Noble Corp - Annual Report: 2011 (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 (State or other jurisdiction of incorporation or organization)		98-0619597 (I.R.S. employer identification number)

Dorfstrasse 19A, Baar, Switzerland 6340
(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 3.28 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 (State or other jurisdiction of incorporation or organization)		98-0366361 (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 preceding 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, 2011, the aggregate market value of the registered shares of Noble Corporation (Switzerland) held by non-affiliates of the registrant was $9.8 billion based on the closing sale price as reported on the New York Stock Exchange.

Number of shares outstanding and trading at February 13, 2012: Noble Corporation (Switzerland) — 252,170,859

Number of shares outstanding: Noble Corporation (Cayman Islands) — 261,245,693

The proxy statement for the 2012 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			18
Item 2. Properties			18
Item 3. Legal Proceedings			22
Item 4. Mine Safety Disclosures			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			26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			46
Item 8. Financial Statements and Supplementary Data			49
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			106
Item 9A. Controls and Procedures			106
Item 9B. Other Information			107
PART III
Item 10. Directors, Executive Officers and Corporate Governance			107
Item 11. Executive Compensation			108
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			109
Item 13. Certain Relationships and Related Transactions and Director Independence			109
Item 14. Principal Accounting Fees and Services			109
PART IV
Item 15. Exhibits, Financial Statement Schedules			109
SIGNATURES			110
Exhibit 3.1
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.

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 79 mobile offshore drilling units and one floating production storage and offloading unit (“FPSO”) located worldwide. Our fleet consists of 14 semisubmersibles, 14 drillships, 49 jackups and two submersibles. Our fleet includes 11 units under construction as follows:

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five dynamically positioned, ultra-deepwater, harsh environment drillships, and

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six high-specification heavy-duty, harsh environment jackup rigs.

For additional information on the specifications of the fleet, see “Item 2. Properties. - Drilling Fleet.” As of February 15, 2012, approximately 84 percent of our fleet was located outside the United States in the following areas: Mexico, Brazil, the North Sea, the Mediterranean, West Africa, the Middle East, India and the Asian Pacific. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.

Business Strategy

Our goal is to be the preferred offshore drilling contractor for the oil and gas industry based upon the following overriding 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 through a large, diverse and technically advanced fleet operated by competent personnel.

We have actively expanded our offshore drilling and deepwater capabilities in recent years through the construction and acquisition of rigs. As part of this technical and operational enhancement, we plan to continue pursuing opportunities to upgrade our fleet to achieve greater technological capability and increase our operational efficiencies.

Our business strategy also focuses on the active expansion of our worldwide deepwater capabilities through upgrades and modifications, acquisitions and divestitures of drilling units, as well as the deployment of our drilling assets in important oil and gas producing areas.

During 2011, we continued our newbuild program with the following projects:

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we completed construction on the Noble Bully I, a dynamically positioned, ultra-deepwater, harsh environment drillship, owned through a joint venture with a subsidiary of Royal Dutch Shell plc. (“Shell”) that left the shipyard during the third quarter of 2011 and is scheduled to complete acceptance testing and begin operations under a long-term contract in the U.S. Gulf of Mexico during the first quarter of 2012;

•

we completed construction on the Noble Bully II, a dynamically positioned, ultra-deepwater, harsh environment drillship, owned through a joint venture with a subsidiary of Shell, that left the shipyard during the fourth quarter of 2011 and is scheduled to complete acceptance testing and begin operations under a long-term contract in Brazil during the first quarter of 2012;

•

we completed construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship that left the shipyard during the fourth quarter of 2011 and is scheduled to complete acceptance testing and begin operations under a long-term contract in the U.S. Gulf of Mexico in the second quarter of 2012;

•

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

•

we began construction on four dynamically positioned, ultra-deepwater, harsh environment drillships at Hyundai Heavy Industries Co. Ltd. (“HHI”), which are estimated to be delivered from the shipyard to begin acceptance testing beginning in the second quarter of 2013; and

•

we began construction on six high-specification heavy duty, harsh environment jackup rigs, which are estimated to be delivered from the shipyard to begin acceptance testing beginning in the first quarter of 2013.

Capital expenditures, including expenditures related to items noted above, totaled $2.6 billion during 2011.

In addition, as part of our business strategy, we continue to review our fleet and the strategic benefits of each of our units. As part of this process, we may dispose of some or all of our lower specification units and related assets and operations in one or more transactions. These dispositions may include sales of assets to third parties, a spin-off or other distribution or separation of assets. In analyzing any disposition, we will consider the strategic benefit to us of the potential transaction while seeking to secure what we consider appropriate value. To date, no potential disposition has provided the results we seek. The drilling market for lower specification units has recently improved, and we have experienced increased utilization and dayrates for these assets in certain areas. Thus, while we continue to evaluate disposition options, we believe these units should provide a positive contribution to our overall results under current market conditions. We can provide no assurance as to whether any disposition transaction will occur or what form it may take.

Demand for our services is a function of the worldwide supply of mobile offshore drilling units. Industry analysts widely acknowledge that a significant expansion of industry supply of both jackups and ultra-deepwater units has commenced, the majority of which currently have no contract. The introduction of non-contracted rigs into the marketplace will increase the supply of rigs which compete for drilling service contracts, which could negatively impact the dayrates we are able to achieve. Our strategy on newbuild 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, in response to the addition of a significant number of new, technologically advanced units in the global fleet and changes in customer requirements and preferences, we believe that in order to maintain long-term competitiveness, 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, three of the ultra-deepwater drillships and all six of the heavy-duty, harsh environment jackups are being constructed without customer contracts. We will attempt to secure contracts for these units prior to their completion. We may continue speculative building, even in the absence of contracts for our units already under construction.

As part of our strategy, we intend to participate in the consolidation of the offshore drilling industry where we believe we can create shareholder value. From time to time, we evaluate 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 markets, higher demand for drilling equipment, and shortages of personnel. This environment drove operating costs higher and magnified the importance of recruiting, training and retaining skilled personnel. While the recent global financial turmoil and governmental actions following the events of the Deepwater Horizon in April 2010 created uncertainty in our industry, we believe the current market offers limited supply and high demand for drilling units and qualified labor.

In recognition of the importance of our offshore operations personnel in achieving a safety record that has historically 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 are necessary to 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;

•

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;

•

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);

•

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

•

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 without requiring an early termination payment to us. Our drilling contracts with Petróleos Mexicanos (“Pemex”) in Mexico, for example, allow early cancellation with 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 assume 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 assume the costs of moving the unit by paying us a reduced dayrate or “move rate” while the unit is being moved.

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.”

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”). 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. Frontier’s results of operations were included in our results beginning July 28, 2010.

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, 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.

Offshore Drilling Operations

Contract Drilling Services

We conduct offshore contract drilling operations, which accounted for over 98 percent of our operating revenues for the years ended December 31, 2011, 2010 and 2009. We conduct our contract drilling operations principally in the U.S. Gulf of Mexico, Mexico, Brazil, the North Sea, the Mediterranean, West Africa, the Middle East, India and the Asian Pacific. Revenues from Shell and its affiliates accounted for approximately 24 percent of our total operating revenues in 2011 and 12 percent of our total operating revenues in each of 2010 and 2009. Revenues from Petróleo Brasileiro S.A. (“Petrobras”) accounted for approximately 18 percent and 19 percent of our total operating revenues in 2011 and 2010, respectively. Petrobras did not account for more than 10 percent of our total operating revenues in 2009. Revenues from Pemex accounted for approximately 15 percent, 20 percent and 23 percent of our total operating revenues in 2011, 2010 and 2009, respectively. No other single customer accounted for more than 10 percent of our total operating revenues in 2011, 2010 or 2009.

Labor Contracts

We perform services for drilling and workover activities covering two rigs off the east coast of Canada, which extends through January 2013. 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.

During 2011, we commenced a refurbishment project with our customer, Shell, for one of its rigs. Under the contract, we provide the management and oversight of the project, as well as the personnel necessary to complete the refurbishment. Upon completion of the project, we anticipate operating the rig under a management agreement.

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 will 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. Our 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 likely will 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 countries in whose waters we operate from time to time regulate the discharge of oil and other contaminants in connection with drilling operations. Failure to comply with these laws and regulations, or failure 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 by regulatory activity 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.

The following is a summary of some of the existing laws and regulations which apply to our operations in the U.S. Gulf of Mexico to serve as an example of the various laws and regulations to which we are subject. While laws vary widely in each jurisdiction, each of the laws and regulations below address environmental issues similar to those in most of the other jurisdictions in which we operate.

Spills and Releases. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and similar 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 to date not received any 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 recipient of a deepwater drilling permit may resume drilling, (i) the operator must demonstrate that containment resources are available promptly in the event of a deepwater blowout, (ii) the chief executive officer of the 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 (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) will conduct inspections of such deepwater drilling operation for compliance with the applicable regulations. We cannot predict when the applicable government agency will determine that any deepwater driller is in compliance with the new regulations. Further, the BSEE and its predecessor agency have issued regulations on the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits. BSEE’s predecessor agency also proposed to further strengthen these regulations in September 2011.

The Oil Pollution Act. The U.S. Oil Pollution Act of 1990 (“OPA”) and similar regulations 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 similar 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 as 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, a petition is currently before the EPA to revoke the oil and natural gas exploration and production exemption. Any repeal or modification of this or similar exemption in similar 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 similar 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. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.

Climate Change. There is increasing attention 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 comprehensive plan 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. The EPA and the National Highway Traffic Safety Administration subsequently developed GHG standards for motor vehicles, the effect of which could reduce demand for motor fuels refined from crude oil. Finally, the EPA and most states have begun to regulate GHG emissions under the Clean Air Act Prevention of Significant Deterioration (“PSD”) program, which requires the use of “best available control technology” for GHG emissions from new and modified major stationary sources, which can sometimes include drillships. EPA regulations known as the “Tailoring Rule” also require the PSD program to address GHG emissions from relatively smaller stationary sources in the future.

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 countries that had ratified it. International discussions have been 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 new treaties and 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 (“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 similar 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.

Insurance and Indemnification Matters

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 sea conditions. These hazards could cause personal injury or loss of life, loss of revenues, pollution and other environmental damage, damage to or destruction of property and equipment and oil and natural gas producing formations, and could result in claims by employees, customers or third parties.

Our drilling contracts provide for varying levels of indemnification from our customers and in most cases also require us to indemnify our customers for certain losses. Under our drilling contracts, liability with respect to personnel and property is typically assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. In addition, our customers may indemnify us in certain instances for damage to our down-hole equipment and, in some cases, our subsea equipment.

Our customers typically assume responsibility for and indemnify us from loss or liability resulting from pollution or contamination, including third-party damages and clean-up and removal, arising from operations under the contract and originating below the surface of the water. We are generally responsible for pollution originating above the surface of the water and emanating from our drilling units. Additionally, our customers typically indemnify us for liabilities incurred as a result of a blow-out or cratering of the well and underground reservoir loss or damage.

In addition to the contractual indemnities described above, we also carry protection and indemnity (“P&I”) insurance, which is a comprehensive general liability insurance program covering liability resulting from offshore operations. Our P&I insurance includes coverage for liability resulting from personal injury or death of third parties and our offshore employees, third party property damage, pollution, spill clean-up and containment and removal of wrecks or debris. Our insurance policy does not exclude losses resulting from our gross negligence or willful misconduct. Our P&I insurance program is renewed annually and currently has a standard deductible of $10 million per occurrence, with maximum liability coverage of $750 million.

Our insurance policies and contractual rights to indemnity may not adequately cover our losses and liabilities in all cases. For additional information, please read “We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all of the risks and hazards we face” included in Item 1A of this Annual Report on Form 10-K.

The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the time of preparation of this report and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.

Employees

At December 31, 2011, we had approximately 5,300 employees, excluding approximately 2,000 persons engaged through labor contractors or agencies. Approximately 77 percent of our employees were engaged in operations outside of the U.S. 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 “Part II Item 8. Financial Statements and Supplementary Data, Note 17 — Segment and Related Information.”

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 “Part II Item 8. Financial Statements and Supplementary Data, Note 17 — Segment and Related Information.”

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 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’s 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 or waivers of compliance) at our website. Among the documents you can find there are 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 and 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:

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

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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;

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worldwide demand for oil and gas, which is impacted by changes in the rate of economic growth in the global economy;

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

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the level of production in non-OPEC countries;

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

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

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the discovery rate of new oil and gas reserves;

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

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available pipeline and other oil and gas transportation capacity;

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the ability of oil and gas companies to raise capital;

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

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the development and exploitation of alternative fuels;

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tax laws, regulations and policies;

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advances in exploration, development and production technology; and

•

the availability of, and access to, suitable locations from which our customers can produce hydrocarbons.

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 level of demand for our drilling services or 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 2012 and 2013. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions and 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.

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:

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terrorist acts, war, revolution and civil disturbances;

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seizure, nationalization or expropriation of property or equipment;

•

monetary policies, government debt downgrades and potential defaults, and foreign currency fluctuations and devaluations;

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the inability to repatriate income or capital;

•

complications associated with repairing and replacing equipment in remote locations;

•

piracy;

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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;

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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;

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currency exchange controls;

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oil and gas exploration and development;

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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. For example, as of December 31, 2011, all three of our rigs operating in Nigeria were operating under temporary import permits and the Department of Petroleum Resources had not yet issued our Nigerian subsidiary a permit to operate as an oil industry service company or licenses to operate the three rigs for year 2012. It is customary in Nigeria that permits and licenses are issued well into the year to which they pertain and, to date, we have been successful in obtaining new, or extending existing, temporary import permits and other permits and licenses. 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 completed 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 16 — 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.

In April 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 asset ownership and 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 Nigerian Content Development and Monitoring Board has indicated that it will require all non-Nigerian offshore drilling companies to reorganize their local operations to include Nigerian indigenous minority interests in the operating assets and to obtain the approval of the Nigerian Content Development and Monitoring Board for future work in Nigeria. 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 are monitoring closely the implementation of the law and are reviewing our structural and strategic alternatives and the associated cost. We cannot predict what impact the new law will have on the drilling industry and our existing or future operations in Nigeria, but the effect on our operations and profitability in the region could be material.

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. Although we do not believe that these laws apply to our ownership of drilling units, NIMASA is seeking to apply a provision of the Nigerian cabotage laws to our offshore drilling units by considering these units to be “vessels”. Following a series of suits, the Federal High Court of Lagos, Nigeria has issued a favorable ruling in response to our originating summons stating that our drilling operations do not fall within the cabotage laws and that our drilling rigs are not “vessels” for purposes of those laws. The court also issued an injunction against NIMASA prohibiting their interference with our drilling rigs or drilling operations. NIMASA has appealed the court’s ruling. We intend to take all further appropriate legal action to resist the application of Nigeria’s cabotage laws to our drilling units. The outcome of any such legal action and the extent to which we may ultimately be responsible for the surcharge is uncertain. If it is ultimately determined that offshore drilling units constitute “vessels” within the meaning of the Nigerian cabotage laws, 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 16— Commitments and Contingencies.”

NIMASA had previously informed the Nigerian Content Division of its position that we were 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 previously 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.

In addition, other governmental actions, 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.

The U.S. government’s regulations and permitting process could continue to have a prolonged and material adverse impact on our U.S. Gulf of Mexico operations.

Subsequent to the April 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. In October 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. BSEE’s predecessor agency also proposed to further strengthen these regulations in September 2011. Although the BOEM and the BSEE (and their predecessor agency) began issuing new deepwater drilling well permits in mid-2011, there has been a delay in receiving permits and the new regulatory requirements have resulted in delays in the resumption of drilling-related activities, and we anticipate that there will continue to be such delays as these various requirements are fully implemented. Such delays could be exacerbated by potential third party environmental lawsuits targeting the permitting process and the new drilling regulations.

The U.S. government has mandated that before beginning a well in the U.S. Gulf of Mexico an operator must: (i) demonstrate that containment resources are available promptly in the event of a deepwater blowout, (ii) have the chief executive officer of the operator seeking to perform deepwater drilling certify that the operator has complied with all applicable regulations and (iii) allow BSEE to conduct inspections of such deepwater drilling operation for compliance with the applicable regulations. During the first half of 2011, our customers and other operators struggled to implement these new regulations, which resulted in increased downtime and decreased rates for a number of our contracted units. While it appears that operators have become accustomed to these new regulations, we cannot predict whether the permitting will continue at the current rate in the future.

Our existing U.S. Gulf of Mexico operations have been negatively impacted by the events, governmental actions and the related industry response described above. U.S. governmental restrictions and regulations have, and may continue to result in, increased expense and downtime of our operations in the U.S. Gulf of Mexico as additional maintenance and redundancy measures are required. 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.

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.

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.

Worldwide instability in the financial and credit sectors could reduce 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 could lead to another global economic recession. A slowdown in economic activity caused by a worldwide recession, combined with lower prices for oil and gas, would reduce worldwide demand for energy and demand for drilling services. If demand for drilling services declines again, 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, Petrobras and Pemex represented approximately 63 percent, 20 percent and 5 percent, respectively, of our backlog at December 31, 2011 and revenues from Shell, Petrobras and Pemex accounted for approximately 24 percent, 18 percent and 15 percent of our total operating revenue for the year ended December 31, 2011. This concentration of customers increases the risks associated with any possible termination or nonperformance of contracts in addition to our exposure to credit risk. If any 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 multiple new construction projects and conversion projects underway and we may undertake additional projects in the future. In addition, we make significant upgrade, refurbishment and repair expenditures to 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:

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shortages of equipment, materials or skilled labor;

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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 availability, 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.

The 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 investigation by these or other agencies 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 additional investigations could be expensive and consume significant time and attention of our senior management. For instance, in February 2012, the SEC charged one current and two former employees of ours with violating the FCPA in connection with the events that were the subject of the internal investigations we began in 2007, as described above. We do not believe that the SEC pleadings against these individuals introduce material facts that were not addressed in our internal investigation, which we resolved with the SEC and the DOJ in November 2010. We are not a party to the SEC proceedings against these individuals, and we do not believe the charges against the individuals will result in fines, sanctions or civil or criminal penalties against us. However, these actions may consume the attention of management and damage our reputation.

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. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in Switzerland, the U.S. or jurisdictions in which we or any of our subsidiaries operate or are incorporated.

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. 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 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 Switzerland, the U.S. or other jurisdictions in which our shareholders are resident. Any such changes could result in increased taxes for our shareholders and 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. We are experiencing competition from newbuild jackups that are scheduled to enter the market in 2012 and beyond. The entry of these newbuild jackups into the market may result in lower dayrates for jackups than currently expected. 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.

As a result of our significant cash flow needs, we may be required to incur additional indebtedness, or delay or cancel discretionary capital expenditures.

Our currently anticipated cash flow needs may include the following:

•

committed capital expenditures, including expenditures for newbuild projects currently underway;

•

normal recurring operating expenses;

•

discretionary capital expenditures, including various capital upgrades;

•

potential newbuild projects and acquisitions; and

•

payments of dividends.

In order to fund our capital expenditures, we may need funding beyond the amount available to us from cash generated by our operations, cash on hand and borrowings under our existing bank credit facilities. We may raise such additional capital in a number of ways, including accessing capital markets, obtaining additional lines of credit or disposing of assets. However, we can provide no assurance that any of these options will be available to us on terms acceptable to us or at all.

Our ability to obtain financing or to access the capital markets may be limited by our financial condition at the time of any such financing and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and uncertainties that are beyond our control. Even if we are successful in obtaining additional capital through debt financings, incurring additional indebtedness may significantly increase our interest expense and may reduce our flexibility to respond to changing business and economic conditions or to fund working capital needs, because we will require additional funds to service our outstanding indebtedness.

We may delay or cancel discretionary capital expenditures, which could have certain adverse consequences including delaying upgrades or equipment purchases that could make the affected rigs less competitive, adversely affect customer relationships and negatively impact our ability to contract such rigs.

We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all of the risks and hazards we face.

We generally identify the operational hazards for which we will procure insurance coverage based on the likelihood of loss, the potential magnitude of loss, the cost of coverage, the requirements of our customer contracts and applicable legal requirements. We do not procure insurance coverage for all of the potential risks and hazards we may face. Furthermore, no assurance can be given that we will be able to obtain insurance against all of the risks and hazards we face or that we will be able to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable.

Although we maintain what we believe to be an appropriate level of insurance covering hazards and risks we currently encounter during our operations, we do not insure against all possible hazards and risks. Furthermore, our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include expatriate activities prohibited by U.S. laws, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes.

In addition, the damage sustained to offshore oil and gas assets as a result of hurricanes in recent years caused the insurance market for U.S. named windstorm perils to deteriorate significantly. Consequently, we currently self-insure U.S. named windstorm coverage for our units deployed in the U.S. Gulf of Mexico. 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 increases in insurance costs, additional coverage restrictions or unavailability of certain insurance products.

Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. Although our drilling contracts generally provide for indemnification from our customers for certain liabilities, including liabilities resulting from pollution or contamination originating below the surface of the water, enforcement of these contractual rights to indemnity may be limited by public policy and other considerations and, in any event, may not adequately cover our losses from such incidents. There can also be no assurance that those parties with contractual obligations to indemnify us will necessarily be in a financial position to do so.

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 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.

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 the Frontier transaction and integration, contract backlog, fleet status, our financial position, business strategy, timing or results of acquisitions or dispositions, backlog, completion and acceptance of our newbuild rigs, contract commitments, dayrates, contract commencements, extension or renewals, contract tenders, the outcome of any dispute, litigation or investigation, plans and objectives of management for future operations, foreign currency requirements, results of

joint ventures, indemnity and other contract claims, construction of rigs, industry conditions including the effect of disruptions of drilling in the U.S. Gulf of Mexico, access to financing, impact of competition, governmental regulations and permitting, availability of labor, worldwide economic conditions, taxes and tax rates, indebtedness covenant compliance, and timing for compliance with any new regulations 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 be correct. 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. Certain of our semisubmersibles are capable of drilling in water depths of up to 12,000 feet. Semisubmersibles are more expensive to construct and operate than jackups.

The semisubmersible fleet consists of 14 units, including:

•

five 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

Our drillships are self-propelled vessels. These units maintain their position over the well through the use of either a fixed mooring system or a computer controlled dynamic positioning system. Our drillships are capable of drilling in water depths from 1,000 to 12,000 feet. The maximum drilling depth of our drillships ranges from 20,000 feet to 40,000 feet. Like semisubmersibles, drillships are more expensive to construct and operate than jackups.

The drillship fleet consists of 14 units, including:

•

four dynamically positioned, harsh environment drillships currently under construction with Hyundai Heavy Industries Co. Ltd. (“HHI”), which are estimated to be delivered from the shipyard to begin acceptance testing beginning in the second quarter of 2013;

	•		three dynamically positioned Gusto Engineering Pelican Class drillships;
	•		two dynamically positioned Bully-class drillships to be operated by us through a 50 percent joint venture with a subsidiary of Shell;

•

one dynamically positioned Globetrotter-class drillship that left the shipyard during the fourth quarter of 2011;

•

one dynamically positioned Globetrotter-class drillship currently under construction, which is scheduled to be delivered to our customer in the fourth quarter of 2013;

•

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

•

one dynamically positioned NAM Nedlloyd-C drillship; and

•

one conventionally moored conversion class drillship.

Jackups

We currently have 49 jackups in our fleet, including six 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 up to 400 feet.

Submersibles

We have two submersibles in the fleet which are currently 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 up to 70 feet.

Drilling Fleet Table

The following table sets forth certain information concerning our offshore fleet at February 15, 2012. 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

Brazil

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

Israel

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

U.S. Gulf of Mexico

Active

Noble Paul Romano

Noble EVA-4000™

1998 R/2007 M

6,000

32,500

Egypt

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 - 14

Noble Bully I (3)(5)(6)

GustoMSC Bully PRD 12000

2011 N

8,200

40,000

U.S. Gulf of Mexico

Pre-Contract

Noble Bully II (3)(5)(6)

GustoMSC Bully PRD 12000

2011 N

8,200

40,000

Brazil

Pre-Contract

Noble Discoverer (3)

Sonat Discoverer Class

2009 R

1,000

20,000

New Zealand

Active

Noble Duchess

Conversion

1975

1,500

25,000

Singapore

Active

Noble Globetrotter I (3)(5)

Globetrotter Class

2011 N

10,000

30,000

U.S. Gulf of Mexico

Pre-Contract

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

2009 R

5,000

25,000

Brazil

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

Noble Newbuild Drillship #3 (3)

Hyundai Gusto P 10000

2014 N

12,000

40,000

South Korea

Shipyard

Noble Newbuild Drillship #4 (3)

Hyundai Gusto P 10000

2014 N

12,000

40,000

South Korea

Shipyard

Independent Leg Cantilevered Jackups - 49 (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

The Netherlands

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

Bahrain

Active

Noble Don Walker

Baker Marine BMC 150-SD

1992 R

150

20,000

Cameroon

Stacked

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

Saudi Arabia

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

Germany

Active

Noble Gus Androes

Levingston Class 111-C

2004 R

300

30,000

U.A.E.

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 - 49 (Continued from previous page)

Noble Hans Deul (3)

F&G JU-2000E

2009 N

400

30,000

U.K.

Active

Noble Harvey Duhaney

Levingston Class 111-C

2001 R

300

25,000

U.A.E.

Active

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

Saudi Arabia

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 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

Saudi Arabia

Active

Noble Ronald Hoope (3)

MSC/CJ-46

1982

250

25,000

The Netherlands

Active

Noble Roy Butler

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

Oman

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

Saudi Arabia

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

Nigeria

Active

Noble Jackup I- Newbuild (3)

F&G JU-3000N

2012 N

400

30,000

Singapore

Shipyard

Noble Jackup II- Newbuild (3)

F&G JU-3000N

2013 N

400

30,000

Singapore

Shipyard

Noble Jackup III- Newbuild (3)

F&G JU-3000N

2013 N

400

30,000

Singapore

Shipyard

Noble Jackup IV- Newbuild (3)

F&G JU-3000N

2014 N

400

30,000

Singapore

Shipyard

Noble Jackup V- Newbuild (3)

F&G JU-3000N

2014 N

400

30,000

Singapore

Shipyard

Noble Jackup VI- Newbuild (3)

F&G JU-3000N

2014 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

Stacked

Footnotes to Drilling Fleet Table

Facilities

Our corporate office is located in Baar, Switzerland, and we maintain 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 16 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.

Item 4.		Mine Safety Disclosures.

Not applicable.

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
2011
Fourth quarter		$	38.42			$	28.58			$	0.14
Third quarter			39.70				27.68				0.17
Second quarter			46.10				37.51				0.15
First quarter			46.12				35.64				0.14
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

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 13, 2012, there were 252,170,859 shares outstanding held by 849 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—Dividends 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.”

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 (2)				per Share				or Programs				or Programs (1)
October 2011			183			$	37.55				—				6,769,891
November 2011			1,046			$	37.15				—				6,769,891
December 2011			4,607			$	31.33				—				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, 2007 to December 31, 2011. 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, 2007 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		2007				2008				2009				2010				2011
Noble Corporation		$	148.80			$	59.16			$	109.61			$	99.03			$	85.00
S&P 500 Index			105.49				66.46				84.05				96.71				98.76
Dow Jones U.S. Oil Equipment & Services			144.95				59.00				97.43				124.07				108.65

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, 2011, 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,
		2011				2010				2009				2008				2007
		(In thousands, except per share amounts)
Statement of Income Data
Operating revenues		$	2,695,832			$	2,807,176			$	3,640,784			$	3,446,501			$	2,995,311
Net income attributable to Noble Corporation			370,898				773,429				1,678,642				1,560,995				1,206,011
Net income per share:
Basic			1.46				3.03				6.44				5.85				4.49
Diluted			1.46				3.02				6.42				5.81				4.45
Balance Sheet Data (at end of period)
Cash and marketable securities		$	239,196			$	337,871			$	735,493			$	513,311			$	161,058
Property and equipment, net			11,897,467				10,048,087				6,634,452				5,647,017				4,795,916
Total assets			13,495,159				11,302,387				8,396,896				7,106,799				5,876,006
Long-term debt			4,071,964				2,686,484				750,946				750,789				774,182
Total debt (1)			4,071,964				2,766,697				750,946				923,487				784,516
Total equity			8,097,852				7,287,634				6,788,432				5,290,715				4,308,322
Other Data
Net cash from operating activities		$	758,984			$	1,654,376			$	2,136,716			$	1,888,192			$	1,414,373
Net cash from investing activities			(2,540,290	)			(2,913,943	)			(1,495,059	)			(1,129,293	)			(1,223,873	)
Net cash from financing activities			1,682,631				861,945				(419,475	)			(406,646	)			(91,152	)
Capital expenditures			2,639,979				1,423,484				1,431,498				1,231,321				1,287,043
Working capital			232,432				110,347				1,049,243				561,348				367,419
Cash dividends/par value reduction declared per share (2) (3)			0.60				0.88				0.18				0.91				0.12

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, 2011 and 2010, and our results of operations for each of the years in the three-year period ended December 31, 2011. You should read the accompanying consolidated financial statements and related notes in conjunction with this discussion.

Executive Overview

Our 2011 financial and operating results include:

	•		operating revenues totaling $2.7 billion;
	•		net income of $371 million or $1.46 per diluted share;
	•		net cash from operating activities totaling $759 million; and
	•		an increase in debt to 33.5 percent of total capitalization at the end of 2011, up from 27.5 percent at the end of 2010 due to the issuance of $1.1 billion in senior notes and $935 million additional debt being drawn on our credit facilities.

During 2011, we began to see some stability in the offshore drilling market after a period of volatility which occurred following the Deepwater Horizon incident in 2010 and the U.S. governmental response to the incident. In the U.S. Gulf of Mexico, the granting of permits and publication of new safety rules has led to more stable activity levels within the industry, especially as it relates to the deepwater markets. This resumption of activity has led to greater investment within the U.S. Gulf of Mexico and is contributing to an improvement in dayrates for deepwater and ultra-deepwater rigs worldwide. While there are still risks, including potential third party environmental lawsuits targeting the permitting process, possible new drilling regulations, a failure of the Bureau of Ocean Energy Management Regulation and Enforcement (“BOEMRE”) to issue permits in a timely manner and the adoption by individual operators of new drilling or equipment standards exceeding those required by regulatory bodies, we believe those risks will be reduced as long as rigs continue to work without incident in the U.S. Gulf of Mexico.

The offshore drilling market displayed indications of improvement during 2011 even though there continues to be uncertainty regarding the sustainability of the global economic recovery, which is proceeding unevenly in different geographic regions. In addition to the political instability in certain oil producing nations in the Middle East and North Africa, there is also uncertainty regarding recovery in the credit markets, particularly in Europe and North America. During 2011, oil prices fluctuated as a result of supply side concerns in response to political unrest in the Middle East and North Africa. Natural gas prices in the United States fluctuated during the year, and ended the year at historical lows. We believe there continues to be competing factors which could impact the volatility in the offshore drilling market and the prices of oil and gas commodities for the foreseeable future.

Despite the instability in the global economy noted above, we saw an increase in demand for offshore drilling services in 2011. We believe both the short-term and long-term outlook for the deepwater market continues to strengthen. Market dayrates for new ultra-deepwater units remain generally above $500,000, which is lower than the peak rates achieved in 2007 and 2008, but higher than rates seen in 2010. Short-term fixtures for very high specification units have exceeded $550,000, and we believe this is an indication of where the market could be going should there continue to be a strong demand for ultra-deepwater drilling units. Although demand for jackup units decreased slightly during 2010, utilization rates for such units stabilized in 2011, especially for those units equipped with standard drilling features. We continue to see differentiation in the jackup market with newer units having utilization rates and dayrates exceeding those units that entered service before 2000, as customers display a preference for technologically advanced and efficient drilling alternatives.

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 access to 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 analysts widely report that a significant expansion of industry supply of both jackups and ultra-deepwater units is underway. 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.

As a result of exploration discoveries offshore Brazil, Petroleo Brasileiro S.A. (“Petrobras”), the Brazilian national oil company, recently announced that it had approved contracts with two contractors to lease a total of 26 drilling rigs, which are expected to be delivered in the next 48 to 90 months. The potential increase in supply from the Petrobras newbuilds could adversely impact overall industry dayrates and economics.

As of February 15, 2012, we have 10 rigs under contract in Mexico with Pemex Exploracion y Produccion (“Pemex”), and three of these rigs have contracts scheduled to expire in 2012. Pemex continues to tender for additional jackup rigs as it attempts to increase the number of working rigs. Some previous tenders published by Pemex contained a requirement that certain units must have entered service since the year 2000. While Pemex did not succeed in securing a significant number of newer rigs from those published tenders, 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 a majority 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. We remain optimistic that many, if not all, of our rigs currently operating in Mexico will be able to continue to secure long-term work with 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 agreed to substitute the Noble Phoenix, then under contract with Shell in Southeast Asia, for the Noble Muravlenko. In connection with the cancellation of the contract on the Noble Phoenix, we recognized a non-cash gain of approximately $52.5 million during the first quarter of 2011, which represents the unamortized fair value of the in-place contract assumed in connection with the Frontier acquisition. As a result of the substitution, we reached a decision not to proceed with the previously announced reliability upgrade to the Noble Muravlenko that was scheduled to take place in 2013. As a result, we incurred a non-cash charge of approximately $32.6 million related to the termination of outstanding shipyard contracts. We expect the actual substitution to take place in the second quarter of 2012 after the Noble Phoenix completes its shipyard work.

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 through 2012, are designed to enhance the reliability and operational performance of these drillships. During the first quarter of 2012, the Noble Leo Segerius completed the shipyard portion of its reliability upgrade and departed the shipyard in Brazil for seatrials, final commissioning and customer acceptance activities. The Noble Leo Segerius is currently scheduled to return to work in the first quarter of 2012. The Noble Roger Eason is expected to enter the shipyard for its reliability upgrade in the second quarter of 2012, which is expected to take approximately 270 days to complete. There are a number of risks associated with shipyard projects of this nature, particularly in Brazil, including potential project delays and cost overruns because of 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 both 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.

While we cannot predict the future level of demand or dayrates 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 and recent newbuild activity further strengthens our position, especially in deepwater drilling.

Our business strategy focuses on the active expansion of our worldwide deepwater capabilities through construction, upgrades and modifications, acquisitions and divestitures of drilling units, as well as the deployment of our drilling assets in important oil and gas producing areas.

We have actively expanded our offshore drilling and deepwater capabilities in recent years through the construction and acquisition of new rigs. As part of this technical and operational enhancement, we plan to continue pursuing opportunities to upgrade our fleet to achieve greater technological capability, which should increase our operational efficiencies.

As part of this process, we may dispose of some or all of our lower specification units and related assets and operations in one or more transactions. These dispositions may include sales of assets to third parties, a spin-off or other distribution or separation of assets. In analyzing any disposition, we will consider the strategic benefit to us of the potential transaction while seeking to secure what we consider appropriate value. To date, no potential disposition has provided the results we seek. The drilling market for lower specification units has recently improved, and we have experienced increased utilization and dayrates for these assets in certain areas. Thus, while we continue to evaluate disposition options, we believe these units should provide a positive contribution to our overall results under current market conditions. We can provide no assurance as to whether any disposition transaction will occur or what form it may take.

During 2011, we continued our newbuild program as indicated by the following activities:

•

we completed construction on the Noble Bully I, a dynamically positioned, ultra-deepwater, harsh environment drillship, owned through a joint venture with a subsidiary of Shell, that left the shipyard during the third quarter of 2011 and is scheduled to complete acceptance testing and begin operations under a long-term contract in the U.S. Gulf of Mexico during the first quarter of 2012;

•

we completed construction on the Noble Bully II, a dynamically positioned, ultra-deepwater, harsh environment drillship, owned through a joint venture with a subsidiary of Shell, that left the shipyard during the fourth quarter of 2011 and is scheduled to complete acceptance testing and begin operations under a long-term contract in Brazil during the first quarter of 2012;

•

we completed construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship that left the shipyard during the fourth quarter of 2011 and is scheduled to complete acceptance testing and begin operations under a long-term contract in the U.S. Gulf of Mexico in the second quarter of 2012;

•

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

•

we began construction on four dynamically positioned, ultra-deepwater, harsh environment drillships at Hyundai Heavy Industries Co. Ltd. (“HHI”), which are estimated to be delivered from the shipyard to begin acceptance testing beginning in the second quarter of 2013; and

	•		we began construction on six high-specification heavy duty, harsh environment jackup rigs, which are estimated to be delivered from the shipyard to begin acceptance testing beginning in the first quarter of 2013.
			Capital expenditures, including expenditures related to items noted above, totaled $2.6 billion during 2011.

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, 2011 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				2012				2013				2014				2015				2016-2023
		(In millions)
Contract Drilling Services Backlog
Semisubmersibles/Drillships (1) (4) (5)		$	11,679			$	2,079			$	2,006			$	2,038			$	1,276			$	4,280
Jackups			2,004				1,071				570				309				47				7
Total (2)		$	13,683			$	3,150			$	2,576			$	2,347			$	1,323			$	4,287
Percent of Available Operating Days Committed (3)							68	%			44	%			31	%			12	%			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.

Nigerian Operations

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 2010, we finalized settlements of this matter with each of the SEC and the DOJ. Pursuant to these settlements, we agreed to pay fines and penalties to the DOJ and the SEC and to certain undertakings, including refraining from violating the FCPA and other anti-corruption laws, self-reporting any violations of the FCPA or such laws to the DOJ and reporting to the DOJ on an annual basis our progress on anti-corruption compliance matters. 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 investigation by these or other agencies 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 additional investigations could be expensive and consume significant time and attention of our senior management.

All of our rigs operating in Nigeria are operating under temporary import permits. To date, we have been successful in obtaining new, or extending existing, temporary import permits. 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.

In April 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 Nigerian Content Development and Monitoring Board has indicated that it will require all non-Nigerian offshore drilling companies to reorganize their local operations to include Nigerian indigenous minority interests in the operating assets and to obtain the approval of the Nigerian Content Development and Monitoring Board for future work in Nigeria. 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.

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. 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 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.

RESULTS OF OPERATIONS

2011 Compared to 2010

General

Net income attributable to Noble Corporation for 2011 was $371 million, or $1.46 per diluted share, on operating revenues of $2.7 billion, compared to net income for 2010 of $773 million, or $3.02 per diluted share, on operating revenues of $2.8 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 2011 and 2010, 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, 2011 was $49 million higher than operating income for Noble-Swiss for the same period, primarily as a result of costs directly attributable to Noble-Swiss for operations support and 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 2011 and 2010 (dollars in thousands):

		Average Rig								Operating												Average
		Utilization (1)								Days (2)												Dayrates
		2011				2010				2011				2010				% Change				2011				2010				% Change
Jackups			75	%			79	%			11,794				12,376				-5	%		$	85,510			$	96,935				-12	%
Semisubmersibles			82	%			86	%			4,176				3,837				9	%			296,331				288,163				3	%
Drillships			59	%			89	%			1,284				1,392				-8	%			242,019				256,067				-5	%
Other			0	%			11	%			—				95				-100	%			—				355,986				-100	%
Total			72	%			78	%			17,254				17,700				-3	%		$	148,185			$	152,292				-3	%

Contract Drilling Services

The following table sets forth the operating revenues and the operating costs and expenses for our contract drilling services segment for 2011 and 2010 (dollars in thousands):

										Change
		2011				2010				$				%
Operating revenues:
Contract drilling services		$	2,556,758			$	2,695,493			$	(138,735	)			-5	%
Reimbursables (1)			77,278				73,959				3,319				4	%
Other			875				2,332				(1,457	)			-62	%
		$	2,634,911			$	2,771,784			$	(136,873	)			-5	%
Operating costs and expenses:
Contract drilling services		$	1,384,200			$	1,177,800			$	206,400				18	%
Reimbursables (1)			56,589				56,674				(85	)			0	%
Depreciation and amortization			647,142				528,011				119,131				23	%
Selling, general and administrative			90,262				91,094				(832	)			-1	%
Gain on contract extinguishments, net			(21,202	)			—				(21,202	)				**
			2,156,991				1,853,579				303,412				16	%
Operating income		$	477,920			$	918,205			$	(440,285	)			-48	%

Operating Revenues. Decreased contract drilling services revenues for the current year as compared to the prior year was driven by reductions in both average dayrates and operating days. The three percent decrease in average dayrates reduced revenues by approximately $71 million, and the three percent decrease in operating days decreased revenues by an additional $68 million.

The decrease in contract drilling services revenues primarily relates to our jackups, drillships and FPSO, which generated approximately $191 million, $46 million and $34 million less revenue, respectively, in 2011.

The decrease in jackup average dayrates of 12 percent resulted in a $135 million decrease in revenues from the prior year. The reduction in average dayrates was primarily from the contractual repricing of rigs in the Middle East, the North Sea, and Mexico for changes in market conditions in the global shallow water market. The five percent decline in jackup operating days resulted in a $56 million decline in revenues. The decrease in utilization primarily related to rigs coming off contract in Mexico and the Middle East during 2011, the majority of which did not return to work until the latter part of the year.

The decrease in drillship revenue was primarily driven by reduced dayrates of five percent and an eight percent decrease in operating days, which resulted in decreased revenues of $18 million and $28 million, respectively, from the prior year. The decrease in drillship revenue is primarily the result of increased downtime in Brazil, as rigs entered the shipyard for upgrades and repairs.

Revenue from our FPSO, the Noble Seillean, decreased $34 million as it was not under contract in 2011.

The decreases in revenue for the above rig classes were partially offset by an increase in revenue of $132 million from our semisubmersibles. The increase was primarily attributable to a nine percent increase in operating days and three percent increase in average dayrates, which contributed additional revenue in 2011 of $98 million and $34 million, respectively. The increase is primarily attributable to operations from the newbuilds, Noble Dave Beard and Noble Jim Day, which were added to the fleet in March 2010 and January 2011, respectively. Additionally, the Noble Driller was added to the fleet in July 2010 as part of the Frontier acquisition.

Operating Costs and Expenses. Contract drilling services operating costs and expenses increased $206 million for the current year as compared to the prior year. The rigs added to the fleet as part of the Frontier acquisition and the Noble Dave Beard and the Noble Jim Day added approximately $120 million of operating costs in the current year. Excluding the additional expenses related to these rigs, our contract drilling costs increased $86 million in the current year from the prior year. This increase was primarily driven by a $22 million increase in maintenance and rig-related expenses, $20 million increase in mobilization costs, $18 million increase in labor costs, and an $11 million increase in safety and training costs. These cost increases were primarily for our rigs returning, or preparing to return, to work in Brazil and Mexico. Additionally, rotation costs and operations support costs increased $10 million and $5 million, respectively.

Depreciation and amortization increased $119 million in 2011 over 2010 as a result of depreciation on newbuilds placed into service, rigs added to the fleet as part of the Frontier acquisition and additional depreciation related to other capital expenditures on our fleet since the beginning of 2010.

Other

The following table sets forth the operating revenues and the operating costs and expenses for our other services for 2011 and 2010 (dollars in thousands):

										Change
		2011				2010				$				%
Operating revenues:
Labor contract drilling services		$	59,004			$	32,520			$	26,484				81	%
Reimbursables (1)			1,917				2,872				(955	)			-33	%
		$	60,921			$	35,392			$	25,529				72	%
Operating costs and expenses:
Labor contract drilling services		$	33,885			$	22,056			$	11,829				54	%
Reimbursables (1)			1,850				2,740				(890	)			-32	%
Depreciation and amortization			11,498				11,818				(320	)			-3	%
Selling, general and administrative			1,115				903				212				23	%
			48,348				37,517				10,831				29	%
Operating income		$	12,573			$	(2,125	)		$	14,698				-692	%

Operating Revenues and Costs and Expenses. The increase in both revenue and expense primarily relates to the commencement of a refurbishment project with our customer, Shell, for one of its rigs to be operated under a labor contract in Alaska, combined with operational increases and foreign currency fluctuations in our Canadian operations.

Other Income and Expenses

Selling, general and administrative expenses. Overall selling, general and administrative expenses were consistent with 2010 as a $6 million increase primarily related to ongoing legal and tax expenses in the current year was offset by a $6 million decrease resulting from the absence of costs related to our completed FCPA investigation in the prior year.

Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $46 million in 2011 from 2010. The increase is a result of $1.25 billion of debt issued in July 2010, which was used to partially fund the Frontier acquisition, $1.1 billion of debt issued in February 2011, which was primarily used to repay the outstanding balance on our revolving credit facility and to repay our portion of outstanding debt under the joint venture credit facilities, and current year drawdowns on the credit facilities.

Income Tax Provision. Our income tax provision decreased $70 million in 2011 compared to 2010 primarily due to a reduction in pre-tax earnings, which was partially offset by a higher effective tax rate. Pre-tax earnings decreased approximately 52 percent in 2011 compared to 2010 resulting in a reduction of approximately $75 million in income tax expense. The higher effective tax rate, which was 16.7 percent in 2011 compared to 15.6 percent in 2010, increased income tax expense by approximately $5 million. The increase in the effective tax rate was a result of a change in our geographic revenue mix primarily resulting from drilling restrictions in the U.S. Gulf of Mexico, partially offset by the resolution of discrete tax items.

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 (dollars in thousands):

		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 (dollars in thousands):

										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	%