NABORS INDUSTRIES LTD - Annual Report: 2007 (Form 10-K)

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

NABORS INDUSTRIES LTD.

98-0363970
(I.R.S. Employer Identification No.)

		Name of each
Title of each class		exchange on which registered
Common shares, $.001 par value per share		The New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934:
None.

Indicate by check mark whether 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 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. o

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		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

The aggregate market value of the 268,520,223 common shares, par value $.001 per share, held by non-affiliates of the registrant, based upon the closing price of our common shares as of the last business day of our most recently completed second fiscal quarter, June 30, 2007, of $33.38 per share as reported on the New York Stock Exchange, was $8,963,205,044. Common shares held by each officer and director and by each person who owns 5% or more of the outstanding common shares have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

The number of common shares, par value $.001 per share, outstanding as of February 22, 2008 was 280,678,568. In addition, our subsidiary, Nabors Exchangeco (Canada) Inc., had 121,008 exchangeable shares outstanding as of February 22, 2008 that are exchangeable for Nabors common shares on a one-for-one basis, and have essentially identical rights as Nabors Industries Ltd. common shares, including but not limited to voting rights and the right to receive dividends, if any.

Specified portions of the 2008 Notice of Annual Meeting of Shareholders and the definitive Proxy
Statement to be distributed in connection with the 2008 annual meeting of shareholders (Part III)

 

 

NABORS INDUSTRIES LTD.
Form 10-K Annual Report
For the Fiscal Year Ended December 31, 2007
Table of Contents

		PART I
Item 1.		Business			3
Item 1A.		Risk Factors			9
Item 1B.		Unresolved Staff Comments			13
Item 2.		Properties			13
Item 3.		Legal Proceedings			14
Item 4.		Submission of Matters to a Vote of Security Holders			14
		PART II
Item 5.		Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities			15
Item 6.		Selected Financial Data			17
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			37
Item 8.		Financial Statements and Supplementary Data			40
Item 9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			93
Item 9A.		Controls and Procedures and Management’s Report on Internal Control over Financial Reporting			93
Item 9B.		Other Information			94
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance			95
Item 11.		Executive Compensation			95
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			96
Item 13.		Certain Relationships and Related Transactions, and Director Independence			97
Item 14.		Principal Accounting Fees and Services			97
		PART IV
Item 15.		Exhibits, Financial Statement Schedules			98
Computation of Ratios
Subsidiaries
Consent of Independent Registered Public Accounting Firm
Certification of Chairman & CEO Pursuant to Rule 13a-14(a)
Certification of VP & CFO Pursuant to Rule 13a-14(a)
Certifications Pursuant to Section 1350

     Our internet address is www.nabors.com. We make available free of charge through our website 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 Securities Exchange Act of 1934 (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). In addition, a glossary of drilling terms used in this document and documents relating to our corporate governance (such as committee charters, governance guidelines and other internal policies) can be found on our website. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

FORWARD-LOOKING STATEMENTS

     We often discuss expectations regarding our future markets, demand for our products and services, and our performance in our annual and quarterly reports, press releases, and other written and oral statements. Statements that relate to matters that are not historical facts are “forward-looking statements” within the meaning of the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These “forward-looking statements” are based on an analysis of currently available competitive, financial and economic data and our operating plans. They are inherently uncertain and investors should recognize that events and actual results could turn out to be significantly different from our expectations. By way of illustration, when used in this document, words such as “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “will,” “should,” “could,” “may,” “predict” and similar expressions are intended to identify forward-looking statements.

     You should consider the following key factors when evaluating these forward-looking statements:

	•		fluctuations in worldwide prices of and demand for natural gas and oil;
	•		fluctuations in levels of natural gas and oil exploration and development activities;
	•		fluctuations in the demand for our services;

	•		the existence of competitors, technological changes and developments in the oilfield services industry;
	•		the existence of operating risks inherent in the oilfield services industry;
	•		the existence of regulatory and legislative uncertainties;
	•		the possibility of changes in tax laws;
	•		the possibility of political instability, war or acts of terrorism in any of the countries in which we do business; and
	•		general economic conditions.

     Our businesses depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Therefore, a sustained increase or decrease in the price of natural gas or oil, which could have a material impact on exploration, development and production activities, could also materially affect our financial position, results of operations and cash flows.

     The above description of risks and uncertainties is by no means all-inclusive, but is designed to highlight what we believe are important factors to consider. For a more detailed description of risk factors, please see Part I — Item 1A. — Risk Factors.

     Unless the context requires otherwise, references in this Annual Report on Form 10-K to “we,” “us,” “our,” “the Company,” or “Nabors” means Nabors Industries Ltd. and, where the context requires, includes our subsidiaries.

PART I

ITEM 1. BUSINESS

Introduction.

     Nabors is the largest land drilling contractor in the world with approximately 535 actively marketed land drilling rigs. We conduct oil, gas and geothermal land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. We are also one of the largest land well-servicing and workover contractors in the United States and Canada. We actively market approximately 564 land workover and well-servicing rigs in the United States, primarily in the southwestern and western United States, and approximately 173 land workover and well-servicing rigs in Canada. Nabors is a leading provider of offshore platform workover and drilling rigs, and actively markets 35 platform, 12 jack-up units and 4 barge rigs in the United States and multiple international markets. These rigs provide well-servicing, workover and drilling services. We have a 51% ownership interest in a joint venture in Saudi Arabia, which actively markets 9 rigs. We also offer a wide range of ancillary well-site services, including engineering, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in selected domestic and international markets. We provide logistics services for onshore drilling in Canada using helicopters and fixed-winged aircraft. We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software. We also invest in oil and gas exploration, development and production activities and have 49% ownership interests in joint ventures in the U.S., Canada and International areas.

     Nabors was formed as a Bermuda-exempt company on December 11, 2001. Through predecessors and acquired entities, Nabors has been continuously operating in the drilling sector since the early 1900s. Our principal executive offices are located at Mintflower Place, 8 Par-La-Ville Road, Hamilton, HM08, Bermuda. Our phone number at our principal executive offices is (441) 292-1510.

Our Fleet of Rigs.

•

Land Rigs. A land-based drilling rig generally consists of engines, a drawworks, a mast (or derrick), pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string and related equipment. The engines power the different pieces of equipment, including a rotary table or top drive that turns the drill string, causing the drill bit to bore through the subsurface rock layers. Rock cuttings are carried to the surface by the circulating drilling fluid. The intended well depth, bore hole diameter and drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job.

A land-based workover or well-servicing rig consists of a mobile carrier, engine, drawworks and a mast. The mobile workover or well-servicing rig is specially designed for periodic maintenance as well as major repairs and modifications of oil and gas wells for which service is required to maximize the productive life of such wells. Workovers may be required to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks or convert a depleted well to an injection well for secondary or enhanced recovery projects. The primary function of a workover or well-servicing rig is to act as a hoist so that pipe, sucker rods and down-hole equipment can be run into and out of a well. Because of size and cost considerations, well-servicing and workover rigs are used for these operations rather than the larger drilling rigs. Land-based drilling rigs are moved between well sites and between geographic areas of operations by using our fleet of cranes, loaders and transport vehicles or those from a third party service vendor. Well-servicing rigs are generally self-propelled units and heavier capacity workover rigs are either self-propelled or trailer mounted and include auxiliary equipment, which is either transported on trailers or moved with trucks.

•

Platform Rigs. Platform rigs provide offshore workover, drilling and re-entry services. Our platform rigs have drilling and/or well-servicing or workover equipment and machinery arranged in modular packages that are transported to, and assembled and installed on, fixed offshore platforms owned by the customer. Fixed offshore platforms are steel tower-like structures that either stand on the ocean floor or are moored floating structures. The top portion, or platform, sits above the water level and provides the foundation upon which the platform rig is placed.

•

Jack-up Rigs. Jack-up rigs are mobile, self-elevating drilling and workover platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the hull, which contains the drilling and/or workover equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. The rig legs may operate independently or have a mat attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas. Many of our jack-up rigs are of cantilever design — a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over adjacent, fixed platforms. Nabors’ shallow workover jack-up rigs generally are subject to a maximum water depth of approximately 125 feet, while some of our jack-up rigs may drill in water depths as shallow as 13 feet. Nabors also has deeper water depth capacity jack-up rigs that are capable of drilling at depths between eight feet and 150 to 250 feet. The water depth limit of a particular rig is determined by the length of the rig’s legs and the operating environment. Moving a rig from one drill site to another involves lowering the hull down into the water until it is afloat and then jacking up its legs with the hull floating. The rig is then towed to the new drilling site.

•

Inland Barge Rigs. One of Nabors’ barge rigs is a full-size drilling unit. Nabors also owns two workover inland barge rigs. These barges are designed to perform plugging and abandonment, well service or workover services in shallow inland, coastal or offshore waters. Our barge rigs can operate at depths between three and 20 feet.

Additional information regarding the geographic markets in which we operate and our business segments can be found in Note 19 of the Notes to Consolidated Financial Statements included in Part II, Item 8. below.

Customers: Types of Drilling Contracts.

     Our customers include major oil and gas companies, foreign national oil and gas companies and independent oil and gas companies. No customer accounted for greater than 10% of consolidated revenues in 2007 or in 2006.

     On land in the U.S. Lower 48 states and Canada, we have historically been contracted on a single-well basis, with extensions subject to mutual agreement on pricing and other significant terms. Beginning in late 2004, as a result of increasing demand for drilling services, our customers started entering into longer term contracts with durations ranging from one to three years. Under these contracts our rigs are committed to one customer over that term. Increasingly, these contracts are being signed for three-year terms for newly constructed rigs. Contracts relating to offshore drilling and land drilling in Alaska and international markets generally provide for longer terms, usually from one to five years. Offshore workover projects are often on a single-well basis. We generally are awarded drilling contracts through competitive bidding, although we occasionally enter into contracts by direct negotiation. Most of our single-well contracts are subject to termination by the customer on short notice, but some can be firm for a number of wells or a period of time, and may provide for early termination compensation in certain circumstances. The contract terms and rates may differ depending on a variety of factors, including competitive conditions, the geographical area, the geological formation to be drilled, the equipment and services to be supplied, the on-site drilling conditions and the anticipated duration of the work to be performed.

     In recent years, all of our drilling contracts have been daywork contracts. A daywork contract generally provides for a basic rate per day when drilling (the dayrate for us providing a rig and crew) and for lower rates when the rig is moving, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. In addition, daywork contracts may provide for a lump sum fee for the mobilization and demobilization of the rig, which in most cases approximates our incurred costs. A daywork contract differs from a footage contract (in which the drilling contractor is paid on the basis of a rate per foot drilled) and a turnkey contract (in which the drilling contractor is paid for drilling a well to a specified depth for a fixed price).

Well-Servicing and Workover Services.

     Although some wells in the United States flow oil to the surface without mechanical assistance, most are in mature production areas that require pumping or some other form of artificial lift. Pumping oil wells characteristically require more maintenance than flowing wells because of the operation of the mechanical pumping equipment installed.

•

Well-Servicing/Maintenance Services. We provide maintenance services on the mechanical apparatus used to pump or lift oil from producing wells. These services include, among other things, repairing and replacing pumps, sucker rods and tubing. We provide the rigs, equipment and crews for these tasks, which are performed on both oil and natural gas wells, but which are more commonly required on oil wells. Maintenance services typically take less than 48 hours to complete. Well-servicing rigs generally are provided to customers on a call-out basis. We are paid an hourly rate and work typically is performed five days a week during daylight hours.

•

Workover Services. Producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workovers normally are carried out with a well-servicing rig that includes additional specialized accessory equipment, which may include rotary drilling equipment, mud pumps, mud tanks and blowout preventers. A workover may last anywhere from a few days to several weeks. We are paid an hourly rate and work is generally performed seven days a week, 24 hours a day.

•

Completion Services. The kinds of activities necessary to carry out a workover operation are essentially the same as those that are required to “complete” a well when it is first drilled. The completion process may involve selectively perforating the well casing at the depth of discrete producing zones, stimulating and testing these zones and installing down-hole equipment. The completion process may take a few days to several weeks. We are paid an hourly rate and work is generally performed seven days a week, 24 hours a day.

•

Production and Other Specialized Services. We also can provide other specialized services, including onsite temporary fluid-storage facilities, the provision, removal and disposal of specialized fluids used during certain completion and workover operations, and the removal and disposal of salt water that often is produced in conjunction with the production of oil and natural gas. We also provide plugging services for wells from which the oil and natural gas has been depleted or further production has become uneconomical. We are paid an hourly or a per unit rate, as applicable, for these services.

Oil and Gas Investments.

     Through our Ramshorn business unit, Nabors makes selective investments in oil and gas exploration, development and production operations. Beginning in late 2006, we entered into an agreement with First Reserve Corporation to form select joint ventures to invest in oil and gas exploration opportunities worldwide. During 2007, three joint ventures were formed for operations in the United States, Canada and International areas. We hold a 49% ownership interest in these joint ventures. Additional information about recent activities for this segment can be found in Part II, Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Oil and Gas.

Other Services.

     Canrig Drilling Technology Ltd., our drilling technologies subsidiary, manufactures top drives, which are installed on both onshore and offshore drilling rigs. Our top drives are marketed throughout the world. During the last three years, approximately 65% of our top drive sales were made to other Nabors companies. We also rent top drives and provide top drive installation, repair and maintenance services to our customers. Canrig Drilling Technology Canada Ltd. manufactures catwalks and wrenches which are installed on both onshore and offshore drilling rigs. During the last nineteen months of operations since acquisition, approximately 62% of the equipment sales were made to other Nabors companies. Epoch Well Services, Inc., our well services subsidiary, offers rig instrumentation equipment, including sensors, proprietary RIGWATCH™ software and computerized equipment that monitors the

real-time performance of a rig. In addition, Epoch specializes in daily reporting software for drilling operations, making this data available through the internet via mywells.com. Epoch also provides mudlogging services. Ryan Energy Technologies, Inc., another one of our subsidiaries, manufactures and sells directional drilling and rig instrumentation and data collection services to oil and gas exploration and service companies. Nabors has a 50% interest in Peak Oilfield Services Company, a general partnership with a subsidiary of Cook Inlet Region, Inc., a leading Alaskan native corporation. Peak Oilfield Services provides heavy equipment to move drilling rigs, water, other fluids and construction materials, primarily on Alaska’s North Slope and in the Cook Inlet region. The partnership also provides construction and maintenance for ice roads, pads, facilities, equipment, drill sites and pipelines. Nabors also has a 50% interest in Alaska Interstate Construction, a limited liability company whose other primary partner is Cook Inlet Region, Inc. Alaska Interstate Construction is a general contractor involved in the construction of roads, bridges, dams, drill sites and other facility sites, as well as providing mining support in Alaska. Revenues are derived from services to companies engaged in mining and public works. Our subsidiary, Peak USA Energy Services, Ltd., provides hauling and maintenance services for customers in the U.S. Lower 48 states. Nabors Blue Sky Ltd. leases aircraft used for logistics services for onshore drilling in Canada using helicopters and fixed-winged aircraft.

Our Employees.

     As of December 31, 2007, Nabors employed approximately 23,965 persons, of whom approximately 3,044 were employed by unconsolidated affiliates. We believe our relationship with our employees generally is good.

     Certain rig employees in Argentina and Australia are represented by collective bargaining units.

Seasonality.

     Our Canadian and Alaskan drilling and workover operations are subject to seasonal variations as a result of weather conditions and generally experience reduced levels of activity and financial results during the second calendar quarter of each year. Seasonality does not have a material impact on the remaining portions of our business. Our overall financial results reflect the seasonal variations experienced in our Canadian and Alaskan operations.

Research and Development.

     Research and development constitutes a growing part of our overall business. The effective use of technology is critical to the maintenance of our competitive position within the drilling industry. As a result of the importance of technology to our business, we expect to continue to develop technology internally or to acquire technology through strategic acquisitions.

Industry/Competitive Conditions.

     To a large degree, Nabors’ businesses depend on the level of capital spending by oil and gas companies for exploration, development and production activities. A sustained increase or decrease in the price of natural gas or oil could have a material impact on exploration, development and production activities by our customers and could also materially affect our financial position, results of operations and cash flows. See Part I — Item 1A. — Risk Factors — Fluctuations in oil and gas prices could adversely affect drilling activity and Nabors’ revenues, cash flows and profitability.

     Our industry remains competitive. Historically, the number of rigs has exceeded demand in many of our markets, resulting in strong price competition. More recently, as a result of improved demand for drilling services driven by a sustained high level of commodity prices, supply and demand have been in balance in most of our markets, with demand actually exceeding supply in some of our markets. This economic reality has resulted in an increase in rates being charged for rigs across our North American, Offshore and International markets. Furthermore, over the last three years, the dramatic increase in rates along with our customers’ willingness to enter into firm three-year commitments has resulted in our building of new rigs in significant quantities for the first time in over 20 years. However, as many existing rigs can be readily moved from one region to another in response to changes in levels of activity and many of the total available contracts are currently awarded on a bid basis, competition based on price for both existing and new rigs still exists across all of our markets. The land drilling, workover and well-servicing market is generally more competitive than the offshore market due to the larger number of rigs and market participants.

     In all of our geographic market areas, we believe price and availability and condition of equipment are the most significant factors in determining which drilling contractor is awarded a job. Other factors include the availability of trained personnel possessing the required specialized skills; the overall quality of service and safety record; and domestically, the ability to offer ancillary services.

Increasingly, as the market requires additional rigs and as a result of new build capacity, the ability to deliver rigs within certain timeframes is becoming a competitive factor. In international markets, experience in operating in certain environments and customer alliances, also have been factors in the selection of Nabors.

     Certain competitors are present in more than one of Nabors’ operating regions, although no one competitor operates in all of these areas. In the U.S. Lower 48 states, there are several hundred competitors with national, regional or local rig operations. In domestic land workover and well-servicing, we compete with Basic Energy Services, Inc. and Key Energy Services, Inc. and with numerous other competitors having smaller regional or local rig operations. In Canada and offshore, Nabors competes with many firms of varying size, several of which have more significant operations in those areas than Nabors. Internationally, Nabors competes directly with various contractors at each location where it operates. Nabors believes that the market for land drilling, workover and well-servicing contracts will continue to be competitive for the foreseeable future.

     Our other operating segments represent a relatively smaller part of our business, and we have numerous competitors in each area. Our Canrig subsidiary is one of the four major manufacturers of top drives. Its largest competitors are National Oilwell Varco, Tesco and MH Pyramid. Epoch’s largest competitors in the manufacture of rig instrumentation systems are Pason and National Oilwell Varco’s Totco subsidiary. Mudlogging services are provided by a number of entities that serve the oil and gas industry on a regional basis. Epoch competes for mudlogging customers with Baker Hughes, Sperry Sun, Diversified, and Stratagraph in the Gulf Coast region, California and Alaska. In the U.S. Lower 48 states, there are hundreds of rig transportation companies, and there are at least three or four that compete with Peak USA in each of its operating regions. In Alaska, Peak Oilfield Services principally competes with Alaska Petroleum Contractors for road, pad and pipeline maintenance, and is one of many drill site and road construction companies, the largest of which is VECO Corporation, and Alaska Interstate Construction principally competes with Wilder Construction Company and Cruz Construction Company for the construction of roads, bridges, dams, drill sites and other facility sites.

Our Business Strategy.

     Since 1987, with the installation of our current management team, Nabors has adhered to a consistent strategy aimed at positioning our company to grow and prosper in good times and to mitigate adverse effects during periods of poor market conditions. We have maintained a financial posture that allows us to capitalize on market weakness and strength by adding to our business base, thereby enhancing our upside potential. The principal elements of our strategy have been to:

	•		Maintain flexibility to respond to changing conditions.
	•		Maintain a conservative and flexible balance sheet.
	•		Build cost effectively a base of premium assets.
	•		Build and maintain low operating costs through economies of scale.
	•		Develop and maintain long-term, mutually attractive relationships with key customers and vendors.
	•		Build a diverse business in long-term, sustainable and worthwhile geographic markets.
	•		Recognize and seize opportunities as they arise.
	•		Continually improve safety, quality and efficiency.
	•		Implement leading edge technology where cost-effective to do so.
	•		Build shareholder value by an expansion of our oil and gas reserves and production.

     Our business strategy is designed to allow us to grow and remain profitable in any market environment. The major developments in our business in the past three years illustrate our implementation of this strategy and its continuing success. Specifically, we have taken advantage of the robust rig market to obtain a high volume of contracts for newly constructed rigs. A large proportion of these rigs are subject to long-term contracts with creditworthy customers with the most significant impact occurring in our International operations. This will not only expand our operations with the latest state-of-the-art rigs, which should better weather downturns in market activity, but eventually replace the oldest least capable rigs in our existing fleet.

Acquisitions and Divestitures.

     We have grown from a land drilling business centered in the U.S. Lower 48 states, Canada and Alaska to an international business with operations on land and offshore in many of the major oil, gas and geothermal markets in the world. At the beginning of 1990, our fleet consisted of 44 actively marketed land drilling rigs in Canada, Alaska and in various international markets. Today, Nabors’ worldwide fleet of actively marketed rigs consist of approximately 535 land drilling rigs, approximately 564 domestic and 173 international land workover and well-servicing rigs, 35 offshore platform rigs, 12 jack-up units, 4 barge rigs and a large component of trucks and fluid hauling vehicles. This growth was fueled in part by strategic acquisitions. Although Nabors continues to examine opportunities, there can be no assurance that attractive rigs or other acquisition opportunities will continue to be available, that the pricing will be economical or that we will be successful in making such acquisitions in the future.

     On January 3, 2006, we completed an acquisition of 1183011 Alberta Ltd., a wholly-owned subsidiary of Airborne Energy Solutions Ltd., through the purchase of all common shares outstanding for cash for a total purchase price of Cdn. $41.7 million (U.S. $35.8 million). In addition, we assumed debt, net of working capital, totaling approximately Cdn. $10.0 million (U.S. $8.6 million). Nabors Blue Sky Ltd. (formerly 1183011 Alberta Ltd.) owns 42 helicopters and fixed-wing aircraft and owns and operates a fleet of heliportable well-service equipment. The purchase price has been allocated based on final valuations of the fair value of assets acquired and liabilities assumed as of the acquisition date and resulted in goodwill of approximately U.S. $18.8 million.

     On May 31, 2006, we completed an acquisition of Pragma Drilling Equipment Ltd.’s business, which manufactures catwalks, iron roughnecks and other related oilfield equipment, through an asset purchase consisting primarily of intellectual property for a total purchase price of Cdn. $46.1 million (U.S. $41.5 million). The purchase price has been allocated based on final valuations of the fair market value of assets acquired and liabilities assumed as of the acquisition date and resulted in goodwill of approximately U.S. $10.5 million.

     On August 8, 2007, we sold our Sea Mar business which had previously been included in Other Operating segments. The assets included 20 offshore supply vessels and certain related assets, including a right under a vessel construction contract. The operating results of this business for all periods presented are accounted for as a discontinued operation in the accompanying audited consolidated statements of income.

     From time to time, we may sell a subsidiary or group of assets outside of our core markets or business, if it is economically advantageous for us to do so.

Environmental Compliance.

     Nabors does not presently anticipate that compliance with currently applicable environmental regulations and controls will significantly change its competitive position, capital spending or earnings during 2008. Nabors believes it is in material compliance with applicable environmental rules and regulations, and the cost of such compliance is not material to the business or financial condition of Nabors. For a more detailed description of the environmental laws and regulations applicable to Nabors operations, see below under Part I — Item 1A. — Risk Factors — Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect Nabors’ results of operations.

ITEM 1A. RISK FACTORS

     In addition to the other information set forth elsewhere in this Form 10-K, the following factors should be carefully considered when evaluating Nabors.

Fluctuations in oil and gas prices could adversely affect drilling activity and our revenues, cash flows and profitability

     Our operations are materially dependent upon the level of activity in oil and gas exploration and production. Both short-term and long-term trends in oil and gas prices affect the level of such activity. Oil and gas prices and, therefore, the level of drilling, exploration and production activity can be volatile. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and gas. Weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, and other factors beyond our control may also affect the supply of and demand for oil and gas. We believe that any prolonged reduction in oil and gas prices would depress the level of exploration and production activity. This would likely result in a corresponding decline in the demand for our services and could have a material adverse effect on our revenues, cash flows and profitability. Lower oil and gas prices could also cause our customers to seek to terminate, renegotiate or fail to honor our drilling contracts; affect the fair market value of our rig fleet which in turn could trigger a write-down for accounting purposes; affect our ability to retain skilled rig personnel; and affect our ability to obtain access to capital to finance and grow our business. There can be no assurances as to the future level of demand for our services or future conditions in the oil and gas and oilfield services industries.

We operate in a highly competitive industry with excess drilling capacity, which may adversely affect our results of operations

     The oilfield services industry in which we operate is very competitive. Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Many drilling, workover and well-servicing rigs can be moved from one region to another in response to changes in levels of activity and provided market conditions warrant, which may result in an oversupply of rigs in an area. In many markets in which we operate, the number of rigs available for use exceeds the demand for rigs, resulting in price competition. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. The land drilling market generally is more competitive than the offshore drilling market because there are larger numbers of rigs and competitors.

The nature of our operations presents inherent risks of loss that, if not insured or indemnified against, could adversely affect our results of operations

     Our operations are subject to many hazards inherent in the drilling, workover and well-servicing industries, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Our offshore operations are also subject to the hazards of marine operations including capsizing, grounding, collision, damage from hurricanes and heavy weather or sea conditions and unsound ocean bottom conditions. In addition, our international operations are subject to risks of war, civil disturbances or other political events. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, there is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will be available to cover any or all of these risks, or, even if available, that it will be adequate or that insurance premiums or other costs will not rise significantly in the future, so as to make such insurance prohibitive. It is possible that we will face continued upward pressure in our upcoming insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or more expensive than it has been in the past. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible. We may choose to increase the levels of deductibles (and thus assume a greater degree of risk) from time to time in order to minimize the overall cost to the Company.

The profitability of our international operations could be adversely affected by war, civil disturbance or political or economic turmoil

     We derive a significant portion of our business from international markets, including major operations in Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. These operations are subject to various risks, including the risk of war, civil disturbances and governmental activities that may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. In certain countries, our operations may be subject to the additional risk of fluctuating currency values and exchange controls. In the international markets in which we operate, we are subject to various laws and regulations that govern the operation and taxation of our business and the import and export of our equipment from country to country, the imposition, application and interpretation of which can prove to be uncertain.

Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect our results of operations

     The drilling of oil and gas wells is subject to various federal, state, local and foreign laws, rules and regulations. Our cost of compliance with these laws and regulations may be substantial. For example, federal law imposes a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of onshore and offshore rigs and transportation equipment, we may be deemed to be a responsible party under federal law. In addition, our well-servicing, workover and production services operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. Our operations and facilities are subject to numerous state and federal environmental laws, rules and regulations, including, without limitation, laws concerning the containment and disposal of hazardous substances, oilfield waste and other waste materials, the use of underground storage tanks and the use of underground injection wells. We generally require customers to contractually assume responsibility for compliance with environmental regulations. However, we are not always successful in allocating to customers all of these risks nor is there any assurance that the customer will be financially able to bear those risks assumed.

     We employ personnel responsible for monitoring environmental compliance and arranging for remedial actions that may be required from time to time and also use consultants and to advise on and assist with our environmental compliance efforts. Liabilities are recorded when the need for environmental assessments and/or remedial efforts become known or probable and the cost can be reasonably estimated.

     Laws protecting the environment generally have become more stringent than in the past and are expected to continue to become more so. Violation of environmental laws and regulations can lead to the imposition of administrative, civil or criminal penalties, remedial obligations, and in some cases injunctive relief. Such violations could also result in liabilities for personal injuries, property damage, and other costs and claims.

     Under the Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, and related state laws and regulations, liability can be imposed jointly on the entire group of responsible parties or separately on any one of the responsible parties, without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources.

     Changes in federal and state environmental regulations may also negatively impact oil and natural gas exploration and production companies, which in turn could have a material adverse effect on us. For example, legislation has been proposed from time to time in Congress which would reclassify certain oil and natural gas production wastes as hazardous wastes, which would make the reclassified wastes subject to more stringent handling, disposal and clean-up requirements. If enacted, such legislation could dramatically increase operating costs for oil and natural gas companies and could reduce the market for our services by making many wells and/or oilfields uneconomical to operate.

     The Oil Pollution Act of 1990, as amended, contains provisions specifying responsibility for removal costs and damages resulting from discharges of oil into navigable waters or onto the adjoining shorelines. In addition, the Outer Continental Shelf Lands Act provides the federal government with broad discretion in regulating the leasing of offshore oil and gas production sites.

As a holding company, we depend on our subsidiaries to meet our financial obligations

     We are a holding company with no significant assets other than the stock of our subsidiaries. In order to meet our financial needs, we rely exclusively on repayments of interest and principal on intercompany loans made by us to our operating subsidiaries and income from dividends and other cash flow from such subsidiaries. There can be no assurance that our operating subsidiaries will generate sufficient net income to pay upstream dividends or cash flow to make payments of interest and principal to us in respect of their intercompany loans. In addition, from time to time, our operating subsidiaries may enter into financing arrangements which may contractually restrict or prohibit such upstream payments to us. There may also be adverse tax consequences associated with making dividend payments upstream.

We do not currently intend to pay dividends

     We have not paid any cash dividends on our common shares since 1982. Nabors does not currently intend to pay any cash dividends on its common shares. However, we note that there have been recent positive industry trends and changes in tax law providing more favorable treatment of dividends. As a result, we can give no assurance that we will not reevaluate our position on dividends in the future.

Because our option, warrant and convertible securities holders have a considerable number of common shares available for issuance and resale, significant issuances or resales in the future may adversely affect the market price of our common shares

     As of February 22, 2008, we had 800,000,000 authorized common shares, of which 280,678,568 shares were outstanding. In addition, 29,557,933 common shares were reserved for issuance pursuant to option and employee benefit plans, and 99,156,387 shares were reserved for issuance upon conversion or repurchase of outstanding zero coupon convertible debentures and zero coupon senior exchangeable notes. In addition, up to 121,008 of our common shares could be issuable on exchange of the shares of Nabors Exchangeco (Canada) Inc. We also may sell up to $700 million of securities of various types in connection with a shelf registration statement declared effective on January 16, 2003 by the SEC. The sale, or availability for sale, of substantial amounts of our common shares in the public market, whether directly by us or resulting from the exercise of warrants or options (and, where applicable, sales pursuant to Rule 144) or the conversion into common shares, or repurchase of debentures and notes using common shares, would be dilutive to existing security holders, could adversely affect the prevailing market price of our common shares and could impair our ability to raise additional capital through the sale of equity securities.

Provisions of our organizational documents may deter a change of control transaction and decrease the likelihood of a shareholder receiving a change of control premium

     Our board of directors is divided into three classes, with each class serving a staggered three-year term. In addition, our board of directors has the authority to issue a significant amount of common shares and up to 25,000,000 preferred shares and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of the preferred shares, in each case without further vote or action by the holders of the common shares. Although we have no present plans to issue preferred shares, the classified board and our board’s ability to issue additional preferred shares may discourage, delay or prevent changes in control of Nabors that are not supported by our board, thereby possibly preventing certain of our shareholders from realizing a possible premium on their shares. In addition, the requirement in the indenture for our $2.75 billion senior exchangeable notes due 2011 and Series B of our $700 million zero coupon senior exchangeable notes due 2023 to pay a make-whole premium in the form of an increase in the exchange rate in certain circumstances could have the effect of making a change in control of Nabors more expensive.

We have a substantial amount of debt outstanding

     As of December 31, 2007, we have long-term debt of approximately $4.0 billion, including current maturities of $700 million, and cash and cash equivalents and investments of $1.1 billion, including $236.3 million of long-term investments and $53.1 million in cash proceeds receivable from the sale of certain non-marketable securities that is included in other current assets. If either of our $2.75 billion 0.94% senior exchangeable notes or the $700 million zero coupon senior exchangeable notes are exchanged or our $700 million zero coupon senior exchangeable notes are put to us, we believe that we have the ability to access capital markets or otherwise obtain financing in order to satisfy any payment obligations that might arise upon exchange of these notes and that any cash payment due of this magnitude, in addition to our other cash obligations, will not ultimately have a material adverse impact on our liquidity or financial position. We have a gross funded debt to capital ratio of 0.44:1 and a net funded debt to capital ratio of 0.37:1. The gross funded debt to capital ratio is calculated by dividing funded debt by funded debt plus deferred tax liabilities net of deferred tax assets plus capital. Funded debt is defined as the sum of (1) short-term borrowings, (2) current portion of long-term debt and (3) long-term debt. Capital is defined as shareholders’ equity. The net funded debt to capital ratio is calculated by dividing net funded debt by net funded debt plus deferred tax liabilities net of deferred tax assets plus capital. Net funded debt is defined as the sum of (1) short-term borrowings, (2) current portion of long-term debt and (3) long-term debt reduced by the sum of cash and cash equivalents and short-term and long-term investments. Capital is

defined as shareholders’ equity. Both of these ratios are methods for calculating the amount of leverage a company has in relation to its capital.

     On February 20, 2008, Nabors Industries, Inc., our wholly-owned subsidiary, issued $575 million aggregate principal amount of 6.15% senior notes due 2018 that are fully and unconditionally guaranteed by Nabors Industries Ltd. See Note 21 Subsequent Event of our accompanying consolidated financial statements for additional information.

Our ability to perform under new contracts and to grow our business as forecasted depends to a substantial degree on timely delivery of rigs and equipment from our suppliers

     The forecasted growth in the operating revenues and net income for our Contract Drilling subsidiaries depends to a substantial degree on the timely delivery of rigs and equipment from our suppliers as part of our recently expanded capital programs. We can give no assurances that our suppliers will meet expected delivery schedules for delivery of these new rigs and equipment or that the new rigs and equipment will be free from defects. Delays in the delivery of new rigs and equipment and delays incurred in correcting any defects in such rigs and equipment could cause us to fail to meet our operating forecasts and could subject us to late delivery penalties under contracts with our customers.

We may have additional tax liabilities

     We are subject to income taxes in both the United States and numerous foreign jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly under audit by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than that which is reflected in historical income tax provisions and accruals. Based on the results of an audit or litigation, a material effect on our financial position, income tax provision, net income, or cash flows in the period or periods for which that determination is made could result.

     It is possible that future changes to tax laws (including tax treaties) could have an impact on our ability to realize the tax savings recorded to date as well as future tax savings as a result of our corporate reorganization, depending on any responsive action taken by us.

     On September 14, 2006, Nabors Drilling International Limited (“NDIL”), a wholly-owned Bermuda subsidiary of Nabors, received a Notice of Assessment (the “Notice”) from the Mexican Servicio de Administracion Tributaria (the “SAT”) in connection with the audit of NDIL’s Mexican branch for tax year 2003. The Notice proposes to deny a depreciation expense deduction that relates to drilling rigs operating in Mexico in 2003, as well as a deduction for payments made to an affiliated company for the provision of labor services in Mexico. The amount assessed by the SAT is approximately $19.8 million (including interest and penalties). Nabors and its tax advisors previously concluded that the deduction of said amounts was appropriate and more recently that the position of the SAT lacks merit. NDIL’s Mexican branch took similar deductions for depreciation and labor expenses in 2004, 2005, 2006 and 2007. It is likely that the SAT will propose the disallowance of these deductions upon audit of NDIL’s Mexican branch’s 2004, 2005, 2006 and 2007 tax years.

Proposed tax legislation could mitigate or eliminate the benefits of our 2002 reorganization as a Bermuda company

     Various bills have been introduced in Congress which could reduce or eliminate the tax benefits associated with our reorganization as a Bermuda company. Legislation enacted by Congress in 2004 provides that a corporation that reorganized in a foreign jurisdiction on or after March 4, 2003 shall be treated as a domestic corporation for United States federal income tax purposes. Nabors’ reorganization was completed June 24, 2002. There have been and we expect that there may continue to be legislation proposed by Congress from time to time applicable to certain companies that completed such reorganizations on or after March 20, 2002 which, if enacted, could limit or eliminate the tax benefits associated with our reorganization.

     Because we cannot predict whether legislation will ultimately be adopted, no assurance can be given that the tax benefits associated with our reorganization will ultimately accrue to the benefit of the Company and its shareholders. It is possible that future changes to the tax laws (including tax treaties) could have an impact on our ability to realize the tax savings recorded to date as well as future tax savings resulting from our reorganization.

Legal proceedings could affect our financial condition and results of operations

     We are from time to time subject to legal proceedings or governmental investigations which include employment, tort, intellectual property and other claims, and purported class action and shareholder derivative actions. We also are subject to complaints or allegations from former, current or prospective employees from time to time, alleging violations of employment-related laws. Lawsuits or claims could result in decisions against us which could have a material adverse effect on our financial condition or results of operations.

Our financial results could be affected by changes in the value of our investment portfolio

     We invest our excess cash in a variety of investment vehicles, many of which are subject to fluctuations resulting from a variety of economic factors or factors associated with a particular investment, including without limitation, overall declines in the equity markets, currency and interest rate fluctuations, volatility in the credit markets, exposures related to concentrations of investments in a particular fund or investment, exposures related to hedges of financial positions, and the performance of particular fund or investment managers. As a result, events or developments which negatively affect the value of our investments could have a material adverse effect on our results of operations.

The loss of key executives could reduce our competitiveness and prospects for future success

     The successful execution of our strategies central to our future success will depend, in part, on a few of our key executive officers. We have entered into employment agreements with our Chairman and Chief Executive Officer, Mr. Eugene M. Isenberg and our Deputy Chairman, President and Chief Operating Officer, Mr. Anthony G. Petrello, to secure their employment through September 30, 2010. We do not carry key man insurance. The loss of Mr. Isenberg or Mr. Petrello could have an adverse effect on our financial condition or results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

     Not applicable.

ITEM 2. PROPERTIES

     Many of the international drilling rigs and certain of the Alaska rigs in our fleet are supported by mobile camps which house the drilling crews and a significant inventory of spare parts and supplies. In addition, we own various trucks, forklifts, cranes, earth moving and other construction and transportation equipment and own various helicopters, fixed-wing aircraft and heliportable well-service equipment, which are used to support drilling and logistics operations.

     Nabors and its subsidiaries own or lease executive and administrative office space in Hamilton, Bermuda (principal executive office); Houston, Texas; Anchorage, Alaska; Harvey, Houma, New Iberia and Lafayette, Louisiana; Bakersfield, California; Magnolia, Texas; Calgary, Red Deer and Nisku, Alberta, Canada; Sana’a, Yemen; Dubai, U.A.E.; Dhahran, Saudi Arabia; Anaco, Venezuela; and Luanda, Angola. We also own or lease a number of facilities and storage yards used in support of operations in each of our geographic markets.

     Nabors and its subsidiaries own certain mineral interests in connection with their investing and operating activities. Nabors does not consider these properties to be material to its overall operations.

     Additional information about our properties can be found in Notes 2 and 6 (each, under the caption Property, Plant and Equipment) and 14 (under the caption Operating Leases) of the Notes to Consolidated Financial Statements in Part II, Item 8. below. The revenues and property, plant and equipment by geographic area for the fiscal years ended December 31, 2005, 2006 and 2007, can be found in Note 19 of the Notes to Consolidated Financial Statements in Part II, Item 8. below. A description of our rig fleet is included under the caption Introduction in Part I, Item 1. — Business.

     Nabors’ management believes that our existing equipment and facilities and our planned expansion of our equipment and facilities through our capital expenditure programs currently in process are adequate to support our current level of operations as well as an expansion of drilling operations in those geographical areas where we may expand.

ITEM 3. LEGAL PROCEEDINGS

     Nabors and its subsidiaries are defendants or otherwise involved in a number of lawsuits in the ordinary course of business. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ from our estimates. In the opinion of management and based on liability accruals provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our consolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particular reporting period.

     On December 22, 2005, we received a grand jury subpoena from the United States Attorney’s Office in Anchorage, Alaska, seeking documents and information relating to an alleged spill, discharge, overflow or cleanup of drilling mud or sludge involving one of our rigs during March 2003. We are cooperating with the authorities in this matter.

     On February 6, 2007, a purported shareholder derivative action entitled Kenneth H. Karstedt v. Eugene M. Isenberg, et al was filed in the United States District Court for the Southern District of Texas against the Company’s officers and directors, and against the Company as a nominal defendant. The complaint alleged that stock options were priced retroactively and were improperly accounted for, and alleged various causes of action based on that assertion. The complaint sought, among other things, payment by the defendants to the Company of damages allegedly suffered by it and disgorgement of profits. On March 5, 2007, another purported shareholder derivative action entitled Gail McKinney v. Eugene M. Isenberg, et al was also filed in the United States District Court for the Southern District of Texas. The complaint made substantially the same allegations against the same defendants and sought the same elements of damages. The two derivative actions were consolidated into one proceeding. On December 31, 2007, the Company and the individual defendants agreed with the plaintiffs-shareholders to settle the derivative action. The settlement is subject to preliminary and final approval of the United States District Court for the Southern District of Texas. Under the terms of the proposed settlement, the Company and the individual defendants have implemented or will implement certain corporate governance reforms and adopt certain modifications to our equity award policy and our Compensation Committee charter. The Company and its insurers have agreed to pay up to $2.85 million to plaintiffs’ counsel for their attorneys’ fees and the reimbursement of their expenses and costs.

     During the fourth quarter of 2006 and the first quarter of 2007, a review was conducted of the Company’s granting practices and accounting for certain employee equity awards to both the senior executives of the Company and other employees from 1988 through 2006. Based on the results of the review, the Company recorded a noncash charge of $38.3 million, net of tax, at December 31, 2006. The Company determined that no restatement of its historical financial statements was necessary because there were no findings of fraud or intentional wrongdoing, and because the effects of certain revised measurement dates were not material in any fiscal year. In a letter dated December 28, 2006, the SEC staff advised us that it had commenced an informal inquiry regarding our stock option grants and related practices, procedures and accounting. By letter dated May 7, 2007, the SEC staff informed us they had closed the investigation without any recommendation of enforcement action.

     On July 5, 2007, we received an inquiry from the U.S. Department of Justice relating to its investigation of one of our vendors and compliance with the Foreign Corrupt Practices Act. Our Audit Committee of the Board of Directors has engaged outside counsel to review certain transactions with this vendor, which provides freight forwarding and customs clearance services, and we are cooperating with the Department of Justice inquiry. The ultimate outcome of this review cannot be determined at this time.

     On October 17, 2007, we settled a dispute with a vendor. Pursuant to the settlement, we received an equity interest in a parent company of the vendor, we granted the vendor a nonexclusive, royalty-free license to use certain technology, and the parties each executed a mutual release of claims against each other.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     Not applicable.

PART II

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

STOCK PERFORMANCE GRAPH

     The following graph illustrates comparisons of five-year cumulative total returns among Nabors Industries Ltd., the S&P 500 Index and the Dow Jones Oil Equipment and Services Index. Total return assumes $100 invested on December 31, 2002 in shares of Nabors Industries Ltd., the S&P 500 Index, and the Dow Jones Oil Equipment and Services Index. It also assumes reinvestment of dividends and is calculated at the end of each calendar year, December 31, 2003 to December 31, 2007.

		2003				2004				2005				2006				2007
Nabors Industries Ltd.			118				145				215				169				155
S&P 500 Index			129				143				150				173				183
Dow Jones Oil Equipment and Services Index			115				155				236				267				388

I. Market and Share Prices.

     Our common shares are traded on the New York Stock Exchange under the symbol “NBR”. At December 31, 2007, there were approximately 2,006 shareholders of record. We have not paid any cash dividends on our common shares since 1982. Nabors does not currently intend to pay any cash dividends on its common shares. However, we note that there have been recent positive industry trends and changes in tax law providing more favorable treatment of dividends. As a result, we can give no assurance that we will not reevaluate our position on dividends in the future.

     On December 13, 2005, our Board of Directors approved a two-for-one stock split of our common shares to be effectuated in the form of a stock dividend. The stock dividend was distributed on April 17, 2006 to shareholders of record on March 31, 2006. For all balance sheets presented, capital in excess of par value was reduced by $.2 million and common shares were increased by $.2 million.

     The following table sets forth the reported high and low sales prices of our common shares as reported on the New York Stock Exchange for the periods indicated.

				Share Price
Calendar Year				High		Low
2006		First quarter		41.35		31.36
		Second quarter		40.71		29.75
		Third quarter		36.04		28.35
		Fourth quarter		34.62		27.26
2007		First quarter		32.74		27.53
		Second quarter		36.42		29.59
		Third quarter		34.10		27.05
		Fourth quarter		31.23		26.00

     The following table provides information relating to Nabors’ repurchase of common shares during the fourth quarter of 2007:

Approximate Dollar

Total Number of

Value of Shares

Shares Purchased as

that May Yet Be

Part of Publicly

Purchased Under the

Total Number of

Average Price Paid

Announced Plans or

Plans or

Period

Shares Purchased

per Share

Programs

Programs(1)

(In thousands, except per share prices)

November 1 — November 30, 2007

951

$

26.87

951

$

380,721

December 1 — December 31, 2007

2,831

$

27.16

2,831

$

303,810

     No common shares were repurchased during October 2007.

     See Part III, Item 12. for a description of securities authorized for issuance under equity compensation plans.

II. Dividend Policy.

     See Part I — Item 1A. — Risk Factors — We do not currently intend to pay dividends.

III. Shareholder Matters.

     Bermuda has exchange controls which apply to residents in respect of the Bermudian dollar. As an exempt company, Nabors is considered to be nonresident for such controls; consequently, there are no Bermuda governmental restrictions on the Company’s ability to make transfers and carry out transactions in all other currencies, including currency of the United States.

     There is no reciprocal tax treaty between Bermuda and the United States regarding withholding taxes. Under existing Bermuda law, there is no Bermuda income or withholding tax on dividends, if any, paid by Nabors to its shareholders. Furthermore, no Bermuda tax or other levy is payable on the sale or other transfer (including by gift or on the death of the shareholder) of Nabors common shares (other than by shareholders resident in Bermuda).

ITEM 6. SELECTED FINANCIAL DATA

Operating Data (1)(2)		Year Ended December 31,
(In thousands, except per share amounts and ratio data)		2007				2006				2005				2004				2003
Revenues and other income:
Operating revenues		$	4,938,848			$	4,707,289			$	3,394,472			$	2,351,571			$	1,814,520
Earnings from unconsolidated affiliates			17,724				20,545				5,671				4,057				10,058
Investment (loss) income			(15,891	)			102,007				85,428				50,044				33,800
Total revenues and other income			4,940,681				4,829,841				3,485,571				2,405,672				1,858,378
Costs and other deductions:
Direct costs			2,764,559				2,511,392				1,958,538				1,542,364				1,225,960
General and administrative expenses			436,282				416,610				247,129				192,692				164,136
Depreciation and amortization			467,730				364,653				285,054				248,057				219,841
Depletion			72,182				38,580				46,894				45,460				8,599
Interest expense			53,702				46,586				44,849				48,507				70,740
Losses (gains) on sales of long-lived assets, impairment charges and other expense (income), net			10,895				24,118				45,952				(5,036	)			1,362
Total costs and other deductions			3,805,350				3,401,939				2,628,416				2,072,044				1,690,638
Income from continuing operations before income taxes			1,135,331				1,427,902				857,155				333,628				167,740
Income tax expense (benefit)			239,664				434,893				219,000				32,660				(19,968	)
Income from continuing operations, net of tax			895,667				993,009				638,155				300,968				187,708
Income from discontinued operations, net of tax			35,024				27,727				10,540				1,489				4,520
Net income		$	930,691			$	1,020,736			$	648,695			$	302,457			$	192,228
Earnings per share:
Basic from continuing operations		$	3.21			$	3.42			$	2.05			$	1.01			$	.64
Basic from discontinued operations			.13				.10				.03				.01				.02
Total Basic		$	3.34			$	3.52			$	2.08			$	1.02			$	.66
Diluted from continuing operations		$	3.13			$	3.31			$	1.97			$	.96			$	.61
Diluted from discontinued operations			.12				.09				.03				—				.01
Total Diluted		$	3.25			$	3.40			$	2.00			$	.96			$	.62
Weighted-average number of common shares outstanding:
Basic			279,026				290,241				312,134				297,872				292,989
Diluted			286,606				299,827				324,378				328,060				313,794
Capital expenditures and acquisitions of businesses (3)		$	1,979,831			$	1,997,971			$	1,003,269			$	544,429			$	353,138
Interest coverage ratio (4)			32.5:1				38.1:1				25.6:1				12.9:1				6.1:1

Balance Sheet Data (2) (In thousands, except ratio data)		2007				2006				2005				2004				2003
Cash and cash equivalents and short-term and long-term investments (5)		$	1,056,358			$	1,653,285			$	1,646,327			$	1,411,047			$	1,579,090
Working capital			710,980				1,650,496				1,264,852				821,120				1,529,691
Property, plant and equipment, net			6,689,126				5,410,101				3,886,924				3,275,495				2,990,792
Total assets			10,103,382				9,142,303				7,230,407				5,862,609				5,602,692
Long-term debt			3,306,433				4,004,074				1,251,751				1,201,686				1,985,553
Shareholders’ equity		$	4,514,121			$	3,536,653			$	3,758,140			$	2,929,393			$	2,490,275
Funded debt to capital ratio:
Gross (6)			0.44:1				0.50:1				0.32:1				0.38:1				0.45:1
Net (7)			0.37:1				0.37:1				0.08:1				0.15:1				0.20:1

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

MANAGEMENT OVERVIEW

     The following Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to help the reader understand the results of our operations and our financial condition. This information is provided as a supplement to, and should be read in conjunction with our consolidated financial statements and the accompanying notes to our consolidated financial statements.

     Nabors is the largest land drilling contractor in the world. We conduct oil, gas and geothermal land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. Nabors also is one of the largest land well-servicing and workover contractors in the United States and Canada and is a leading provider of offshore platform workover and drilling rigs in the United States and multiple international markets. To further supplement and complement our primary business, we offer a wide range of ancillary well-site services, including engineering, construction,

maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services, in selected domestic and international markets. We offer logistics services for onshore drilling in Canada using helicopter and fixed-winged aircraft. We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, and rig reporting software. We also invest in oil and gas exploration, development and production activities worldwide.

     The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, workover and well-servicing operations, on land and offshore. Our oil and gas exploration, development and production operations are included in a category labeled Oil and Gas for segment reporting purposes. Our operating segments engaged in drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations are aggregated in a category labeled Other Operating Segments for segment reporting purposes.

     Our businesses depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Therefore, a sustained increase or decrease in the price of natural gas or oil, which could have a material impact on exploration, development and production activities, could also materially affect our financial position, results of operations and cash flows.

     The magnitude of customer spending on new and existing wells is the primary driver of our business. The primary determinate of customer spending is the degree of their cash flow and earnings which are largely determined by natural gas prices in our U.S. Lower 48 Land Drilling, Canadian and U.S. Offshore (Gulf of Mexico) operations, while oil prices are the primary determinate in our Alaskan, International and U.S. Land Well-servicing operations. The following table sets forth natural gas and oil price data per Bloomberg for the last three years:

		Year Ended December 31,												Increase / (Decrease)
		2007				2006				2005				2007 to 2006								2006 to 2005
Commodity prices:
Average Henry Hub natural gas spot price ($/million cubic feet (mcf))		$	6.97			$	6.73			$	8.89			$	0.24				4	%		$	(2.16	)			(24	%)
Average West Texas intermediate crude oil spot price ($/barrel)		$	72.23			$	66.09			$	56.59			$	6.14				9	%		$	9.50				17	%

     Operating revenues and earnings from unconsolidated affiliates for the year ended December 31, 2007 totaled $5.0 billion, representing an increase of $228.7 million, or 5%, compared to the year ended December 31, 2006. Adjusted income derived from operating activities and net income for the year ended December 31, 2007 totaled $1.2 billion and $930.7 million ($3.25 per diluted share), respectively, representing decreases of 13% and 9%, respectively, compared to the year ended December 31, 2006. Operating revenues and earnings from unconsolidated affiliates for the year ended December 31, 2006 totaled $4.7 billion, representing an increase of $1.3 billion, or 39%, compared to the year ended December 31, 2005. Adjusted income derived from operating activities and net income for the year ended December 31, 2006 totaled $1.4 billion and $1.0 billion ($3.40 per diluted share), respectively, representing increases of 62% and 57%, respectively, compared to the year ended December 31, 2005.

     The decrease in our adjusted income derived from operating activities from 2006 to 2007 related primarily to our U.S. Lower 48 Land Drilling, Canada Drilling and Well-servicing, and our U.S. Well-servicing operations, where activity levels have decreased despite slightly higher natural gas prices and higher oil prices. Operating results were further negatively impacted by higher levels of depreciation expense due to our capital expenditures. Partially offsetting the decreases in our adjusted income derived from operating activities were the increases in operating results from our International operations and to a lesser extent by our Alaska operations, driven by continuing high oil prices. In addition, our net income and earnings per share for 2007 has decreased compared to 2006 as a result of investment net losses during 2007 only partially offset by a lower effective tax rate and a lower number of average shares outstanding.

     The increase in operating results from 2005 to 2006 resulted from higher revenues realized by essentially all of our operating segments. Revenues increased as a result of higher average dayrates and activity levels during 2006 compared to 2005. This increase in average dayrates and activity reflects an increase in demand for our services in these markets during 2006, which resulted from continuing higher expenditures by our customers for drilling and workover services as a result of historically high oil and natural gas prices throughout 2006.

     Our operating results for 2008 are expected to approximate the levels realized during 2007. We expect our International operations to show substantial increases resulting from the deployment of additional rigs under long-term contracts and the renewal of existing contracts at higher current market rates. However, our North American natural gas driven operations are expected to decrease. In our U.S. Lower 48 Land Drilling operations, we expect a significant number of expiring term contracts for older rigs to rollover in 2008 at lower margins. These decreases should be partially offset by the remaining new rig deployments at higher margins and improved margins of the previously deployed new rigs. We expect our Canadian operations to decrease as a result of the depressed market conditions there.

     The following tables set forth certain information with respect to our reportable segments and rig activity:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Reportable segments:
Operating revenues and earnings from unconsolidated affiliates from continuing operations: (1)
Contract Drilling: (2)
U.S. Lower 48 Land Drilling		$	1,710,990			$	1,890,302			$	1,306,963			$	(179,312	)			(9	%)		$	583,339				45	%
U.S. Land Well-servicing			715,414				704,189				491,704				11,225				2	%			212,485				43	%
U.S. Offshore			212,160				221,676				158,888				(9,516	)			(4	%)			62,788				40	%
Alaska			152,490				110,718				85,768				41,772				38	%			24,950				29	%
Canada			545,035				686,889				553,537				(141,854	)			(21	%)			133,352				24	%
International			1,094,802				746,460				552,656				348,342				47	%			193,804				35	%
Subtotal Contract Drilling (3)			4,430,891				4,360,234				3,149,516				70,657				2	%			1,210,718				38	%
Oil and Gas (4) (5)			152,320				59,431				62,913				92,889				156	%			(3,482	)			(6	%)
Other Operating Segments (6) (7)			588,483				505,286				282,910				83,197				16	%			222,376				79	%
Other reconciling items (8)			(215,122	)			(197,117	)			(95,196	)			(18,005	)			(9	%)			(101,921	)			(107	%)
Total		$	4,956,572			$	4,727,834			$	3,400,143			$	228,738				5	%		$	1,327,691				39	%
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)
Contract Drilling:
U.S. Lower 48 Land Drilling		$	596,302			$	821,821			$	464,570			$	(225,519	)			(27	%)		$	357,251				77	%
U.S. Land Well-servicing			156,243				199,944				107,728				(43,701	)			(22	%)			92,216				86	%
U.S. Offshore			51,508				65,328				38,783				(13,820	)			(21	%)			26,545				68	%
Alaska			37,394				17,542				16,608				19,852				113	%			934				6	%
Canada			87,046				185,117				136,368				(98,071	)			(53	%)			48,749				36	%
International			332,283				208,705				135,588				123,578				59	%			73,117				54	%
Subtotal Contract Drilling(3)			1,260,776				1,498,457				899,645				(237,681	)			(16	%)			598,812				67	%
Oil and Gas			56,133				4,065				10,194				52,068				N/M	(10)			(6,129	)			(60	%)
Other Operating Segments (6)			35,273				30,028				17,619				5,245				17	%			12,409				70	%
Other reconciling items (11)			(136,363	)			(135,951	)			(64,930	)			(412	)			0	%			(71,021	)			(109	%)
Total			1,215,819				1,396,599				862,528				(180,780	)			(13	%)			534,071				62	%
Interest expense			(53,702	)			(46,586	)			(44,849	)			(7,116	)			(15	%)			(1,737	)			(4	)%
Investment (loss) income			(15,891	)			102,007				85,428				(117,898	)			(116	%)			16,579				19	%
(Losses) gains on sales of long-lived assets, impairment charges and other income (expense), net			(10,895	)			(24,118	)			(45,952	)			13,223				55	%			21,834				48	%
Income from continuing operations before income taxes		$	1,135,331			$	1,427,902			$	857,155			$	(292,571	)			(20	%)		$	570,747				67	%

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Rig activity:
Rig years: (12)
U.S. Lower 48 Land Drilling			229.4				255.5				235.9				(26.1	)			(10	%)			19.6				8	%
U.S. Offshore			15.8				16.4				15.6				(0.6	)			(4	%)			0.8				5	%
Alaska			8.7				8.6				7.1				0.1				1	%			1.5				21	%
Canada			36.7				53.3				53.0				(16.6	)			(31	%)			0.3				1	%
International (13)			115.2				97.1				82.3				18.1				19	%			14.8				18	%
Total rig years			405.8				430.9				393.9				(25.1	)			(6	%)			37.0				9	%
Rig hours: (14)
U.S. Land Well-servicing			1,119,497				1,256,141				1,216,453				(136,644	)			(11	%)			39,688				3	%
Canada Well-servicing			283,471				360,129				367,414				(76,658	)			(21	%)			(7,285	)			(2	%)
Total rig hours			1,402,968				1,616,270				1,583,867				(213,302	)			(13	%)			32,403				2	%

SEGMENT RESULTS OF OPERATIONS

Contract Drilling

     Our Contract Drilling operating segments contain one or more of the following operations: drilling, workover and well-servicing, on land and offshore.

     U.S. Lower 48 Land Drilling. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	1,710,990			$	1,890,302			$	1,306,963			$	(179,312	)			(9	%)		$	583,339				45	%
Adjusted income derived from operating activities		$	596,302			$	821,821			$	464,570			$	(225,519	)			(27	%)		$	357,251				77	%
Rig years			229.4				255.5				235.9				(26.1	)			(10	%)			19.6				8	%

     The decrease in operating results from 2006 to 2007 is a result of year-over-year decreases in drilling activity. Additionally, the decrease in operating results is due to higher drilling rig operating costs, including depreciation expense related to capital expansion projects.

     The increase in our operating results from 2005 to 2006 primarily resulted from year-over-year increases in average dayrates and drilling activity, which is reflected in the increase in rig years from 2005 to 2006. Average dayrates and activity levels improved during 2005 and 2006 as a result of an increase in demand for drilling services, which resulted primarily from continuing higher price levels for natural gas during 2006.

     U.S. Land Well-servicing. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	715,414			$	704,189			$	491,704			$	11,225				2	%		$	212,485				43	%
Adjusted income derived from operating activities		$	156,243			$	199,944			$	107,728			$	(43,701	)			(22	%)		$	92,216				86	%
Rig hours			1,119,497				1,256,141				1,216,453				(136,644	)			(11	%)			39,688				3	%

     Operating revenues and earnings from unconsolidated affiliates increased from 2006 to 2007 primarily due to year-over-year higher average dayrates, supported by the sustained level of high oil prices and an expansion of our geographic market through nine additional service centers from our capital spending program. Higher average dayrates were partially offset by lower rig utilization. The decrease in adjusted income derived from operating activities from 2006 to 2007 reflects lower rig utilization, higher operating costs, higher SG&A costs and higher depreciation expense related to capital expansion projects.

     The increase in our operating results from 2005 to 2006 primarily resulted from a year-over-year increase in average dayrates and from higher well-servicing hours. This increase in dayrates and well-servicing hours resulted from higher customer demand for our services in a number of markets in which we operate, which was driven by a sustained level of higher oil prices.

     U.S. Offshore. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	212,160			$	221,676			$	158,888			$	(9,516	)			(4	%)		$	62,788				40	%
Adjusted income derived from operating activities		$	51,508			$	65,328			$	38,783			$	(13,820	)			(21	%)		$	26,545				68	%
Rig years			15.8				16.4				15.6				(0.6	)			(4	%)			0.8				5	%

     The decrease in operating results from 2006 to 2007 primarily resulted from a decrease in average dayrates and utilization for our jack-up rigs partially offset by the deployment of two new-built Barge and one Platform Workover Drilling rigs in early 2007. Operating results were further negatively impacted by increased depreciation expense relating to the new rigs added to the fleet.

     The increase in operating results from 2005 to 2006 primarily resulted from an increase in dayrates for our entire rig fleet due to higher customer demand for our services stemming from higher natural gas prices. Additionally, our fourth quarter operating results for 2006 were increased by $4.0 million of net business interruption insurance proceeds related to rigs of ours that were significantly damaged during Hurricane Rita in the third quarter of 2005.

     Alaska. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	152,490			$	110,718			$	85,768			$	41,772				38	%		$	24,950				29	%
Adjusted income derived from operating activities		$	37,394			$	17,542			$	16,608			$	19,852				113	%		$	934				6	%
Rig years			8.7				8.6				7.1				0.1				1	%			1.5				21	%

     The increase in operating results from 2006 to 2007 and from 2005 to 2006 is primarily due to year-over-year increases in average dayrates, driven by the sustained level of high oil prices. Drilling activity levels have increased as a result from new customer demand and deployment and utilization of additional rigs in 2006 and 2007. The increases in 2006 and 2007 were partially offset by increased labor and repairs and maintenance costs in 2006 and 2007 as compared to prior years.

     Canada. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	545,035			$	686,889			$	553,537			$	(141,854	)			(21	%)		$	133,352				24	%
Adjusted income derived from operating activities		$	87,046			$	185,117			$	136,368			$	(98,071	)			(53	%)		$	48,749				36	%
Rig years — Drilling			36.7				53.3				53.0				(16.6	)			(31	%)			0.3				1	%
Rig hours — Well-servicing			283,471				360,129				367,414				(76,658	)			(21	%)			(7,285	)			(2	%)

     The decrease in operating results from 2006 to 2007 resulted from year-over-year decreases in drilling and well-servicing activity. Our operating results for 2007 were further negatively impacted by proposed changes to the Alberta royalty and tax regime causing customers to assess the impact of such changes. The continued strengthening of the Canadian dollar versus the U.S. dollar positively impacted operating results in 2007 when translated to U.S. dollar equivalents but negatively impacted demand for our services as much of our customers revenue is denominated in U.S. dollars while their costs are denominated in Canadian dollars. Additionally, operating results were negatively impacted by increased operating expenses, including depreciation expense related to capital expansion projects.

     The increase in our operating results from 2005 to 2006 primarily resulted from year-over-year increases in average dayrates and hourly rates for our Canadian drilling and well-servicing operations, respectively, and from year-over-year increases in drilling activity. Average dayrates and hourly rates and drilling activity levels improved as a result of increased demand for our services in this market, which was driven by increased commodity prices from 2005 to 2006. The increases in drilling activity are reflected in the year-over-year increases in rig years. Well-servicing hours decreased from 2005 to 2006 as lower natural gas prices during the fourth quarter of 2006 reduced the demand for completion work on gas wells. Our results for 2006 and 2005 were also positively impacted by the strengthening of the Canadian dollar versus the U.S. dollar during those years.

     International. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase
and rig activity)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	1,094,802			$	746,460			$	552,656			$	348,342				47	%		$	193,804				35	%
Adjusted income derived from operating activities		$	332,283			$	208,705			$	135,588			$	123,578				59	%		$	73,117				54	%
Rig years			115.2				97.1				82.3				18.1				19	%			14.8				18	%

     The increase in operating results from 2006 to 2007 and from 2005 to 2006 primarily resulted from year-over-year increases in average dayrates and increases in drilling activities which is reflected in the increase in rig years from 2006 to 2007 and from 2005 to 2006. Average dayrates and activity levels improved during 2007 and 2006 as a result of an increase in demand for drilling services, due to the continuing high price for oil during 2006 and 2007. Results for 2007 have also been positively impacted from an expansion of our rig fleet and renewal of existing multi-year contracts at higher average dayrates.

Oil and Gas

     This operating segment represents our oil and gas exploration, development and production operations. The results of operations for this reportable segment are as follows:

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	152,320			$	59,431			$	62,913			$	92,889				156	%		$	(3,482	)			(6	%)
Adjusted income derived from operating activities		$	56,133			$	4,065			$	10,194			$	52,068				N/M	(1)		$	(6,129	)			(60	%)

     The increase in our operating results from 2006 to 2007 was primarily a result of year-over-year increases in income attributable to earnings related to production payment contracts and gains totaling $88 million recognized on the sale of certain properties during 2007. Additionally, operating results were higher year-over-year due to increases in production and increases in oil, gas and natural gas liquid prices. These increases to operating results were partially offset by a $33.6 million increase in depletion expense and approximately $3.9 million in net losses from the First Reserve joint ventures which commenced operations in 2007, as well as higher seismic costs and workover expenses compared to the prior year. The higher depletion expense resulted from increased units-of-production depletion and impairment charges, related to higher costs and lower than expected performance of certain oil and gas developmental wells.

     The decrease in our operating results from 2005 to 2006 primarily resulted from a reduction in production stemming from the payout of one investment with El Paso Corporation in late 2005 and the reversion of our net profits interest to an overriding royalty interest. The net impact of changes in commodity prices from 2005 to 2006 further contributed to the decrease in operating results from 2005 to 2006. Additionally, we incurred higher seismic costs and work-over expenses as compared to prior period and also recorded an impairment of oil and gas properties totaling approximately $9.9 million that was recorded as depletion expense. This impairment resulted from lower than expected performance of certain asset groups. These decreases were partially offset by a $20.7 million gain on the sale of certain leasehold interests in the first quarter of 2006.

Other Operating Segments

     These operations include our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations. The results of operations for these operating segments are as follows:

		Year Ended December 31,												Increase
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
Operating revenues and earnings from unconsolidated affiliates		$	588,483			$	505,286			$	282,910			$	83,197				16	%		$	222,376				79	%
Adjusted income (loss) derived from operating activities		$	35,273			$	30,028			$	17,619			$	5,245				17	%		$	12,409				70	%

     The increase in our operating results from 2006 to 2007 and from 2005 to 2006 primarily resulted from increased sales of top drives driven by the strengthening of the oil market and increased equipment sales associated with the acquisition of Pragma Drilling Equipment Ltd. in May 2006 and increased demand for the directional drilling market in the U.S. and increased market share in Canada. Results for construction and logistics services decreased during 2007 compared to 2006 due to lower demand for our services and increased in 2006 compared to 2005 due to higher demand for our services.

Discontinued Operations

     During the third quarter of 2007, we sold our Sea Mar business which had previously been included in Other Operating Segments for a cash purchase price of $194.3 million. The assets included 20 offshore supply vessels and certain related assets, including a right under a vessel construction contract. The operating results of this business for all periods presented are accounted for as discontinued operations in the accompanying consolidated statements of income, including a gain, net of tax of $19.6 million recorded in the third quarter of 2007. The results of operations from discontinued operations are as follows:

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
Revenues		$	58,887			$	112,873			$	65,436			$	(53,986	)			(48	%)		$	47,437				72	%
Income from discontinued operations, net of tax		$	35,024			$	27,727			$	10,540			$	7,297				26	%		$	17,187				163	%

     The decrease in revenues from 2006 to 2007 resulted from seven months of operations before our sale of the Sea Mar business in August 2007. The increase in income, net of tax, from 2006 to 2007 resulted from the gain recognized on the sale. The increase in our operating results from 2005 to 2006 primarily resulted from increased margins for our marine transportation and supply services driven by higher average dayrates and higher utilization, which was primarily driven by an improvement in the offshore drilling market that resulted in increased demand for our services.

OTHER FINANCIAL INFORMATION

General and administrative expenses

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
General and administrative expenses		$	436,282			$	416,610			$	247,129			$	19,672				5	%		$	169,481				69	%
General and administrative expenses as a percentage of operating revenues			8.8	%			8.9	%			7.3	%			(.1	%)			(1	%)			1.6	%			22	%

     General and administrative expenses increased from 2006 to 2007 and from 2005 to 2006 primarily as a result of increases in wages and burden for a majority of our operating segments compared to the prior year period, which primarily resulted from an increase in the number of employees required to support the increase in activity levels and from higher wages, and increased corporate compensation expense, which primarily resulted from higher bonuses and non-cash compensation expenses recorded for stock options and restricted stock grants during each sequential year. During 2006, the increase was also impacted by $51.6 million additional compensation expense recorded during the fourth quarter relating to the review of employee stock option granting practices performed by the Company as more fully described in Note 3.

Depreciation and amortization, and depletion expense

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
Depreciation and amortization expense		$	467,730			$	364,653			$	285,054			$	103,077				28	%		$	79,599				28	%
Depletion expense		$	72,182			$	38,580			$	46,894			$	33,602				87	%		$	(8,314	)			(18	%)

     Depreciation and amortization expense. Depreciation and amortization expense increased from 2006 to 2007 and from 2005 to 2006 as a result of depreciation on capital expenditures made throughout 2005, 2006 and 2007 from our expanded capital expenditure program commenced in early 2005.

     Depletion expense. Depletion expense increased from 2006 to 2007 as a result of increased units-of-production depletion and impairment charges resulting from higher costs and lower than expected performance of certain oil and gas developmental wells.

     Depletion expense decreased from 2005 to 2006 as a result of lower oil and gas production due to the payout of the El Paso Red River program in late 2005. These decreases were partially offset due to increases in depletion expense on non-El Paso properties due to impairments of approximately $9.9 million. The impairments resulted from lower than expected performance of certain asset groups.

Interest expense

		Year Ended December 31,												Increase
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
Interest expense		$	53,702			$	46,586			$	44,849			$	7,116				15	%		$	1,737				4	%

     Interest expense increased from 2006 to 2007 and from 2005 to 2006 as a result of the additional interest expense related to the May 2006 issuance of the $2.75 billion 0.94% senior exchangeable notes due 2011. This increase was partially offset by interest expense reductions resulting from the redemption of 93% or $769.8 million of our zero coupon convertible senior debentures due 2021 on February 6, 2006. These zero coupon notes accreted at a rate of 2.5% per annum. See further discussion of these transactions in Note 9 to our accompanying consolidated financial statements in Part II, Item 8.

Investment (loss) income

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
Investment (loss) income		$	(15,891	)		$	102,007			$	85,428			$	(117,898	)			(116	%)		$	16,579				19	%

     Investment (loss) income during 2007 was a net loss of $15.9 million compared to income of $102.0 million during the prior year. The current year loss reflected a net loss of $61.4 million from the portion of our long-term investments comprised of our actively managed funds inclusive of substantial gains from sales of our marketable equity securities. Investment income from our short-term investments was approximately $45.5 million during 2007 and slightly lower than 2006 primarily due to a combination of decreasing interest rates and a lower average cash balance.

     Investment income increased from 2005 to 2006 as a result of higher interest income earned on investments in cash and short-term and long-term investments due to rising interest rates and a higher average investment balance related to the proceeds from the issuance of the $2.75 billion 0.94% senior exchangeable notes due 2011 received in May 2006. The proceeds from the note issuance were reduced by approximately $1.2 billion, which represents the cost of the purchase of the call options and the buy back of our stock, net of the sale of warrants. In addition, earnings on our long-term investments increased during 2006 as compared to the prior year period. The increase was partially reduced in 2006 compared to the prior year periods by reduced gains realized from the sale of equity securities.

Gains (losses) on sales of long-lived assets, impairment charges and other income (expense), net

		Year Ended December 31,												Increase
(In thousands, except percentages)		2007				2006				2005				2007 to 2006								2006 to 2005
Gains (losses) on sales of long- lived assets, impairment charges and other income (expense), net		$	(10,895	)		$	(24,118	)		$	(45,952	)		$	13,223				55	%		$	21,834				48	%

     The amount of gains (losses) on sales of long-lived assets, impairment charges and other income (expense), net for 2007 includes losses on retirements and impairment charges on long-lived assets of approximately $40.0 million and increases to litigation reserves of $9.6 million. These losses were partially offset by the $38 million gain on the sale of three accommodation jack-up rigs in the second quarter of 2007.

     The amount of gains (losses) on sales of long-lived assets, impairment charges and other income (expense), net for 2006 primarily includes losses on sales of long-lived assets of approximately $21.6 million, of which approximately $12.4 million relates to asset impairment charges.

Income tax rate

		Year Ended December 31,
		2007				2006				2005
Effective income tax rate from continuing operations			21	%			30	%			26	%

     The decrease in our effective income tax rate from 2006 to 2007 is a direct result of (1) the reversal of certain tax reserves during 2007 in the amount of $25.5 million, (2) a decrease in tax expense of approximately $16 million resulting from a reduction in Canadian tax rates, and (3) a decrease in the proportion of income generated in the U.S. versus the international jurisdictions in which we operate. Income generated in the U.S. is generally taxed at a higher rate than international jurisdictions. During 2006, a tax expense relating to the redemption of common shares held by a foreign parent of a U.S. based Nabors’ subsidiary in the amount of $36.2 million increased taxes while a reduction in Canadian tax rates decreased tax expense in the amount of $20.5 million.

     Significant judgment is required in determining our worldwide provision for income taxes. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly under audit by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than that which is reflected in our income tax provisions and accruals. Based on the results of an audit or litigation, a material effect on our financial position, income tax provision, net income, or cash flows in the period or periods for which that determination is made could result.

     In October 2004, the U.S. Congress passed and the President signed into law the American Jobs Creation Act of 2004 (“the Act”). The Act did not impact the corporate reorganization completed by Nabors effective June 24, 2002, that made us a foreign entity. It is possible that future changes to tax laws (including tax treaties) could have an impact on our ability to realize the tax savings recorded to date as well as future tax savings as a result of our corporate reorganization, depending on any responsive action taken by Nabors.

     We expect our effective tax rate during 2008 to be in the 22-24% range. We are subject to income taxes in both the U.S. and numerous foreign jurisdictions. Significant judgment is required in determining our worldwide provision for income tax. One of the most volatile factors in this determination is the relative proportion of our income being recognized in high versus low tax jurisdictions.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

     Our cash flows depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Sustained increases or decreases in the price of natural gas or oil could have a material impact on these activities, and could also materially affect our cash flows. Certain sources and uses of cash, such as the level of discretionary capital expenditures, purchases and sales of investments, issuances and repurchases of debt and of our common shares are within our control and are adjusted as necessary based on market conditions. The following is a discussion of our cash flows for the years ended December 31, 2007 and 2006.

     Operating Activities Net cash provided by operating activities totaled $1.4 billion during 2007 compared to net cash provided by operating activities of $1.5 billion during 2006. During 2007 and 2006, net income was increased for non-cash items, such as depreciation and amortization, depletion, and deferred income tax expense and was reduced for changes in our working capital and other balance sheet accounts.

     Investing Activities Net cash used for investing activities totaled $1.5 billion during 2007 compared to net cash used for investing activities of $1.8 billion during 2006. During 2007 and 2006, cash was primarily used for capital expenditures. During 2007, cash was provided by sales of investments, net of purchases, totaling $482.1 million, proceeds from sales of assets and insurance claims totaling $162.1 million primarily from the sale of three accommodation jack-up rigs in the second quarter and $194.3 million from the sale of our Sea Mar business. During 2006, cash was provided by sales of investments, net of purchases, totaling $190.4 million.

     Financing Activities Net cash used for financing activities totaled $78.9 million during 2007 compared to net cash provided by financing activities of $418.3 million during 2006. During 2007, cash was used to repurchase our common shares totaling $102.5

million, which was partially offset by our receipt of proceeds totaling $61.6 million from the exercise of options to acquire our common shares by our employees.

     During 2006, cash was provided by approximately $2.72 billion in net proceeds from the issuance of the $2.75 billion 0.94% senior exchangeable notes due 2011 by Nabors Delaware, our receipt of proceeds totaling $25.7 million from the exercise of options to acquire our common shares by our employees, and by approximately $421.2 million from the sale of the warrants. During 2006, cash was used for the purchase of call options in the amount of $583.6 million, the redemption of 93% of our zero coupon senior convertible debentures due 2021 for a total redemption price of $769.8 million and for repurchases of our common shares in the open market for $1.4 billion.

Future Cash Requirements

     As of December 31, 2007, we had long-term debt, including current maturities, of $4.0 billion and cash and cash equivalents and investments of $1.1 billion, including $236.3 million of long-term investments and $53.1 million in cash proceeds receivable from the sale of certain non-marketable securities that is included in other current assets. The cash proceeds were received during January.

     Nabors Delaware’s $2.75 billion 0.94% senior exchangeable notes due 2011 provide that upon an exchange of these notes, it will be required to pay holders of the notes, in lieu of common shares, cash up to the principal amount of the notes and our common shares for any amount exceeding the principal amount of the notes required to be paid pursuant to the terms of the note indentures. The notes cannot be exchanged until the price of our shares exceeds approximately $59.57 for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter; or during the five business days immediately following any ten consecutive trading day period in which the trading price per note for each day of that period was less than 95% of the product of the sale price of Nabors’ common shares and the then applicable exchange rate; or upon the occurrence of specified corporate transactions set forth in the indenture.

     The $700 million zero coupon senior exchangeable notes due 2023 provide that upon an exchange of these notes, we will be required to pay holders of the notes, in lieu of common shares, cash up to the principal amount of the notes and, at our option, consideration in the form of either cash or our common shares for any amount above the principal amount of the notes required to be paid pursuant to the terms of the note indentures. The notes cannot be exchanged until the price of our shares exceeds $42.06 for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter, or with respect to all calendar quarters beginning on or after July 1, 2008, $38.56 on such last trading day, or subject to certain exceptions, during the five business day period after any ten consecutive trading day period in which the trading price per note for each day of that period was less than 95% of the product of the sale price of Nabors’ common shares and the then applicable exchange rate; or if Nabors Delaware calls the notes for redemption; or upon the occurrence of specified corporate transactions described in the note indenture. The notes can be put to us on June 15, 2008, June 15, 2013 and June 15, 2018 for a purchase price equal to 100% of the principal amount of the notes plus contingent interest and additional amounts, if any. Accordingly, as our $700 million zero coupon senior exchangeable notes can be put to us on June 15, 2008, the outstanding principal amount of these notes of $700 million were reclassified from long-term debt to current liabilities in our balance sheet as of June 30, 2007. If these notes are not put to us on June 15, 2008, the notes will be reclassified back to long-term debt in our balance sheet at that time. See a detailed discussion of the terms of these notes included in Note 9 to our accompanying consolidated financial statements in Part II, Item 8.

     As of December 31, 2007, we had outstanding purchase commitments of approximately $318.0 million, primarily for rig-related enhancing, construction and sustaining capital expenditures. Total capital expenditures over the next twelve months, including these outstanding purchase commitments, are currently expected to be approximately $.9-1.1 billion, including currently planned rig-related enhancing, construction and sustaining capital expenditures. This amount could change significantly based on market conditions and new business opportunities. The level of our outstanding purchase commitments and our expected level of capital expenditures over the next twelve months represent a number of capital programs that are currently underway or planned. These programs have resulted in an expansion in the number of drilling and well-servicing rigs that we own and operate and consist primarily of land drilling and well-servicing rigs.

     On September 22, 2006, we entered into an agreement with First Reserve Corporation to form a new joint venture, NFR Energy LLC, to invest in oil and gas exploration opportunities worldwide. First Reserve Corporation is a private equity firm specializing in the energy industry. Each party initially made a non-binding commitment to fund its proportionate share of $1.0 billion in equity. During 2007, joint venture operations in the U.S., Canada, and International areas, were divided among three separate joint venture entities, including NFR Energy LLC (“NFR”), Stone Mountain Ventures Partnership (“Stone Mountain”), and Remora Energy International LP (“Remora”), respectively. We hold a 49%

ownership interest in these joint ventures. Each joint venture pursues development and exploration projects with both existing customers of ours and with other operators in a variety of forms including operated and non-operated working interests, joint ventures, farm-outs and acquisitions. As of December 31, 2007, we had made capital contributions of approximately $243.1 million, $19.1 million and $14.7 million, respectively, to NFR, Stone Mountain and Remora.

     We have historically completed a number of acquisitions and will continue to evaluate opportunities to acquire assets or businesses to enhance our operations. Several of our previous acquisitions were funded through issuances of our common shares. Future acquisitions may be paid for using existing cash or issuance of debt or Nabors’ shares. Such capital expenditures and acquisitions will depend on our view of market conditions and other factors.

     See our discussion of guarantees issued by Nabors that could have a potential impact on our financial position, results of operations or cash flows in future periods included under Off-Balance Sheet Arrangements (Including Guarantees) below.

     The following table summarizes our contractual cash obligations as of December 31, 2007:

		Payments due by Period
(In thousands)		Total				< 1 Year				1-3 Years				3-5 Years				Thereafter				Other
Contractual cash obligations:
Long-term debt:
Principal		$	4,014,557			$	700,000	(1)		$	225,000	(2)		$	3,089,557	(3)		$	—			$	—
Interest			186,320				51,600				92,232				42,488				—				—
Operating leases (4)			34,940				12,794				15,061				5,117				1,968				—
Purchase commitments (5)			317,980				317,942				38				—				—				—
Employment contracts (4)			6,685				2,616				4,069				—				—				—
Pension funding obligations (6)			1,050				1,050				—				—				—				—
Tax reserves (7)			83,989				—				—				—				—				83,989
Total contractual cash obligations		$	4,645,521			$	1,086,002			$	336,400			$	3,137,162			$	1,968			$	83,989

     In July 2006, our Board of Directors authorized a share repurchase program under which we may repurchase up to $500 million of our common shares in the open market or in privately negotiated transactions. This program supersedes and cancels our previous share repurchase program. Through December 31, 2007, approximately $196.2 million of our common shares had been repurchased under this program. As of December 31, 2007, we had $303.8 million of shares that still may be purchased under the July 2006 share repurchase program.

     See Note 14 to our accompanying consolidated financial statements for discussion of commitments and contingencies relating to (i) employment contracts that could result in significant cash payments by the Company if there are terminations of certain executives in the event of death, disability, termination without cause or in the event of a change in control and (ii) off-balance sheet arrangements (including guarantees).

Financial Condition and Sources of Liquidity

     Our primary sources of liquidity are cash and cash equivalents, short-term and long-term investments and cash generated from operations. As of December 31, 2007, we had cash and cash equivalents investments of $1.1 billion (including $236.3 million of long-term investments and $53.1 million in cash proceeds receivable from the sale of certain non-marketable securities that is included in other current assets) and working capital of $711.0 million. This compares to cash and cash equivalents and investments of $1.7 billion (including $513.3 million of long-term investments) and working capital of $1.7 billion as of December 31, 2006.

     Our gross funded debt to capital ratio was 0.44:1 as of December 31, 2007 and 0.50:1 as of December 31, 2006. Our net funded debt to capital ratio was 0.37:1 as of December 31, 2007 and 2006, respectively. The gross funded debt to capital ratio is calculated by dividing funded debt by funded debt plus deferred tax liabilities net of deferred tax assets plus capital. Funded debt is defined as the sum of (1) short-term borrowings, (2) current portion of long-term debt and (3) long-term debt. Capital is defined as shareholders’ equity. The net funded debt to capital ratio is calculated by dividing net funded debt by net funded debt plus deferred tax liabilities net of deferred tax assets plus capital. Net funded debt is defined as the sum of (1) short-term borrowings, (2) current portion of long-term debt and (3) long-term debt reduced by the sum of cash and cash equivalents and short-term and long-term investments. Capital is defined as shareholders’ equity. Both of these ratios are a method for calculating the amount of leverage a company has in relation to its capital.

     Long-term investments consist of investments in overseas funds investing primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed securities and mortgage-backed securities, global structured asset securitizations, whole loan mortgages, and participations in whole loans and whole loan mortgages). These investments are classified as non-marketable, because they do not have published fair values. Our interest coverage ratio from continuing operations was 32.5:1 as of December 31, 2007, compared to 38.1:1 as of December 31, 2006. The interest coverage ratio is a trailing twelve-month computation of the sum of income from continuing operations before income taxes, interest expense, depreciation and amortization, and depletion expense less investment income and then dividing by interest expense. This ratio is a method for calculating the amount of operating cash flows available to cover interest expense.

     We have four letter of credit facilities with various banks as of December 31, 2007. Availability and borrowings under our credit facilities as of December 31, 2007 are as follows:

(In thousands)
Credit available		$	211,165
Letters of credit outstanding			(157,877	)
Remaining availability		$	53,288

     We have a shelf registration statement on file with the SEC to allow us to offer, from time to time, up to $700 million in debt securities, guarantees of debt securities, preferred shares, depository shares, common shares, share purchase contracts, share purchase units and warrants. We currently have not issued any securities registered under this registration statement.

     Our current cash and cash equivalents, investments and projected cash flows generated from current operations are expected to more than adequately finance our purchase commitments, our debt service requirements, and all other expected cash requirements for the next twelve months. However, as discussed under Future Cash Requirements above, the $2.75 billion 0.94% senior exchangeable notes and $700 million zero coupon senior exchangeable notes can be exchanged when the price of our shares exceeds $59.57 and $42.06, respectively, for the required periods of time, resulting in our payment of the principal amount of the notes, or $2.75 billion and $700 million, respectively, in cash. Our $700 million zero coupon senior exchangeable notes can be put to us on June 15, 2008 resulting in our payment of cash or we may redeem some or all of the notes at any time on or after June 15, 2008, at a redemption price equal to 100% of the principal amount of the notes plus

contingent interest, if any, and accordingly, the outstanding principal amount of these notes of $700 million was reclassified from long-term debt to current liabilities in our balance sheet as of June 30, 2007.

     On February 20, 2008, Nabors Industries, Inc. (“Nabors Delaware”), our wholly-owned subsidiary, completed a private placement of $575 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. The issue of senior notes was resold by a placement agent to qualified institutional buyers under Rule 144A of the Securities Act of 1933, as amended (“Securities Act”). The notes bear interest at a rate of 6.15% per year, payable semiannually on February 15 and August 15 of each year, beginning August 15, 2008. We intend to use the remaining proceeds of the offering for general corporate purposes, including the repayment of debt.

     On February 22, 2008, the market price for our shares closed at $30.90. If the market price threshold of $59.57 for our $2.75 billion 0.94% senior exchangeable notes or $42.06 for our $700 million zero coupon senior exchangeable notes was exceeded and the notes were exchanged or if the holders of the $700 million zero coupon senior exchangeable notes require us to repurchase the notes at a purchase price equal to 100% of the principal amount of the notes on June 15, 2008, the required cash payment could have a significant impact on our level of cash and cash equivalents and investments available to meet our other cash obligations. Management believes that the holders of these notes would not be likely to exchange the notes as it would be more economically beneficial to them if they sold the notes on the open market. However, there can be no assurance that the holders would not exchange the notes. If either of the notes were exchanged or the $700 million zero coupon senior exchangeable notes are put to us on June 15, 2008, management believes, in addition to our current cash and cash equivalents and investments, that we have the ability to access capital markets or otherwise obtain financing in order to satisfy any payment obligations that might arise upon exchange of these notes and that any cash payment due of this magnitude, in addition to our other cash obligations, will not ultimately have a material adverse impact on our liquidity or financial position. Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by Dominion Bond Rating Service (“DBRS”), Fitch Ratings, Moody’s Investor Service and Standard & Poor’s, which are currently “A-1”, “A-”, “A3” and “BBB+”, respectively, and our historical ability to access those markets as needed.

     See our discussion of the impact of changes in market conditions on our derivative financial instruments discussed under Item 7A. Quantitative and Qualitative Disclosures About Market Risk below.

OFF-BALANCE SHEET ARRANGEMENTS (INCLUDING GUARANTEES)

     We are a party to certain transactions, agreements or other contractual arrangements defined as “off-balance sheet arrangements” that could have a material future effect on our financial position, results of operations, liquidity and capital resources. The most significant of these off-balance sheet arrangements involve agreements and obligations in which we provide financial or performance assurance to third parties. Certain of these agreements serve as guarantees, including standby letters of credit issued on behalf of insurance carriers in conjunction with our workers’ compensation insurance program and other financial surety instruments such as bonds. In addition, we have provided indemnifications to certain third parties which serve as guarantees. These guarantees include indemnification provided by Nabors to our share transfer agent and our insurance carriers. We are not able to estimate the potential future maximum payments that might be due under our indemnification guarantees.

     Management believes the likelihood that we would be required to perform or otherwise incur any material losses associated with any of these guarantees is remote. The following table summarizes the total maximum amount of financial and performance guarantees issued by Nabors:

		Maximum Amount
(In thousands)		2008				2009				2010				Thereafter				Total
Financial standby letters of credit and other financial surety instruments		$	131,732			$	100			$	1,953			$	—			$	133,785
Contingent consideration in acquisitions			—				1,417				1,417				1,416				4,250
Total		$	131,732			$	1,517			$	3,370			$	1,416			$	138,035

OTHER MATTERS

Recent Legislation and Actions

     Our Sea Mar division time chartered supply vessels to offshore operations in U.S. waters. The vessels were owned by one of our financing company subsidiaries, but were operated and managed by a U.S. citizen-controlled company pursuant to long-term bareboat charters. As a result of legislation, beginning in August 2007, Sea Mar no longer qualified to charter vessels for employment in the U.S. coastwise trade. In August 2007, we sold our Sea Mar business to an unrelated third party for a cash purchase price of $194.3 million, resulting in a pre-tax gain of $49.5 million. The operating results of this business for all periods presented are accounted for as a discontinued operation in the accompanying audited consolidated statements of income.

     As a result of our internal stock option review concluded in the first quarter of 2007, we determined that the exercise price for certain of our employee stock options was less than the fair market value of our common shares on the date the options were granted. On November 29, 2007, we made an offer to eligible employees to amend certain outstanding options granted under the Nabors Industries, Inc. 1996 Employee Stock Plan and the Nabors Industries, Inc. 1998 Employee Stock Plan to increase the exercise price per option to the fair market value of a common share of Nabors on each option’s measurement date for financial accounting purposes and to make to eligible employees a cash payment equal to the difference between the new exercise price per share of the amended option and the original exercise price per share, multiplied by the number of unexercised eligible options. As a result of the tender offer, we cancelled options with a fair value of $24.3 million, replaced with a new award of options with a fair value of $22.2 million and paid $3.3 million in cash. This resulted in $1.2 million of additional compensation expense. See Note 14 regarding our internal stock option review in the accompanying consolidated financial statements.

Recent Accounting Pronouncements

     In December 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 141(R), “Business Combinations.” This statement retains the fundamental requirements in SFAS No. 141, “Business Combinations” that the acquisition method of accounting be used for all business combinations and expands the same method of accounting to all transactions and other events in which one entity obtains control over one or more other businesses or assets at the acquisition date and in subsequent periods. This statement replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any noncontrolling interest. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) beginning January 1, 2009 and apply to future acquisitions.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51.” This statement establishes the accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests and applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 beginning January 1, 2009. We are currently evaluating the impact that this pronouncement may have on our consolidated financial statements.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. There is a one year deferral for the implementation of SFAS No. 157 for other nonfinancial assets and liabilities. We will adopt SFAS No. 157 beginning January 1, 2008. We are currently evaluating the impact on our consolidated results of operations and financial condition.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115.” This statement permits entities to choose to measure many financial

instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. We will adopt SFAS No. 159 beginning January 1, 2008. We are currently evaluating the impact on our consolidated results of operations and financial condition.

     Pursuant to their employment agreements, Nabors and its Chairman and Chief Executive Officer, Deputy Chairman, President and Chief Operating Officer, and certain other key employees entered into split-dollar life insurance agreements pursuant to which we paid a portion of the premiums under life insurance policies with respect to these individuals and, in certain instances, members of their families. Under these agreements, we are reimbursed for such premiums upon the occurrence of specified events, including the death of an insured individual. Any recovery of premiums paid by Nabors could potentially be limited to the cash surrender value of these policies under certain circumstances. As such, the values of these policies are recorded at their respective cash surrender values in our consolidated balance sheets. We have made premium payments to date totaling $11.2 million related to these policies. The cash surrender value of these policies of approximately $10.5 million and $10.3 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2007 and 2006, respectively.

     Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors under the agreements with our Chairman and Chief Executive Officer and with our Deputy Chairman, President and Chief Operating Officer may be deemed to be prohibited loans by us to these individuals. We have paid no premiums related to our agreements with these individuals since the adoption of the Sarbanes-Oxley Act and have postponed premium payments related to our agreements with these individuals.

     In the ordinary course of business, we enter into various rig leases, rig transportation and related oilfield services agreements with our unconsolidated affiliates at market prices. Revenues from business transactions with these affiliated entities totaled $153.4 million, $99.2 million and $82.3 million for the years ended December 31, 2007, 2006 and 2005, respectively. Expenses from business transactions with these affiliated entities totaled $6.6 million, $4.7 million and $4.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. Additionally, we had accounts receivable from these affiliated entities of $62.3 million and $41.2 million as of December 31, 2007 and 2006, respectively. We had accounts payable to these affiliated entities of $14.7 million and $.3 million as of December 31, 2007 and 2006, respectively, and long-term payables with these affiliated entities of $7.8 million and $6.6 million as of December 31, 2007 and 2006, respectively, which is included in other long-term liabilities.

     During the fourth quarter of 2006, the Company entered into a transaction with Shona Energy Company, LLC (“Shona”), a company in which Mr. Payne, an outside director of the Company, is the Chairman and Chief Executive Officer. Pursuant to the transaction, a subsidiary of the Company acquired and holds a minority interest of less than 20% of the issued and outstanding common shares of Shona in exchange for certain rights derived from an oil and gas concession held by that subsidiary.

Critical Accounting Estimates

     The preparation of our financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. We analyze our estimates based on our historical experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The following is a discussion of our critical accounting estimates. Management considers an accounting estimate to be critical if:

	•		it requires assumptions to be made that were uncertain at the time the estimate was made; and
	•		changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated financial position or results of operations.

     For a summary of all of our significant accounting policies, see Note 2 to the accompanying consolidated financial statements.

     Depreciation of Property, Plant and Equipment The drilling, workover and well-servicing industries are very capital intensive. Property, plant and equipment represented 66% of our total assets as of December 31, 2007, and depreciation constituted 12% of our total costs and other deductions for the year ended December 31, 2007.

     Depreciation for our primary operating assets, drilling and workover rigs, is calculated based on the units-of-production method over an approximate 4,900-day period, with the exception of our jack-up rigs which are depreciated over an 8,030-day period, after provision for salvage value. When our drilling and workover rigs are not operating, a depreciation charge is provided using the straight-line method over an assumed depreciable life of 20 years, with the exception of our jack-up rigs, where a 30-year day depreciable life is used.

     Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, aircraft equipment, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings — 10 to 30 years; well-servicing rigs — 3 to 15 years; marine transportation and supply vessels — 10 to 25 years; aircraft equipment — 5 to 20 years; oilfield hauling and mobile equipment and other machinery and equipment — 3 to 10 years).

     These depreciation periods and the salvage values of our property, plant and equipment were determined through an analysis of the useful lives of our assets and based on our experience with the salvage values of these assets. Periodically, we review our depreciation periods and salvage values for reasonableness given current conditions. Depreciation of property, plant and equipment is therefore based upon estimates of the useful lives and salvage value of those assets. Estimation of these items requires significant management judgment. Accordingly, management believes that accounting estimates related to depreciation expense recorded on property, plant and equipment are critical.

     There have been no factors related to the performance of our portfolio of assets, changes in technology or other factors that indicate that these lives do not continue to be appropriate. Accordingly, for the years ended December 31, 2007, 2006 and 2005, no significant changes have been made to the depreciation rates applied to property, plant and equipment, the underlying assumptions related to estimates of depreciation, or the methodology applied. However, certain events could occur that would materially affect our estimates and assumptions related to depreciation. Unforeseen changes in operations or technology could substantially alter management’s assumptions regarding our ability to realize the return on our investment in operating assets and therefore affect the useful lives and salvage values of our assets.

     Impairment of Long-Lived Assets As discussed above, the drilling, workover and well-servicing industries are very capital intensive, which is evident in the fact that our property, plant and equipment represented 66% of our total assets as of December 31, 2007. Other long-lived assets subject to impairment consist primarily of goodwill, which represented 4% of our total assets as of December 31, 2007. We review our long-lived assets for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In addition, we review goodwill and intangible assets with indefinite lives for impairment annually, as required by SFAS No. 142, “Goodwill and Other Intangible Assets.” An impairment loss is recorded in the period in which it is determined that the carrying amount of the long-lived asset is not recoverable. Such determination requires us to make judgments regarding long-term forecasts of future revenues and costs related to the assets subject to review in order to determine the future cash flows associated with the asset or, in the case of goodwill, our reporting units. These long-term forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions, technological advances in the industry, and changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could require a provision for impairment in a future period. As the determination of whether impairment charges should be recorded on our long-lived assets is subject to significant management judgment and an impairment of these assets could result in a material charge on our consolidated statements of income, management believes that accounting estimates related to impairment of long-lived assets are critical.

     Assumptions made in the determination of future cash flows are made with the involvement of management personnel at the operational level where the most specific knowledge of market conditions and other operating factors exists. For the years ended December 31, 2007, 2006 and 2005, no significant changes have been made to the methodology utilized to determine future cash flows.

     Given the nature of the evaluation of future cash flows and the application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions.

     Income Taxes Deferred taxes represent a substantial liability for Nabors. For financial reporting purposes, management determines our current tax liability as well as those taxes incurred as a result of current operations yet deferred until future periods. In accordance with the liability method of accounting for income taxes as specified in SFAS No. 109, “Accounting for Income Taxes,” the provision for income taxes is the sum of income taxes both currently payable and deferred. Currently payable taxes represent the liability related to our income tax return for the current year while the net deferred tax expense or benefit represents the change in the

balance of deferred tax assets or liabilities reported on our consolidated balance sheets. The tax effects of unrealized gains and losses on investments and derivative financial instruments are recorded through accumulated other comprehensive income (loss) within shareholders’ equity. The changes in deferred tax assets or liabilities are determined based upon changes in differences between the basis of assets and liabilities for financial reporting purposes and the basis of assets and liabilities for tax purposes as measured by the enacted tax rates that management estimates will be in effect when these differences reverse. Management must make certain assumptions regarding whether tax differences are permanent or temporary and must estimate the timing of their reversal, and whether taxable operating income in future periods will be sufficient to fully recognize any gross deferred tax assets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, management has considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These judgments and estimates are made for each tax jurisdiction in which we operate as the calculation of deferred taxes is completed at that level. Further, under U.S. federal tax law, the amount and availability of loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests applicable to Nabors and our subsidiaries. The utilization of such carryforwards could be limited or effectively lost upon certain changes in ownership. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future. These loss carryforwards are also considered in our calculation of taxes for each jurisdiction in which we operate. Additionally, we record reserves for uncertain tax positions which are subject to a significant level of management judgment related to the ultimate resolution of those tax positions. Accordingly, management believes that the estimate related to the provision for income taxes is critical to our results of operations. We have received notifications from the IRS on various matters as a result of IRS audits of certain tax years. See Item 1A. Risk Factors — We may have additional tax liabilities and Note 10 under Item 8. Financial Statements and Supplementary Data for additional discussion.

     Effective January 1, 2007, we adopted the provisions of the FASB issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes.” In connection with the adoption of FIN 48, we recognized increases of $24 million and $21 million to our tax reserves for uncertain tax positions and interest and penalties, respectively. See Note 10 under Item 8. Financial Statements and Supplementary Data for additional discussion.

     We are subject to income taxes in both the United States and numerous foreign jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly under audit by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than that which is reflected in historical income tax provisions and accruals. Based on the results of an audit or litigation, a material effect on our financial position, income tax provision, net income, or cash flows in the period or periods for which that determination is made could result. However, certain events could occur that would materially affect management’s estimates and assumptions regarding the deferred portion of our income tax provision, including estimates of future tax rates applicable to the reversal of tax differences, the classification of timing differences as temporary or permanent, reserves recorded for uncertain tax positions, and any valuation allowance recorded as a reduction to our deferred tax assets. Management’s assumptions related to the preparation of our income tax provision have historically proved to be reasonable in light of the ultimate amount of tax liability due in all taxing jurisdictions.

     For the year ended December 31, 2007, our provision for income taxes from continuing operations was $239.7 million, consisting of $228.0 million of current tax expense and $11.7 million of deferred tax expense. Changes in management’s estimates and assumptions regarding the tax rate applied to deferred tax assets and liabilities, the ability to realize the value of deferred tax assets, or the timing of the reversal of tax basis differences could potentially impact the provision for income taxes. Changes in these assumptions could potentially change the effective tax rate. A 1% change in the effective tax rate from 21% to 22% would increase the current year income tax provision by approximately $11.4 million.

     Self-Insurance Reserves Our operations are subject to many hazards inherent in the drilling, workover and well-servicing industries, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, there is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention.

     Based on the risks discussed above, it is necessary for us to estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Reserves related to self-insurance are based on the facts and circumstances specific to the claims and our past experience with similar claims. The actual outcome of self-insured claims could differ significantly from estimated amounts. We maintain actuarially-determined accruals in our consolidated balance sheets to cover self-insurance retentions for workers’ compensation, employers’ liability, general liability and automobile liability claims. These accruals are based on certain assumptions developed utilizing historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and reported claims. These loss estimates and accruals recorded in our financial statements for claims have historically been reasonable in light of the actual amount of claims paid.

     As the determination of our liability for self-insured claims is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, and such liabilities could be material in nature, management believes that accounting estimates related to self-insurance reserves are critical.

     For the years ended December 31, 2007, 2006 and 2005, no significant changes have been made to the methodology utilized to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2007 reserves for insurance were adjusted (increased or decreased) by 10%, total costs and other deductions would have changed by $15.7 million, or 0.4%.

     Fair Value of Assets Acquired and Liabilities Assumed We have completed a number of acquisitions in recent years as discussed in Note 4 to our accompanying consolidated financial statements. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed in the various business combinations, which involved the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations or technology could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our consolidated statements of income. As the determination of the fair value of assets acquired and liabilities assumed is subject to significant management judgment and a change in purchase price allocations could result in a material difference in amounts recorded in our consolidated financial statements, management believes that accounting estimates related to the valuation of assets acquired and liabilities assumed are critical.

     The determination of the fair value of assets and liabilities are based on the market for the assets and the settlement value of the liabilities. These estimates are made by management based on our experience with similar assets and liabilities. For the years ended December 31, 2007, 2006 and 2005, no significant changes have been made to the methodology utilized to value assets acquired or liabilities assumed. Our estimates of the fair values of assets acquired and liabilities assumed have proved to be reliable.

     Given the nature of the evaluation of the fair value of assets acquired and liabilities assumed and the application to specific assets and liabilities, it is not possible to reasonably quantify the impact of changes in these assumptions.

     Share-Based Compensation We have historically compensated our executives and employees through the awarding of stock options and restricted stock. Based on the requirements of SFAS 123(R), which we adopted on January 1, 2006, we account for stock option awards in 2006 and 2007 using a fair-value based method, resulting in compensation expense for stock option awards being recorded in our consolidated statements of income. Additionally, under the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation — an Amendment to FAS 123,” we are currently required to disclose the effect on our net income and earnings per share as if we had applied the fair value recognition provisions of SFAS 123 to the periods presented in our consolidated statements of income. This tabular disclosure is included in Note 3 to our accompanying consolidated financial statements for the year ended December 31, 2005. Determining the fair value of stock-based awards at the grant date requires judgment, including estimating the expected term of stock options, the expected volatility of our stock and expected dividends. In addition, judgment is also required in estimating the amount of stock-based awards that are expected to be forfeited. As the determination of these various assumptions is subject to significant management judgment and different assumptions could result in material differences in amounts recorded in our consolidated financial statements beginning in the first quarter of 2006 and in our disclosure presented in the footnotes to our accompanying consolidated financial statements for the year ended December 31, 2005, management believes that accounting estimates related to the valuation of stock options are critical.

     The assumptions used to estimate the fair market value of our stock options are based on historical and expected performance of our common shares in the open market, expectations with regard to the pattern with which our employees will exercise their options

and the likelihood that dividends will be paid to holders of our common shares. For the years ended December 31, 2007, 2006 and 2005, no significant changes have been made to the methodology utilized to determine the assumptions used in these calculations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. This risk arises primarily as a result of potential changes in the fair market value of financial instruments that would result from adverse fluctuations in foreign currency exchange rates, credit risk, interest rates, and marketable and non-marketable security prices as discussed below.

     Foreign Currency Risk We operate in a number of international areas and are involved in transactions denominated in currencies other than U.S. dollars, which exposes us to foreign exchange rate risk. The most significant exposures arise in connection with our operations in Canada, which usually are substantially unhedged.

     At various times, we utilize local currency borrowings (foreign currency-denominated debt), the payment structure of customer contracts and foreign exchange contracts to selectively hedge our exposure to exchange rate fluctuations in connection with monetary assets, liabilities, cash flows and commitments denominated in certain foreign currencies. A foreign exchange contract is a foreign currency transaction, defined as an agreement to exchange different currencies at a given future date and at a specified rate. A hypothetical 10% decrease in the value of all our foreign currencies relative to the U.S. dollar as of December 31, 2007 would result in a $24.0 million decrease in the fair value of our net monetary assets denominated in currencies other than U.S. dollars.

     Credit Risk Our financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash equivalents, investments and marketable and non-marketable securities, accounts receivable and our range cap and floor derivative instrument. Cash equivalents such as deposits and temporary cash investments are held by major banks or investment firms. Our investments in marketable and non-marketable securities are managed within established guidelines which limit the amounts that may be invested with any one issuer and which provide guidance as to issuer credit quality. Certain of our non-marketable securities are invested in a fund that invests in securities which have been significantly impacted by the current credit market and comprise approximately $26.2 million of our $236.3 million long-term investments in our cash and investment portfolio as of December 31, 2007. We believe that the credit risk in our cash and investment portfolio is minimized as a result of the mix of our investments. In addition, our trade receivables are with a variety of U.S., international and foreign-country national oil and gas companies. Management considers this credit risk to be limited due to the financial resources of these companies. We perform ongoing credit evaluations of our customers and we generally do not require material collateral. However, we do occasionally require prepayment of amounts from customers whose creditworthiness is in question prior to provision of services to those customers. We maintain reserves for potential credit losses, and such losses have been within management’s expectations.

     Interest Rate, and Marketable and Non-marketable Security Price Risk Our financial instruments that are potentially sensitive to changes in interest rates include the $2.75 billion 0.94% senior exchangeable notes due 2011, our $82.8 million zero coupon convertible senior debentures, our $700 million zero coupon senior exchangeable notes, our 4.875% and 5.375% senior notes, our range cap and floor derivative instrument, our investments in debt securities (including corporate, asset-backed, U.S. Government, Government agencies, foreign government, mortgage-backed debt and mortgage-CMO debt securities) and our investments in overseas funds investing primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed securities and mortgage-backed securities, global structured asset securitizations, whole loan mortgages, and participations in whole loans and whole loan mortgages), which are classified as non-marketable securities.

     We may utilize derivative financial instruments that are intended to manage our exposure to interest rate risks. We account for derivative financial instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” (collectively, “SFAS 133, as amended”). The use of derivative financial instruments could expose us to further credit risk and market risk. Credit risk in this context is the failure of a counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty would owe us, which can create credit risk for us. When the fair value of a derivative contract is negative, we would owe the counterparty, and therefore, we would not be exposed to credit risk. We attempt to minimize credit risk in derivative instruments by entering into transactions with major financial institutions that have a significant asset base. Market risk related to derivatives is the adverse effect to the value of a financial instrument that results from changes in interest rates. We try to manage market risk associated with interest-rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that we undertake.

     Our $700 million zero coupon senior exchangeable notes include a contingent interest provision, discussed under Liquidity and Capital Resources above, which qualifies as an embedded derivative under SFAS 133, as amended. This embedded derivative is required to be separated from the notes and valued at its fair value at the inception of the note indenture. Any subsequent change in fair value of this embedded derivative would be recorded in our consolidated statements of income. The fair value of the contingent interest provision at inception of the note indenture was nominal. In addition, there was no significant change in the fair value of this embedded derivative through December 31, 2007, resulting in no impact on our consolidated statements of income for the year ended December 31, 2007 or 2006.

     On October 21, 2002, we entered into an interest rate swap transaction with a third-party financial institution to hedge our exposure to changes in the fair value of $200 million of our fixed rate 5.375% senior notes due 2012, which has been designated as a fair value hedge under SFAS 133, as amended. Additionally, on October 21, 2002, we purchased a LIBOR range cap and sold a LIBOR floor, in the form of a cashless collar, with the same third-party financial institution with the intention of mitigating and managing our exposure to changes in the three-month U.S. dollar LIBOR rate. This transaction does not qualify for hedge accounting treatment under SFAS 133, as amended, and any change in the cumulative fair value of this transaction is reflected as a gain or loss in our consolidated statements of income. In June 2004 we unwound $100 million of the $200 million range cap and floor derivative instrument. During the fourth quarter of 2005, we unwound the interest rate swap resulting in a loss of $2.7 million, which has been deferred and will be recognized as an increase to interest expense over the remaining life of our 5.375% senior notes due 2012. During the year ended December 31, 2005, we recorded interest savings related to our interest rate swap agreement accounted for as a fair value hedge of $2.7 million, which served to reduce interest expense.

     The fair value of our range cap and floor transaction is recorded as a derivative asset, included in other long-term assets, and was nominal as of December 31, 2007 and totaled approximately $2.3 million as of December 31, 2006. We recorded a loss of approximately $1.3 million for the year ended December 31, 2007 and gains of approximately $1.4 million and $1.1 million for the years ended December 31, 2006 and 2005, respectively, related to this derivative instrument; such amounts are included in losses (gains) on sales of long-lived assets, impairment charges and other expense (income), net in our consolidated statements of income.

     A hypothetical 10% adverse shift in quoted interest rates as of December 31, 2007 would decrease the fair value of our range cap and floor derivative instrument by approximately $.5 million.

     Fair Value of Financial Instruments The fair value of our fixed rate long-term debt is estimated based on quoted market prices or prices quoted from third-party financial institutions. The carrying and fair values of our long-term debt, including the current portion, are as follows:

		December 31,
		2007												2006
		Effective												Effective
(In thousands, except interest rates)		Interest Rate				Carrying Value				Fair Value				Interest Rate				Carrying Value				Fair Value
$2.75 billion 0.94% senior exchangeable notes due May 2011			1.15	%		$	2,750,000			$	2,595,313				1.09	%		$	2,750,000			$	2,628,725
$700 million zero coupon senior exchangeable notes due June 2023			0.32	%			700,000				696,990				0.32	%			700,000				730,380
5.375% senior notes due August 2012			5.69	%(1)			272,097	(2)			279,043				5.69	% (1)			271,470	(2)			270,545
4.875% senior notes due August 2009			5.10	%			224,562				225,709				5.10	%			224,296				221,749
$82.8 million zero coupon convertible senior debentures due February 2021			2.48	%(3)			59,774				56,897				2.94	% (3)			58,308				50,354
						$	4,006,433			$	3,853,952							$	4,004,074			$	3,901,753

     The fair values of our cash equivalents, trade receivables and trade payables approximate their carrying values due to the short-term nature of these instruments. Our cash and cash equivalents, and investments are included in the table below:

		December 31,
		2007												2006
										Weighted-Average												Weighted-Average
(In thousands, except interest rates)		Fair Value				Interest Rates				Life (Years)				Fair Value				Interest Rates				Life (Years)
Cash and cash equivalents		$	531,306				3.15%-6.07	%			0.01			$	700,549				4.12%-5.37	%			0.1
Available-for-sale marketable equity securities			—				—				—				117,220				N/A				N/A
Marketable debt securities:
Commercial paper and CDs			—				—				—				16,778				5.04%-5.69	%			0.3
Corporate debt securities			95,456				4.38%-7.60	%			0.5				131,079				4.86%-5.76	%			1.0
U.S. Government debt securities			20,048				3.06%-3.32	%			1.2				—				—				—
Government agencies debt securities			39,634				4.25%-5.14	%			1.1				61,318				5.05%-5.76	%			0.7
Mortgage-backed debt securities			6,788				2.79%-5.39	%			1.5				1,373				5.20%-5.69	%			1.4
Mortgage-CMO debt securities			23,784				2.49%-5.68	%			0.9				49,629				4.99%-5.98	%			1.0
Asset-backed debt securities			50,035				3.96%-10.53	%			1.1				62,070				4.60%-5.83	%			1.0
Total marketable debt securities			235,745												322,247
Long-term investments			236,253				N/A				N/A				513,269				N/A				N/A
Total cash and cash equivalents and investments		$	1,003,304											$	1,653,285