three-year period ended December 31, 2010. You should read the accompanying consolidated financial statements and related notes in conjunction with this discussion.

Executive Overview

Our 2010 financial and operating results include:

•

operating revenues totaling $2.8 billion;

•

net income of $773 million or $3.02 per diluted share;

•

net cash from operating activities totaling $1.7 billion; and

•

an increase in debt to 27.5 percent of total capitalization at the end of 2010, up from 10.0 percent at the end of 2009 due to the issuance of $1.25 billion in debt and the assumption of $689 million in consolidated joint venture debt to fund the acquisition of Frontier.

The overall offshore drilling market has been challenging since the events occurring in connection with the Deepwater Horizon and the U.S. governmental response to the incident. Despite the lifting of the moratorium and publication of new safety rules, we are unable to predict when normal drilling operations will resume in the U.S. Gulf of Mexico and we believe it is unlikely that we will see significant activity in the U.S. Gulf of Mexico for some time as indicated by the difficulties surrounding the issuance of new drilling permits. Outside of the U.S. Gulf of Mexico, demand has been fairly steady, but well below the previous peak levels of 2008. We believe the risk for early contract terminations or defaults under existing contracts has decreased and the overall future market for offshore drilling activity is positive.

Despite improvements in the economy, there is still uncertainty regarding the sustainability of the global economic recovery, which is proceeding unevenly in different geographic regions. In addition, there is still uncertainty regarding the sustainability of the recovery of the global financial markets highlighted by issues in the credit markets. During 2010, oil prices increased fifteen percent while U.S. natural gas prices decreased almost twenty percent. While we believe that this improvement in oil prices will result in increased drilling activity in 2011, we continue to anticipate volatility in our industry for the foreseeable future.

Despite the increase in commodity prices, we have not seen a significant increase in demand for offshore drilling services. Developments in the U.S. Gulf of Mexico will continue to have an impact on the deepwater market segment in the short-term, however, we believe that the long-term outlook is stronger. Market dayrates for new ultra-deepwater units remain generally above $400,000, which is a significantly lower than the rates in 2007-2008. Demand in the jackup segment increased during 2010 and utilization for units operating outside the U.S. Gulf of Mexico was approximately 80 percent. We did not operate any jackups in the U.S. Gulf of Mexico in 2010. During 2010, we started to see differentiation in the jackup market segment with newer units having utilization rates exceeding 90 percent, while units that entered service before 2000 having utilization rates closer to 70 percent. Likewise, there has been a bifurcation of dayrates between older and newer units in the jackup market with new units earning a premium. Dayrates for both older and newer units have been relatively stable over the second half of 2010, but significantly lower than the highs reached during 2007 and 2008.

Demand for our drilling services generally depends on a variety of economic and political factors, including worldwide demand for oil and gas, the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and pricing, the level of production of non-OPEC countries and the policies of various governments regarding exploration and development of their oil and gas reserves. Our results of operations depend on offshore drilling activity worldwide. Historically, oil and gas prices and market expectations of potential changes in these prices have significantly affected that level of activity. Generally, higher oil and natural gas prices or our customers’ expectations of higher prices result in greater demand for our services and lower oil and gas prices result in reduced demand for our services. Demand for our services is also a function of the worldwide supply of mobile offshore drilling units. Industry sources report that a total of 55 newbuild jackups and 61 deepwater newbuilds are planned or under construction with scheduled delivery dates in 2011 and beyond. Industry analysts have predicted that a new wave of speculative building of both jackups and ultra-deepwater units has commenced. The introduction of additional non-contracted rigs into the marketplace could have an adverse effect on demand for our services or the dayrates we are able to achieve.

In addition, as a result of exploration discoveries offshore Brazil, Petrobras, the Brazilian national oil company, announced a plan to construct up to 28 deepwater rigs in Brazil and recently accepted bids to construct these units from a number of shipyards and drilling contractors. Petrobras originally declared its intention to finance and own the first nine of these additional rigs. Petrobras also stated that they would seek long-term contracts for the remaining 19 rigs to support construction and to allow drilling contractors to bid for the opportunity to supply up to four rigs per contractor. During 2010, shipyards and Brazilian contractors submitted bids to build deepwater rigs for Petrobras. A deepwater drilling rig construction industry does not currently exist in Brazil and Noble did not participate in these bids primarily because we felt the capital risk associated with constructing a unit in Brazil at this time was inappropriate. On February 11, 2011, media reported that Petrobras had awarded the first tranche of seven drillships to a Brazilian shipyard for delivery beginning in 2015. The future of Petrobras’ building program remains uncertain and the ultimate number of deepwater rigs to be built in Brazil is still unknown. While Petrobras is currently in the market tendering for existing deepwater drilling units, the potential increase in supply from the Petrobras newbuild could also adversely impact overall industry dayrates and economics.

As of January 19, 2011, we had five jackup units operating with Pemex in Mexico, all of which have contracts scheduled to expire in 2011. Pemex has approved extensions to contracts for certain of these rigs as the contracts have reached expiration and has issued four ‘fast-track’ tenders aimed at keeping units working through the first quarter of 2011, but has allowed some of our other rigs to become available. Some recent tenders published by Pemex contain a requirement that certain units must have entered service since the year 2000. While Pemex has not yet succeeded in securing a significant number of younger rigs, we cannot predict whether this age requirement will be present in future Pemex tenders. If this requirement is present in future tenders, it could require us to seek work for our rigs in other locations, as the ages of our rigs currently operating in Mexico do not meet this requirement. If such work is not available, it could lead to additional idle time on some of our rigs. We cannot predict how many rigs might be affected or how long they could remain idle. As of February 11, 2011, tenders for 14 jackup rigs had been published. These tenders do not contain age restrictions and are due to be opened in the first quarter of 2011 with work commencing in the first and second quarters of 2011. We remain optimistic that many, if not all, of our rigs currently operating in Mexico will continue to work for Pemex.

In January 2011, we announced the signing of a Memorandum of Understanding (“MOU”) with Petrobras regarding operations in Brazil. Under the terms of the MOU, we would substitute the dynamically positioned deepwater drillship Noble Phoenix, then under contract with Shell in Southeast Asia, for the dynamically positioned drillship Noble Muravlenko. In January 2011, Shell agreed to release the Noble Phoenix from its contract. Upon release by Shell, the Noble Phoenix will undergo limited contract preparations, after which the unit would mobilize to Brazil. We expect that acceptance of the Noble Phoenix in Brazil by Petrobras will take place in the fourth quarter of 2011. In connection with the cancelation of the contract on the Noble Phoenix, we recognized a non-cash gain of approximately $55 million in the first quarter of 2011.

In January 2011, we reached a decision that we will not proceed with the previously announced reliability upgrade to the Noble Muravlenko that was scheduled to take place in 2013. As a result of the cancelation of the upgrade, we expect that our first quarter 2011 results will include an associated non-cash impairment charge currently estimated to be approximately $40 million.

In connection with our existing drilling contracts with Petrobras for two of our drillships operating in Brazil, we approved certain shipyard reliability upgrade projects for these drillships, the Noble Leo Segerius, and the Noble Roger Eason. These upgrade projects, planned for 2010 through 2012, are designed to enhance the reliability and operational performance of these drillships. There are a number of risks associated with shipyard projects of this nature, particularly in Brazil, including potential project delays and cost overruns due to labor, customs, local shipyard, local content and other issues. In addition, the drilling contracts for these vessels provide Petrobras with certain rights of termination in the event of excessive downtime, and it is possible that Petrobras could exercise this right in the future with respect to one or more of these drillships. We intend to continue to closely monitor and discuss with Petrobras the status of these projects and plan to take appropriate steps to mitigate identified risks, which depending upon the circumstances could involve a variety of options. In January 2011, we canceled an upgrade project on a third drillship in Brazil, the Noble Muravlenko.

While we cannot predict the future level of demand for our drilling services or future conditions in the offshore contract drilling industry, we continue to believe we are well positioned within the industry and believe our acquisition of Frontier further strengthens our position, especially in deepwater drilling. Furthermore, we believe that our financial strength as demonstrated by our entrance into a new credit facility and our recent sale of $1.1 billion of senior notes will continue to serve us well if additional opportunities present themselves in the future.

Our business strategy continues to be the active expansion of our worldwide offshore drilling and deepwater capabilities whereby we move our fleet towards the latest technology while maintaining the highest level of operational integrity with respect to health, safety, and the environment. Historically, we have accomplished this via rig and hull upgrades and modifications, acquisitions, and divestitures of lower specification units. While divestitures of non-competitive assets continue to be a part of the strategy, many of our existing units have been upgraded to their technical limits and our ability to complete acquisitions has been limited by market conditions. As a result, in recent years, we have actively expanded our fleet through the construction of new rigs, including jackups and drillships. In all of our investment decisions we seek to achieve a strong return on capital for the benefit of our shareholders. During 2010, we continued our strategy as indicated by the following activities:

•

we completed the acquisition of Frontier which added a total of five drillships (including two Bully-class joint venture-owned drillships under construction and to be completed in 2011), one semisubmersible and an FPSO to the fleet;

•

we completed construction on the Noble Dave Beard, a dynamically positioned ultra-deepwater semisubmersible that left the shipyard during the first quarter of 2010 and began operating under a long-term contract in Brazil;

•

we completed construction on the Noble Jim Day, a dynamically positioned ultra-deepwater semisubmersible that left the shipyard during the third quarter of 2010;

•

we continued construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered to our customer in the fourth quarter of 2011;

•

we began construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered to our customer in the fourth quarter of 2013; and

•

we announced we would construct two high-specification heavy duty, harsh environment jackup rigs both of which are scheduled to be delivered during 2013.

In addition to the 2010 projects listed above, in January 2011 we announced we would construct two additional newbuild drillships at Hyundai Heavy Industry (“HHI”). The new ultra-deepwater drillships, to be named at a later date, will be constructed on a fixed price basis with expected deliveries from the shipyard in the second and fourth quarters of 2013, respectively. We have a letter of intent for one of these units for a five and one-half year contract with a subsidiary of Shell at a dayrate of $410,000, plus a 15 percent performance bonus opportunity. We have also negotiated options for two additional jackups and two additional HHI drillships.

Excluding the Frontier acquisition, capital expenditures totaled $1.4 billion during 2010.

Acquisition of Frontier Holdings Limited

On July 28, 2010, Noble-Swiss and Noble AM Merger Co., a Cayman Islands company and indirect wholly-owned subsidiary of Noble-Swiss (“Merger Sub”), completed the acquisition of FDR Holdings Limited, a Cayman Islands company (“Frontier”). Under the terms of the Agreement and Plan of Merger with Frontier and certain of Frontier’s shareholders, Merger Sub merged with and into Frontier, with Frontier surviving as an indirect wholly-owned subsidiary of Noble-Swiss and a wholly-owned subsidiary of Noble-Cayman. The Frontier acquisition was for a purchase price of approximately $1.7 billion in cash plus liabilities assumed and strategically expanded and enhanced our global fleet by adding three dynamically positioned drillships (including two Bully-class joint venture-owned drillships under construction), two conventionally moored drillships, including one that is Arctic-class, a conventionally moored deepwater semisubmersible and one dynamically positioned FPSO to our fleet. Frontier’s results of operations were included in our results beginning July 28, 2010. We funded the cash consideration paid at closing of approximately $1.7 billion using proceeds from our July 2010 offering of senior notes and existing cash on hand.

U.S. Gulf of Mexico Operations

Subsequent to the April 20, 2010 fire and explosion on the Deepwater Horizon, a competitor’s drilling rig in the U.S. Gulf of Mexico, U.S. governmental authorities implemented a moratorium on and suspension of specified types of drilling activities in the U.S. Gulf of Mexico.

On October 12, 2010, the U.S. government lifted the moratorium following adoption of new regulations including a drilling safety rule and a workplace safety rule, each of which imposed multiple obligations relating to offshore drilling operations. These obligations relate to, among other things, additional certifications and verifications relating to compliance with applicable regulations; compatibility of blowout preventers with drilling rigs and well design; third-party inspections and design review of blowout preventers; testing of casing installations; minimum requirements for personnel operating blowout preventers; and training in deepwater well control.

In addition, the U.S. government has indicated that before any new deepwater drilling resumes, (i) operators must demonstrate that containment resources are available promptly in the event of a deepwater blowout, (ii) the chief executive officer of each operator seeking to perform deepwater drilling must certify that the operator has complied with all applicable regulations and (iii) the Bureau of Ocean Energy Management, Regulation and Enforcement will conduct inspections of each deepwater drilling operation for compliance with the applicable regulations.

Our existing U.S. Gulf of Mexico operations have been and will continue to be negatively impacted by the events and governmental action described above. As of December 31, 2010, our U.S. Gulf of Mexico operations included eight deepwater drilling units: the Noble Amos Runner, Noble Clyde Boudreaux, Noble Danny Adkins, Noble Jim Thompson, Noble Driller, Noble Paul Romano, Noble Lorris Bouzigard and Noble Jim Day. We estimate the negative impact to our revenues for the year ended December 31, 2010 to be approximately $450 million. We have worked and continue to work closely with our customers for drilling services in the U.S. Gulf of Mexico to address the hardships imposed by the governmental actions described above. The discussion below briefly describes the current status of each of these drilling units.

•

Noble Amos Runner. The Noble Amos Runner received its blow out preventer (“BOP”) certification and is currently operating in place of the Noble Lorris Bouzigard for LLOG Exploration, LLC (“LLOG”) at the full dayrate under the Noble Lorris Bouzigard contract.

•

Noble Clyde Boudreaux. In late June 2010, we reached agreement with our customer, Noble Energy, Inc. (“Noble Energy”), relating to the Noble Clyde Boudreaux to place the drilling unit on standby for a daily rate of $145,000 per day from June 15 through December 12, 2010. This unit has received its BOP certification. We have been awarded a letter of intent for this drilling unit by a subsidiary of Shell for work in Brazil. We expect to mobilize the unit in the first quarter of 2011.

•

Noble Danny Adkins. This unit received its BOP certification. The unit currently is operating under a permit, however, we cannot guarantee that our customer Shell will be able to continue to secure required permits, at which point, it could return to the lower stand-by rate.

•

Noble Jim Thompson. This unit is under contract with Shell and is receiving a reduced stand-by rate. This unit has received its BOP certification.

•

Noble Driller. This unit is under contract with Shell and is receiving a reduced stand-by rate while undergoing a shipyard project. This unit is expected to receive its BOP certification in the second quarter of 2011.

•

Noble Paul Romano. This unit is idle, having completed its drilling contract in June 2010. The unit has received its BOP certification and is being actively marketed to potential customers.

•

Noble Lorris Bouzigard. Prior to being swapped with the Noble Amos Runner this unit was under contract with LLOG. Currently, this drilling unit is cold stacked, but is being actively marketed to potential customers.

•

Noble Jim Day. Effective December 31, 2010 Marathon Oil Company (“Marathon”) terminated the drilling contract for the ultra-deepwater semisubmersible drilling rig Noble Jim Day. Marathon’s stated reason for the termination was that the rig had not been accepted by Marathon by the contracted deadline of December 31, 2010. We believe the rig was ready to commence operations and should have been accepted by Marathon. This rig has received its BOP certification. We intend to pursue our rights under the contract against Marathon. In February 2011, we were awarded a letter of intent for this drilling unit by a subsidiary of Shell for work in the U.S. Gulf of Mexico.

It is still unclear when normal operations will resume, what the cost of additional safety measures will be and how additional regulations will impact our operations in the U.S. Gulf of Mexico.

Consummation of Migration and Internal Restructuring

On March 26, 2009, we completed a series of transactions that effectively changed the place of incorporation of our parent holding company from the Cayman Islands to Switzerland. As a result of these transactions, Noble-Cayman, our former publicly-traded parent company, became a direct, wholly-owned subsidiary of Noble-Swiss, our current publicly-traded parent company. Noble-Swiss’ principal asset is all of the shares of Noble-Cayman. Noble-Cayman has no public equity outstanding after March 26, 2009. The consolidated financial statements of Noble-Swiss include the accounts of Noble-Cayman, and Noble-Swiss conducts substantially all of its business through Noble-Cayman and its subsidiaries. In connection with these transactions, we relocated our principal executive offices, executive officers and selected personnel to Geneva, Switzerland.

Contract Drilling Services Backlog

We maintain a backlog (as defined below) of commitments for contract drilling services. The following table sets forth as of December 31, 2010 the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:

						Year Ending December 31,
		Total				2011				2012				2013				2014				2015-2023
		(In millions)
Contract Drilling Services Backlog
Semisubmersibles/Drillships (1) (5) (6) (7) (8) (9)		$	11,430			$	1,637			$	1,760			$	1,642			$	1,707			$	4,684
Jackups/Submersibles (2)			1,263				707				304				182				67				3
Other			—				—				—				—				—				—
Total (3)		$	12,693			$	2,344			$	2,064			$	1,824			$	1,774			$	4,687
Percent of Available Operating Days
Committed (4)							53	%			31	%			25	%			19	%			5	%

Our contract drilling services backlog reported above reflects estimated future revenues attributable to both signed drilling contracts and letters of intent that we expect to become firm. A letter of intent is generally subject to customary conditions, including the execution of a definitive drilling contract. It is possible that some customers that have entered into letters of intent will not enter into signed drilling contracts. We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.

The amount of actual revenues earned and the actual periods during which revenues are earned may be different than the backlog amounts and backlog periods set forth in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, weather conditions and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated.

Internal Investigation

In 2007, we began, and voluntarily contacted the SEC and the U.S. Department of Justice (“DOJ”) to advise them of, an internal investigation of the legality under the United States Foreign Corrupt Practices Act (“FCPA”) and local laws of certain reimbursement payments made by our Nigerian affiliate to our customs agents in Nigeria. In November 2010, we finalized settlements of this matter with each of the SEC and the DOJ. In order to resolve the DOJ investigation, we entered into a non-prosecution agreement with the DOJ, which provides for the payment of a fine of $2.6 million, as well as certain undertakings, including continued cooperation with the DOJ, compliance with the FCPA, certain self-reporting and annual reporting obligations and certain restrictions on our public discussion regarding the agreement. The agreement does not require that we install a monitor to oversee our activities and compliance with laws. In order to resolve the SEC investigation, we agreed to the entry of a civil judgment against us for violations of the FCPA. Pursuant to the agreed judgment, we agreed to disgorge profits of $4.3 million, pay prejudgment interest of $1.3 million and refrain from denying the allegations contained in the SEC’s petition, except in other litigation to which the SEC is not a party. We also agreed to an injunction restraining us from violating the anti-bribery, books and records, and internal controls provisions of the FCPA, and we waived a variety of litigation rights with respect to the conduct at issue. The agreed judgment does not require a monitor. Our ability to comply with the terms of the settlements is dependent on the success of our ongoing compliance program, including our ability to continue to manage our agents and supervise, train and retain competent employees, and the efforts of our employees to comply with applicable law and our code of business conduct and ethics.

In January 2011, the Nigerian Economic and Financial Crimes Commission and the Nigerian Attorney General Office initiated an investigation into these same activities. A subsidiary of Noble-Swiss resolved this matter through the execution of a non-prosecution agreement dated January 28, 2011. Pursuant to this agreement, the subsidiary paid $2.5 million to resolve all charges and claims of the Nigerian government. Any additional sanctions we may incur as a result of any such investigation could damage our reputation and result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, results of operations or financial condition. Further, resolving any such investigation could be expensive and consume significant time and attention of our senior management.

We have one jackup rig in Nigeria which is operating under a temporary import permit which expired in November 2008 and we have a pending application to renew this permit. We have received approval from the Nigerian Customs office that we will be allowed to obtain a new temporary import permit for this rig. We recently received a new temporary import permit for another rig in Nigeria that had been waiting for a temporary import permit based on a long-standing application. We continue to seek to avoid material disruption to our Nigerian operations; however, there can be no assurance that we will be able to obtain new permits or further extensions of permits necessary to continue the operation of our rigs in Nigeria. If we cannot obtain a new permit or an extension necessary to continue operations of any rig, we may need to cease operations under the drilling contract for such rig and relocate such rig from Nigerian waters. We cannot predict what impact these events may have on any such contract or our business in Nigeria, and we could face additional fines and sanctions in Nigeria. Furthermore, we cannot predict what changes, if any, relating to temporary import permit policies and procedures may be established or implemented in Nigeria in the future, or how any such changes may impact our business there.

RESULTS OF OPERATIONS

2010 Compared to 2009

General

Net income attributable to Noble Corporation for 2010 was $773 million, or $3.02 per diluted share, on operating revenues of $2.8 billion, compared to net income for 2009 of $1.7 billion, or $6.42 per diluted share, on operating revenues of $3.6 billion.

The consolidated financial statements of Noble-Swiss include the accounts of Noble-Cayman, and Noble-Swiss conducts substantially all of its business through Noble-Cayman and its subsidiaries. As a result, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between 2010 and 2009, would be the same as the information presented below regarding Noble-Swiss in all material respects, except operating income for Noble-Cayman for the year ended December 31, 2010 was $42 million higher than operating income for Noble-Swiss for the same period, primarily as a result of costs directly attributable to Noble-Swiss for stewardship related services.

Rig Utilization, Operating Days and Average Dayrates

Operating revenues and operating costs and expenses for our contract drilling services segment are dependent on three primary metrics — rig utilization, operating days and dayrates. The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2010 and 2009:

		Average Rig								Operating												Average
		Utilization (1)								Days (2)												Dayrates
		2010				2009				2010				2009				% Change				2010				2009				% Change
Jackups			79	%			82	%			12,376				12,719				-3	%		$	96,935			$	147,701				-34	%
Semisubmersibles			86	%			100	%			3,837				3,673				4	%			288,163				368,398				-22	%
Drillships			89	%			91	%			1,392				993				40	%			256,067				254,084				1	%
FPSO/Submersibles (3)			11	%			51	%			95				418				-77	%			355,986				61,711				477	%
Total			78	%			84	%			17,700				17,803				-1	%		$	152,292			$	197,144				-23	%

Contract Drilling Services

The following table sets forth the operating revenues and the operating costs and expenses for our contract drilling services segment for 2010 and 2009:

										Change
		2010				2009				$				%
Operating revenues:
Contract drilling services		$	2,695,493			$	3,509,755			$	(814,262	)			-23	%
Reimbursables (1)			73,959				96,161				(22,202	)			-23	%
Other			2,332				1,302				1,030				79	%
		$	2,771,784			$	3,607,218			$	(835,434	)			-23	%
Operating costs and expenses:
Contract drilling services		$	1,177,800			$	1,006,764			$	171,036				17	%
Reimbursables (1)			56,674				82,122				(25,448	)			-31	%
Depreciation and amortization			528,011				398,572				129,439				32	%
Selling, general and administrative			91,094				80,004				11,090				14	%
(Gain)/Loss on asset disposal/involuntary conversion, net			—				31,053				(31,053	)			**
			1,853,579				1,598,515				255,064				16	%
Operating income		$	918,205			$	2,008,703			$	(1,090,498	)			-54	%

Operating Revenues. The decrease in contract drilling services revenue for 2010 as compared to the prior year was primarily driven by reductions in both average dayrates and utilization. Lower dayrates decreased revenues approximately $798 million, while fewer operating days decreased revenues by approximately $16 million. The reduction in utilization was partially offset by the acquisition of Frontier and the addition of newbuilds.

The decrease in contract drilling services revenue related primarily to our jackups and semisubmersibles, which generated approximately $679 million and $248 million less revenue for the current year as compared to the prior year, respectively. The decrease in jackup revenue was from a 34 percent decline in dayrates primarily from the contractual re-pricing of rigs in the Middle East, the North Sea, and Mexico resulting from changes in market conditions in the global shallow water market. Reductions in average dayrates by 22 percent contributed to the decline in semisubmersible revenue. These reductions resulted from the drilling restrictions in the U.S. Gulf of Mexico where lower standby rates replaced the standard operating dayrates for a majority of our customers, lower utilization from the termination of certain contracts and a dispute with a customer over the Noble Homer Ferrington contract.

The decreases in revenue for the above rig classes were partially offset by higher revenues from our drillships and other rigs, which increased $113 million in the current year as compared to the prior year. The increase was primarily due to the addition of the drillships and FPSO added to the fleet as part of the Frontier acquisition of $143 million, partially offset by a decrease in revenues from our drillships operating in Brazil.

Operating Costs and Expenses. Contract drilling services operating costs and expenses increased $171 million for the current year as compared to the prior year. Our newbuild rigs, the Noble Scott Marks, Noble Danny Adkins and Noble Dave Beard, which were added to the fleet in June 2009, October 2009 and March 2010, respectively, added approximately $109 million of operating costs in 2010. The acquisition of the Frontier rigs added an additional $55 million of operating costs. Excluding the additional expenses related to these newbuild and Frontier rigs, our contract drilling costs increased $7 million in 2010 as compared to 2009. This change was principally due to acquisition costs of $19 million coupled with increases in safety costs of $4 million, partially offset by a decrease in maintenance expenses of $9 million and a decrease in transportation and other expenses of $7 million.

Depreciation and amortization increased $129 million in 2010 over 2009 as a result of depreciation on newbuilds placed into service, and additional depreciation related to other capital expenditures on our fleet since the beginning of 2009. Also, the acquisition of Frontier added approximately $39 million in depreciation during the current year.

Loss on asset disposal/involuntary conversion in 2009 primarily consists of a charge of $17 million for our jackup, the Noble David Tinsley, which experienced a “punch-through” while being positioned on location offshore Qatar. The $17 million charge includes approximately $9 million for the write-off of the damaged legs and $8 million for non-reimbursable expenses. Also during 2009, we recorded an impairment charge of $12 million for the Noble Fri Rodli as a result of a decision to evaluate disposition alternatives for this submersible drilling unit.

Other

The following table sets forth the operating revenues and the operating costs and expenses for our other services for 2010 and 2009 (in thousands):

										Change
		2010				2009				$				%
Operating revenues:
Labor contract drilling services		$	32,520			$	30,298			$	2,222				7	%
Reimbursables (1)			2,872				3,040				(168	)			-6	%
Other			—				228				(228	)			-100	%
		$	35,392			$	33,566			$	1,826				5	%
Operating costs and expenses:
Labor contract drilling services		$	22,056			$	18,827			$	3,229				17	%
Reimbursables (1)			2,740				2,913				(173	)			-6	%
Depreciation and amortization			11,818				9,741				2,077				21	%
Selling, general and administrative			903				258				645				250	%
(Gain)/Loss on asset disposal, net			—				(214	)			214				**
			37,517				31,525				5,992				19	%
Operating income		$	(2,125	)		$	2,041			$	(4,166	)			-204	%

Operating Revenues and Costs and Expenses. Revenues and expenses associated with our Canadian labor contract drilling services increased in the current year primarily for fluctuations in foreign currency exchange rates coupled with increased labor and contract drilling services costs. The increase in depreciation results from fixed asset additions in conjunction with the relocation of our corporate offices to Switzerland.

Other Income and Expenses

Selling, general and administrative expenses. Overall selling, general and administrative expenses increased $12 million in 2010 from 2009 primarily as a result of the FCPA settlement of $8 million, along with increases in employee related costs of $2 million, increases in consulting fees of $2 million and Swiss VAT taxes of $2 million, partially offset by the worldwide asset consolidation project and migration costs and other expenses in 2009 of $2 million.

Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized increased $8 million primarily for the addition of $1.25 billion of debt issued in July 2010 to partially fund the Frontier acquisition.

Income Tax Provision. Our income tax provision decreased $194 million in 2010 compared to 2009 primarily due to a reduction in pre-tax earnings combined with a lower effective tax rate. Pre-tax earnings decreased approximately 55 percent in 2010 compared to 2009 resulting in a reduction of approximately $184 million in income tax expense. The lower effective tax rate, which was 15.6 percent in 2010 compared to 16.7 percent in 2009, reduced income tax expense by approximately $10 million.

2009 Compared to 2008

General

Net income for 2009 was $1.7 billion, or $6.42 per diluted share, on operating revenues of $3.6 billion, compared to net income for 2008 of $1.6 billion, or $5.81 per diluted share, on operating revenues of $3.4 billion.

Rig Utilization, Operating Days and Average Dayrates

Operating revenues and operating costs and expenses for our contract drilling services segment are dependent on three primary metrics — rig utilization, operating days and dayrates. The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2009 and 2008:

		Average Rig								Operating												Average
		Utilization (1)								Days (2)												Dayrates
		2009				2008				2009				2008				% Change				2009				2008				% Change
Jackups			82	%			92	%			12,719				13,879				-8	%		$	147,701			$	148,532				-1	%
Semisubmersibles
> 6000’ (3)			98	%			96	%			2,578				2,466				5	%			417,177				327,558				27	%
Semisubmersibles
< 6000’ (4)			100	%			100	%			1,095				1,098				0	%			253,557				220,475				15	%
Drillships			91	%			67	%			993				732				36	%			254,084				201,819				26	%
Submersibles (5)			51	%			66	%			418				729				-43	%			61,711				54,106				14	%
Total			84	%			90	%			17,803				18,904				-6	%		$	197,143			$	174,506				13	%

Contract Drilling Services

The following table sets forth the operating revenues and the operating costs and expenses for our contract drilling services segment for 2009 and 2008:

										Change
		2009				2008				$				%
Operating revenues:
Contract drilling services		$	3,509,755			$	3,298,850			$	210,905				6	%
Reimbursables (1)			96,161				76,099				20,062				26	%
Other			1,302				1,275				27				2	%
		$	3,607,218			$	3,376,224			$	230,994				7	%
Operating costs and expenses:
Contract drilling services		$	1,006,764			$	1,011,882			$	(5,118	)			-1	%
Reimbursables (1)			82,122				65,251				16,871				26	%
Depreciation and amortization			398,572				349,448				49,124				14	%
Selling, general and administrative			80,004				72,381				7,623				11	%
(Gain)/Loss on asset disposal/involuntary conversion, net			31,053				10,000				21,053				**
			1,598,515				1,508,962				89,553				6	%
Operating income		$	2,008,703			$	1,867,262			$	141,441				8	%