Nabors Industries - 10-K annual report

Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act of 1933).

YES þ NO o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

YESo 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 Exchange Act 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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 120,821,647 common shares 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, 2005, of $60.62 per share as reported on the American Stock Exchange, was $7,324,208,241. 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 24, 2006 was 156,556,748. In addition, our subsidiary, Nabors Exchangeco (Canada) Inc., had 107,603 exchangeable shares outstanding as of February 24, 2006 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.

     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. A glossary of drilling terms used in this document 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.

     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:

     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,” or “Nabors” means Nabors Industries Ltd. and, where the context requires, includes our subsidiaries.

     Nabors is the largest land drilling contractor in the world, with almost 600 land drilling rigs. We conduct oil, gas and geothermal land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South and Central America, the Middle East, the Far East and Africa. We are also one of the largest land well-servicing and workover contractors in the United States and Canada. We own approximately 565 land workover and well-servicing rigs in the United States, primarily in the southwestern and western United States, and approximately 215 land workover and well-servicing rigs in Canada. Nabors is a leading provider of offshore platform workover and drilling rigs, and owns 43 platform, 19 jack-up units and three barge rigs in the United States and multiple international markets. These rigs provide well-servicing, workover and drilling services. We have a 50% ownership interest in a joint venture in Saudi Arabia, which owns 18 rigs. We also offer a wide range of ancillary well-site services, including engineering, transportation, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in selected domestic and international markets. We time charter a fleet of 28 marine transportation and supply vessels, which provide transportation of drilling materials, supplies and crews for offshore operations. 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 have also made selective investments in oil and gas exploration, development and production activities.

     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 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 2005 or in 2004.

     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 and throughout 2005, as a result of increasing demand for drilling services, our customers have begun to enter 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 been 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).

     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.

     Through our Ramshorn business unit, Nabors makes selective investments in oil and gas exploration, development and production operations. 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 Operations — Oil and Gas.

     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 58% 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. 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.

     We time charter a fleet of 28 offshore support vessels, including one crew boat, which operate in the Gulf of Mexico, Trinidad and the Middle East and provide marine transportation of drilling materials, supplies and crews for offshore rig operations and support for other offshore facilities. The supply vessels are used as freight-carrying vessels for bringing drill pipe, tubing, casing, drilling mud and other equipment to drilling rigs and production platforms.

     As of December 31, 2005, Nabors employed approximately 22,599 persons, of whom approximately 2,885 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.

     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 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.

     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 “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 approximately the last 18 months, 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 smaller national, regional or

local rig operations. In domestic land workover and well-servicing, we compete with 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.

     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 continued to strive to attain a financial posture that would allow us to capitalize on market weakness by adding to our business base, thereby enhancing our upside potential at reasonable costs. The principal elements of our strategy have been to:

     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 year illustrate our implementation of this strategy and its continuing success.

     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 land drilling rigs in Canada, Alaska and in various international markets. Today, Nabors’ worldwide fleet consists of almost 600 land drilling rigs, approximately 565 domestic and 215 international land workover and well-servicing rigs, 43 offshore platform rigs, 19 jack-up units, three 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.

     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.

     During 2005, we expanded our capital expenditure programs and are building new rigs in significant quantities for the first time in over 20 years. In conjunction with these programs, we received delivery of ten new drilling rigs prior to February 7, 2006, which are currently working. Additionally, we have commitments and options for the building of up to 95 additional drilling rigs, of which five are offshore drilling rigs and the remainder are land drilling rigs. As of February 7, 2006, we had signed contracts or letters of intent for 70 of these rigs; 50 for our U.S. Lower 48 Land Drilling operations, three for our Canadian drilling operations and 17 for our International operations. Our customers have otherwise committed to sign contracts or letters of intent for another 12 of these rigs; seven for our U.S. Lower 48 Land Drilling operations and five for our Canadian drilling operations. Additionally, our Canadian drilling unit expects to add a total of 21 coiled tubing/stem drilling rigs to its fleet; one of which is already working and 20 of which we expect to be delivered during 2006 and 2007. Additionally, our U.S. Land Well-servicing unit expects to add 120 newly built workover and well-servicing rigs to meet growing demand for their services.

     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 2006. 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 “Risk Factors — Noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect Nabors’ results of operations.”

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

     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.

     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.

     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 likely 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 an insurance coverage deductible. We expect that 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 effect of insurance premium increases.

     We derive a significant portion of our business from international markets, including major operations in Canada, the Middle East, the Far East and South and Central America. 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.

     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 outside experts 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. Because our offshore support vessel operations rely on offshore oil and gas exploration and production, if the government were to exercise its authority under this law to restrict the availability of offshore oil and gas leases, such an action could have a material adverse effect on our offshore support vessel operations.

     Our Sea Mar division time charters supply vessels to offshore operators in U.S. waters. The vessels are owned by one of our financing company subsidiaries, but are operated and managed by a U.S. citizen-controlled company pursuant to long-term bareboat charters. As a result of recent legislation, beginning in August 2007 Sea Mar will no longer be able to use this arrangement to qualify vessels for employment in the U.S. coastwise trade. Accordingly, we will be required to restructure the arrangement, redeploy the vessels outside the United States, or sell the vessels by no later than such time.

     As of December 31, 2005, the net assets of Sea Mar totaled approximately $151 million. During 2005 Sea Mar had income before income taxes totaling $17 million.

     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 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.

     As of February 24, 2006, we had 400,000,000 authorized common shares, of which 156,556,748 shares were outstanding. In addition, 21,587,691 common shares were reserved for issuance pursuant to option and employee benefit plans, and 10,571,231 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 107,603 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 Securities and Exchange Commission. 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.

     We will hold a Special Meeting of Shareholders on March 30, 2006 to approve the proposal to amend our Amended and Restated Bye-Laws to increase our authorized share capital by the creation of additional common shares. The additional shares will accommodate a two-for-one stock split (to be effected in the form of a stock dividend), which has been approved

by our Board of Directors, subject to shareholder approval of the increase in the number of authorized shares. If this proposal is approved, our authorized common shares will increase to 800,000,000.

     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 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 had approximately $2.0 billion in debt outstanding as of December 31, 2005, resulting in a funded debt to capital ratio of 0.35:1 and a net funded debt to capital ratio of 0.9:1. Both of these ratios are a method for calculating the amount of leverage a company has in relation to its capital. On February 6, 2006, we redeemed 93% of our zero coupon senior convertible debentures due 2021 for a total redemption price of $769.8 million. Subsequent to this redemption, we had approximately $1.2 billion in debt outstanding, resulting in a funded debt to capital ratio of 0.25:1 and a net funded debt to capital ratio, which remained unchanged at 0.9:1.

     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. Delays in the delivery of new 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 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.

     We are from time to time subject to legal proceedings which include employment, tort, intellectual property and other claims. 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.

     Not applicable.

     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, which are used to support the 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 4 and 16 (each, under the caption “Property, Plant and Equipment”) and 12 (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, 2003, 2004 and 2005, can be found in Note 16 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 are equipment and facilities through our capital expansion 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.

     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.

     One such lawsuit involves wage and hour claims relating primarily to meal periods and travel time of current and former rig-based employees in our California well-servicing business. Those claims were heard by an arbitrator during the fourth quarter of 2005. On February 6, 2006, we received an interim judgment against us in the amount of $25.6 million (plus an undetermined amount of attorneys’ fees and costs), which has been accrued for in our consolidated statements of income for the year ended December 31, 2005.

     Additionally, 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.

     Not applicable.

     Our shares are traded on the New York Stock Exchange under the symbol “NBR”. At December 31, 2005, there were approximately 2,063 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.

     The following table sets forth the reported high and low sales prices of our common shares as reported on the American Stock Exchange (through November 2, 2005) and the New York Stock Exchange (from November 3, 2005 through December 31, 2005).

     During 2002 our Board of Directors authorized the continuation of a share repurchase program under which we may repurchase our common shares in the open market. Under this program we are authorized to purchase up to $400 million of our common shares. This repurchase program does not have an expiration date. We repurchased common shares during the second and fourth quarters of 2005 as follows:

     No common shares were repurchased during the first and third quarters of 2005.

     The following table provides information relating to Nabors’ repurchase of common shares during the fourth quarter of 2005:

     No common shares were repurchased during November and December 2005.

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

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

     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).

     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 and Central America, the Middle East, the Far East 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, transportation, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services, in selected domestic and international markets. We have also made selective investments in oil and gas exploration, development and production activities.

     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 limited 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 marine transportation and supply services, 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.

     Natural gas prices are the primary driver of our U.S. Lower 48 Land Drilling, Canadian and U.S. Offshore (Gulf of Mexico) operations, while oil prices are the primary driver of 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:

     Operating revenues and Earnings from unconsolidated affiliates for the year ended December 31, 2005 totaled $3.5 billion, representing an increase of $1.1 billion, or 45%, compared to the year ended December 31, 2004. Adjusted income derived from operating activities and net income for the year ended December 31, 2005 totaled $879.8 million and $648.7 million ($4.00 per diluted share), respectively, representing increases of 167% and 114%, respectively, compared to the year ended December 31, 2004. Operating revenues and Earnings from unconsolidated affiliates for the year ended December 31, 2004 totaled $2.4 billion, representing an increase of $507.9 million, or 27%, compared to the year ended December 31, 2003. Adjusted income derived from operating activities and net income for the year ended December 31, 2004 totaled $329.7 million and $302.5 million ($1.92 per diluted share), respectively, representing increases of 55% and 57%, respectively, compared to the year ended December 31, 2003.

     The increase in our operating results from 2004 to 2005 and from 2003 to 2004 resulted from higher revenues during each sequential year realized by essentially all of our operating segments. Revenues increased as a result of higher average dayrates and activity levels during 2005 compared to 2004 and 2004 compared to 2003. This increase in average dayrates and activity reflects an increase in demand for our services in these markets during these years, which resulted from continuing higher price levels for natural gas and oil during 2004 and 2005.

     Our operating results for 2006 are expected to increase from levels realized during 2005 as a result of:

     The expansion of our rig fleet through our expanded capital program is expected to most significantly impact the results of our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, Canadian and International operations. For our existing rigs, we expect the largest increase in drilling activity and dayrates to exist in our U.S. Lower 48 Land Drilling operations as a result of strong demand for drilling services in that market driven by the sustained level of higher natural gas prices. We also expect strong demand for our drilling and well-servicing services across a number of our other markets, resulting from higher commodity prices, to improve our results of operations from existing rigs for our U.S. Land Well-servicing, Canadian, International and U.S. Offshore operations. Canadian drilling activity is subject to substantial levels of seasonality, as activity levels typically peak in the first quarter, decline substantially in the second quarter, and then generally increase over the last half of the year. We expect that the improvement in our International operations will also be driven by multiple rig contract re-pricings, which should begin to impact our results in the second half of 2006. We expect that the improvement in our U.S. Offshore operations will also be driven by a continuing improvement in the utilization of and pricing for our workover jack-up rigs. We expect results from our operations in Alaska to be substantially unchanged during 2006 when compared to 2005, as the improvement in commodity prices has yet to result in an improvement in demand for drilling services in that market.

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

     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:

     The increase in our operating results from 2004 to 2005 and from 2003 to 2004 primarily resulted from year-over-year increases in average dayrates and drilling activity, which is reflected in the increase in rig years from 2004 to 2005 and from 2003 to 2004. Average dayrates and activity levels improved during 2004 and 2005 as a result of an increase in demand for drilling services, which resulted from continuing higher price levels for natural gas during those years.

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

     The increase in our operating results from 2004 to 2005 and from 2003 to 2004 primarily resulted from year-over-year increases in average hourly rates and activity. The increases in average hourly rates and activity resulted from higher customer demand for our services in all markets in which we operate, which was driven by a sustained level of higher commodity prices.

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

     The increase in our operating results from 2004 to 2005 primarily resulted from increases in average dayrates and from increased utilization for our jack-up rigs, both of which resulted from improvement in demand for our drilling services in this market driven by increased natural gas prices from 2004 to 2005. Furthermore, two new platform rigs added during the second quarter of 2004 contributed to our results for all of 2005. Additionally, our operating results for 2005 were increased by $1.5 million of net business interruption insurance proceeds recorded during the third quarter of 2005 related to one of our Super Sundowner rigs that was significantly damaged during Hurricane Katrina in the third quarter of 2005 and by

an additional $2.2 million of net business interruption insurance proceeds recorded in the second quarter of 2005 related to one of our MODS deepwater platform rigs significantly damaged during Hurricane Ivan in September 2004. We also recorded involuntary conversion losses related to certain other rigs damaged during Hurricanes Katrina and Rita during the third quarter of 2005 (see our discussion of gains (losses) on sales of long-lived assets, impairment charges and other income (expense), net under Other Financial Information below for further discussion of these losses).

     The increase in our operating results from 2003 to 2004 primarily resulted from the addition of the two new platform rigs for deepwater development projects, which commenced operations late in the second quarter of 2004 and from an increase in average dayrates for our platform and jack-up rigs from 2003 to 2004, which resulted from an improvement in demand for our drilling services in this market driven by increased natural gas prices from 2003 to 2004.

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

     Results did not change significantly from 2004 to 2005 as average dayrates and drilling activity levels in this market were substantially unchanged year-over-year. The improvement in commodity prices, which has resulted in improved demand for our services and improved dayrates across our other drilling segments, has not resulted in these same improvements in Alaska. The mature status of most of the larger existing fields in Alaska has led to diminished activity in recent years, which has yet to recover despite the extended period of higher commodity prices. While there are numerous projects in various stages of planning that are likely to result in incremental activity, the extraordinarily long lead times and capital intensity of these projects makes it difficult to predict when and to what extent they would impact our results. Meanwhile, Alaska continues to generate positive cash flow and consume minimal capital, leaving us in a good position to capitalize on future prospects in this market.

     The decrease in our operating results from 2003 to 2004 primarily resulted from lower drilling activity, deferred revenue recognized on one of our rigs in 2003 that did not recur in 2004, and an incremental $5.7 million of Operating revenues recorded in the first quarter of 2003, representing business interruption insurance proceeds related to the damage incurred on one of our land drilling rigs. The decrease in drilling activity during 2004 primarily resulted from the completion of a significant long-term contract in late 2003 that has not yet been renewed or replaced and is reflected in the decrease in rig years from 2003 to 2004.

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

     The increase in our operating results from 2004 to 2005 and from 2003 to 2004 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 2004 to 2005 and from 2003 to 2004. The increases in drilling activity are reflected in the year-over-year increases in rig years. Well-servicing hours decreased from 2004 to 2005 primarily as a result of an unseasonably wet summer during 2005 in certain of our operating areas, which restricted our ability to move our well-servicing rigs. The increase in our operating

results from 2003 to 2004 also resulted from increased well-servicing activity during 2004 compared to 2003, which was driven by increased natural gas prices. Our results for 2005 and 2004 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:

     The increase in our operating results from 2004 to 2005 primarily resulted from an increase in operations in South and Central America (primarily in Mexico, Colombia, Venezuela and Ecuador) and in the Middle East (primarily in Saudi Arabia, the United Arab Emirates and Qatar) resulting from improved demand for our services and improved dayrates in these markets during 2005 compared to 2004, and from a full year of results in 2005 from our accommodation units added to certain of our markets in the Middle East during mid-2004.

     The increase in our results from 2003 to 2004 primarily resulted from an increase in operations in Mexico and Saudi Arabia and from the addition of operations in India and Indonesia, which began in the fourth quarter of 2003, partially offset by a decrease in operations in Trinidad, Yemen, Colombia and Algeria during 2004 compared to 2003.

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

     The decrease in our operating results from 2004 to 2005 primarily resulted from the expected decline in production under our contracts with El Paso Corporation that commenced in the fourth quarter of 2003, which was partially offset by increased production resulting from new investments in oil and gas properties and higher commodity prices during 2005. The decrease in adjusted income derived from operating activities from 2004 to 2005 was also partially offset by lower expense amounts recorded for dry holes during 2005 compared to 2004. During 2004, we recorded expense of $2.4 million as a result of a dry hole offshore in the Gulf of Mexico and during 2005, we recorded expense of $0.8 million as a result of a dry hole onshore in South Texas.

     The increase in our operating results from 2003 to 2004 primarily resulted from our new investments in oil and gas properties with El Paso in the fourth quarter of 2003. The increase in adjusted income derived from operating activities for 2004 was partially offset by the $2.4 million in expense recognized during 2004 as a result of the dry hole offshore in the Gulf of Mexico, which exceeded $1.4 million in expense recognized during 2003 as a result of a dry hole also in the Gulf of Mexico.

     These operations include our marine transportation and supply services, 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:

     The increase in our operating results from 2004 to 2005 primarily resulted from (i) increased sales of top drives driven by the strengthening of the oil and gas drilling market during 2005, (ii) increased demand for directional drilling, rig instrumentation and data collection services, primarily driven by a strong Canadian market for directional drilling services as the number of horizontal and directional wells drilled increased substantially from 2004 to 2005, and (iii) increased margins for our marine transportation and supply services driven by higher average dayrates during 2005 compared to 2004, primarily driven by an improvement in the offshore drilling market that resulted in increased demand for our services.

     The slight increase in our Operating revenues and Earnings from unconsolidated affiliates from 2003 to 2004 primarily resulted from an increase in revenues for our drilling technology and top drive manufacturing, directional drilling, and rig instrumentation and software operations during 2004 compared to 2003. This increase in revenues was primarily driven by the strengthening in the drilling market in the U.S. and Canada during 2004. This increase was partially offset by a decrease in revenues for our marine and supply services operations resulting from the consolidation of Sea Mar Management LLC beginning in 2004 (see discussion in Note 2 to our consolidated financial statements in Part II Item 8) and a decrease in average dayrates during 2004 compared to 2003, which resulted from the loss of some higher rate contracts during the first quarter of 2004 and from an increase in the impact of competition in the markets in which we operated during 2004. The decrease in adjusted income (loss) derived from operating activities from 2003 to 2004 primarily resulted from a decrease in results for our Alaskan construction and logistics operations from 2003 to 2004, which resulted from certain projects in 2003 that did not recur in 2004 and the loss of a significant contract during the second quarter of 2003, and decreased margins from our marine transportation and supply services, which was driven by lower average dayrates from 2003 to 2004.

     General and administrative expenses increased from 2004 to 2005 primarily as a result of year-over-year increases in wages and burden for a majority of our operating segments, primarily resulting 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, primarily resulting from taxes paid on stock options exercised, expenses recorded for restricted stock grants and higher bonus accruals during 2005. As a percentage of operating revenues, general and administrative expenses decreased from 2004 to 2005 as these expenses were spread over a larger revenue base.

     General and administrative expenses increased from 2003 to 2004 primarily as a result of year-over-year increases in activity in a number of our operating segments including our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing and Canadian operations, and from increased expenses at our corporate level, primarily related to increased management bonuses and higher professional fees. As a percentage of operating revenues, general and administrative expenses decreased from 2003 to 2004 as these expenses were spread over a larger revenue base.

     Depreciation and amortization expense. Depreciation and amortization expense increased from 2004 to 2005 and from 2003 to 2004 as a result of depreciation on capital expenditures made during 2003, 2004 and 2005, and year-over-year increases in average rig years for our U.S. Lower 48 Land Drilling, Canadian land drilling and International operations.

     Depletion expense. Depletion expense increased from 2004 to 2005 as a result of production increases from new investments in oil and gas properties, which were almost entirely offset by the decline in production on oil and gas properties added through our El Paso investments in the fourth quarter of 2003.

     Depletion expense increased from 2003 to 2004 as a result of depletion on the oil and gas properties added through our El Paso investments.

     Interest expense decreased from 2004 to 2005 primarily as a result of the payment upon maturity of our 6.8% senior notes totaling $305.3 million in April 2004.

     Interest expense decreased from 2003 to 2004 primarily as a result of the payment upon maturity of our 6.8% senior notes in April 2004 and the redemption of our $825 million zero coupon convertible senior debentures totaling $494.9 million in June 2003. In June 2003 we issued $700 million in zero coupon senior exchangeable notes; the proceeds of which were used to redeem our $825 million senior debentures. The $700 million notes will not accrue interest unless we become obligated to pay contingent interest, while our $825 million senior debentures had an effective interest rate of 2.5%.

     Investment income increased from 2004 to 2005 as a result of (i) increased returns realized on our marketable security portfolios during 2005 compared to 2004, resulting from the positive impact of higher interest rates on our investments in interest-bearing marketable debt securities, (ii) a gain realized upon the redemption of certain of our non-marketable securities during 2005, and (iii) higher earnings on our non-marketable securities accounted for under the equity method of accounting recorded during 2005.

     Investment income increased from 2003 to 2004 primarily as a result of an increase in gains realized on sales of marketable securities and an increase in gains realized upon redemption of non-marketable securities during 2004. This increase was partially offset by a decrease in interest income resulting from lower average cash and marketable securities balances in 2004 compared to 2003 and from lower average yields on our investments driven by an overall declining interest rate environment.

     The amounts of gains (losses) on sales of long-lived assets, impairment charges and other income (expense), net for 2005 include (1) increases to litigation reserves of approximately $27.2 million during 2005, which primarily relates to the wage and hour claims litigation in our California well servicing business discussed in Note 12 to our accompanying consolidated financial statements, and (2) losses on long-lived assets of approximately $18.8 million, which primarily consists of involuntary conversion losses recorded as a result of Hurricanes Katrina and Rita during the third quarter of 2005 totaling approximately $7.8 million and net losses recorded on sales or retirements of other long-lived assets during 2005 totaling approximately $11.1 million. The amounts for 2004 include mark-to-market gains recorded on our range cap and floor derivative instrument of approximately $2.4 million. The amounts for 2003 include the recognition of approximately $1.2 million of expense related to the settlement of amounts due to the counterparty for our range cap and floor derivative instrument (offset by mark-to-market gains on that derivative instrument of $.1 million) and a loss of approximately $.9 million resulting from the redemption of our 8.625% senior subordinated notes at prices higher than their carrying value on April 1, 2003, partially offset by gains on sales of long-lived assets of approximately $2.5 million.

     The increase in our effective income tax rate from 2004 to 2005 and from 2003 to 2004 resulted from a higher proportion of our taxable income being generated in the U.S. during 2005 compared to 2004 and during 2004 compared to 2003. Income generated in the U.S. is generally taxed at a higher rate than in international jurisdictions in which we operate. Our effective tax rate for 2004 was also positively impacted by the release of certain tax reserves, which were determined to no longer be necessary, resulting in a reduction in deferred income tax expense (non-cash) totaling approximately $16.0 million ($.10 per diluted share).

     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.

     In October 2004 the U.S. Congress passed and the President signed into law the American Jobs Creation Act of 2004. 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 2006 to be in the 27%-30% range because we expect a higher proportion of our income to be generated in the U.S. We are subject to income taxes in both the United States and numerous foreign jurisdictions.

     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, 2005 and 2004.

     Operating Activities Net cash provided by operating activities totaled $1.0 billion during 2005 compared to net cash provided by operating activities of $563.2 million during 2004. During 2005 and 2004, net income was increased for non-cash items such as depreciation and amortization, and depletion, and was reduced for changes in our working capital (primarily accounts receivable) and other balance sheet accounts.

     Investing Activities Net cash used for investing activities totaled $958.2 million during 2005 compared to net cash used for investing activities of $549.1 million during 2004. During 2005 and 2004 cash was primarily used for capital expenditures. See a discussion of our expanded capital program discussed under Future Cash Requirements below.

     Financing Activities Net cash provided by financing activities totaled $102.6 million during 2005 compared to net cash used for financing activities of $221.2 million during 2004. During 2005 cash was provided by our receipt of proceeds totaling $194.5 million from the exercise of options to acquire our common shares by our employees and was used for the repurchase of our common shares in the open market totaling $99.5 million. During 2004 cash was used for the reduction of long-term debt of $302.4 million (including the payment upon maturity of our 6.8% senior notes in April 2004 totaling $295.3 million) and was provided by our receipt of proceeds totaling $71.2 million from the exercise of options to acquire our common shares by our employees.

     As of December 31, 2005, we had long-term debt, including current maturities, of $2.0 billion and cash and cash equivalents and investments of $1.6 billion.

     On February 6, 2006, we redeemed 93% of our zero coupon senior convertible debentures due 2021 for a total redemption price of $769.8 million. Because this portion of our zero coupon convertible senior debentures were redeemed on February 6, 2006, the outstanding principal amount of the redeemed debentures of $767.9 million was included in current liabilities in our balance sheet as of December 31, 2005. We treat the repurchase price, including accrued original issue discount, on such debentures as a financing activity for purposes of reporting cash flows in our consolidated statements of cash flows.

     Additionally, our $700 million zero coupon senior exchangeable notes 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 indenture. The notes cannot be exchanged until the price for our shares exceeds approximately $84 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 in various other circumstances as described in the note indenture. If these notes are exchanged, we would be required to pay the principle amount of the notes, or $700 million, in cash. See a detailed discussion of the terms of these notes included in Note 7 to our accompanying consolidated financial statements in Part II, Item 8.

     As of December 31, 2005, we had outstanding purchase commitments of approximately $704.3 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 $1.5 – 1.6 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 will result in an expansion in the number of drilling and well-servicing rigs that we own and operate and will consist primarily of land drilling and well-servicing rigs. The increase

in capital expenditures is expected across a majority of our operating segments, most significantly within our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, Canadian, and International operations.

     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 underOff-Balance Sheet Arrangements (Including Guarantees) below.

     The following table summarizes our contractual cash obligations as of December 31, 2005:

     During 2002 our Board of Directors authorized the continuation of a share repurchase program under which we may repurchase our common shares in the open market. Under this program we are authorized to purchase up to $400 million of our common shares. Through December 31, 2005, approximately $102 million of our common shares had been repurchased under this program, which includes 1.8 million of our common shares repurchased and retired for $99.5 million during 2005. Additionally, during February and March 2006 we repurchased and retired 3.2 million of our common shares in the open market for $222.3 million.

     Our primary sources of liquidity are cash and cash equivalents, marketable and non-marketable securities and cash generated from operations. As of December 31, 2005, we had cash and cash equivalents and investments of $1.6 billion (including $222.8 million of long-term investments) and working capital of $1.3 billion. This compares to cash and cash equivalents and investments of $1.4 billion (including $71.0 million of long-term investments) and working capital of $821.1 million as of December 31, 2004.

     Our funded debt to capital ratio was 0.35:1 as of December 31, 2005 and 0.41:1 as of December 31, 2004. Our net funded debt to capital ratio was 0.9:1 as of December 31, 2005 and 0.17:1 as of December 31, 2004. On February 6, 2006, we redeemed 93% of our zero coupon senior convertible debentures due 2021 for a total redemption price of $769.8 million. If this redemption had occurred on December 31, 2005, our funded debt of capital ratio would have been 0.25:1 and our net funded debt to capital ratio would have remained unchanged at 0.9:1. The funded debt to capital ratio is calculated by

dividing funded debt by funded debt 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 nets cash and cash equivalents and marketable and non-marketable securities against funded debt. This ratio is calculated by dividing net funded debt by net funded debt plus capital. Both of these ratios are a method for calculating the amount of leverage a company has in relation to its capital. Non-marketable securities 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 was 28.0:1 as of December 31, 2005, compared to 14.1:1 as of December 31, 2004. The interest coverage ratio is computed by calculating the sum of income before income taxes, interest expense, depreciation and amortization, and depletion expense and then dividing by interest expense. This ratio is a method for calculating the amount of cash flows available to cover interest expense.

     We have three letter of credit facilities with various banks as of December 31, 2005. Availability and borrowings under our credit facilities as of December 31, 2005 are as follows:

     We have a shelf registration statement on file with the Securities and Exchange Commission 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 in marketable and non-marketable securities and projected cash flows generated from current operations are expected to more than adequately finance our purchase commitments, our debt service requirements (including the portion of our $1.2 billion zero coupon convertible senior debentures that were put to us on February 6, 2006), any repurchases of our common shares in the open market (including those common shares repurchased in February and March 2006), and all other expected cash requirements for the next twelve months. However, as discussed under Future Cash Requirements above, our $700 million zero coupon senior exchangeable notes can be exchanged when the price for our shares exceeds approximately $84 for the required period of time, resulting in our payment of the principle amount of the notes, or $700 million, in cash.

     On February 24, 2006, the market price for our shares closed at $67.64. If the market price threshold of $84 were exceeded and the notes were exchanged, 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. Nabors’ 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. Further, management believes 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 Moody’s Investor Service and Standard & Poor’s, which are currently “A3” and “A-”, 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 Riskbelow.

     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. We have also guaranteed payment of contingent consideration in conjunction with a minor acquisition completed during the first quarter of 2005, which is based on future operating results of that business. In addition, we have provided indemnifications to certain third parties which serve as guarantees. These

guarantees include indemnification provided by Nabors to our stock 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:

     Our Sea Mar division time charters supply vessels to offshore operators in U.S. waters. The vessels are owned by one of our financing company subsidiaries, but are operated and managed by a U.S. citizen-controlled company pursuant to long-term bareboat charters. As a result of recent legislation, beginning in August 2007 Sea Mar will no longer be able to use this arrangement to qualify vessels for employment in the U.S. coastwise trade. Accordingly, we will be required to restructure the arrangement, redeploy the vessels outside the United States, or sell the vessels by no later than such time.

     As of December 31, 2005, the net assets of Sea Mar totaled approximately $151 million. During 2005 Sea Mar had income before income taxes totaling $17 million.

     As discussed under Stock-Based Compensation in Note 2 to our accompanying consolidated financial statements, we currently account for stock-based compensation as prescribed by Accounting Principals Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and because we grant options at prices equal to the market price of our shares on the date of the grant, we do not record compensation expense related to these grants in our consolidated statements of income. On December 16, 2004, the Financial Accounting Standards Board (FASB) issued a revision to Statement of Financial Accounting Standards (SFAS) No. 123, “Share-Based Payment,” which will eliminate our ability to account for stock-based compensation using APB 25 and instead would require us to account for stock option awards using a fair-value based method resulting in compensation expense for stock option awards being recorded in our consolidated statements of income. The statement will be effective for stock options granted, modified, or settled in cash in annual periods beginning after June 15, 2005 (2006 for Nabors). Additionally, for stock options granted or modified after December 15, 1994 that have not vested as of the effective date of the statement, compensation cost will be measured and recorded in our consolidated statements of income based on the same estimates of fair value calculated as of the date of grant as currently disclosed within the table required by SFAS No. 148, “Accounting for Stock-Based Compensation — an Amendment to FAS 123,” presented in Note 2 to our accompanying consolidated financial statements. The statement may have a material adverse effect on our results of operations during the periods of adoption and annual and interim periods thereafter. The impact that the adoption of this statement in its current form on January 1, 2005, 2004 or 2003 would have had on our net income and basic and diluted earnings per share for the years ended December 31, 2005, 2004 and 2003 is presented in the table included in Note 2 to our accompanying consolidated financial statements.

     Pursuant to his employment agreement entered into in October 1996, we provided an unsecured, non-interest bearing loan of approximately $2.9 million to Nabors’ Deputy Chairman, President and Chief Operating Officer. This loan is due on September 30, 2006.

     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 pay 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 $13.5 million related to these policies. The cash surrender value of these policies of approximately $10.1 million and $11.8 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2005 and 2004, 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 Alaskan and Saudi Arabian unconsolidated affiliates at market prices. Revenues from business transactions with these affiliated entities totaled $82.3 million, $63.2 million and $51.3 million for the years ended December 31, 2005, 2004 and 2003, respectively. Expenses from business transactions with these affiliated entities totaled $4.0 million, $3.3 million and $3.3 million for the years ended December 31, 2005, 2004 and 2003, respectively. Additionally, we had accounts receivable from these affiliated entities of $33.1 million and $20.7 million as of December 31, 2005 and 2004, respectively. We had accounts payable to these affiliated entities of $2.2 million and $3.6 million as of December 31, 2005 and 2004, respectively, and a long-term payable with one of these affiliated entities of $5.8 million and $4.1 million as of December 31, 2005 and 2004, respectively, which is included in other long-term liabilities.

     Additionally, we own certain marine vessels that are chartered under a bareboat charter arrangement to Sea Mar Management LLC, an entity in which we own a 25% interest. Under the requirements of FASB Interpretation No. 46R this entity was consolidated by Nabors beginning in 2004. Revenues from business transactions with Sea Mar totaled $29.5 million and expenses from business transactions with Sea Mar totaled $47.9 million for the year ended December 31, 2003.

     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:

     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 54% of our total assets as of December 31, 2005, and depreciation constituted 11% of our total costs and other deductions for the year ended December 31, 2005.

     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 depreciable life is used.

     Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, 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; 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, 2005, 2004 and 2003, 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 54% of our total assets as of December 31, 2005. Other long-lived assets subject to impairment consist primarily of goodwill, which represented 5% of our total assets as of December 31, 2005. 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, 2005, 2004 and 2003, 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 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. In addition to estimating the future tax rates applicable to the reversal of tax differences, management must also make certain assumptions regarding whether tax differences are permanent or temporary, management 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 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.

     For the years ended December 31, 2005, 2004 and 2003, management made no material changes in its assumptions regarding the determination of the provision for income taxes. 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 tax liability due in all taxing jurisdictions.

     For the year ended December 31, 2005, our provision for income taxes was $225 million, consisting of $30 million of current tax expense and $195 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 26% to 27% would increase the current year income tax provision by approximately $8.7 million.

     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 an insurance coverage deductible.

     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 insurance are based on the facts and circumstances specific to the insurance claims and our past experience with similar claims. The actual outcome of 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 insurance 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 insurance reserves are critical.

     For the years ended December 31, 2005, 2004 and 2003, no significant changes have been made to the methodology utilized to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2005 reserves for insurance were adjusted (increased or decreased) by 10%, total costs and other deductions would have changed by $11.7 million, or .4%.

     Fair Value of Assets Acquired and Liabilities Assumed We have completed a number of acquisitions in recent years as discussed in Note 3 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, 2005, 2004 and 2003, no significant changes have been made to the methodology utilized to value assets acquired or liabilities assumed. As we have not recorded any significant impairment charges on property, plant and equipment or goodwill in any of the years ended December 31, 2005, 2004 and 2003, 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.

     Stock-Based Compensation We have typically compensated our executives and employees through the awarding of stock options. Based on the requirements of SFAS 123(R), which we adopted on January 1, 2006, we have begun to account for stock option awards in the first quarter of 2006 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; or the years ended December 31, 2005, 2004 and 2003. This tabular disclosure is included in Note 2 to our accompanying consolidated financial statements. 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 years ended December 31, 2005, 2004 and 2003, 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, 2005, 2004 and 2003, no significant changes have been made to the methodology utilized to determine the assumptions used in these calculations.

     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, 2005 would result in a $19.7 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. We believe that the credit risk in such instruments is minimal. 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 our $1.2 billion zero coupon convertible senior debentures (93% of which were put to us on February 6, 2006), 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. 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 by SFAS 149. 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, 2005, resulting in no impact on our consolidated statements of income for the year ended December 31, 2005.

     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 No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS 149. 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 by SFAS 149, 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 years ended December 31, 2005, 2004 and 2003, we recorded interest savings related to our interest rate swap agreement accounted for as a fair value hedge of $2.7 million, $6.5 million and $6.8 million, respectively, which served to reduce interest expense. The fair value of our interest rate swap agreement recorded as a derivative asset and included in other long-term assets totaled approximately $4.6 million as of December 31, 2004. The carrying value of our 5.375% senior notes was increased by the same amount as of December 31, 2004.

     The fair value of our range cap and floor transaction is recorded as a derivative asset, included in other long-term assets, and totaled approximately $1.5 million and $.3 million as of December 31, 2005 and 2004, respectively, and is recorded as a derivative liability, included in other long-term liabilities, and totaled approximately $3.7 million as of December 31, 2003. We recorded gains of approximately $1.1 million and $2.4 million for the years ended December 31, 2005 and 2004, and losses of approximately $1.1 million for the year ended December 31, 2003, 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, 2005 would decrease the fair value of our range cap and floor derivative instrument by approximately $.8 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:

     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 in marketable and non-marketable debt and equity securities are included in the table below.

     Our investments in marketable debt securities listed in the above table and a portion of our investment in non-marketable securities are sensitive to changes in interest rates. Additionally, our investment portfolio of marketable debt and equity securities, which are carried at fair value, expose us to price risk. A hypothetical 10% decrease in the market prices for all marketable securities as of December 31, 2005 would decrease the fair value of our available-for-sale securities by $85.9 million.

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2005. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein which expresses an unqualified opinion on management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005.

To the Shareholders and Board of Directors of Nabors Industries Ltd:

We have completed integrated audits of Nabors Industries Ltd.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of changes in shareholders’ equity present fairly, in all material respects, the financial position of Nabors Industries Ltd. and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed the balance sheet classification of certain of its investment securities.

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control- Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 16, 2006