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

For the fiscal year ended December 31, 2007

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

For the transition period from                      to                     

Commission file number: 001-31306

NOBLE CORPORATION

(Exact name of registrant as specified in its charter)

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

13135 South Dairy Ashford, Suite 800, Sugar Land, Texas 77478
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, Including Area Code: (281) 276-6100
Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Ordinary Shares, Par Value $.10 Per Share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

     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 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.     þ

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
		(Do not check if a smaller reporting company)

     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 29, 2007, the aggregate market value of the registrant’s ordinary shares held by non-affiliates of the registrant was $12.9 billion based on the closing sale price as reported on the New York Stock Exchange.

     Number of Ordinary Shares outstanding as of February 15, 2008: 268,645,643

DOCUMENTS INCORPORATED BY REFERENCE

     Listed below are documents parts of which are incorporated herein by reference and the part of this report into which the document is incorporated:

     (1) Proxy statement for the 2008 annual general meeting of members scheduled to be held on May 1, 2008 — Part III

 

 

TABLE OF CONTENTS

		PAGE
PART I
ITEM 1. BUSINESS			1
General			1
Business Strategy			1
Business Development During 2007			2
Drilling Contracts			3
Offshore Drilling Operations			4
Contract Drilling Services			4
Labor Contracts			4
Competition			4
Governmental Regulation and Environmental Matters			5
Employees			5
Financial Information about Segments and Geographic Areas			5
Available Information			5
ITEM 1A. RISK FACTORS			6
Risk Factors			6
Forward-Looking Statements			12
ITEM 1B. UNRESOLVED STAFF COMMENTS			12
ITEM 2. PROPERTIES			13
Drilling Fleet			13
Semisubmersibles			13
Dynamically Positioned Drillships			13
Independent Leg Cantilevered Jackups			13
Submersibles			13
Drilling Fleet Table			14
Facilities			17
ITEM 3. LEGAL PROCEEDINGS			17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			17
EXECUTIVE OFFICERS OF THE REGISTRANT			17
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			18
ITEM 6. SELECTED FINANCIAL DATA			20
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			20
Executive Overview			21
Internal Investigation			22
Results of Operations			24
Liquidity and Capital Resources			32
Critical Accounting Policies and Estimates			35
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			38
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			40
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			90
ITEM 9A. CONTROLS AND PROCEDURES			90
ITEM 9B. OTHER INFORMATION			90
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			91
ITEM 11. EXECUTIVE COMPENSATION			91
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			91
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE			91
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES			91
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES			92
SIGNATURES			93
Employment Agreement - David W. Williams
Parent Guaranty of Employment Agreement - David W. Williams
Amendment No. 4 to 401(k) Savings Restoration Plan
Subsidiaries of the Registrant
Consent of PricewaterhouseCoopers LLP
Certification of David W. Williams Pursuant to Rule 13a-14(a) or Rule 15d-14(a)
Certification of Thomas L. Mitchell Pursuant to Rule 13a-14(a) or 15d-14(a)
Certification of David W. Williams Pursuant to Section 906
Certification of Thomas L. Mitchell Pursuant to Section 906

PART I

long-term drilling contract that covers a substantial portion of our capital investment and provides an acceptable return on our capital employed.

     We have developed personnel retention programs that we believe are important to allow us to attract and retain the skilled personnel required to maintain safe and efficient operations in our competitive industry. Because hydrocarbon exploration and development activities have increased in recent years, the drilling industry has experienced significant increases in dayrates for drilling services in most markets, a tightening market for drilling equipment, and a shortage of personnel. This environment has driven operating costs higher and magnified the importance of recruiting, training and retaining skilled personnel. In recognition of the importance of our offshore operations personnel in achieving a safety record that has consistently outperformed the offshore drilling industry sector and to retain such personnel, since 2005 we have implemented three separate key operations personnel retention programs. First, in 2005 we implemented an incentive program for personnel associated with our day-to-day rig-based operations. Under this program, we distribute incentive payments based upon individual performance over the three-year period 2006-2008. Second, in 2006 we implemented a program for shore-based and engineering personnel under which participants may receive payments over the four-year period 2006-2009. Third, in 2007 we implemented a follow-on to the first program for personnel associated with our day-to-day rig-based operations. Under the 2007 program, we will make performance-based payments over the three-year period 2008-2010. We believe these programs will complement our other short- and long-term incentive programs to attract and retain the skilled personnel we need to maintain safe and efficient operations.

     Our active participation in the consolidation of the offshore drilling industry continues to be an important element of our growth strategy. Consolidation typically takes one of two forms: an individual transaction for specific mobile offshore drilling units or a transaction for an entire company. In the last five years, we have added six premium jackups to our fleet through individual rig transactions. From time to time, we evaluate other individual rig transactions and business combinations with other parties, and we will continue to consider business opportunities that promote our business strategy.

BUSINESS DEVELOPMENT DURING 2007

     We entered into a drilling contract with a wholly-owned subsidiary of Marathon Oil Corporation for the Noble Jim Day , a Bingo 9000 design to be completed as a dynamically positioned (DP-3) unit capable of operating in water depths up to 12,000 feet with living accommodations for 200 persons. The unit’s highly efficient operational design is similar to that of the Noble Danny Adkins , currently under construction in Singapore. The Noble Jim Day , currently under construction in Singapore, is expected to operate in the U.S. Gulf of Mexico at a dayrate of $515,000 commencing in the fourth quarter of 2009.

     We entered into a drilling contract with Petróleos Mexicanos (“Pemex”) for the Noble Max Smith at a dayrate of $484,000. The Noble Max Smith will be the first mobile offshore rig capable of drilling in water depths up to 7,000 feet to operate offshore Mexico. The Noble Max Smith is expected to commence operating under its Pemex contract in the third quarter of 2008 after completion of its current contract in the U.S. Gulf of Mexico and time in the shipyard for regulatory inspections and contract preparation.

     In response to the effects of Hurricanes Ivan, Katrina and Rita during the 2004 and 2005 hurricane seasons, the U.S. Minerals Management Service (“MMS”), working together with the U.S. Coast Guard and industry, has developed and issued interim guidelines for moored drilling rig fitness requirements in the U.S. Gulf of Mexico.  We worked closely with the MMS in the formulation of these guidelines, which were designed to improve performance in the area of moored rig station-keeping during the environmental loading that may be experienced during hurricanes. The interim guidelines were in effect for the 2006 and 2007 hurricane seasons. Our recently developed Noble Category 5 (NC-5 ^SM ) mooring standard meets the interim guidelines. We upgraded the mooring systems on the Noble Paul Romano and the Noble Jim Thompson to the NC-5 ^SM standard in 2007 and 2006, respectively. The mooring system on the Noble Amos Runner semisubmersible is scheduled to be upgraded in 2008.

     In 2007, we continued to upgrade the capabilities of our deepwater fleet through the use of our patented aluminum alloy drilling riser (“AAR”), which is used in place of steel risers to connect floating drilling units to equipment on the seabed. We have equipped each of the newbuild semisubmersible rigs, including the Noble Clyde Boudreaux which went into service in the second quarter of 2007, with the AAR. The AAR can be manufactured cost competitively as compared to a steel riser, but the AAR weighs significantly less (up to 40 percent less) than the

typical steel riser. This significant savings in weight allows us to extend the water depth specifications of our floating drilling units with less capital investment.

     We completed the planned rationalization of our technology services division in the fourth quarter of 2007 with the sale of the rotary steerable system assets and intellectual property of our Noble Downhole Technology Ltd. (“Downhole Technology”) subsidiary. In the first quarter of 2007, we closed the operations of our Triton Engineering Services Inc. (“Triton”) subsidiary.

     At January 11, 2008, our contracted backlog totaled approximately $6.7 billion with 39 of our rigs contracted for 2008 and thereafter. We anticipate that the primary terms of the current contracts on 21 of our rigs will expire at varying times in 2008. At January 11, 2008, approximately 81 percent of our available operating days were committed for 2008, approximately 40 percent for 2009 and approximately 15 percent for 2010, which percentages take into account new capacity under our newbuild rigs that we anticipate commencing operations during the 2008 through 2009 period.

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 competitive bidding. Our drilling contracts generally contain the following terms:

	•		contract duration extending over a specific period of time or a period necessary to drill one or more wells;
	•		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 either breakdown of major equipment or “force majeure” events beyond our control and the control of the customer;
	•		options in favor of the customer to extend the contract term, generally upon advance notice to us and usually (but not always) at mutually agreed upon rates;
	•		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 our customers (in contracts for approximately 67 percent of our rigs).

     The terms of some of our drilling contracts permit early termination of the contract by the customer, without cause, generally exercisable upon advance notice to us and in some cases upon the making of an early termination payment to us. Certain of our drilling contracts with Pemex in Mexico, for example, contain provisions that allow early cancellation on 30 days or less notice to us without Pemex making an early termination payment.

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

     Generally, our contracts allow us to recover our mobilization and demobilization costs associated with moving a drilling unit from one regional location to another. When market conditions require us to bear these costs, our operating margins are reduced accordingly. We cannot predict our ability to recover these costs in the future.

For shorter moves such as “field moves”, our customers have generally agreed to bear the costs of moving the unit by paying us a reduced dayrate or “move rate” while the unit is being moved.

OFFSHORE DRILLING OPERATIONS

Contract Drilling Services

     We conduct offshore contract drilling operations, which accounted for approximately 93 percent, 93 percent and 90 percent of operating revenues for the years ended December 31, 2007, 2006 and 2005, respectively. We conduct our contract drilling operations principally in the Middle East, India, U.S. Gulf of Mexico, Mexico, the North Sea, Brazil, and West Africa. In 2007, Pemex accounted for approximately 15 percent of our total operating revenues. No other single customer accounted for more than 10 percent of our total operating revenues in 2007.

     Our contract drilling services revenues from international sources accounted for approximately 76 percent, 72 percent and 77 percent of total contract drilling services revenues for 2007, 2006 and 2005, respectively.

     Our contract drilling services revenues generated in the U.S. accounted for approximately 24 percent, 28 percent and 23 percent of our total contract drilling services revenues for 2007, 2006 and 2005, respectively.

Labor Contracts

     We perform services under labor contracts for drilling and workover activities covering 11 rigs operating in the United Kingdom sector of the North Sea and two rigs under a labor contract (the “Hibernia Contract”) off the east coast of Canada. We do not own or lease these rigs.

     Under our labor contracts, we provide the personnel necessary to manage and perform the drilling operations from drilling platforms owned by the operator. With the exception of the Hibernia Contract, which is operating under a recently renewed five-year agreement that extends through January 2013, our labor contracts are generally renewable on an annual basis.

     In January 2008, we reached agreement to sell our North Sea labor contract drilling services business to Seawell Holding UK Limited (“Seawell”) for $35 million. The sale to Seawell includes labor contracts covering 11 platform operations in the United Kingdom sector of the North Sea. These operations employ approximately 450 people and generated $96.2 million of revenue in 2007. The Hibernia Contract is not included in this sale. Closing is subject to regulatory approval and other customary closing conditions and is expected to occur on or about March 31, 2008.

     Additionally, we operate the Noble Kolskaya through a bareboat charter that expires by its terms in July 2008. Under the bareboat charter, we receive a 30 percent effective net profit interest in the Noble Kolskaya operations.

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 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.

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

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

GOVERNMENTAL REGULATION 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. 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.

     The U.S. Oil Pollution Act of 1990 (“OPA 90”) and regulations thereunder impose certain additional operational requirements on our offshore rigs operating in the U.S. Gulf of Mexico and govern liability for leaks, spills and blowouts involving pollutants. Regulations under OPA 90 require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. 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 any differently or to any greater or lesser extent than other companies in the energy services industry.

EMPLOYEES

     At December 31, 2007, we employed approximately 6,600 persons, including persons engaged through labor contractors or agencies. Of the 6,600 persons, approximately 79 percent were engaged in international operations and approximately 21 percent were engaged in U.S. operations. We are not a party to any collective bargaining agreements that are material, and we consider our employee relations to be satisfactory.

FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHIC AREAS

     Information regarding our revenues from external customers, segment profit or loss and total assets attributable to each segment for the last three fiscal years is presented in Note 15 to our consolidated financial statements included in this Annual Report on Form 10-K.

     Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operations for the last three fiscal years is presented in Note 15 to our consolidated financial statements included in this Annual Report on Form 10-K.

AVAILABLE INFORMATION

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

ITEM 1A. RISK FACTORS .

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 ordinary shares.

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

     Demand for drilling services depends on a variety of economic and political factors and the level of activity in offshore oil and gas exploration, development and production markets worldwide. Commodity prices, and market expectations of potential changes in these prices, 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:

	•		the political environment of oil-producing regions, including uncertainty or instability resulting from an outbreak or escalation of armed hostilities or acts of war or terrorism;
	•		worldwide demand for oil and gas, which is impacted by changes in the rate of economic growth in the U.S. and other international economies;
	•		the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and pricing;
	•		the level of production in non-OPEC countries;
	•		the policies and regulations of the various governments regarding exploration and development of their oil and gas reserves;
	•		the cost of exploring for, developing, producing and delivering oil and gas;
	•		the discovery rate of new oil and gas reserves;
	•		the rate of decline of existing and new oil and gas reserves;
	•		available pipeline and other oil and gas transportation capacity;
	•		the ability of oil and gas companies to raise capital;
	•		adverse weather conditions (such as hurricanes and monsoons) and seas;
	•		the development and exploitation of alternative fuels;
	•		tax policy; and
	•		advances in exploration, development and production technology.

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 have reduced 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 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.

     Although oil and natural gas prices are currently above historical averages resulting in higher utilization and dayrates earned by our drilling units, we can give no assurance that such prices will not decrease, perhaps materially, or that the current industry cycle of high demand, short rig supply and higher dayrates will continue.

     The increase in supply created by the number of rigs being built, as well as changes in our competitors’ drilling rig fleets, could intensify price competition and require higher capital investment to keep our rigs competitive. In addition, the supply attributable to newbuild rigs, especially those being built on speculation, could cause a reduction in future dayrates. In certain markets, for example, we are experiencing competition from newbuild jackups that are scheduled to enter the market in 2008. The inability of the market to absorb these newbuild jackups may result in lower marketplace dayrates for jackups.

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

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

	•		shortages of equipment, materials or skilled labor;
	•		work stoppages and labor disputes;
	•		unscheduled delays in the delivery of ordered materials and equipment;
	•		local customs strikes or related work slowdowns that could delay importation of equipment or materials;
	•		weather interferences;
	•		difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;
	•		design and engineering problems;
	•		latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
	•		unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
	•		unanticipated actual or purported change orders;
	•		client acceptance delays;
	•		disputes with shipyards and suppliers;

	•		shipyard failures and difficulties; and
	•		failure or delay of third-party equipment vendors or service providers.

     Failure to complete a rig upgrade or new construction on time, or the inability to complete a rig conversion or new construction in accordance with its design specifications, may, in some circumstances, result in loss of revenues, penalties, or delay, renegotiation or cancellation of a drilling contract. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms. 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.

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 has increased, shortages of qualified personnel have occurred from time to time. Shortages of such personnel could result as the rigs currently being built enter service. 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.

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

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

     The 2005 losses sustained in the oil and gas industry from Hurricanes Katrina and Rita had a material adverse impact on marine energy insurance markets. Subsequent to these losses, the insurance industry has generally offered reduced coverage for U.S. Gulf of Mexico named windstorm perils, and has priced premiums for renewal programs of insured parties that sustained losses from these 2005 hurricanes on a basis designed to recover hurricane-related underwriting losses in an accelerated manner, particularly for companies that have an exposure in the U.S. Gulf of Mexico. Our March 2007 insurance program renewal included an annual aggregate coverage limit of $200 million applicable to our drilling units operating in the U.S. Gulf of Mexico for physical damage and loss of hire resulting from named windstorm perils. Our units operating in the U.S. Gulf of Mexico include six semisubmersibles and three submersibles. This coverage limit may not fully insure our losses in the event that one or more named windstorms damage our drilling units in the U.S. Gulf of Mexico. The reduced coverage does not apply to our units in the Mexican portion of the 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 further increases in insurance costs, additional coverage restrictions or unavailability of certain insurance products.

     Although we maintain insurance in the geographic areas in which we operate, pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet. Uninsured exposures may include war risk, activities prohibited by U.S. laws and regulations, radiation hazards, certain loss or damage to property on board our rigs and losses relating to 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. There can be no assurance that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks.

Demand for our drilling services may decrease due to events beyond our control.

     Our business could be impacted by events beyond our control including changes in our customers’ drilling programs or budgets driven by their internal corporate events, changes in the 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 provisions found in some of our drilling contracts, for a variety of reasons, many of which are beyond our control. Depending upon market conditions, our customers may also seek renegotiation of firm drilling contracts to reduce their obligations. If the future level of demand for our drilling services or if future conditions in the offshore contract drilling industry decline, our financial position, results of operations and cash flows could be adversely affected.

Our business involves numerous operating hazards.

     Our operations are subject to many hazards inherent in the drilling business, including blowouts, cratering, 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.

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. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs.

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

Our international operations involve additional risks not associated with U.S. Gulf of Mexico operations.

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

	•		terrorist acts, war and civil disturbances;
	•		seizure, nationalization or expropriation of property or equipment;
	•		foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
	•		the inability to repatriate income or capital;
	•		complications associated with repairing and replacing equipment in remote locations;
	•		piracy;
	•		import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;
	•		regulatory or financial requirements to comply with foreign bureaucratic actions; and
	•		changing taxation policies.

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

	•		the importing, exporting, equipping and operation of drilling units;
	•		repatriation of foreign earnings;
	•		currency exchange controls;
	•		oil and gas exploration and development;
	•		taxation of offshore earnings and earnings of expatriate personnel; and
	•		use and compensation of local employees and suppliers by foreign contractors.

     Our ability to do business in a number of jurisdictions is subject to maintaining required licenses and permits and complying with applicable laws and regulations. We are operating drilling units offshore Nigeria, and there is a risk that we may not be able to obtain new or extended temporary importation permits for these units necessary to continue uninterrupted operations in Nigerian waters for the duration of the units’ drilling contracts. We cannot predict what changes, if any, relating to temporary import policies and procedures may be established or implemented in Nigeria in the future. For additional information regarding our ongoing internal investigation of our Nigerian operations and the status of our temporary import permits in Nigeria, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Internal Investigation”. 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.

     During the fourth quarter of 2007, our Nigerian subsidiary received letters from a Nigerian government agency 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 letters are applicable to our ownership of drilling units, the agency may be seeking to apply a provision of the Nigerian cabotage laws (which became effective on May 1, 2004) to our offshore drilling units by

considering these units to be “vessels” within the meaning of those laws and therefore subject to the surcharge, which is imposed only upon “vessels”. Our offshore drilling units are not engaged in the Nigerian coastal shipping trade and are not in our view “vessels” within the meaning of Nigeria’s cabotage laws. On January 24, 2008, we filed an originating summons in the Federal High Court of Lagos, Nigeria seeking, among other things, a declaration that our drilling operations do not constitute “coastal trade” or “cabotage” within the meaning of Nigeria’s cabotage laws and our offshore drilling units are not “vessels” within the meaning of those laws. 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.

     Governmental action, including initiatives by OPEC, may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some foreign 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.

We could be adversely affected by violations of applicable anti-corruption laws.

     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 our 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”). Any such violation 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. For a discussion of an ongoing internal investigation relating to our operations in Nigeria, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Internal Investigation”.

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

     Due to our international operations, 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, environmental claims or proceedings, asbestos and other toxic tort claims, 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.

We are subject to changes in tax laws.

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

     In 2004, the U.S. Congress enacted legislation as part of the American Jobs Creation Act of 2004 (the “AJCA”) that tightened the rules regarding corporate inversion transactions, which legislation grandfathered companies that implemented an inversion transaction before March 4, 2003. Noble’s corporate inversion effected on April 30, 2002 was therefore grandfathered. Nevertheless, there has been activity in the U.S. Congress subsequent to the AJCA to enact legislation that would retroactively reverse the status of Noble under the law. Congress may approve future tax legislation relating to Noble’s corporate inversion. Any such legislation could contain provisions that would subject Noble to U.S. Federal income tax as if Noble were a U.S. corporation. Payment of any such tax would reduce our net income. We cannot predict what legislation relating to Noble’s corporate inversion, if any, may result from any future Congressional legislative activities.

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

Forward-Looking Statements

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

ITEM 2. PROPERTIES.

DRILLING FLEET

     Our offshore fleet is composed of the following types of units: semisubmersibles, dynamically positioned drillships, independent leg cantilevered jackups and submersibles. Each type is described further below. Several factors determine the type of unit most suitable for a particular job, the most significant of which include the water depth and bottom conditions at the proposed drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth.

Semisubmersibles

     Our semisubmersible fleet consists of 13 units. Among the 13 are five units that have been converted to Noble EVA-4000™ semisubmersibles and three Friede & Goldman 9500 Enhanced Pacesetter semisubmersibles. This fleet also includes two Pentagone 85 semisubmersibles, two Bingo 9000 baredeck hulls (the Noble Danny Adkins and Noble Jim Day , both of which are under construction), and one semisubmersible capable of operating in harsh environments. 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 can drill. However, semisubmersibles normally require water depth of at least 200 feet in order to conduct operations. Our semisubmersibles are capable of drilling in water depths of up to 12,000 feet, depending on the unit. Semisubmersibles are more expensive to construct and operate than jackups.

Dynamically Positioned Drillships

     We have three dynamically positioned drillships in the fleet. Drillships are ships that are equipped for drilling and are typically self-propelled. Our units are positioned over the well through the use of a computer controlled dynamic positioning system. Two wholly-owned drillships, the Noble Leo Segerius and Noble Roger Eason , are capable of drilling in water depths up to 5,600 feet and 7,200 feet, respectively. The Noble Muravlenko , in which we own an 82 percent interest through a joint venture, is capable of drilling in water depths up to 4,900 feet.

Independent Leg Cantilevered Jackups

     We have 43 jackups in the fleet, including the Noble Hans Deul and Noble Scott Marks , which are under construction. Jackups are mobile, self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established for support. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. All of our jackups are independent leg (i.e., the legs can be raised or lowered independently of each other) and cantilevered. A cantilevered jackup has a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over pre-existing platforms or structures. Moving a rig to the drill site involves jacking up its legs until the hull is floating on the surface of the water. The hull is then towed to the drill site by tugs and the legs are jacked down to the ocean floor. The jacking operation continues until the hull is raised out of the water, and drilling operations are conducted with the hull in its raised position. Our jackups are capable of drilling to a maximum depth of 30,000 feet in water depths ranging between eight and 400 feet, depending on the jackup.

Submersibles

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

Drilling Fleet Table

     The following table sets forth certain information concerning our offshore fleet at January 11, 2008. The table does not include any units owned by operators for which we had labor contracts. We operate and, unless otherwise indicated, own all of the units included in the table. All of our units are equipped with top drives.

See footnotes on the following page.

Footnotes to Drilling Fleet Table

(1)		Rigs designated with an “R” were modified, refurbished or otherwise upgraded in the year indicated by capital expenditures in an amount deemed material by management. Rigs designated with an “N” are newbuilds. Rigs designated with an “M” have been upgraded to the Noble NC-5 SM mooring standard.
(2)		Rigs listed as “active” were operating under contract; rigs listed as “contracted” have signed contracts or have letters of intent with operators but have not begun operations; rigs listed as “shipyard” are in a shipyard for construction, repair, refurbishment or upgrade; rigs listed as “stacked” are idle without a contract.
(3)		Harsh environment capability.
(4)		Water depth rating is subsequent to the rig’s planned upgrade. The Noble Danny Adkins and Noble Jim Day were baredeck hulls built in 1999. We began a project to construct the Noble Danny Adkins as an ultra-deepwater semisubmersible in late 2005 and the Noble Jim Day in early 2007.
(5)		We operate the unit and own an 82 percent interest in the unit through a joint venture.
(6)		Although designed for a water depth rating of 390 feet of water in a non-harsh environment, the rig is currently equipped with legs adequate to drill in approximately 200 feet of water in a harsh environment. We own the additional leg sections required to extend the drilling depth capability to 390 feet of water.
(7)		Although designed for a water depth rating of 300 feet of water, the rig is currently equipped with legs adequate to drill in approximately 250 feet of water. We own the additional leg sections required to extend the drilling depth capability to 300 feet of water.
(8)		Although designed for a water depth rating of 328 feet of water, the rig is currently equipped with legs adequate to drill in approximately 250 feet of water. We own the additional leg sections required to extend the water depth capability to 328 feet of water.
(9)		Although designed for a water depth rating of 280 feet of water, the rig is currently equipped with legs adequate to drill in approximately 250 feet of water. We own the additional leg sections required to extend the water depth capability to 280 feet of water.
(10)		Although designed for a water depth rating of 400 feet of water, the rig is currently equipped with legs adequate to drill in approximately 225 feet of water. We own the additional leg sections required to extend the drilling depth capability to 400 feet of water.

     The Noble Jim Thompson is subject to a first naval mortgage securing project financing of $33.0 million outstanding at December 31, 2007. See Note 5 to our consolidated financial statements included in this Annual Report on Form 10-K.

FACILITIES

     Our principal executive offices are located in Sugar Land, Texas, and are leased through June 2011. We also lease administrative and marketing offices, and sites used primarily for storage, maintenance and repairs, and research and development for drilling rigs and equipment, in Zug, Switzerland; Sugar Land, Texas; New Orleans, Louisiana; Leduc, Alberta and St. John’s, Newfoundland, Canada; Lagos and Port Harcourt, Nigeria; Bata and Malabo, Equatorial Guinea; Mexico City and Ciudad del Carmen, Mexico; Doha, Qatar; Abu Dhabi and Dubai, U.A.E.; Beverwijk and Den Helder, The Netherlands; Macae, Brazil; Dalian, China; Jurong, Singapore; and Esjberg, Denmark. We own certain tracts of land, including office and administrative buildings and warehouse facilities, in Bayou Black, Louisiana and Aberdeen, Scotland.

President Production and Director Natural Gas Marketing. From 1982 to 1989, Mr. Mitchell was a manager at Arthur Andersen & Co.

     Robert D. Campbell was named Senior Vice President and General Counsel of Noble effective February 10, 2006. Mr. Campbell served as Vice President and General Counsel of Noble Drilling Services Inc. since June 2003. From January 1999 to June 2003, he served as President of Noble, and from February 1999 to April 2003, he served as a director of Noble. Prior to January 1999, Mr. Campbell practiced corporate/securities law as a senior partner with the firm of Thompson & Knight LLP and served as general counsel to Noble Drilling for more than five years.

Purchases of Ordinary Shares

     The following table sets forth for the periods indicated certain information about ordinary shares that we purchased:

										Total Number of Shares				Maximum Number of
		Total Number								Purchased as Part of				Shares that May Yet Be
		of Shares				Average Price				Publicly Announced				Purchased Under the
Period		Purchased				Paid per Share(2)(4)				Plans or Programs(1)(2)(4)				Plans or Programs(1)
October 2007			—				—				—				27,748,000
November 2007			702,720	(3)		$	51.25				693,000				27,055,000
December 2007			750,374	(5)		$	52.84				750,000				26,305,000

reclassified to conform to the current year presentation of segments. See Note 15 of our Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

EXECUTIVE OVERVIEW

			Our 2007 financial and operating results include:
	•		operating revenues totaling $3 billion;
	•		net income of $1.2 billion or $4.48 per diluted share;
	•		net cash provided by operating activities totaling $1.4 billion;
	•		an increase in our average dayrate across our worldwide fleet to $139,948 from $97,837 in 2006;
	•		taking delivery of the ultra-deepwater semisubmersible, the Noble Clyde Boudreaux , and the enhanced premium jackup, the Noble Roger Lewis ;
	•		announcement of a long-term contract for a fourth newbuild ultra-deepwater semisubmersible, the Noble Jim Day ;
	•		a two-for-one stock split in the form of a 100 percent stock dividend, with the payment of a quarterly cash dividend thereafter in an amount that effectively doubled our cash dividend paid for the quarter preceding the stock split; and
	•		a decrease in debt to 15 percent of total capitalization at the end of 2007, down from 18 percent at the end of 2006.

     Demand for drilling services depends on a variety of economic and political factors, including worldwide demand for oil and gas, the ability of OPEC to set and maintain production levels and pricing, the level of production of non-OPEC countries and the policies of the various governments regarding exploration and development of their oil and gas reserves.

     Our results of operations depend on the levels of activity in offshore oil and gas exploration, development and production in markets 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 a greater demand for our services. These prices are extremely volatile. The average Brent oil price was $72.47 per barrel during 2007, or 11 percent higher than the average Brent oil price of $65.15 per barrel during 2006, following a 20 percent increase over 2005. The average Brent oil price moderated in the first half of 2007 before increasing significantly to an average of $88.56 in the fourth quarter of 2007. The continuation of strong oil prices in 2007 supported increases in drilling activity in oil markets worldwide.

     U.S. natural gas prices reached a 20-year high in 2005, averaging $8.81 per thousand cubic feet (average Henry Hub monthly spot price). Natural gas prices moderated during 2007 and 2006, averaging $6.98 and $6.74 per thousand cubic feet, respectively. We do not have significant exposure to the U.S. natural gas markets because we have only three mobile offshore drilling units (two contracted submersibles and one cold stacked submersible) currently deployed in the shallow waters of the U.S. Gulf of Mexico. However, the moderation of natural gas prices during 2007 and 2006 has caused some competitors to move jackup rigs from the U.S. Gulf of Mexico market to various international markets and these actions may increase competition within those markets.

     At January 11, 2008, approximately 81 percent of our operating days were committed under contract for 2008, approximately 40 percent for 2009 and approximately 15 percent for 2010, which percentages take into account new capacity under our newbuild rigs that we anticipate commencing operations during the 2008 through 2009 period.

     We continue to face significant cost pressure as a result of increases in labor costs and prices for materials and services that are essential to our operations. Daily operating costs increased to $45,375 per day in 2007 from $36,100 per day in 2006. Given the current high demand for personnel and equipment, we expect to see continued pressure on operating costs in 2008.

     We cannot predict the future level of demand for our drilling services or future conditions in the offshore contract drilling industry. Decreases in the level of demand for our drilling services would have an adverse effect on our results of operations.

     Our long-standing business strategy continues to be the active expansion of our worldwide offshore drilling and deepwater capabilities through acquisitions, upgrades and modifications, and the deployment of our drilling assets in important geological areas. Since the beginning of 2001 we have added seven jackups, two deepwater semisubmersibles, and two ultra-deepwater semisubmersible baredeck hulls to our worldwide fleet through acquisitions. We have also actively expanded our offshore drilling and deepwater capabilities in recent years through the construction of new rigs. In 2007 we continued execution of our active expansion strategy as indicated by the following developments and activities:

	•		we signed a long-term drilling contract for a fourth newbuild ultra-deepwater semisubmersible, the Noble Jim Day ;
	•		we took delivery of the newbuild ultra-deepwater semisubmersible, the Noble Clyde Boudreaux , which is now operating under a long-term contract in the U.S. Gulf of Mexico;
	•		construction continued on two other newbuild ultra-deepwater semisubmersibles, the Noble Dave Beard and Noble Danny Adkins , which are scheduled for delivery in the fourth quarter of 2008 and the first quarter of 2009, respectively;
	•		construction was completed and we took delivery of our newbuild F&G JU-2000E enhanced premium independent leg cantilevered jackup, the Noble Roger Lewis , which is now operating under a long-term drilling contract in Qatar; and
	•		construction continued on two F&G JU-2000E enhanced premium independent leg cantilevered jackups, the Noble Hans Deul and Noble Scott Marks , which are being constructed in China and are scheduled for delivery in the third quarter of 2008 and the second quarter of 2009, respectively.

     Newbuild capital expenditures totaled $755 million in 2007 for our seven rigs under construction during the year.

INTERNAL INVESTIGATION

       In June 2007, we announced that we were conducting an internal investigation of our Nigerian operations, focusing on the legality under the FCPA and local laws of our Nigerian affiliate’s reimbursement of certain expenses incurred by our customs agents in connection with obtaining and renewing permits for the temporary importation of drilling units and related equipment into Nigerian waters, including permits that are necessary for our drilling units to operate in Nigerian waters. We also announced that the audit committee of Noble’s board of directors had engaged a leading law firm with significant experience in investigating and advising on FCPA matters to lead the investigation as independent outside counsel. The scope of the investigation also includes our dealings with customs agents and customs authorities in certain parts of the world other than Nigeria in which we conduct our operations, as well as dealings with other types of local agents in Nigeria and these other parts of the world. There can be no assurance that evidence of additional potential FCPA violations may not be uncovered through the investigation.

     The audit committee commissioned the internal investigation after our management brought to the attention of the audit committee a news release issued by another company that disclosed that the other company was conducting an internal investigation into the FCPA implications of certain actions by a customs agent in Nigeria in connection with the temporary importation of that company’s vessels into Nigeria. Our drilling units that conduct operations in Nigeria do so under temporary import permits, and management considered it prudent to review our own practices in this regard.

     We voluntarily contacted the SEC and the U.S. Department of Justice (“DOJ”) to advise them that an independent investigation was under way. We have been cooperating, and intend to continue to cooperate, fully with both agencies. If the SEC or the DOJ determines that violations of the FCPA have occurred, they could seek civil and criminal sanctions, including monetary penalties, against us and/or certain of our employees, as well as additional changes to our business practices and compliance programs, any of which could have a material adverse effect on our business or financial condition. In addition, such actions, whether actual or alleged, could damage our reputation and ability to do business, to attract and retain employees, and to access capital markets. Further, detecting, investigating, and resolving such actions is expensive and consumes significant time and attention of our senior management.

     The internal investigation is ongoing, and we cannot predict whether either the SEC or the DOJ will open its own proceeding to investigate this matter, or if a proceeding is opened, what potential remedies these agencies may seek. We could also face fines or sanctions in relevant foreign jurisdictions. Based on information obtained to date in our internal investigation, we have not determined that any potential liability that may result is either probable or can be reasonably estimated. As a result, we have not made any accrual in our financial statements at December 31, 2007.

     We previously disclosed that, due to the ongoing internal investigation, we had not been able to obtain or renew temporary import permits for our seven drilling units operating offshore Nigeria, although Nigerian customs authorities had informed us that our applications for permits for our drilling units would be approved. Currently, six of the seven drilling units are operating offshore Nigeria, and the seventh drilling unit is undergoing modifications and regulatory inspections outside of Nigeria. We have now received temporary import permit extension documentation from the Nigerian Customs Service and have been engaged in causing bank bonds to be issued, and delivered to and accepted by, the Nigerian Customs Service as is required by the extension documentation in order to cause the permit extensions to become effective. We have completed this bonding process for five of the six units still operating offshore Nigeria. The administrative process at the Nigerian Customs Service is not yet completed for the sixth unit, but we expect this process to be completed shortly. The term of each extended permit is through May 27, 2008. Since the seventh unit is no longer in Nigerian waters, we would need to obtain a new temporary import permit for the unit upon any return of the unit to Nigeria following completion of its modifications and regulatory inspections. Our management continues to seek to avoid material disruption to our Nigerian operations; however, there can be no assurance that we will be able to obtain new permits or further extensions necessary to continue operations with our drilling units in Nigeria after expiration of the term of the permit extensions. If we cannot obtain a new permit or a further extension necessary to continue operations of any unit, we may need to terminate the drilling contract of such unit and relocate such unit from Nigerian waters. 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.

     Notwithstanding that the internal investigation is ongoing, we have concluded that certain changes to our FCPA compliance program would provide us greater assurance that our assets are not used, directly or indirectly, to make improper payments, including customs payments, and that we are in compliance with the FCPA’s record-keeping requirements. Although we have had a long-time published policy requiring compliance with the FCPA and broadly prohibiting any improper payments by us to government officials, we have since the commencement of the internal investigation adopted, and may adopt additional, intermediate measures intended to enhance FCPA compliance procedures. Additional measures may be required once the investigation concludes.

RESULTS OF OPERATIONS

Rig Utilization, Operating Days and Average Dayrates

     The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2007 and 2006:

      Operating Revenues. Contract drilling services revenues increased $827.3 million, or 44 percent, primarily due to higher average dayrates. Higher average dayrates increased revenues approximately $812.2 million and the higher number of operating days increased revenues approximately $15.1 million. Average dayrates increased from $97,837 to $139,948, or $42,111 (43 percent), in 2007 as compared to 2006. Higher average dayrates were received across all rig categories as strong demand for drilling rigs drove dayrates higher. Operating days increased from 19,287 in 2006 to 19,395 in 2007, or 108 days. Two newbuilds, the ultra-deepwater semisubmersible Noble Clyde Boudreaux and the enhanced premium jackup Noble Roger Lewis , which were added to the fleet in June and September 2007, respectively, contributed 307 additional operating days in 2007. These additional operating days were partially offset by 86 fewer operating days on our submersible the Noble Fri Rodli , which was stacked in October 2007, due to weakening demand in the shallow waters of the U.S. Gulf of Mexico and 49 fewer operating days on our drillship the Noble Roger Eason , principally due to a fire incident in late November 2007. Additionally, in 2007, there were 49 more unpaid shipyard and regulatory inspection days than in 2006. Utilization of our contract drilling fleet decreased to 95 percent for 2007 from 96 percent in 2006.

      Operating Costs and Expenses. Contract drilling services expenses increased $183.8 million, or 26 percent, in 2007 as compared to 2006. The Noble Clyde Boudreaux and the Noble Roger Lewis , two newbuild rigs which began operations in 2007, added $22.9 million of operating costs in 2007. Additionally, we incurred start-up costs on our newbuild rigs under construction in advance of their completion as rig personnel were added and other costs were incurred. Newbuild rig start-up costs incurred in 2007 were $10.8 million, or $10.1 million higher than start-up costs incurred in 2006. Excluding the effect of our newbuild rigs, our labor costs increased $63.5 million due to higher compensation, including retention programs designed to retain key rig and operations personnel. Repair and maintenance costs during 2007 increased $26.6 million as rig equipment and oilfield labor service costs continued to increase. Higher agency fees of $14.0 million were incurred in 2007 in those countries where we retain agents who are compensated based on a percentage of revenues. Higher safety and training costs of $8.5 million were incurred in 2007 due to increased new hire personnel. In 2007, we also incurred a $7.8 million increase in the costs of rotating our rig crews due to more rigs operating internationally and experienced a $6.1 million increase in offshore drilling crew personal injury claims. A $10 million charge, which equals our insurance deductible in 2007, was recorded related to a fire incident onboard the Noble Roger Eason in November 2007.

     Depreciation and amortization increased $34.4 million, or 14 percent, to $283.2 million in 2007 due to $14.2 million of additional depreciation on the Noble Clyde Boudreaux , which began operations in June 2007, and $20.2 million of additional depreciation related to other capital expenditures on our fleet.

      Hurricane Losses and Recoveries. Certain of our rigs operating in the U.S. Gulf of Mexico sustained damage in 2005 as a result of Hurricanes Katrina and Rita. All such units had returned to work by April 2006.

     During the fourth quarter of 2007, we recognized a net recovery of $5.1 million on the final settlement of all remaining physical damage and loss of hire insurance claims for damage caused by Hurricanes Katrina and Rita in 2005. This settlement was partially offset by an additional claim loss of $1.6 million earlier in 2007, the net effect of which is reflected in Hurricane losses and recoveries, net as a component of Operating Costs and Expenses in our Consolidated Statements of Income. During 2006, we recorded $10.7 million in loss of hire insurance proceeds for two of our units that suffered downtime attributable to the hurricanes. Our insurance receivables at December 31, 2007 related to claims for hurricane damage were $39.1 million. We anticipate receiving $39.1 million during the first quarter of 2008 as final settlement of all remaining hurricane-related claims and receivables for physical damage and loss of hire.

Other

     The following table sets forth the operating revenues and the operating costs and expenses for our other services for 2007 and 2006:

      Operating Revenues . Our labor contract drilling services revenues increased $45.3 million in 2007. Noble Kolskaya operations generated $23.4 million in higher revenues principally due to higher dayrates. Our Canadian and North Sea labor contracts produced $21.9 million in additional revenue, which was primarily due to increases in contract rates and operating days. The increased operating activity in the North Sea also generated $13.1 million in additional reimbursables revenue in 2007.

     Engineering, consulting and other operating revenues decreased $6.3 million primarily due to the sale of the software business of our Maurer Technology Inc. (“Maurer”) subsidiary in June 2006, and the closure of our Triton subsidiary in March 2007. Subsequent to such sale and closure, the engineering, consulting and other operating revenues were primarily derived from the rotary steerable system assets and intellectual property owned by Downhole Technology, which were sold in November 2007.

      Operating Costs and Expenses . Operating costs and expenses for labor contract drilling services increased $34.3 million over 2006 due to higher labor costs in Canada and the North Sea and additional operating days in the North Sea, which added $17.2 million in additional costs, and $17.1 million higher bareboat charter and other operating costs on the Noble Kolskaya . The increased operating activity in the North Sea also generated $12.6 million in additional reimbursables expense in 2007.

     Engineering, consulting and other expenses increased $0.7 million in 2007. In March 2007, the operations of our Triton subsidiary were closed resulting in closure costs of $1.9 million, including a $0.4 million impairment of goodwill. In November 2007, Downhole Technology sold its rotary steerable system assets and intellectual property resulting in a loss of $12.9 million for the sale of these assets and intellectual property and other related exit activities, including a $9.4 million impairment of goodwill. In June 2006, the software business of Maurer was sold resulting in a loss of $3.8 million, including the write-off of goodwill totaling $4.8 million. Excluding the above charges related to Triton, Downhole Technology and Maurer, costs and expenses declined $10.3 million due to the disposal of these businesses and the reduction in project levels.

     Depreciation and amortization increased $5.2 million in 2007 as compared to 2006 primarily due to $4.1 million higher depreciation on the Noble Kolskaya . The Noble Kolskaya bareboat charter agreement expires in July 2008, and contract specific capital expenditures related to its operations are depreciated over the remaining term of the bareboat charter.

Other Items

      Selling, General and Administrative Expenses . Consolidated selling, general and administrative expenses increased $39.5 million to $85.8 million in 2007 from $46.3 million in 2006. The increase is principally due to $14.9 million of costs incurred in the internal investigation of our Nigerian operations, $6.7 million related to the retirement and resignation of our former chief executive officers, $6.7 million in higher employee-related costs for our employee benefit and retention plans and the addition of personnel, and approximately $5.7 million higher professional services fees including internal audit, tax and information technology services.

      Interest Expense . Interest expense, net of amount capitalized, decreased $3.1 million in 2007. During 2007, we incurred interest expense of $7.7 million related to the debt incurred in connection with a short-term loan agreement (see “—Liquidity and Capital Resources — Credit Facilities and Long-Term Debt”). This compares with interest expense of approximately $8.2 million related to debt incurred in connection with our former investment in Smedvig ASA (“Smedvig”) during 2006. Excluding interest expense related to these debt balances, interest expense increased $10.0 million in 2007 primarily due to a higher level of borrowings in 2007 under our unsecured revolving bank credit facility and a full year of interest expense on our 5.875% Senior Notes issued in May 2006. Interest capitalized in 2007 increased $12.5 million from $37.9 million in 2006 to $50.4 million in 2007. The increase in interest incurred and interest capitalized is primarily attributable to our newbuild construction.

      Other, net. Other, net increased $1.1 million in 2007. Interest income increased $3.9 million as a result of higher levels of cash investments in 2007, in part due to the investment of the proceeds of the borrowing under a short-term loan agreement with Goldman Sachs Credit Partners L.P., which contributed $6.3 million of interest income in 2007. In addition, 2006 included income of $4.4 million from the interests in deepwater oil and gas properties received pursuant to a prior year litigation settlement, $1.8 million of gains on sale of drill pipe and a $3.5 million charge for the settlement and release of claims by one of our agents for commissions relating to certain of our Middle East division activities.

      Income Tax Provision . The income tax provision increased $93.5 million primarily due to higher pre-tax earnings in 2007, increasing income tax expense by $116.7 million, offset by a decrease in the effective tax rate from 20.6 percent in 2006 to 19.0 percent in 2007 decreasing income tax expense by $23.2 million. The lower effective tax rate resulted primarily from higher pre-tax earnings of non-U.S. owned assets, which generally have a lower statutory tax rate, and lower pre-tax earnings of U.S. owned assets.

Rig Utilization, Operating Days and Average Dayrates

     The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2006 and 2005:

      Operating Revenues. Contract drilling services revenues increased $699.8 million, or 59 percent, as strong demand for drilling rigs drove higher operating days and average dayrates. Higher average dayrates increased revenues approximately $642.2 million and the higher number of operating days increased revenues approximately $57.6 million. Average dayrates increased from $63,494 to $97,837, or $34,343 (54 percent), in 2006 as compared to 2005. Higher average dayrates were received across all rig categories. Operating days increased from 18,698 in 2005 to 19,287 in 2006, or 589 days (three percent). The Noble Harvey Duhaney and Noble Mark Burns , which were added to the fleet in August 2005, contributed 450 additional operating days in 2006 as compared to 2005. In 2006, there were 141 fewer unpaid shipyard and regulatory inspection days than in 2005. Utilization of our contract drilling fleet was unchanged at 96 percent for 2006 when compared to 2005.

      Operating Costs and Expenses. Contract drilling services expenses increased $115.4 million, or 20 percent, in 2006 as compared to 2005. The higher number of operating days resulted in a $21.3 million increase in operating costs in 2006 as compared to 2005. The balance of the increase, $94.1 million, resulted primarily from $59.1 million of higher compensation, including retention programs designed to retain key rig and operations personnel, $28.4 million of higher costs of fleet insurance and $8.0 million of higher agency fees in those countries where we retain agents who are compensated based on a percentage of revenues. Depreciation and amortization increased to $248.8 million in 2006 as compared to $236.7 million in 2005, or five percent, primarily resulting from units added to the drilling fleet as described under Operating Revenues above, as well as capital expenditures on our fleet since 2005.

      Hurricane Losses and Recoveries. Certain of our rigs operating in the U.S. Gulf of Mexico sustained damage in 2005 as a result of Hurricanes Katrina and Rita. All such units had returned to work by April 2006.

     During 2006, we recorded $10.7 million in loss of hire insurance proceeds for two of our units that suffered downtime attributable to Hurricanes Katrina and Rita. During 2005, we recorded a $20.0 million charge, net of insurance recoveries, for the non-reimbursable portion of damages sustained in the 2005 hurricanes and $49.8 million in loss of hire insurance proceeds for our Noble EVA-4000™ semisubmersibles (the Noble Jim Thompson , Noble Max Smith , Noble Paul Romano and Noble Amos Runner ) that suffered downtime attributable to these events. Our loss of hire coverage commenced at the respective dates of occurrence of Hurricanes Katrina and Rita, and losses covered thereunder, combined with physical damage losses, were subject to a $10.0 million deductible for each insurable event. Our loss of hire coverage continued through the respective dates the units returned on contract. These financial impacts are presented in Hurricane losses and recoveries, net as a component of Operating

Costs and Expenses in our Consolidated Statements of Income. Earnings in 2005 were also adversely impacted by $9.0 million in lost revenue as a result of Hurricane Rita on rigs for which we did not carry loss of hire insurance.

   Other

     The following table sets forth the operating revenues and the operating costs and expenses for our other services for 2006 and 2005:

      Operating Revenues . Our labor contract drilling services revenues increased $19.7 million in 2006. Noble Kolskaya operations generated $15.4 million in higher revenues principally due to higher dayrates. Our Canadian and North Sea labor contracts produced $4.3 million in additional revenue. This increase was primarily due to billings under cost escalation clauses for revenue contracts in Canada and the North Sea and currency exchange fluctuations, offset in part by fewer operating days in the North Sea. The decreased operating activity in the North Sea also caused a $3.0 million decrease in reimbursables revenue in 2006.

     Operating revenues for engineering, consulting and other decreased $4.9 million primarily due to reduced project levels and the sale of the software business of our Maurer subsidiary in June 2006.

      Operating Costs and Expenses . Operating costs and expenses for labor contract drilling services increased $14.3 million over 2005 due primarily to $11.1 million of higher bareboat charter fees and other operating costs on the Noble Kolskaya in 2006. Additionally, operating costs and expenses for labor contract drilling services increased $3.2 million primarily due to higher labor costs in Canada and the North Sea and currency exchange fluctuations, reduced in part by fewer operating days in the North Sea. The decreased operating activity in the North Sea also caused a $4.3 million decrease in reimbursables expense in 2006.

     Engineering, consulting and other expenses decreased $3.6 million. The 2006 results included a pre-tax loss of $3.8 million on the sale of the Maurer software business. This loss included the write-off of goodwill totaling $4.8 million. Excluding the Maurer transaction, costs and expenses declined $7.4 million due to reduced project levels.

   Other Items

      Selling, General and Administrative Expenses . Consolidated selling, general and administrative expenses increased $6.0 million to $46.3 million in 2006 from $40.3 million in 2005 primarily due to the adoption of SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123R”), expenses related to our employee benefit and retention plans, and the addition of personnel.

      Interest Expense . Interest expense, net of amount capitalized, decreased $3.6 million primarily due to $23.9 million of additional interest capitalization in 2006 as compared to 2005, offset by additional interest costs of $20.3 million primarily from higher levels of borrowings in 2006. Each of these factors is primarily attributable to

the higher level of capital expenditures in 2006 as compared to 2005. Additionally, the interest incurred in 2006 included interest costs of approximately $8.2 million related to the debt incurred in connection with our former investment in Smedvig.

      Other, net. Other, net decreased $0.8 million. The 2005 results included $3.2 million of equity in earnings of a 50 percent owned joint venture that owned the Panon (renamed the Noble Harvey Duhaney ). In August 2005, we acquired the remaining 50 percent equity interest in the joint venture. The 2006 results include a $3.5 million charge for the settlement and release of claims by one of our agents for commissions relating to certain of our Middle East division activities. The 2006 results also include income of $4.4 million from the interests in deepwater oil and gas properties received pursuant to a prior year litigation settlement. Interest income increased an aggregate of $2.5 million in 2006 as compared to 2005 primarily due to higher levels of cash, cash equivalents and short-term marketable securities in 2006 as compared to 2005, as well as higher interest rates on such cash investments in 2006.

      Income Tax Provision . The income tax provision increased $122.0 million primarily due to higher pre-tax earnings in 2006 (adding $103.1 million in higher income tax) and an increase in the effective tax rate from 18.5 percent in 2005 to 20.6 percent in 2006 (adding $18.9 million in higher income tax). The higher effective tax rate resulted primarily from higher pre-tax earnings of U.S. owned assets in 2006, which generally have a higher statutory tax rate, and additional current taxes in certain of the non-U.S. jurisdictions.

   Capital Expenditures

     Capital expenditures totaled $1.29 billion, $1.12 billion and $545.4 million for 2007, 2006 and 2005, respectively.

     Capital expenditures for new construction in 2007 totaled $755.0 million and included $173.3 million for the Noble Danny Adkins, $150.7 million for the Noble Clyde Boudreaux , $151.7 million for the Noble Dave Beard and $118.5 million for the Noble Jim Day . Additionally, 2007 included $160.8 million of capital expenditures toward the construction of the Noble Roger Lewis , Noble Hans Deul and Noble Scott Marks , three F&G JU-2000E enhanced premium newbuild jackups under construction. Other capital expenditures totaled $423.6 million in 2007 and included approximately $191.2 million for major upgrade projects. Major maintenance expenditures totaled $108.4 million in 2007.

     Our capital expenditures and major maintenance expenditures for 2008 are budgeted at approximately $1.45 billion. In connection with our capital expenditure program, we have entered into certain commitments, including shipyard and purchase commitments of $776.8 million outstanding at December 31, 2007.

     Certain projects currently under consideration could require, if they materialize, capital expenditures or other cash requirements not included in the 2008 budget. In addition, we will continue to evaluate acquisitions of drilling units from time to time. Factors that could cause actual capital expenditures to materially exceed the planned capital expenditures include delays and cost overruns in shipyards, shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, and changes in design criteria or specifications during repair or construction.

     We believe that our cash and cash equivalents, net cash provided by operating activities, available capacity under the bank credit facility, and access to other financing sources will be adequate to meet our anticipated short-term and long-term liquidity requirements, including capital expenditures and scheduled debt repayments.

   Investment in Smedvig

     We entered into a Share Purchase Agreement (the “Share Purchase Agreement”) dated December 12, 2005 with Nora Smedvig, Peter T. Smedvig, Hjordis Smedvig, HKS AS, AS Veni, Petrus AS and Peder Smedvig Capital AS (collectively, the “Sellers”) relating to our acquisition, directly and indirectly, of 21,095,600 Class A shares and 2,501,374 Class B shares (collectively, the “Owned Shares”) of Smedvig. We completed our acquisition of the Owned Shares on December 23, 2005. The acquisition comprised 39.2 percent of the Class A shares and 28.9 percent of the total capital shares of Smedvig. The purchase price was NOK 200 per Class A share and NOK 150 per Class B share (the “Noble Purchase Price”), totaling NOK 4,594.3 million (or approximately US $691.1 million at the date of acquisition) before certain legal and other transaction costs. We financed the acquisition of the Owned Shares, including related transaction costs, with an aggregate of $700 million in new debt borrowings.

     Subsequent to our acquisition of the Owned Shares, SeaDrill Limited, a Bermudian limited company (“SeaDrill”), reported that it had acquired control of 51.24 percent of the Class A shares and 52.47 percent of the Smedvig capital, after which SeaDrill made a mandatory offer (the “Mandatory Offer”) pursuant to Norwegian law (and a parallel tender offer in the U.S.) to purchase all the shares of Smedvig not already owned by SeaDrill at a price of NOK 205 per Class A share and NOK 165 per Class B share (the “SeaDrill Offer Price”).

     To mitigate our foreign currency exposure on our investment in Smedvig shares, on March 15, 2006, we entered into a foreign currency contract that obligated the counterparty to pay us $691.7 million in exchange for NOK 4,594.3 million on April 18, 2006.

     On April 7, 2006, we sold the Owned Shares to SeaDrill pursuant to the Mandatory Offer for NOK 4,737.3 million. On April 10, 2006, we settled the forward currency contract described above and received $691.3 million. Also on April 10, 2006, we prepaid the outstanding principal amount of $600.0 million under a credit agreement, which was entered into to finance a portion of the acquisition of the Owned Shares. This credit agreement terminated as a result of all parties thereto completing their obligations thereunder.

     On April 18, 2006, pursuant to the Share Purchase Agreement, we paid to the Sellers the excess of the SeaDrill Offer Price over the Noble Purchase Price on the Owned Shares sold to SeaDrill (an aggregate of NOK 143.0 million, or $21.8 million), as a purchase price adjustment under the Share Purchase Agreement.

   Credit Facilities and Long-Term Debt

     On March 15, 2007, Noble entered into an unsecured revolving bank credit facility totaling $600 million (the “Bank Credit Agreement”). The Bank Credit Agreement has an initial term of five years and replaced Noble Drilling Corporation’s (“Noble Drilling”) $300 million unsecured revolving bank credit facility. Noble Drilling has issued a guaranty of the obligations under the Bank Credit Agreement. Pursuant to the terms of the Bank Credit Agreement, Noble may, subject to certain conditions, elect to increase the maximum amount available under the Bank Credit Agreement from $600 million to an amount not to exceed $800 million. Noble may, subject to certain conditions, also request that the term of the Bank Credit Agreement be extended for up to two additional one-year periods. Borrowings may be made under the facility (i) at the sum of Adjusted LIBOR (as defined in the Bank Credit Agreement) plus the Applicable Margin (as defined in the Bank Credit Agreement; 0.235 percent based on Noble’s current credit ratings), or (ii) at the base rate, determined as the greater of the prime rate for U.S. Dollar loans announced by Citibank, N.A. in New York or the sum of the weighted average overnight federal funds rate published by the Federal Reserve Bank of New York plus 0.50 percent. The Bank Credit Agreement contains various covenants, including a debt to total tangible capitalization covenant, and restrictions on incurring additional indebtedness and additional liens. At December 31, 2007, borrowings of $100 million were outstanding under the Bank Credit Agreement with a weighted average interest rate of 5.17 percent per annum. At December 31, 2007, we have $500 million remaining available for borrowings under the Bank Credit Agreement.

     On July 24, 2007, Noble entered into a short-term loan agreement (the “Short-Term Loan Agreement”) with Goldman Sachs Credit Partners L.P., as the initial lender and administrative agent, pursuant to which Noble borrowed $685 million. Noble Drilling issued a guaranty of the obligations of Noble under the Short-Term Loan Agreement. The proceeds of the borrowing were used to repay an intercompany loan from a direct wholly-owned subsidiary of Noble. On September 26, 2007, the short-term loan was repaid with proceeds distributed in connection with the liquidation and dissolution of this subsidiary. The net pre-tax cost of this financing was $1.4 million.

     In May 2006, Noble issued $300 million principal amount of 5.875% Senior Notes due June 1, 2013. Proceeds, net of discount and issuance costs, totaled approximately $296 million. Interest on the 5.875% Senior Notes is payable semi-annually, in arrears, on June 1 and December 1 of each year. The 5.875% Senior Notes are redeemable, as a whole or from time to time in part, at our option on any date prior to maturity at prices equal to 100 percent of the outstanding principal amount of the notes redeemed plus accrued interest to the redemption date plus a make-whole premium, if any is required to be paid. The 5.875% Senior Notes are senior unsecured obligations, and the indenture governing the 5.875% Senior Notes contains covenants that, among other things, limit our ability to create certain liens, engage in certain sale and lease-back transactions and merge, consolidate and sell assets, except under certain conditions.

     At December 31, 2007, we had letters of credit of $89.4 million and performance, customs and tax assessment bonds totaling $209.4 million supported by surety bonds. In February 2008, we had an additional $222.1 million of letters of credit issued to support bank bonds in connection with the temporary import permit extensions for our drilling units in Nigeria. For additional information regarding our temporary import permit extensions in Nigeria, see “— Internal Investigation”. Additionally, certain of our subsidiaries issue, from time to time, guarantees of the temporary import status of rigs or equipment imported into certain countries in which we operate. These guarantees are issued in lieu of payment of custom, value added or similar taxes in those countries.

     Our debt increased from $694.1 million (including current maturities of $9.6 million) at December 31, 2006 to $784.5 million (including current maturities of $10.3 million) at December 31, 2007, primarily due to $100.0 million of net borrowings under our Bank Credit Agreement described above. At December 31, 2007 and 2006, we had no off-balance sheet debt or other off-balance sheet arrangements. At December 31, 2007, we were in compliance with all our debt covenants. For additional information on long-term debt, see Note 5 to our accompanying consolidated financial statements.

   Summary of Contractual Cash Obligations and Commitments

     The following table summarizes our contractual cash obligations and commitments at December 31, 2007 (in thousands):

     At December 31, 2007, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, tax and other obligations in various jurisdictions. These letters of credit and surety bond obligations are not normally called as we typically comply with the underlying performance requirement. The following table summarizes our other commercial commitments at December 31, 2007 (in thousands):