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

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

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

Registrant’s Telephone Number, Including Area Code: (281) 276-6100

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

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.

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

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

As of June 30, 2008, the aggregate market value of the registrant’s ordinary shares held by non-affiliates of the registrant was $17.3 billion based on the closing sale price as reported on the New York Stock Exchange.

Number of Ordinary Shares outstanding as of February 15, 2009: 261,500,479

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) The registrant has announced a transaction that, if completed, would result in a Swiss company becoming a successor issuer to the registrant for purposes of Rule 12g-3 under the Securities Exchange Act of 1934. The proxy statement for the 2009 annual meeting of members of the registrant or, if the transaction described above is completed, the proxy statement for the 2009 annual meeting of shareholders of such successor issuer, which meetings are in either case scheduled to be held in May 2009, will be incorporated by reference into Part III.

 

 

 

		PAGE
PART I
Item 1. Business			2
Item 1A. Risk Factors			7
Item 1B. Unresolved Staff Comments			13
Item 2. Properties			14
Item 3. Legal Proceedings			18
Item 4. Submission of Matters to a Vote of Security Holders			18
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			21
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			39
Item 8. Financial Statements and Supplementary Data			41
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			93
Item 9A. Controls and Procedures			93
Item 9B. Other Information			93
PART III
Item 10. Directors, Executive Officers and Corporate Governance			94
Item 11. Executive Compensation			95
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			95
Item 13. Certain Relationships and Related Transactions, and Director Independence			95
Item 14. Principal Accounting Fees and Services			95
PART IV
Item 15. Exhibits, Financial Statement Schedules			95
SIGNATURES			96
Exhibit 10.26
Exhibit 10.27
Exhibit 10.28
Exhibit 10.29
Exhibit 10.30
Exhibit 10.31
Exhibit 10.32
Exhibit 10.33
Exhibit 10.34
Exhibit 10.35
Exhibit 10.36
Exhibit 10.37
Exhibit 10.38
Exhibit 10.39
Exhibit 10.40
Exhibit 21.1
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

 

1

 

Noble Corporation, a Cayman Islands exempted company limited by shares (“Noble” or, together with its consolidated subsidiaries, unless the context requires otherwise, the “Company”, “we”, “our” and words of similar import) is a leading offshore drilling contractor for the oil and gas industry. We perform contract drilling services with our fleet of 63 mobile offshore drilling units located worldwide. This fleet consists of 13 semisubmersibles, four dynamically positioned drillships, 43 jackups and three submersibles. The fleet count includes five units under construction, including one F&G JU-2000E enhanced premium jackup, one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, and three deepwater dynamically positioned semisubmersibles. We have secured customer contracts for the one jackup and three semisubmersibles under construction. For additional information on the specifications of the fleet, see “Item 2. Properties. — Drilling Fleet”. As of January 8, 2009, approximately 87 percent of our fleet was deployed in areas outside of the United States, principally in the Middle East, India, Mexico, the North Sea, Brazil, and West Africa.

Noble became the successor to Noble Drilling Corporation, a Delaware corporation (which we sometimes refer to as “Noble Drilling”) that was organized in 1939, as part of the 2002 internal corporate restructuring of Noble Drilling and its subsidiaries. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.

In December 2008, we announced a proposed merger, reorganization and consolidation transaction (the “Transaction”), which will restructure our corporate organization. The Transaction would result in a new Swiss holding company, also called Noble Corporation (“Noble-Switzerland”), serving as the publicly traded parent of the Noble group of companies. The Transaction would effectively change the place of incorporation of the publicly traded parent company from the Cayman Islands to Switzerland. We cannot assure you that the Transaction will be completed or, if it is, that we will realize the benefits we anticipate from the Transaction. For further discussion of the proposed Transaction, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proposed Transaction.”

Our long-standing business strategy is the active expansion of our worldwide offshore drilling and deepwater capabilities through acquisitions, upgrades and modifications, and the deployment of drilling assets in important geological areas. We have also actively expanded our offshore drilling and deepwater capabilities in recent years through the construction of new rigs. In 2008, we continued our expansion strategy as indicated by the following developments and activities:

	•		we took delivery of our newbuild F&G JU-2000E enhanced premium independent leg cantilevered jackup, the Noble Hans Deul, which is now operating under a long-term drilling contract;
	•		construction continued on one F&G JU-2000E enhanced premium independent leg cantilevered jackups, the Noble Scott Marks, which is being constructed in China and is scheduled for delivery in the second quarter of 2009;
	•		construction continued on three newbuild ultra-deepwater semisubmersibles, the Noble Danny Adkins, which is scheduled for delivery in the third quarter of 2009, and the Noble Dave Beard and the Noble Jim Day, which are scheduled for delivery in the fourth quarter of 2009; and
	•		we entered into agreements for the construction of a new, dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered in the second half of 2011.

Newbuild capital expenditures totaled $800 million in 2008 for our rigs under construction during the year.

 

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We typically have not entered into a newbuild shipyard construction contract without a client contract for the rig, although a number of our competitors have done so. At the end of 2008, shipyards worldwide reportedly had received commitments to construct 74 jackups and 96 deepwater floaters, including our units. These units are expected to be delivered between 2009 and 2012. The majority of these units reportedly do not have a contractual commitment from a customer and are referred to in the offshore drilling industry as “being built on speculation.” The introduction of non-contracted rigs into the marketplace could have an adverse affect on the level of demand for our services or the dayrates we are able to achieve. Our strategy on new construction has typically been to expand our drilling fleet with technologically advanced units only in connection with a long-term drilling contract that covers a substantial portion of our capital investment and provides an acceptable return on our capital employed. Although we commenced construction of the Globetrotter without a long-term drilling contract in place, we believe that a long-term contract will be achieved in the near term because of the technologically innovative design of the drillship and the strength in the deepwater market.

Many client contracts for newbuild rigs contain termination provisions for late delivery. The drilling contracts for our newbuild rigs currently under construction similarly include provisions that would allow our customers to terminate the contract for late delivery. The Noble Scott Marks, currently scheduled to be completed during the second quarter of 2009, must be provided by September 30, 2009 or our customer has the right to terminate the contract. The Noble Danny Adkins, currently scheduled for completion during the third quarter of 2009, must be delivered from the shipyard by July 30, 2009 or the customer has the right to terminate the contract. The drilling contract for the Noble Jim Day, scheduled for completion in the fourth quarter of 2009, contains a termination right in the event the rig is not ready to commence operations by December 31, 2010. The drilling contract for the Noble Dave Beard gives the customer the right to terminate the contract if the rig did not commence operations by December 2008 and also gives the customer the right to apply a penalty for delay beyond the date upon which it had the right to cancel. We continue to discuss an extension for commencement and a reduction in penalty for this rig and believe we will come to an accommodation with the client that is acceptable to us.

While we currently anticipate that our newbuild rigs will be completed and commissioned in a timely manner, unforeseen events could result in delays. If there are delays in the construction or commissioning of any or all of these rigs and our customers exercise their early termination rights, we may not be able to secure a replacement contract on as favorable terms.

Our 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. 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. Given the global economic downturn that began in mid-2008, it is possible that some of our competitors’ rigs being built on speculation could become available for purchase.

In recent years, the drilling industry has experienced significant increases in dayrates for drilling services in most market segments, a tightening market for drilling equipment, and a shortage of personnel. This environment has driven operating costs higher and magnified the importance of recruiting, training and retaining skilled personnel. While the global financial crisis has created an environment of uncertainty and downward pressure on certain types of costs, in the short-term it may not have a material effect on many of our costs, even though we could see a reduction in demand for our services.

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

In March 2008, we signed commitments for approximately $4.0 billion of contract backlog with Petroleo Brasileiro S.A. — PETROBRAS. The commitments are in the form of Memorandums of Understanding on five deepwater rigs: Noble Paul Wolff, Noble Therald Martin, Noble Roger Eason, Noble Leo Segerius and Noble Muravlenko. Upon execution of the definitive drilling contract, each rig will be contracted for a period of five to six years. Additionally, we committed to perform a reliability upgrade on each of our three drillships operating in Brazil, the Noble Roger Eason, the Noble Leo Segerius and the Noble Muravlenko, at the start of each contract. The upgrades are expected to cost approximately $175 million per rig and take approximately five months to complete. During the five-month shipyard period, Petrobras has agreed to pay us $90,000 per day per rig.

In June 2008, we signed an agreement to extend the primary term of our newbuild semisubmersible, the Noble Jim Day, from two years to four years. The dayrate during the term of the contract is $515,000.

In September 2008, we signed contracts for the construction of a new, dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship with South Korea’s STX Heavy Industries Co., LTD (“STX”) and the Dutch-based design and construction firm Huisman Equipment B.V (“Huisman”). The drillship will be built on a fixed-price basis in two phases. Following construction of the hull and installation of the propulsion system by STX at their new state-of-the-art facility in Dalian, China, the drillship will sail under its own power to the Netherlands where Huisman will complete the installation and commissioning of the topside equipment. The drillship will measure 620 feet long and 105 feet wide and will utilize Huisman’s multi-purpose tower design with a drilling side and a pipe assembly side. The Globetrotter will be capable of drilling to a vertical depth of 40,000 feet and will feature dynamic position station-keeping ability, 18,000 tons of variable deck load, and quarters for 180 personnel. We have options with STX and Huisman to construct up to three additional Globetrotter-class drillships, two of which expire in early March 2009. We may decide to allow these, as well as the third option, to expire at no cost to us under the contract, or we may seek to extend one or more of these options. We continue to evaluate potential opportunities for these rigs, as well as opportunities to acquire existing rigs already under construction.

 

3

 

In the third and fourth quarters of 2008, we were awarded bids with Petróleos Mexicanos (“Pemex”) for two of our jackups, the Noble Roy Butler and the Noble Carl Norberg, which enabled us to move these rigs to Mexico from West Africa, a market segment that saw little bidding activity during 2008. The contract for the Noble Roy Butler is 433 days and the contract for the Noble Carl Norberg is 731 days.

At December 31, 2008, our contracted backlog totaled approximately $11.5 billion with approximately 79 percent of our available operating days committed for 2009, approximately 40 percent for 2010 and approximately 24 percent for 2011. These percentages take into account new capacity added by our newbuild rigs that we anticipate commencing operations during the 2009 through 2011 period. See further discussion of our contract drilling backlog in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 equipment or “force majeure” events beyond our control and the control of the customer;
	•		options 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 certain of our customers.

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

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

During times of depressed market conditions, our customers may seek to avoid or reduce their 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.

 

4

 

We conduct offshore contract drilling operations, which accounted for approximately 98 percent, 93 percent and 93 percent of operating revenues for the years ended December 31, 2008, 2007 and 2006, 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. Pemex accounted for approximately 20 percent, 15 percent and 12 percent of our total operating revenues for the years ended December 31, 2008, 2007 and 2006, respectively. No other single customer accounted for more than 10 percent of our total operating revenues in 2008, 2007 or 2006.

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

Under our labor contracts, we provide the personnel necessary to manage and perform the drilling operations from drilling platforms owned by the operator. The Hibernia Contract extends through January 2013.

During the second quarter of 2008, we sold our North Sea labor contract drilling services business to Seawell Holding UK Limited (“Seawell”) for $35 million plus working capital. This sale included labor contracts covering 11 platform operations in the United Kingdom sector of the North Sea. In connection with this sale, we recognized a gain of $36 million, net of closing costs. This gain includes approximately $5 million in cumulative currency translation adjustments.

Additionally, we operated the jackup Noble Kolskaya through a bareboat charter that was to expire by its terms in July 2008. During the second quarter of 2008, the drilling contract for the Noble Kolskaya was terminated early, and we returned the rig to its owner.

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.

Political developments and numerous governmental regulations, which may relate directly or indirectly to the contract drilling industry, affect many aspects of our operations. Non-U.S. contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel and use of local employees and suppliers by foreign contractors. A number of countries actively regulate

 

5

 

and control the ownership of concessions and companies holding concessions, the exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government action, including initiatives by the Organization of Petroleum Exporting Countries (“OPEC”), may continue to contribute to oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies and their need for drilling services and may continue to do so.

The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment or require remediation of contamination under certain circumstances. 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. Many of the other countries in whose waters we operate from time to time also regulate the discharge of oil and other contaminants in connection with drilling operations. We have made and will continue to make expenditures to comply with environmental requirements. To date we have not expended material amounts in order to comply, and we do not believe that our compliance with such requirements will have a material adverse effect upon our results of operations or competitive position or materially increase our capital expenditures. Although these requirements impact the energy and energy services industries, generally they do not appear to affect us in any material respect that is different, or to any materially greater or lesser extent, than other companies in the energy services industry.

At December 31, 2008, we had approximately 6,000 employees, including employees engaged through labor contractors or agencies. Approximately 81 percent of our employees were engaged in operations outside of the U.S. and approximately 19 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.

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.

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

You may also find information related to our corporate governance, board committees and company code of ethics at our website. Among the information you can find there is the following:

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

 

6

 

ITEM 1A. RISK FACTORS.

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

In addition, you should consider the risk factors relating to our proposed Transaction that would restructure our corporate organization to result in a new Swiss holding company serving as the publicly traded parent of the Noble group of companies. We cannot assure you that the Transaction will be completed or, if it is, that we will realize the benefits we anticipate from the Transaction. The risk factors relating to the proposed Transaction are described under “Risk Factors” in our definitive proxy statement filed with the SEC on February 11, 2009, which section is incorporated by reference herein.

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

	•		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 non-U.S. 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.

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

 

7

 

 

 

In addition, we have a number of contracts that will expire in 2009 and 2010. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions and the condition of our customers. We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the dayrates under any new contracts may be below, perhaps substantially below, the existing dayrates, which could have a material adverse effect on our results of operations and cash flows.

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

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

The increase in supply created by the number of rigs being built, as well as changes in our competitors’ drilling rig fleets, could intensify price competition and require higher capital investment to keep our rigs competitive. In addition, the supply attributable to newbuild rigs, especially those being built on speculation, could cause a reduction in future dayrates. In certain markets, for example, we are experiencing competition from newbuild jackups that are scheduled to enter the market in 2009 and beyond. The entry of these newbuild jackups into the market may result in lower marketplace dayrates for jackups. Similarly, there are a number of deepwater newbuilds that are scheduled to enter the market over the next several years, which could also adversely affect the dayrates for these units.

The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has led to a recession in the United States, Europe and Japan and could lead to an extended worldwide economic recession. A slowdown in economic activity caused by a worldwide recession, combined with lower prices for oil and gas, would likely reduce worldwide demand for energy and demand for drilling services. If demand for drilling services declines, we could experience a decline in dayrates for new contracts and a slowing in the pace of new contract activity. Crude oil prices declined significantly in the second half of 2008 and forecasted crude oil prices for the remainder of 2009 are not expected to return to prior levels. Demand for our services depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices. Demand for our services is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies. Any prolonged reduction in oil and natural gas prices or material impairment of our customers’ cash flow or liquidity, including their access to capital, could result in lower levels of exploration, development and production activity. Lower levels of exploration activity could result in a corresponding decline in the demand for our drilling services, which could have a material adverse effect on our financial position, results of operations and cash flows. The financial crisis may also adversely affect the ability of shipyards to meet scheduled deliveries of our newbuilds and our ability to renew our fleet through new vessel construction projects and conversion projects.

 

8

 

 

 

The global financial and credit crisis and related instability in the global financial system may impact our liquidity and financial condition, and we may face significant challenges if conditions in the financial markets do not improve. Banks and other lenders have suffered significant losses and have implemented stricter standards for lending, which has contributed to a general restriction on the availability of credit. It may be difficult or more expensive for us to access the capital markets or borrow money at a time when we would like, or need, to access capital, which could have an adverse impact on our ability to react to changing economic and business conditions, and to fund our operations and capital expenditures and to make acquisitions. The credit crisis could also impact our lenders and customers, causing them to fail to meet their obligations to us. While there can be no assurance that the current financial crisis will improve and its impact on our future liquidity and financial condition cannot be predicted, we will continue to monitor it.

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

	•		shortages of equipment, materials or skilled labor;
	•		work stoppages and labor disputes;
	•		unscheduled delays in the delivery of ordered materials and equipment;
	•		local customs strikes or related work slowdowns that could delay importation of equipment or materials;
	•		weather interferences;
	•		difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;
	•		design and engineering problems;
	•		latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
	•		unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
	•		unanticipated actual or purported change orders;
	•		client acceptance delays;
	•		disputes with shipyards and suppliers;
	•		delays in, or inability to obtain, access to funding;
	•		shipyard failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and
	•		failure or delay of third-party equipment vendors or service providers.

Failure to complete a rig upgrade or new construction on time, or the inability to complete a rig conversion or new construction in accordance with its design specifications, may, in some circumstances, result in loss of revenues, penalties, or delay, renegotiation or cancellation of a drilling contract. For example, drilling contracts for our newbuild rigs currently under construction include provisions that would allow our customers to terminate the contract if we experience construction or commissioning delays. Any unforeseen delays, many of which are beyond our control, could result in delays in delivery of these rigs to our customers. 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.

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.

 

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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 or otherwise cause us to be treated as a U.S. corporation. Congress may approve future tax legislation relating to Noble’s corporate inversion or otherwise affecting our status as a foreign corporation. 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. Legislation has also been proposed in Congress that would deny us the benefits under U.S. tax treaties with respect to certain intercompany transactions. We cannot predict what legislation, if any, relating to our corporate inversion, our status as a foreign corporation, or our eligibility for benefits under tax treaties 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, treaties or regulations change or if the U.S. Internal Revenue Service or other taxing authorities do not agree with our assessment of the effects of such laws, treaties and regulations, this could have a material adverse effect on us, including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

We operate in a number of countries throughout the world, including countries known to have a reputation for corruption. We are committed to doing business in accordance with applicable anti-corruption laws and our code of business conduct and ethics. We are subject, however, to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”). 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”.

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. 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.

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

 

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Following Hurricanes Katrina and Rita in 2005, the insurance industry offered reduced coverage for U.S. Gulf of Mexico named windstorm perils at significantly higher premiums 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. The damage sustained to offshore oil and gas assets as a result of Hurricane Ike in 2008 has caused the insurance market for U.S. named windstorm perils to deteriorate even further. Our units deployed in the U.S. Gulf of Mexico include five semisubmersibles and three submersibles (two contracted submersibles and one cold stacked submersible). We have not yet concluded the March 2009 renewal of our insurance program, but we believe that coverage terms will be more restrictive and premium pricing much higher for U.S. named windstorm perils as compared to our expiring insurance program. Accordingly, we may decide to self insure U.S. named windstorm perils until such time the insurance market can once again offer terms and pricing that are acceptable to us. If we self insure U.S. named windstorm perils, such self insurance would not apply to our units in the Mexican portion of the Gulf of Mexico. We also expect to assume generally higher deductibles for our other insurance coverage. 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 onboard 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. Additionally, there can be no assurance that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks.

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.

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

 

11

 

 

 

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.

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.

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

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

Our ability to do business in a number of jurisdictions is subject to maintaining required licenses and permits and complying with applicable laws and regulations. We have historically operated our drilling units offshore Nigeria under temporary import permits. The permits covering the two units currently operating in Nigeria expired in November 2008 and we have pending applications to renew these permits. However, as of February 25, 2009, the Nigerian customs office had not acted upon our applications. We may not be able to obtain these extensions or replacement permits. Even if we are able to obtain these extensions, we may not be able to obtain further extensions or new temporary import permits necessary to continue uninterrupted operations in Nigerian waters for the duration of the units’ drilling contracts. We cannot predict what impact these events may have on any such contract or our business in Nigeria. 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 such changes may impact our business there. For additional information regarding our ongoing internal investigation of our Nigerian operations and the status of our temporary import permits in Nigeria, see “Part I, Item 2. 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 affect on our results of operations.

We have been advised by the Nigerian Maritime Administration and Safety Agency (“NIMASA”) that it is seeking to collect a two percent surcharge on contract amounts under contracts performed by “vessels”, within the meaning of Nigeria’s cabotage laws, engaged in the Nigerian coastal shipping trade. We have also been informed that NIMASA has recently filed suit against us in the Federal High Court of Nigeria seeking collection of this surcharge. We do not believe that our offshore drilling units are engaged in the Nigerian coastal shipping trade nor that our units are “vessels” within the meaning of Nigeria’s cabotage laws. We are taking legal action to resist the application of Nigeria’s cabotage laws to our drilling units, although the outcome of any such legal action and the extent to which we may ultimately be responsible for the surcharge is uncertain. We may be required to pay the surcharge and comply with other aspects of the Nigerian cabotage laws, which could adversely effect our operations in Nigerian waters and require us to incur additional costs of compliance. For additional information regarding this action, see “Part II, Item 8. Financial Statements and Supplementary Data, Note 12 — Commitments and Contingencies”.

 

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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 and our results of operations.

Due to our non-U.S. 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, 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.

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.

None.

 

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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 ocean floor conditions at the proposed drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth.

Our semisubmersible fleet consists of 13 units, including:

	•		five units that have been converted to Noble EVA-4000™ semisubmersibles;
	•		three Friede & Goldman 9500 Enhanced Pacesetter semisubmersibles (including the Noble Dave Beard, which is currently under construction);
	•		two Pentagone 85 semisubmersibles;
	•		two Bingo 9000 design units (the Noble Danny Adkins and the 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.

We have four dynamically positioned drillships in the fleet, including our dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship under construction. 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 drillships, the Noble Leo Segerius and the 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.

In addition, in September 2008 we signed contracts for the construction of a new, dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship as described under “Item 1. Business – Business Developments During 2008.” That description is incorporated herein by reference. The Globetrotter-class drillship will be capable of drilling in water depths up to 10,000 feet.

 

14

 

 

 

We have 43 jackups in the fleet, including the Noble Scott Marks which is currently under construction and the recently completed Noble Hans Deul. 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.

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.

 

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The following table sets forth certain information concerning our offshore fleet at January 8, 2009. 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.

Water

Drilling

Depth

Depth

Year Built

Rating

Capacity

Name

Make

or Rebuilt (1)

(feet)

(feet)

Location

Status (2)

Semisubmersibles - 13

Noble Paul Wolff

Noble EVA-4000™ - DP

2006 R

9,200

30,000

Brazil

Active

Noble Paul Romano

Noble EVA-4000™

1998R/2007M

6,000

30,000

U.S. Gulf of Mexico

Active

Noble Amos Runner

Noble EVA-4000™

1999R/2008M

8,000

32,500

U.S. Gulf of Mexico

Active

Noble Jim Thompson

Noble EVA-4000™

1999R/2006M

6,000

30,000

U.S. Gulf of Mexico

Active

Noble Max Smith

Noble EVA-4000™

1999 R

7,000

30,000

Mexico

Active

Noble Homer Ferrington

F&G 9500 Enhanced Pacesetter

2004 R

6,000

30,000

Cote d’Ivorie

Active

Noble Lorris Bouzigard

Pentagone 85

2003 R

4,000

25,000

U.S. Gulf of Mexico

Active

Noble Therald Martin

Pentagone 85

2004 R

4,000

25,000

Brazil

Active

Noble Ton van Langeveld (3)

Offshore Co. SCP III Mark 2

2000 R

1,500

25,000

U.K.

Active

Noble Clyde Boudreaux

F&G 9500 Enhanced Pacesetter

2007 R/M

10,000

35,000

U.S. Gulf of Mexico

Active

Noble Dave Beard

F&G 9500 Enhanced Pacesetter - DP

2008 N

10,000

35,000

China

Shipyard/Contracted

Noble Danny Adkins

Bingo 9000 - DP

2009 N

12,000

35,000

Singapore

Shipyard/Contracted

Noble Jim Day

Bingo 9000 - DP

2009 N

12,000

35,000

Singapore

Shipyard/Contracted

Dynamically Positioned Drillships - 4

Noble Roger Eason

NAM Nedlloyd - C

2005 R

7,200

25,000

Brazil

Shipyard/Contracted

Noble Leo Segerius

Gusto Engineering Pelican Class

2002 R

5,600

20,000

Brazil

Active

Noble Muravlenko (4)

Gusto Engineering Pelican Class

1997 R

4,900

20,000

Brazil

Active

Globetrotter (3)

Globetrotter Class

2011 N

10,000

30,000

China

Shipyard

Independent Leg Cantilevered Jackups - 43

Noble Bill Jennings

MLT Class 84 - E.R.C.

1997 R

390

25,000

Mexico

Active

Noble Eddie Paul

MLT Class 84 - E.R.C.

1995 R

390

25,000

Mexico

Active

Noble Leonard Jones

MLT Class 53 - E.R.C.

1998 R

390

25,000

Mexico

Active

Noble Julie Robertson (3) (5)

Baker Marine Europe Class

2001 R

390

25,000

U.K.

Active

Noble Al White (3)

CFEM T-2005-C

2005 R

360

30,000

The Netherlands

Active

Noble Johnnie Hoffman

Baker Marine BMC 300

1993 R

300

25,000

Mexico

Active

Noble Byron Welliver (3)

CFEM T-2005-C

1982

300

30,000

Denmark

Active

Noble Roy Butler (6)

F&G L-780 MOD II

1998 R

300

25,000

Mexico

Active

Noble Tommy Craighead

F&G L-780 MOD II

2003 R

300

25,000

Nigeria

Active

Noble Kenneth Delaney

F&G L-780 MOD II

1998 R

300

25,000

Qatar

Active

Noble Percy Johns

F&G L-780 MOD II

1995 R

300

25,000

Nigeria

Active

Noble George McLeod

F&G L-780 MOD II

1995 R

300

25,000

India

Active

Noble Jimmy Puckett

F&G L-780 MOD II

2002 R

300

25,000

Qatar

Active

Noble Gus Androes

Levingston Class 111-C

2004 R

300

30,000

U.A.E.

Active

Noble Lewis Dugger

Levingston Class 111-C

1997 R

300

25,000

Mexico

Active

Noble Ed Holt

Levingston Class 111-C

2003 R

300

25,000

India

Active

Noble Sam Noble

Levingston Class 111-C

1982

300

25,000

Mexico

Active

Noble Gene Rosser

Levingston Class 111-C

1996 R

300

20,000

Mexico

Active

Noble John Sandifer

Levingston Class 111-C

1995 R

300

25,000

Mexico

Active

Noble Harvey Duhaney

Levingston Class 111-C

2001 R

300

25,000

Qatar

Active

Noble Mark Burns

Levingston Class 111-C

2005 R

300

25,000

U.A.E.

Active

Noble Cees van Diemen

Modec 300C-38

2004 R

300

25,000

U.A.E.

Shipyard/Contracted

Noble David Tinsley

Modec 300C-38

2004 R

300

25,000

Qatar

Active

Noble Gene House

Modec 300C-38

1998 R

300

25,000

Qatar

Active

Noble Charlie Yester

MLT Class 116-C

1980

300

25,000

India

Active

Noble Roy Rhodes (6)

MLT Class 116-C

1979

300

25,000

U.A.E.

Active

Noble Charles Copeland (7)

MLT Class 82-SD-C

2001 R

280

20,000

Qatar

Active

Noble Earl Frederickson

MLT Class 82-SD-C

1999 R

250

20,000

Mexico

Active

Noble Tom Jobe

MLT Class 82-SD-C

1982

250

25,000

Mexico

Active

Noble Ed Noble

MLT Class 82-SD-C

2003 R

250

20,000

Nigeria

Active

Noble Lloyd Noble

MLT Class 82-SD-C

1990 R

250

20,000

Nigeria

Active

Noble Carl Norberg

MLT Class 82-C

2003 R

250

20,000

Mexico

Active

Noble Chuck Syring

MLT Class 82-C

1996 R

250

20,000

Qatar

Active

Noble George Sauvageau (3)

NAM Nedlloyd-C

1981

250

25,000

The Netherlands

Active

Noble Ronald Hoope (3)

MSC/CJ-46

1982

250

25,000

U.K.

Active

Noble Lynda Bossler (3)

MSC/CJ-46

1982

250

25,000

The Netherlands

Active

Noble Piet van Ede (3)

MSC/CJ-46

1982

250

25,000

The Netherlands

Active

Noble Dick Favor

Baker Marine BMC 150

2004 R

150

20,000

U.A.E.

Shipyard

Noble Don Walker

Baker Marine BMC 150-SD

1992 R

150

20,000

Benin

Active

Dhabi II

Baker Marine BMC 150

2006 R

150

20,000

U.A.E.

Active

Noble Roger Lewis (3) (8)

F&G JU-2000E

2007

400

30,000

Qatar

Active

Noble Hans Deul (3)

F&G JU-2000E

2008

400

30,000

U.K

Shipyard/Contracted

Noble Scott Marks (3)

F&G JU-2000E

2009 N

400

30,000

China

Shipyard/Contracted

Submersibles - 3

Noble Joe Alford

Pace Marine 85G

2006 R

70

25,000

U.S. Gulf of Mexico

Active

Noble Lester Pettus

Pace Marine 85G

2007 R

70

25,000

U.S. Gulf of Mexico

Active

Noble Fri Rodli

Transworld

1998 R

70

25,000

U.S. Gulf of Mexico

Cold Stacked

 

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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-5SM mooring standard.
2.		Rigs listed as “active” were operating under contract as of January 8, 2009; 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.		We operate the unit and own an 82 percent interest in the unit through a joint venture.
5.		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.
6.		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.
7.		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.
8.		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.

 

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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 Baar, Switzerland; Sugar Land, Texas; New Orleans and Lafitte, Louisiana; Leduc, Alberta and St. John’s, Newfoundland, Canada; Lagos and Port Harcourt, Nigeria; Ivory Coast; Equatorial Guinea; Mexico City and Ciudad del Carmen, Mexico; Doha, Qatar; Abu Dhabi and Dubai, U.A.E.; Beverwijk and Den Helder, The Netherlands; Norfolk, England; Macae and Rio de Janiero, 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.

For a description of the Transaction and our consideration of a possible relocation of our principal executive offices, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proposed Transaction.”

Information regarding legal proceedings is set forth in Note 12 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.

None.

ITEM 5.		MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our ordinary shares are listed and traded on the New York Stock Exchange under the symbol “NE”. The following table sets forth for the periods indicated the high and low sales prices and dividends declared and paid per ordinary share:

										Dividends
		High				Low				Declared and Paid
2008
Fourth quarter		$	42.96			$	20.62			$	0.04
Third quarter			65.78				41.27				0.04
Second quarter			67.98				50.49				0.79
First quarter			57.01				42.11				0.04
2007
Fourth quarter		$	57.64			$	46.21			$	0.04
Third quarter			54.29				43.48				0.04
Second quarter			49.52				39.19				0.02
First quarter			40.78				33.81				0.02

The declaration and payment of dividends, or distributions of capital, in the future are at the discretion of our Board of Directors or, in the event the Transaction is completed, our shareholders, and the amount of any future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors.

On February 15, 2009, there were 261,500,479 of our ordinary shares outstanding held by 1,777 member accounts of record.

 

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If the Transaction is completed, we expect the shares of the new Swiss holding company, also named “Noble Corporation”, to be listed and traded on the NYSE under the symbol “NE”. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proposed Transaction.”

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

										Total Number of				Maximum Number
										Shares Purchased				of Shares that May
		Total Number				Average				as Part of Publicly				Yet Be Purchased
		of Shares				Price Paid				Announced Plans				Under the Plans
Period		Purchased				per Share				or Programs (1)				or Programs (1)
October 2008			463	(2)		$	38.22	(2)			—				20,339,891
November 2008			151,124	(3)			33.54	(3)			100,000				20,239,891
December 2008			1,900,336	(4)			21.16	(4)			1,900,000				18,339,891

 

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This graph shows the cumulative total shareholder return of our ordinary shares over the five-year period from December 31, 2003 to December 31, 2008. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and the Dow Jones U.S. Oil Equipment & Services Index. The graph assumes that $100 was invested in our ordinary shares and the two indices on December 31, 2003 and that all dividends were reinvested on the date of payment.

 

		INDEXED RETURNS
		Years Ending December 31,
Company Name / Index		2003				2004				2005				2006				2007				2008
Noble Corporation		$	100.00			$	139.02			$	197.45			$	213.64			$	317.89			$	126.39
S&P 500 Index			100.00				110.88				116.33				134.70				142.10				89.53
Dow Jones U.S. Oil Equipment & Services			100.00				135.40				205.46				233.14				337.92				137.55

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

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

 

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The following table sets forth selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2008, which information is derived from our audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in our financial statements included in Item 8 of this Annual Report on Form 10-K.

		Year Ended December 31,
		2008				2007				2006				2005				2004
						(In thousands, except per share amounts)
Statement of Income Data
Operating revenues		$	3,446,501			$	2,995,311			$	2,100,239			$	1,382,137			$	1,066,231
Net income			1,560,995				1,206,011				731,866				296,696				146,086
Net income per share:
Basic			5.90				4.52				2.69				1.09				0.55
Diluted			5.85				4.48				2.66				1.08				0.55
Balance Sheet Data (at end of period)
Cash and marketable securities		$	513,311			$	161,058			$	61,710			$	166,302			$	191,578
Property and equipment, net			5,642,549				4,795,916				3,858,393				2,999,019				2,743,620
Total assets			7,102,331				5,876,006				4,585,914				4,346,367				3,307,973
Long-term debt			750,789				774,182				684,469				1,129,325				503,288
Total debt (1)			923,487				784,516				694,098				1,138,297				511,649
Shareholders’ equity			5,290,715				4,308,322				3,228,993				2,731,734				2,384,434
Other Data
Net cash from operating activities		$	1,888,192			$	1,414,373			$	988,715			$	529,010			$	332,221
Net cash from investing activities			(1,129,293	)			(1,223,873	)			(349,910	)			(1,147,411	)			(297,423	)
Net cash from financing activities			(406,646	)			(91,152	)			(698,940	)			681,456				(38,575	)
Capital expenditures			1,231,321				1,287,043				1,122,061				545,095				333,989
Working capital			561,348				367,419				143,720				263,120				211,117
Cash dividends declared per share (2)			0.91				0.12				0.08				0.05				—

 

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ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion is intended to assist you in understanding our financial position at December 31, 2008 and 2007, and our results of operations for each of the years in the three-year period ended December 31, 2008. You should read the accompanying consolidated financial statements and related notes in conjunction with this discussion.

Our 2008 financial and operating results include:

	•		operating revenues totaling $3.4 billion;
	•		net income of $1.6 billion or $5.85 per diluted share;
	•		net cash from operating activities totaling $1.9 billion;
	•		an increase in our average dayrate across our worldwide fleet to $174,506 from $139,948 in 2007;
	•		a decrease in debt to 14.9 percent of total capitalization at the end of 2008, down from 15.4 percent at the end of 2007.

The global financial crisis created an environment of uncertainty during late 2008 that has continued into 2009, and it has raised concerns that the worldwide economy may enter into a prolonged recession. Deterioration in the worldwide economy could result in reduced demand for oil and gas exploration and production activity and, therefore, reduce demand for offshore drilling services. The financial crisis has created significant reductions in available credit and other sources of capital, which may restrict our ability to fund our operations and capital expenditures and adversely impact our customers’ and lenders’ ability to fulfill their obligations to us. Other possible negative impacts include a decline in dayrates under new contracts, an increase in early termination of or defaults under existing contracts and a slowing in the pace of new contract activity.

Demand for our drilling services generally depends on a variety of economic and political factors, including worldwide demand for oil and gas, the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and pricing, the level of production of non-OPEC countries and the policies of various governments regarding exploration and development of their oil and gas reserves. Our results of operations depend on activity in the oil and gas production and development 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 and lower oil and gas prices result in reduced demand for our services. Oil and gas prices are extremely volatile and have declined sharply since mid-2008.

Demand for our services is also a function of the worldwide supply of mobile offshore drilling units. Industry sources report that a total of 74 newbuild jackups and 96 deepwater newbuilds are scheduled to enter service worldwide between 2009 and 2012. The majority of these units reportedly do not have a contractual commitment from a customer and are referred to in the offshore drilling industry as “being built on speculation”. The introduction of non-contracted rigs into the marketplace could have an adverse affect on the level of demand for our services or the dayrates we are able to achieve.

We cannot predict the future level of demand for our drilling services or future conditions in the offshore contract drilling industry. Decreases in commodity prices or the level of demand for our drilling services or increases in the supply of drilling rigs in the market could have an adverse effect on our results of operations.

We continued to face significant cost pressure in 2008 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 $53,528 per day in 2008 from $45,375 per day in 2007. Given the current high demand for personnel and equipment, we expect to see continued upward pressure on operating costs in 2009.

 

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Our long-standing business strategy is the active expansion of our worldwide offshore drilling and deepwater capabilities through acquisitions, upgrades and modifications, and the deployment of 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, both of which are now being completed into rigs, 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 2008, we continued our expansion strategy as indicated by the following developments and activities:

	•		we took delivery of our newbuild F&G JU-2000E enhanced premium independent leg cantilevered jackup, the Noble Hans Deul, which is now operating under a long-term drilling contract;
	•		construction continued on one F&G JU-2000E enhanced premium independent leg cantilevered jackups, the Noble Scott Marks, which is being constructed in China and is scheduled for delivery in the second quarter of 2009;
	•		construction continued on three newbuild ultra-deepwater semisubmersibles, the Noble Danny Adkins, which is scheduled for delivery in the third quarter of 2009, and the Noble Dave Beard and the Noble Jim Day, which are scheduled for delivery in the fourth quarter of 2009; and
	•		we entered into agreements for the construction of a new, dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered in the second half of 2011. We are continuing to evaluate the possibility of exercising options to construct up to three additional Globetrotter-class drillships.

Newbuild capital expenditures totaled $800 million in 2008 for our rigs under construction during the year.

In December 2008, we announced a proposed merger, reorganization and consolidation transaction (the “Transaction”), which, if completed, will restructure our corporate organization. The Transaction would result in a new Swiss holding company serving as the publicly traded parent of the Noble group of companies. The Transaction would effectively change the place of incorporation of the publicly traded parent company from the Cayman Islands to Switzerland.

The Transaction will involve several steps. First, we have formed a new Swiss corporation registered in the Canton of Zug, Switzerland named Noble Corporation (“Noble-Switzerland”) as a direct, wholly-owned subsidiary of Noble Corporation, the Cayman Islands company that is the current ultimate parent company (“Noble-Cayman”). Noble-Switzerland, in turn, has formed a new Cayman Islands subsidiary named Noble Cayman Acquisition Ltd. (“merger sub”). We have set a meeting of members on March 17, 2009 to approve the Transaction, and, assuming we have obtained the necessary member approval, we plan to have a subsequent hearing of the Grand Court of the Cayman Islands on March 26, 2009 to approve the Transaction. If the requisite member and court approvals are obtained, we expect to close the Transaction promptly following the court approval.

In connection with the Transaction, merger sub will merge with Noble-Cayman, with Noble-Cayman as the surviving company. As a result of the Transaction, merger sub will be dissolved and will cease to exist and Noble-Cayman will become a direct, wholly-owned subsidiary of Noble-Switzerland, the resulting publicly traded parent of the Noble group. In the Transaction, all of the outstanding ordinary shares of Noble-Cayman will be cancelled, and Noble-Switzerland will issue, through an exchange agent, one share of Noble-Switzerland in exchange for each share of Noble-Cayman, plus an additional 15 million shares of Noble-Switzerland to Noble-Cayman, which may in turn subsequently transfer these shares to one or more other subsidiaries of Noble-Switzerland for future use to satisfy our obligation to deliver these shares in connection with awards granted under our employee benefits plans and other general corporate purposes. We expect the Noble-Switzerland shares to be listed and traded on the New York Stock Exchange under the symbol “NE”, the same symbol under which our shares are currently listed and traded.

We have not concluded whether we will relocate our principal executive offices from Sugar Land, Texas. However, we are continuing to analyze this issue and we may relocate such offices either before or after the consummation of the Transaction if we believe it would be in the best interests of Noble and our shareholders.

We currently believe that the Transaction should have no material impact on how we conduct our day-to-day operations. Where we conduct our future operations will depend on a variety of factors, independent of our legal domicile, including the worldwide demand for our services and the overall needs of our business.

 

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We maintain a backlog (as defined below) of commitments for contract drilling services. The following table sets forth as of December 31, 2008 the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:

						Year Ending December 31,
		Total				2009				2010				2011				2012				2013-2016
		(In thousands)
Contract Drilling Services Backlog
Semisubmersibles/Drillships (1)		$	8,894,000			$	1,794,000			$	2,016,000			$	1,695,000			$	1,167,000			$	2,222,000
Jackups/Submersibles (2)			2,646,000				1,887,000				577,000				182,000				—				—
Total (3)(4)		$	11,540,000			$	3,681,000			$	2,593,000			$	1,877,000			$	1,167,000			$	2,222,000
Percent of Available
Operating Days Committed (5)							79	%			40	%			24	%			13	%			7	%

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

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

 

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In June 2007, we announced that we were conducting an internal investigation of our Nigerian operations, focusing on the legality under the U.S. Foreign Corrupt Practices Act of 1977, as amended (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 our 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 such 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. The news release 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 underway. 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 independent outside counsel appointed by the audit committee to perform the internal investigation made a presentation of the results of its investigation to the DOJ and the SEC in June 2008. The SEC and the DOJ have begun to review these results and information gathered by the independent outside counsel in the course of the investigation. Neither the SEC nor the DOJ has indicated what action it may take, if any, against us or any individual, or whether it may request that the audit committee’s independent outside counsel conduct further investigation. Therefore, we consider the internal investigation to be ongoing and cannot predict when it will conclude. Furthermore, 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 probable or remote or can be reasonably estimated. As a result, we have not made any accrual in our consolidated financial statements at December 31, 2008.

We are currently operating two jackup rigs offshore Nigeria. The temporary import permits covering the rigs expired in November 2008 and we have pending applications to renew these permits. However, as of February 25, 2009, the Nigerian customs office had not acted on our applications. We continue to seek to avoid material disruption to our Nigerian operations; however, there can be no assurance that we will be able to obtain new permits or further extensions of permits necessary to continue the operation of our rigs in Nigeria. If we cannot obtain a new permit or an extension necessary to continue operations of any rig, we may need to cease operations under the drilling contract for such rig and relocate such rig from Nigerian waters. In any case, we also could be subject to actions by Nigerian customs for import duties and fines for these two rigs, as well as other drilling rigs that operated in Nigeria in the past. We cannot predict what impact these events may have on any such contract or our business in Nigeria. Furthermore, we cannot predict what changes, if any, relating to temporary import permit policies and procedures may be established or implemented in Nigeria in the future, or how any such changes may impact our business there.

 

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Notwithstanding that the internal investigation is ongoing, we 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-standing published policy requiring compliance with the FCPA and broadly prohibiting any improper payments by us to foreign or U.S. officials, we adopted additional measures intended to enhance FCPA compliance procedures. Further measures may be required once the investigation concludes.

Net income for 2008 was $1.6 billion, or $5.85 per diluted share, on operating revenues of $3.4 billion, compared to net income for 2007 of $1.2 billion, or $4.48 per diluted share, on operating revenues of $3.0 billion.

Operating revenues and operating costs and expenses for our contract drilling services segment are dependent on three primary metrics — rig utilization, operating days and dayrates. The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2008 and 2007:

		Average Rig
		Utilization(1)								Operating Days(2)												Average Dayrates
																		%												%
		2008				2007				2008				2007				Change				2008				2007				Change
Jackups			92	%			97	%			13,879				14,294				-3	%		$	148,532			$	120,229				24	%
Semisubmersibles >6,000’(3)			96	%			99	%			2,466				2,358				5	%			327,558				274,613				19	%
Semisubmersibles <6,000’(4)			100	%			89	%			1,098				971				13	%			220,475				177,790				24	%
Drillships			67	%			89	%			732				970				-25	%			201,819				119,669				69	%
Submersibles			66	%			73	%			729				802				-9	%			54,106				74,171				-27	%
Total			90	%			95	%			18,904				19,395				-3	%		$	174,506			$	139,948				25	%

 

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The following table sets forth the operating revenues and the operating costs and expenses for our contract drilling services segment for 2008 and 2007:

										Change
		2008				2007				$				%
Operating Revenues:
Contract drilling services		$	3,298,850			$	2,714,250			$	584,600				22	%
Reimbursables (1)			76,099				83,944				(7,845	)			-9	%
Other			1,275				1,326				(51	)			-4	%
		$	3,376,224			$	2,799,520			$	576,704				21	%
Operating Costs and Expenses:
Contract drilling services		$	1,011,882			$	880,049			$	131,833				15	%
Reimbursables (1)			65,251				70,964				(5,713	)			-8	%
Depreciation and amortization			349,448				283,225				66,223				23	%
Selling, general and administrative			72,381				83,695				(11,314	)			-14	%
Hurricane losses and (recoveries), net			10,000				(3,514	)			13,514				**
			1,508,962				1,314,419				194,543				15	%
Operating Income		$	1,867,262			$	1,485,101			$	382,161				26	%

** Not a meaningful percentage

Operating Revenues. Contract drilling services revenue increases for 2008 as compared to 2007 were primarily driven by increases in average dayrates. Average dayrates increased revenues approximately $670 million for 2008, while fewer operating days reduced revenues approximately $86 million.

Average dayrates increased 25 percent in 2008 as compared to 2007. Except for our submersible rigs, which were impacted by weakening demand in the shallow waters of the U.S. Gulf of Mexico, higher average dayrates were received across all rig categories as strong demand for drilling rigs drove market dayrates higher. Demand in the U.S. Gulf of Mexico has been weakened due to decreases in natural gas prices and increases in operating costs compared to on-shore drilling.

The decrease in operating days in 2008 as compared to 2007 was primarily due to an increase in downtime of certain rigs in 2008. Unpaid shipyard days increased 417 days in 2008 as compared to 2007, as the Noble Roy Butler and the Noble George McLeod each spent significant time in the shipyard during 2008 for rig modifications and regulatory inspections, and the Noble Roger Eason is currently completing repairs for fire damage suffered in November 2007. Additionally, the Noble Fri Rodli, the Noble Don Walker, the Noble Roy Butler and the Noble Carl Norberg spent an aggregate total of 852 days stacked during 2008. The Noble Fri Rodli has been cold-stacked since October 2007 due to weakening demand in the shallow waters of the U.S. Gulf of Mexico. The Noble Don Walker, the Noble Roy Butler and the Noble Carl Norberg spent time stacked in 2008 due to weakness in the Nigerian market. The Noble Carl Norberg and the Noble Roy Butler are currently under contract in Mexico, and the Noble Don Walker is operating under a contract off the West African coast of Benin. The aggregate number of stacked days in 2007 was 255 days. These decreases in operating days were partially offset by increased operating days of 471 days for three recently completed newbuilds, the ultra-deepwater semisubmersible the Noble Clyde Boudreaux and the enhanced premium jackups the Noble Roger Lewis and the Noble Hans Deul, which were added to the fleet in June 2007, September 2007 and November 2008, respectively. Additionally, 2008 had one more available operating day than 2007 due to leap year, which added 54 more operating days in 2008.

Operating Costs and Expenses. Contract drilling services expenses increased 15 percent in 2008 as compared to 2007. Our recently completed newbuild rigs, including the Noble Clyde Boudreaux, the Noble Roger Lewis and the Noble Hans Deul, added $45 million of operating costs in 2008 as compared to 2007. Excluding the effect of these rigs, our labor costs increased $42 million in 2008 over 2007 due to higher compensation, including retention programs designed to retain key rig and operations personnel. The remaining $45 million of the operating cost increase in 2008 over 2007 was primarily due to increases in costs of daily rig operations, including a $19 million increase in maintenance expenses, an $11 million increase in crew rotation and transportation costs and to a lesser extent, increases in catering, fuel, rig communications and safety and training costs.

 

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Depreciation and amortization increased $66 million in 2008 over 2007 due to depreciation on newbuilds added to the fleet, and additional depreciation related to other capital expenditures on our fleet since the beginning of 2007.

Selling, general and administrative expenses decreased $11 million in 2008 from 2007 primarily due to a $6 million decrease in severance costs related to executive departures, a $3 million reduction in compensation expense on our Restoration Plan mark-to-market adjustment and a $2 million decrease in costs incurred in the internal investigation of our Nigerian operations.

Hurricane losses and recoveries, net for 2008 relate to a charge of $10 million, which represents our deductible under our insurance program, for certain of our rigs operating in the U.S. Gulf of Mexico that sustained damage as a result of Hurricane Ike. All damaged rigs have subsequently returned to work. During 2007, we recognized a net recovery of $4 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.

The following table sets forth the operating revenues and the operating costs and expenses for our other services for 2008 and 2007:

										Change
		2008				2007				$				%
Operating Revenues:
Labor contract drilling services		$	55,078			$	156,508			$	(101,430	)			-65	%
Reimbursables (1)			14,750				37,297				(22,547	)			-60	%
Engineering, consulting and other			449				1,986				(1,537	)			-77	%
		$	70,277			$	195,791			$	(125,514	)			-64	%
Operating Costs and Expenses:
Labor contract drilling services		$	42,573			$	125,624			$	(83,051	)			-66	%
Reimbursables (1)			14,076				34,988				(20,912	)			-60	%
Engineering, consulting and other			—				17,520				(17,520	)			-100	%
Depreciation and amortization			7,210				9,762				(2,552	)			-26	%
Selling, general and administrative			1,762				2,136				(374	)			-18	%
Gain on disposal of assets, net			(36,485	)			—				(36,485	)			100	%
			29,136				190,030				(160,894	)			-85	%
Operating Income		$	41,141			$	5,761			$	35,380				614	%

Operating Revenues. Our labor contract drilling services revenues decreased primarily due to the sale of our North Sea labor contract drilling services business in April 2008. Additionally, during the second quarter of 2008, we returned the jackup Noble Kolskaya, which we had operated under a bareboat charter, to its owner. Revenues during 2008 related to our North Sea labor contract drilling services business and the Noble Kolskaya were $22 million as compared to $124 million in 2007.

Engineering, consulting and other operating revenues decreased $2 million in 2008 from 2007 due to closure of the operations of our Triton Engineering Services, Inc. (“Triton”) subsidiary in March 2007 and the sale of the rotary steerable assets and intellectual property of our Noble Downhole Technology Ltd. (“Downhole Technology”) subsidiary in November 2007. We no longer conduct engineering and consulting operations.

Operating Costs and Expenses. Labor contract drilling services costs and expenses decreased in 2008 due to the sale of our North Sea labor contract drilling services business and the return of the Noble Kolskaya to its owner.

 

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Engineering, consulting and other expenses decreased $17 million in 2008 due to the sale of the Downhole Technology assets and the closure of the operations of Triton.

The decrease in depreciation and amortization was primarily due to the return of the Noble Kolskaya to its owner during 2008.

Gain on disposal of assets, net for 2008 primarily relates to the sale of our North Sea labor contract drilling services business in April 2008. In connection with this transaction, we recognized a gain of $36 million, net of closing costs, which included approximately $5 million in cumulative currency translation adjustments.

Interest Expense. Interest expense, net of amount capitalized, decreased $9 million due to lower average debt levels in 2008 than 2007 primarily as a result of short-term borrowings during 2007 that contributed $8 million in interest expense. The short-term borrowings were used to repay an inter-company loan in connection with the dissolution of a wholly-owned subsidiary. Capitalized interest for 2008 was $48 million as compared to $50 million for 2007.

Interest income and other, net. Interest income decreased $3 million in 2008 from 2007 primarily as a result of the investment of the proceeds from the short-term borrowings described above during 2007 that contributed $6 million in interest income during 2007. This decrease was partially offset by interest on increased average cash and cash equivalent balances during 2008.

Income Tax Provision. The income tax provision increased $69 million primarily due to higher pre-tax earnings in 2008 over 2007. The higher pre-tax earnings increased income tax expense by approximately $81 million, offset by a lower effective tax rate of 18.4 percent in 2008 compared to 19.0 percent in 2007, that decreased income tax expense by approximately $12 million. The lower effective tax rate in 2008 resulted primarily from higher pre-tax earnings of non-U.S. owned assets, which generally have a lower statutory tax rate.

Net income for 2007 was $1.2 billion, or $4.48 per diluted share, on operating revenues of $3.0 billion, compared to net income for 2006 of $732 million, or $2.66 per diluted share, on operating revenues of $2.1 billion.

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

		Average Rig
		Utilization (1)								Operating Days (2)								Average Dayrate
		2007				2006				2007				2006				2007				2006
Jackups			97	%			97	%			14,294				14,147			$	120,229			$	76,450
Semisubmersibles — >6,000’(3)			99	%			100	%			2,358				2,190				274,613				229,025
Semisubmersibles — <6,000’(4)			89	%			85	%			971				930				177,790				142,522
Drillships			89	%			100	%			970				1,095				119,669				99,795
Submersibles			73	%			84	%			802				925				74,171				67,452
Total			95	%			96	%			19,395				19,287			$	139,948			$	97,837

 

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

										Operating Costs
		Operating Revenues								and Expenses
		2007				2006				2007				2006
		(In thousands)
Contract drilling services		$	2,714,250			$	1,886,987			$	880,049			$	696,264
Reimbursables (1)			83,944				68,141				70,964				57,158
Other			1,326				1,380				—				—
Depreciation and amortization			N/A				N/A				283,225				248,800
Selling, general and administrative			N/A				N/A				83,695				41,986
Hurricane losses and recoveries, net			—				—				(3,514	)			(10,704	)
Total		$	2,799,520			$	1,956,508			$	1,314,419			$	1,033,504

Operating Revenues. Contract drilling services revenues increased $827 million, or 44 percent, primarily due to higher average dayrates. Higher average dayrates increased revenues approximately $812 million and the higher number of operating days increased revenues approximately $15 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 cold-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 $184 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 $23 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 $11 million, or $10 million higher than start-up costs incurred in 2006. Excluding the effect of our newbuild rigs, our labor costs increased $64 million due to higher compensation, including retention programs designed to retain key rig and operations personnel. Repair and maintenance costs during 2007 increased $27 million as rig equipment and oilfield labor service costs continued to increase. Higher agency fees of $14 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 $9 million were incurred during the year due to increased new hire personnel. We also incurred a $8 million increase in the costs of rotating our rig crews due to more rigs operating internationally and experienced a $6 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 million, or 14 percent, to $283 million in 2007 due to $14 million of additional depreciation on the Noble Clyde Boudreaux, which began operations in June 2007, and $20 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.

 

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During the fourth quarter of 2007, we recognized a net recovery of $5 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 $2 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 $11 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 million. We received $39 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.

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

										Operating Costs
		Operating Revenues								and Expenses
		2007				2006				2007				2006
		(In thousands)
Labor contract drilling services		$	156,508			$	111,201			$	125,624			$	91,353
Engineering, consulting and other			1,986				8,317				17,520				16,779
Reimbursables (1)			37,297				24,213				34,988				22,362
Depreciation and amortization			N/A				N/A				9,762				4,525
Selling, general and administrative			N/A				N/A				2,136				4,286
Total		$	195,791			$	143,731			$	190,030			$	139,305

Operating Revenues. Our labor contract drilling services revenues increased $45 million in 2007. Noble Kolskaya operations generated $23 million in higher revenues principally due to higher dayrates. Our Canadian and North Sea labor contracts produced $22 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 million in additional reimbursables revenue in 2007.

Engineering, consulting and other operating revenues decreased $6 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 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 million in additional costs, and $17 million higher bareboat charter and other operating costs on the Noble Kolskaya. The increased operating activity in the North Sea also generated $13 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 $2 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 $13 million for the sale of these assets and intellectual property and other related exit activities, including a $9 million impairment of goodwill. In June 2006, the software business of Maurer was sold resulting in a loss of $4 million, including the write-off of goodwill totaling $5 million. Excluding the above charges related to Triton, Downhole Technology and Maurer, costs and expenses declined $10 million due to the disposal of these businesses and the reduction in project levels.

Depreciation and amortization increased $5 million in 2007 as compared to 2006 primarily due to $4 million higher depreciation on the Noble Kolskaya. The Noble Kolskaya bareboat charter agreement expired in July 2008, and contract specific capital expenditures related to its operations are depreciated over the remaining term of the bareboat charter.

 

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Selling, General and Administrative Expenses. Consolidated selling, general and administrative expenses increased $40 million to $86 million in 2007 from $46 million in 2006. The increase is principally due to $15 million of costs incurred in the internal investigation of our Nigerian operations, $7 million related to the retirement and resignation of our former chief executive officers, $7 million in higher employee-related costs for our employee benefit and retention plans and the addition of personnel, and approximately $6 million higher professional services fees including internal audit, tax and information technology services.

Interest Expense. Interest expense, net of amount capitalized, decreased $3 million in 2007. During 2007, we incurred interest expense of $8 million related to the debt incurred in connection with short-term borrowings. This compares with interest expense of approximately $8 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 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 $13 million from $38 million in 2006 to $50 million in 2007. The increase in interest incurred and interest capitalized is primarily attributable to our newbuild construction.

Interest income and other, net. Other, net increased $1 million in 2007. Interest income increased $4 million as a result of higher levels of cash investments in 2007, in part due to the investment of the proceeds of short-term borrowings, which contributed $6 million of interest income in 2007. In addition, 2006 included income of $4 million from the interests in deepwater oil and gas properties received pursuant to a prior year litigation settlement, $2 million of gains on sale of drill pipe and a $4 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 $94 million primarily due to higher pre-tax earnings in 2007, increasing income tax expense by $117 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 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.

Our principal capital resource in 2008 was net cash from operating activities of $1.9 billion, which compared to $1.4 billion and $1.0 billion in 2007 and 2006, respectively. The increase in net cash from operating activities in 2008 was primarily attributable to higher net income. At December 31, 2008, we had cash and cash equivalents of $513 million and $600 million available under our bank credit facility. We had working capital of $561 million and $367 million at December 31, 2008 and 2007, respectively. Total debt as a percentage of total debt plus shareholders’ equity was 14.9 percent and 15.4 percent at December 31, 2008 and 2007, respectively.

As a result of the significant cash generated by our operations, our cash on hand and the availability under our bank credit facility, we believe our liquidity and financial condition are sufficient to meet all of our reasonably anticipated cash flow needs for 2009 including:

	•		normal recurring operating expenses;
	•		short-term debt service requirements;
	•		recurring capital expenditures;
	•		repurchase of, and dividends on, our ordinary shares, or if the Transaction is completed, distributions with respect to a reduction in par value; and
	•		contributions to our pension plans.

 

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The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide and may impact our liquidity and financial condition if conditions in the financial markets do not improve. It may be difficult or more expensive for us to access the capital markets or borrow money at a time when we would like, or need, to access capital, which could have an adverse impact on our ability to react to changing economic and business conditions, and to fund our operations and capital expenditures and to make acquisitions. For more information relating to the risks affecting our business, see “Item 1A. Risk Factors”.

Our primary liquidity requirement in 2009 will be for capital expenditures. We had total capital expenditures of $1.2 billion in 2008, and $1.3 billion and $1.1 billion for 2007 and 2006, respectively.

At December 31, 2008, we had five rigs under construction, and capital expenditures for new construction in 2008 totaled $800 million. Capital expenditures for newbuild rigs in 2008 included $219 million for the Noble Danny Adkins, $218 million for the Noble Jim Day, $166 million for the Noble Dave Beard and $99 million for our Globetrotter-class drillship. Additionally, new construction capital expenditures for 2008 included $98 million for our remaining newbuilds, which include the Noble Scott Marks and the recently completed Noble Hans Deul. Other capital expenditures totaled $324 million in 2008, which included approximately $116 million for major upgrade projects. Capitalized major maintenance expenditures, which typically occur every 3 to 5 years, totaled $108 million in 2008.

Our total capital expenditures budget for 2009 is approximately $1.3 billion. In connection with our 2009 and future capital expenditure programs, we have entered into certain commitments, including shipyard and purchase commitments, for approximately $1.2 billion, of which we expect to spend $825 million in 2009. Our remaining 2009 capital expenditure budget will generally be spent at our discretion. We may accelerate or delay capital projects, as needed.

From time to time we consider possible projects that would require capital expenditures or other cash expenditures that are not included in our capital budget, and such unbudgeted capital or cash expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units from time to time. Other factors that could cause actual capital expenditures to materially exceed planned capital expenditures include delays and cost overruns in shipyards (including costs attributable to labor shortages), 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.

Our Board of Directors has authorized and adopted a share repurchase program. At December 31, 2008, 18.3 million ordinary shares remained available under this authorization. Share repurchases for each of the three years ended December 31, 2008 were as follows:

		Total Number								Average
Year Ended		of Shares				Total Cost				Price Paid
December 31,		Purchased				(in thousands)				per Share
2008			7,965,109			$	331,514			$	41.62
2007			4,219,000				178,494				42.31
2006			7,600,000				267,021				35.13

Additionally, during 2006, we completed an odd-lot offer to purchase ordinary shares by purchasing 12,060 shares tendered during the offer for $0.4 million. Additional repurchases, if any, may be made on the open market or in private transactions at prices determined by us.

Our most recent quarterly dividend declaration, to be paid on March 2, 2009 to holders of record on February 11, 2009, was $0.04 per ordinary share, or an aggregate of approximately $42 million on an annualized basis. The declaration and payment of dividends in the future are at the discretion of our Board of Directors and the amount thereof will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors. In addition, if our proposed Transaction is completed, all dividends by the new Swiss parent company must be approved in advance by the shareholders of the company, and we may propose to effect distributions through a reduction in par value. Such a reduction in par value could affect the timing of the distribution payments.

 

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In August 2006, U.S. President Bush signed into law the Pension Protection Act of 2006 (“PPA”). The PPA requires that pension plans fund towards a target of at least 100 percent with a transition through 2011 and increases the amount we are allowed to contribute to our U.S. pension plans in the near term. During 2008, 2007 and 2006 we made contributions to our non-U.S. and U.S. pension plans totaling $21 million, $54 million and $20 million, respectively. We expect the minimum aggregate contributions to our non-U.S. and U.S. plans in 2009, subject to applicable law, to be $6 million. We continue to monitor and evaluate funding options based upon market conditions and may increase contributions at our discretion.

We have a $600 million unsecured bank credit facility (the “Credit Facility”), which was originally scheduled to mature on March 15, 2012. During the first quarter of 2008, the term of the Credit Facility was extended for an additional one-year period to March 15, 2013. During this one-year extension period, the total amount available under the Credit Facility will be $575 million, but we have the right to seek an increase of the total amount available during that period to $600 million. We may, subject to certain conditions, request that the term of the Credit Facility be further extended for an additional one-year period. Our subsidiary, Noble Drilling Corporation (“Noble Drilling”), has guaranteed the obligations under the Credit Facility. Pursuant to the terms of the Credit Facility, we may, subject to certain conditions, elect to increase the amount available up to $800 million. Borrowings may be made under the facility (i) at the sum of Adjusted LIBOR (as defined in the Credit Facility) plus the Applicable Margin (as defined in the Credit Facility; 0.235 percent based on our 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 Credit Facility contains various covenants, including a debt to total tangible capitalization covenant that limits this ratio to 0.60. As of December 31, 2008, our debt to total tangible capitalization was 0.15. In addition, the Credit Facility includes restrictions on certain fundamental changes such as mergers, unless we are the surviving entity or the other party assumes the obligations under the Credit Facility, and the ability to sell or transfer all or substantially all of our assets unless to a subsidiary. The Credit Facility also limits our subsidiaries’ additional indebtedness, excluding intercompany advances and loans, to 10 percent of our consolidated net assets, as defined in the Credit Facility, unless a subsidiary guarantee is issued to the parent company borrower. There are also restrictions on our incurring or assuming additional liens in certain circumstances. We were in compliance with all covenants under the Credit Facility at December 31, 2008. We continually monitor compliance under our Credit Facility covenants and, based on our expectations for 2009, expect to remain in compliance.

In connection with the Transaction, in January 2009 we obtained consent agreements (the “Consents”) with certain lenders under the Credit Facility necessary to effect certain waivers of default under the Credit Facility that would result from the technical change of ownership of the Company that would occur as a result of the Transaction. Pursuant to the Consents, the required lenders under the Credit Facility (i) consented to the Transaction and (ii) waived any default or event of default under the change of ownership event of default set forth in Section 7.1(j) of the Credit Facility that would arise due to the Transaction.

The Credit Facility provides us with the ability to issue up to $150 million in letters of credit. While the issuance of letters of credit does not increase our borrowings outstanding, it does reduce the amount available. At December 31, 2008, we had no borrowing or letters of credit outstanding under the Credit Facility. We believe that we maintain good relationships with our lenders under the Credit Facility, and we believe that our lenders have the liquidity and capability to perform should the need arise for us to draw on the Credit Facility.

In November 2008, we issued through our indirect wholly-owned subsidiary, Noble Holding International Limited (“NHIL”), $250 million principal amount of 7.375% Senior Notes due 2014. Proceeds, net of discount and issuance costs, totaled approximately $247 million. Interest on the 7.375% Senior Notes is payable semi-annually, in arrears, on March 15 and September 15 of each year. The 7.375% Senior Notes are senior unsecured obligations of NHIL, unconditionally guaranteed by Noble, and 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.

 

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The indentures governing our four series of outstanding senior unsecured notes contain covenants that place restrictions on certain merger and consolidation transactions, unless we are the surviving entity or the other party assumes the obligations under the indenture, and on the ability to sell or transfer all or substantially all of our assets. In addition, there are restrictions on incurring or assuming certain liens and sale and lease-back transactions. At December 31, 2008, we were in compliance with all our debt covenants. We continually monitor compliance with the covenants under our notes and, based on our expectations for 2009, expect to remain in compliance during the year.

At December 31, 2008, we had letters of credit of $150 million and performance and tax assessment bonds totaling $301 million supported by surety bonds outstanding. Of the letters of credit outstanding, $100 million were issued to support bank bonds in connection with our drilling units in Nigeria. 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 to $923 million (including current maturities of $173 million) at December 31, 2008 from $785 million (including current maturities of $10 million) at December 31, 2007, primarily due to the issuance of the 7.375% Senior Notes discussed above, partially offset by the repayment of the outstanding balance under the Credit Facility in 2008. We expect to meet current maturity requirements either through cash on hand at maturity or by using borrowings available under our Credit Facility. Other than our outstanding letters of credit and surety bonds discussed above, at December 31, 2008 and 2007, we had no other off-balance sheet debt or other off-balance sheet arrangements. For additional information on our long-term debt, see Note 5 to our accompanying consolidated financial statements.

						Payments Due by Period
		Total				2009				2010				2011				2012				2013				Thereafter
Contractual Cash Obligations
Long-term debt obligations (including current maturities)		$	923,487			$	172,698			$	—			$	—			$	—			$	299,837			$	450,952
Interest payments			330,515				53,410				51,190				51,190				51,190				40,908				82,627
Operating leases			22,108				7,764				6,046				3,059				477				228				4,534
Pension plan contributions (1)			11,687				6,699				267				766				284				413				3,258
Purchase commitments			1,222,875				824,848				255,794				142,233				—				—				—
Total contractual cash obligations		$	2,510,672			$	1,065,419			$	313,297			$	197,248			$	51,951			$	341,386			$	541,371