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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2010
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission File Number 001-32657
NABORS INDUSTRIES LTD.
(Exact name of registrant as specified in its charter)
 
     
Bermuda   980363970
(State or Other Jurisdiction of
Incorporation or Organization
)
  (I.R.S. Employer
Identification No
.)
Mintflower Place
8 Par-La-Ville Road
Hamilton, HM08
Bermuda
(Address of principal executive offices)
  N/A
(Zip Code)
 
(441) 292-1510
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
 
     
Title of Each Class   Name of Each Exchange on Which Registered
 
Common shares, $.001 par value per share
  The New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934:
None.
 
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  YES þ     NO o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  YES o     NO þ
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  YES þ     NO o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.  YES þ     NO o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller Reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  YES o     NO þ
 
The aggregate market value of the 192,800,936 common shares, par value $.001 per share, held by non-affiliates of the registrant, based upon the closing price of our common shares as of the last business day of our most recently completed second fiscal quarter, June 30, 2010, of $17.62 per share as reported on the New York Stock Exchange, was $3,397,152,492. 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, 2011 was 286,145,675.
 
DOCUMENTS INCORPORATED BY REFERENCE (to the extent indicated herein)
 
Specified portions of the definitive Proxy
Statement to be distributed in connection with our 2011 annual meeting of shareholders (Part III).
 


 

 
NABORS INDUSTRIES LTD.

Form 10-K Annual Report
For the Year Ended December 31, 2010

Table of Contents
 
                 
PART I
  Item 1.     Business     4  
  Item 1A.     Risk Factors     11  
  Item 1B.     Unresolved Staff Comments     18  
  Item 2.     Properties     19  
  Item 3.     Legal Proceedings     24  
  Item 4.     (Removed and Reserved)     25  
 
PART II
  Item 5.     Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities     26  
  Item 6.     Selected Financial Data     28  
  Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations     30  
  Item 7A.     Quantitative and Qualitative Disclosures About Market Risk     59  
  Item 8.     Financial Statements and Supplementary Data     62  
  Item 9.     Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     143  
  Item 9A.     Controls and Procedures     143  
  Item 9B.     Other Information     144  
 
PART III
  Item 10.     Directors, Executive Officers and Corporate Governance     145  
  Item 11.     Executive Compensation     145  
  Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters     145  
  Item 13.     Certain Relationships and Related Transactions, and Director Independence     147  
  Item 14.     Principal Accounting Fees and Services     147  
 
PART IV
  Item 15.     Exhibits, Financial Statement Schedules     148  
 EX-12
 EX-21
 EX-23.1
 EX-23.2
 EX-23.3
 EX-23.4
 EX-23.5
 EX-23.6
 EX-23.7
 EX-31.1
 EX-31.2
 EX-32.1
 EX-99.1
 EX-99.2
 EX-99.3
 EX-99.4
 EX-99.5
 EX-99.6


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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, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). In addition, a glossary of drilling terms used in this document and documents relating to our corporate governance (such as committee charters, governance guidelines and other internal policies) can be found on our website. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
 
FORWARD-LOOKING STATEMENTS
 
We often discuss expectations regarding our future markets, demand for our products and services, and our performance in our annual and quarterly reports, press releases, and other written and oral statements. Statements relating 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, as amended (the “Securities Act”), and Section 21E of the Exchange Act. These “forward-looking statements” are based on an analysis of currently available competitive, financial and economic data and our operating plans. They are inherently uncertain and investors should recognize that events and actual results could turn out to be significantly different from our expectations. By way of illustration, when used in this document, words such as “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “will,” “should,” “could,” “may,” “predict” and similar expressions are intended to identify forward-looking statements.
 
You should consider the following key factors when evaluating these forward-looking statements:
 
  •  fluctuations in worldwide prices of and demand for natural gas and oil;
 
  •  fluctuations in levels of natural gas and oil exploration and development activities;
 
  •  fluctuations in the demand for our services;
 
  •  the existence of competitors, technological changes and developments in the oilfield services industry;
 
  •  the existence of operating risks inherent in the oilfield services industry;
 
  •  the possibility of changes in tax and other laws and regulations;
 
  •  the possibility of political instability, war or acts of terrorism in any of the countries where we operate; and
 
  •  general economic conditions including the capital and credit markets.
 
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 that has a material impact on exploration, development or 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 refer to Part I, Item 1A. — Risk Factors.
 
Unless the context requires otherwise, references in this report to “we,” “us,” “our,” “the Company,” or “Nabors” mean Nabors Industries Ltd. and, where the context requires, includes our subsidiaries. Our subsidiaries include Nabors Industries, Inc., a Delaware corporation (“Nabors Delaware”).


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PART I
 
ITEM 1.   BUSINESS
 
Introduction
 
Nabors is the largest land drilling contractor in the world and one of the largest land well-servicing and workover contractors in the United States and Canada:
 
  •  We actively market approximately 550 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa.
 
  •  We actively market approximately 555 rigs for land well-servicing and workover work in the United States and approximately 172 rigs for land well-servicing and workover work in Canada.
 
We are also a leading provider of offshore platform workover and drilling rigs, and actively market 37 platform, 13 jack-up and three barge rigs in the United States, including the Gulf of Mexico, and multiple international markets.
 
In addition to the foregoing services:
 
  •  We offer a wide range of ancillary well-site services, including hydraulic fracturing, engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select United States and international markets.
 
  •  We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software.
 
  •  We invest in oil and gas exploration, development and production activities in the United States, Canada and Colombia through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests.
 
  •  We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets nine rigs in addition to the rigs we lease to the joint venture.
 
  •  We also provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft.
 
During the third quarter of 2010, we acquired through a tender offer and merger transaction (the “Superior Merger”), all of the outstanding common stock of Superior Well Services, Inc. (“Superior”). Superior provides a wide range of wellsite solutions to oil and natural gas companies, consisting primarily of technical pumping services, including hydraulic fracturing, a process sometimes used in the completion of oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production, and down-hole surveying services. The effects of the Superior Merger and the operating results of Superior from the acquisition date to December 31, 2010 are included in the accompanying audited consolidated financial statements and are reflected in our operating segment, titled “Pressure Pumping.” See Note 7 — Acquisitions and Divestitures in Part II, Item 8. — Financial Statements and Supplementary Data for additional information.
 
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, and our phone number there is (441) 292-1510.
 
Our Fleet of Rigs
 
  •  Land Rigs.  A land-based drilling rig generally consists of engines, a drawworks, a mast (or derrick), pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string and


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  related equipment. The engines power the different pieces of equipment, including a rotary table or top drive that turns the drill string, causing the drill bit to bore through the subsurface rock layers. Rock cuttings are carried to the surface by the circulating drilling fluid. The intended well depth, bore hole diameter and drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job.
 
Special-purpose drilling rigs used to perform workover services consist of a mobile carrier, which includes an engine, drawworks and a mast, together with other standard drilling accessories and specialized equipment for servicing wells. These rigs are specially designed for major repairs and modifications of oil and gas wells, including standard drilling functions. A well-servicing rig is specially designed for periodic maintenance of oil and gas wells for which service is required to maximize the productive life of the wells. The primary function of a well-servicing rig is to act as a hoist so that pipe, sucker rods and down-hole equipment can be run into and out of a well, although they also can perform standard drilling functions. Because of size and cost considerations, these specially designed rigs are used for these operations rather than the larger drilling rigs typically used for the initial drilling job.
 
Land-based drilling rigs are moved between well sites and between geographic areas of operations using our fleet of cranes, loaders and transport vehicles or those of third-party service providers. Well-servicing rigs are typically self-propelled, while heavier capacity workover rigs are either self-propelled or trailer-mounted and include auxiliary equipment, which is either transported on trailers or moved with trucks.
 
  •  Platform Rigs.  Platform rigs provide offshore workover, drilling and re-entry services. Our platform rigs have drilling and/or well-servicing or workover equipment and machinery arranged in modular packages that are transported to, and assembled and installed on, fixed offshore platforms owned by the customer. Fixed offshore platforms are steel tower-like structures that either stand on the ocean floor or are moored floating structures. The top portion, or platform, sits above the water level and provides the foundation upon which the platform rig is placed.
 
  •  Jack-up Rigs.  Jack-up rigs are mobile, self-elevating drilling and workover platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the hull, which contains the drilling and/or workover equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. The rig legs may operate independently or have a mat attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas. Many of our jack-up rigs are of cantilever design — a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over adjacent, fixed platforms. Nabors’ shallow workover jack-up rigs generally are subject to a maximum water depth of approximately 125 feet, while some of our jack-up rigs may drill in water depths as shallow as 13 feet. Nabors also has deeper water jack-up rigs that are capable of drilling at depths between eight feet and 150 to 250 feet. The water depth limit of a particular rig is determined by the length of its legs and by the operating environment. Moving a rig from one drill site to another involves lowering the hull down into the water until it is afloat and then jacking up its legs with the hull floating. The rig is then towed to the new drilling site.
 
  •  Inland Barge Rigs.  One of Nabors’ barge rigs is a full-size drilling unit. We also own two workover inland barge rigs. These barges are designed to perform plugging and abandonment, well-service or workover services in shallow inland, coastal or offshore waters. Our barge rigs can operate at depths between three and 20 feet.
 
Additional information regarding the geographic markets in which we operate and our business segments can be found in Note 22 — Segment Information in Part II, Item 8. — Financial Statements and Supplementary Data.


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Customers: Types of Drilling Contracts
 
Our customers include major oil and gas companies, national oil and gas companies and independent oil and gas companies. No customer accounted for more than 10% of our consolidated revenues in 2010 or 2009.
 
On land in the U.S. Lower 48 states and Canada, we typically enter into contracts with durations ranging from one to three years. Under these contracts, our rigs are committed to one customer over that term. Most of our recent contracts for newly constructed rigs have three-year terms. 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 contracted 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. Contract terms and rates 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 our providing a rig and crew) and for lower rates when the rig is moving, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. In addition, daywork contracts may provide for a lump-sum fee for the mobilization and demobilization of the rig, which in most cases approximates our incurred costs. A daywork contract differs from a footage contract (in which the drilling contractor is paid on the basis of a rate per foot drilled) and a turnkey contract (in which the drilling contractor is paid for drilling a well to a specified depth for a fixed price).
 
Well-servicing and Workover Services
 
Although some wells in the United States flow oil to the surface without mechanical assistance, most are in mature production areas that require pumping or some other form of artificial lift. Pumping oil wells characteristically require more maintenance than flowing wells because of the operation of the mechanical pumping equipment.
 
  •  Well-servicing/Maintenance Services.  We provide maintenance services on the mechanical apparatus used to pump or lift oil from producing wells. These services include, among other activities, repairing and replacing pumps, sucker rods and tubing. They also occasionally include drilling services. We provide the rigs, equipment and crews for these tasks, which are performed on both oil and natural gas wells, but which are more commonly required on oil wells. Maintenance services typically take less than 48 hours to complete. Rigs generally are provided to customers on a call-out basis. We are paid an hourly rate and work typically is performed five days a week during daylight hours.
 
  •  Workover Services.  Producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workovers may be required to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks or convert a depleted well to an injection well for secondary or enhanced recovery projects. Workovers normally are carried out with a rig that includes standard drilling accessories such as rotary drilling equipment, mud pumps, mud tanks and blowout preventers plus other specialized equipment for servicing rigs. A workover may last anywhere from a few days to several weeks. We are paid a daily rate and work is generally performed seven days a week, 24 hours a day.
 
  •  Completion Services.  The kinds of activities necessary to carry out a workover operation are essentially the same as those required to “complete” a well when it is first drilled. The completion process may involve selectively perforating the well casing at the depth of discrete producing zones, stimulating and testing these zones and installing down-hole equipment. The completion process may


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  take a few days to several weeks. We are paid an hourly rate and work is generally performed seven days a week, 24 hours a day.
 
  •  Production and Other Specialized Services.  We also can provide other specialized services, including onsite temporary fluid storage; the supply, removal and disposal of specialized fluids used during certain completion and workover operations; and the removal and disposal of salt water that often accompanies the production of oil and natural gas. We also provide plugging services for wells from which the oil and natural gas has been depleted or further production has become uneconomical. We are paid an hourly or a per-unit rate, as applicable, for these services.
 
Pressure Pumping Services
 
In connection with the Superior Merger, we conduct technical and fluid logistics services. Technical services include technical pumping services, completion, production and rental tool services and down-hole surveying services. Fluid logistics services include those services related to the transportation, storage and disposal of fluids that are used in the drilling, development and production of hydrocarbons. During the period September 10, 2010 through December 31, 2010, approximately 5.5% of revenues from our Pressure Pumping operating segment came from an unconsolidated Nabors affiliate. Our proportionate share of any profits resulting from sales to this affiliate were eliminated in consolidation.
 
Oil and Gas Investments
 
In our Oil and Gas operating segment, we invest in oil and gas exploration, development and production operations in the United States, Canada and Colombia. In addition, in 2006, we entered into an agreement with First Reserve Corporation to form select joint ventures to invest in oil and gas exploration opportunities worldwide. During 2007, three joint ventures were formed for operations in the United States, Canada and Colombia. We hold a 50% ownership interest in the Canadian entity, Stone Mountain Venture Partnership (“SMVP”) and 49.7% ownership interests in the U.S. and Colombia entities, NFR Energy LLC (“NFR Energy”) and Remora Energy International LP (“Remora”), respectively. We account for these investments using the equity method of accounting. Each joint venture pursues development and exploration projects with both existing Nabors customers and other operators in a variety of forms, including operated and non-operated working interests, joint ventures, farm-outs and acquisitions. Our Oil and Gas operating segment includes both wholly owned and joint-venture operations and focuses on the exploration for and the acquisition, development and production of natural gas, oil and natural gas liquids in Alaska, Arkansas, Louisiana, Oklahoma, Mississippi, Montana, North Dakota, Texas, Utah and Wyoming. Outside of the United States, we and our joint ventures own or have interests in the Canadian provinces of Alberta and British Columbia and in Colombia.
 
During 2010, we began actively marketing some of our oil and gas assets in Canada and Colombia, including our ownership interests in SMVP and Remora. Additional information about recent activities for this segment can be found in Part II, Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Part II, Item 8. — Financial Statements and Supplementary Data — Note 21 — Discontinued Operations.
 
Other Services
 
Canrig Drilling Technology Ltd., our drilling technologies and well services subsidiary, manufactures top drives, which are installed on both onshore and offshore drilling rigs. We market our top drives throughout the world. We rent top drives and catwalks, and provide installation, repair and maintenance services to our customers. We also offer rig instrumentation equipment, including proprietary RIGWATCHtm software and computerized equipment that monitors a rig’s real-time performance. Our directional drilling system, ROCKITtm, is experiencing high growth in the marketplace. In addition, we specialize in daily reporting software for drilling operations, making this data available through the internet. We also provide mudlogging services. Canrig Drilling Technology Canada Ltd., one of our Canadian subsidiaries, manufactures catwalks


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which are installed on both onshore and offshore drilling rigs. Ryan Energy Technologies, Inc., another one of our subsidiaries, manufactures and sells directional drilling and rig instrumentation equipment and provides data collection services to oil and gas exploration and service companies. Nabors has a 50% ownership interest in Peak Oilfield Service Company, a general partnership with a subsidiary of Cook Inlet Region, Inc., a leading Alaskan native corporation. Peak Oilfield Service Company 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% membership interest in Alaska Interstate Construction, L.L.C., a general contractor involved in the construction of roads, bridges, dams, drill sites and other facility sites, as well as the provision of mining support in Alaska; the other member of Alaska Interstate Construction, L.L.C. is a subsidiary of Cook Inlet Region, Inc. Revenues are derived from services to companies engaged in mining and public works. Nabors Blue Sky Ltd. leases aircraft used for logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft.
 
Our Employees
 
As of December 31, 2010, Nabors employed approximately 23,412 persons, of whom approximately 2,892 were employed by unconsolidated affiliates. We believe our relationship with our employees is generally good.
 
Some rig employees in Argentina and Australia are represented by collective bargaining units.
 
Seasonality
 
Our Canada and Alaska 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 quarter of each year. In addition, our pressure pumping operations located in the Appalachian, Mid-Continent, and Rocky Mountain regions of the United States can be adversely affected by seasonal weather conditions, primarily in the spring, as many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. Global warming could lengthen these periods of reduced activity, but we cannot currently estimate to what degree. Our overall financial results reflect the seasonal variations experienced in these operations. Seasonality does not materially impact the remaining portions of our business.
 
Research and Development
 
Research and development constitutes a growing part of our overall business. The effective use of technology is critical to maintaining our competitive position within the drilling industry. We expect to continue developing technology internally and acquiring technology through strategic acquisitions.
 
Industry/Competitive Conditions
 
To a large degree, Nabors’ businesses depend on the level of capital spending by oil and gas companies for exploration, development and production activities. A sustained increase or decrease in the price of natural gas or oil could have a material impact on the exploration, development and production activities of our customers and could materially affect our financial position, results of operations and cash flows. See Part I, Item 1A. — Risk Factors — Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows and profitability.
 
Our industry remains competitive. The number of available rigs exceeds demand in many of our markets, resulting in strong price competition. Many rigs can be readily moved from one region to another in response to changes in levels of activity, which may result in an oversupply of rigs in such areas. Many of the total available contracts are currently awarded on a bid basis, which further increases competition based on price. 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.


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From 2005 through most of 2008, demand was strong for drilling services driven by a sustained increase in the level of commodity prices; supply of and demand for land drilling services were largely in balance in the United States and other markets, with demand actually exceeding supply in some of our markets. This resulted in an increase in rates being charged for rigs across our North American, Offshore and International markets. In late 2008, falling oil prices and the declines in natural gas prices forced a curtailment of drilling-related expenditures by many companies and resulted in an oversupply of rigs in the markets where we operate. During 2009 and the first half of 2010, this continued decline in drilling and related activity impacted our key markets.
 
In all of our geographic markets, we believe price and the 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 the ability to offer ancillary services. Increasingly, the ability to deliver rigs with new technology and features is becoming a competitive factor. In international markets, experience in operating in certain environments, as well as customer alliances, 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, we compete with Helmerich and Payne, Inc. and Patterson-UTI Energy, Inc., and several hundred other competitors with national, regional or local rig operations. In our U.S. Land Well-servicing operating segment, we compete with Basic Energy Services, Inc., Key Energy Services, Inc., Complete Energy Services and numerous other competitors having smaller regional or local rig operations. In Canada and U.S. Offshore, we compete with many firms of varying size, several of which have more significant operations in those areas than Nabors. Elsewhere, we compete directly with various contractors at each location where we operate. Our Pressure Pumping operating segment competes with small and mid-sized independent contractors, as well as major oilfield services companies with operations outside of the United States. We believe that the market for land drilling, well-servicing and workover and pressure pumping 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 Drilling Technology Ltd. subsidiary is one of the three major manufacturers of top drives. Its largest competitors in that market are National Oilwell Varco and Tesco. Its 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. In the U.S. Lower 48 states, there are hundreds of rig transportation companies in each of our operating regions. In Alaska, Peak Oilfield Service 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 large general contractors, including Granite Construction Company and Quality Asphalt Paving on public works projects and Alaska Frontier Constructors and CH2MHill on resource development projects.
 
Our Business Strategy
 
Since 1987, with the installation of our current management team, we have adhered to a consistent strategy aimed at positioning Nabors to grow and prosper in times of good market conditions and to mitigate adverse effects during periods of poor market conditions. We have maintained a financial posture that allows us to capitalize on market weakness and strength by adding to our business base, thereby enhancing our upside potential. The principal elements of our strategy have been to:
 
  •  Maintain flexibility to respond to changing conditions.
 
  •  Maintain a conservative and flexible balance sheet.
 
  •  Build a base of premium assets cost effectively.
 
  •  Establish and maintain low operating costs through economies of scale.
 
  •  Develop and maintain long-term, mutually attractive relationships with key customers and vendors.


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  •  Build a diverse business in long-term, sustainable and worthwhile geographic markets.
 
  •  Recognize and seize opportunities as they arise.
 
  •  Continually improve safety, quality and efficiency.
 
  •  Implement leading-edge technology where cost effective to do so.
 
  •  Increase shareholder value by expanding our oil and gas reserves and production.
 
We have designed our business strategy to allow us to grow and remain profitable in any market environment. The major developments in our business in recent years illustrate our implementation of this strategy and its continuing success. Beginning in 2005, we took advantage of the robust rig market in the United States and elsewhere to obtain a high volume of contracts for newly constructed rigs. A large portion of these rigs are subject to long-term contracts with creditworthy customers with the most significant impact occurring in our International operations. This will not only expand our operations with the latest state-of-the-art rigs, which should better weather downturns in market activity, but eventually replace the oldest and least capable rigs in our existing fleet. However, this positive trend in the rig market slowed in the fourth quarter of 2008 and throughout 2009 and the first half of 2010, due to the continued steady decline in natural gas and oil prices. As a result of lower commodity prices, many of our customers’ drilling programs were reduced and the demand for additional rigs was substantially reduced. In the latter half of 2010, commodity prices strengthened and our drilling activity improved. Although we expect market conditions to remain challenging during 2011, we believe the deployment of our newer and higher-margin rigs under long-term contracts will enhance our competitive position when market conditions improve.
 
Acquisitions and Divestitures
 
We have grown from a land drilling business centered in the U.S. Lower 48 states, Canada and Alaska to an international business with operations on land and offshore in many of the major oil and gas markets in the world. At the beginning of 1990, our fleet consisted of 44 actively marketed land drilling rigs in Canada, Alaska and in various international markets. Today, our worldwide fleet of actively marketed rigs consists of over 550 land drilling rigs, more than 700 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jack-up units, barge rigs and a large component of trucks and fluid hauling vehicles. This growth was fueled in part by strategic acquisitions. Although Nabors continues to examine opportunities, there can be no assurance that attractive rigs or other acquisition opportunities will continue to be available, that the pricing will be economical or that we will be successful in making such acquisitions in the future.
 
On January 3, 2006, we completed an acquisition of 1183011 Alberta Ltd., a wholly owned subsidiary of Airborne Energy Solutions Ltd., through the purchase of all common shares outstanding for cash for a total purchase price of Cdn.$41.7 million (U.S. $35.8 million). In addition, we assumed debt, net of working capital, totaling approximately Cdn.$10.0 million (U.S. $8.6 million). On that date, Nabors Blue Sky Ltd. (formerly 1183011 Alberta Ltd.) owned 42 helicopters and fixed-wing aircraft and owned and operated a fleet of heliportable well-service equipment. The purchase price was allocated based on final valuations of the fair value of assets acquired and liabilities assumed as of the acquisition date and resulted in goodwill of approximately U.S. $18.8 million. During 2008 and 2009, the results of our impairment tests of goodwill and intangible assets indicated a permanent impairment to goodwill and to an intangible asset of Nabors Blue Sky Ltd. As such, the goodwill has been fully impaired as of December 31, 2009.
 
On May 31, 2006, we completed an acquisition of Pragma Drilling Equipment Ltd.’s business, which manufactures catwalks, iron roughnecks and other related oilfield equipment, through an asset purchase consisting primarily of intellectual property for a total purchase price of Cdn.$46.1 million (U.S. $41.5 million). The purchase price has been allocated based on final valuations of the fair market value of assets acquired and liabilities assumed as of the acquisition date and resulted in goodwill of approximately U.S. $10.5 million.
 
On August 8, 2007, we sold our Sea Mar business which had previously been included in Other Operating Segments. The assets included 20 offshore supply vessels and related assets, including a right under a vessel


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construction contract. The operating results of this business for years ended December 31, 2007 and before are accounted for as discontinued operations.
 
On September 10, 2010, we completed the Superior Merger at a cash purchase price of $22.12 per share, or approximately $681.3 million in the aggregate. The purchase price was allocated to the net tangible and intangible assets acquired and liabilities assumed based on their fair value at the acquisition date. The excess of the purchase price over such fair values was $335.0 million and was recorded as goodwill. Superior provides a wide range of wellsite solutions to oil and natural gas companies, primarily technical pumping services and down-hole surveying services. The effects of the Superior Merger and the operating results from the acquisition date to December 31, 2010 are reflected in the accompanying audited consolidated financial statements. Additional information about Superior can be found in Part II, Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Part II, Item 8. — Financial Statements and Supplementary Data — Note 7 — Acquisitions and Divestitures.
 
On December 31, 2010, we purchased the business of Energy Contractors LLC (“Energy Contractors”) for a total cash purchase price of $53.4 million. The assets were comprised of vehicles and rig equipment and are included in our U.S. Land Well-servicing operating segment. The purchase price was allocated to the net tangible and intangible assets acquired based on their preliminary fair value estimates as of December 31, 2010. The excess of the purchase price over the fair value of the assets acquired was recorded as goodwill in the amount of $5 million.
 
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 2010, we began actively marketing our oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia. These assets include our 49.7% and 50.0% ownership interests in our investments of Remora and SMVP, respectively, which we account for using the equity method of accounting. All of these assets are included in our Oil and Gas operating segment. We determined that the plan of sale criteria in the ASC Topic relating to the Presentation of Financial Statements for Assets Sold or Held for Sale had been met during the third quarter of 2010. Accordingly, the accompanying consolidated statements of income (loss) and accompanying notes to the consolidated financial statements have been updated to retroactively reclassify the operating results of these assets as discontinued operations for all periods presented. See Note 21 — Discontinued Operations for additional discussion in Part II, Item 8. — Financial Statements and Supplementary Data.
 
Environmental Compliance
 
Nabors does not currently anticipate that compliance with currently applicable environmental regulations and controls will significantly change its competitive position, capital spending or earnings during 2011. 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 Part I, Item 1A. — Risk Factors — Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect Nabors’ results of operations.
 
ITEM 1A.   RISK FACTORS
 
In addition to the other information set forth elsewhere in this report, the following factors should be carefully considered when evaluating Nabors. The risks described below are not the only ones facing Nabors. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations.
 
Our business, financial condition or results of operations could be materially adversely affected by any of these risks.


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We have a substantial amount of debt outstanding
 
As of December 31, 2010, we had long-term debt outstanding of approximately $4.4 billion, including $1.4 billion in current maturities, and cash and cash equivalents and investments of $841.5 million, including $40.3 million of long-term investments and other receivables. Long-term investments and other receivables include $32.9 million in oil and gas financing receivables. Our ability to service our debt obligations depends in large part upon the level of cash flows generated by our subsidiaries’ operations, possible dispositions of non-core assets, availability under our unsecured revolving credit facility and our ability to access the capital markets. At December 31, 2010, we had $700 million available under a senior unsecured revolving credit facility; in January 2011, we added another lender to the facility raising the amount available to $750 million. On February 11, 2011, one of our subsidiaries established a credit facility, which we unconditionally guarantee, for approximately US$50 million. If our 0.94% senior exchangeable notes were exchanged before their maturity in May 2011, 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. We calculate our leverage in relation to capital (i.e., shareholders’ equity) utilizing two commonly used ratios:
 
  •  Gross funded debt to capital, which is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portions of long-term debt and (3) long-term debt; and
 
  •  Net funded debt to capital, which is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables.
 
At December 31, 2010, our gross funded debt to capital ratio was 0.42:1 and our net funded debt to capital ratio was 0.37:1.
 
Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows and profitability
 
Our operations depend on the level of spending by oil and gas companies for exploration, development and production activities. Both short-term and long-term trends in oil and natural gas prices affect these levels. Oil and natural gas prices, as well as the level of drilling, exploration and production activity, can be highly volatile. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, affect both the demand for, and the supply of, oil and natural 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 natural gas. Recent volatility and the effects of recent declines in oil and natural gas prices are likely to continue in the near future, especially given the general contraction in the world’s economy that began during 2008. We believe that any prolonged suppression of oil and natural gas prices could continue to depress the level of exploration and production activity. Lower oil and natural gas prices have also caused some of our customers to seek to terminate, renegotiate or fail to honor our drilling contracts and affected the fair market value of our rig fleet, which in turn has resulted in impairments of our assets. A prolonged period of lower oil and natural gas prices could affect our ability to retain skilled rig personnel and affect our ability to access 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 natural gas and oilfield services industries.
 
Uncertain or negative global economic conditions could continue to adversely affect our results of operations
 
The recent and substantial volatility and extended declines in oil and natural gas prices in response to a weakened global economic environment has adversely affected our results of operations. In addition, economic conditions have resulted in substantial uncertainty in the capital markets and both access to and terms of available financing. During 2009, many of our customers curtailed their drilling programs, which, in many


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cases, has resulted in a decrease in demand for drilling rigs and a reduction in dayrates and utilization. Additionally, some customers have terminated drilling contracts prior to the expiration of their terms. A prolonged period of lower oil and natural gas prices could continue to impact our industry and our business, including our future operating results and the ability to recover our assets, including goodwill, at their stated values. In addition, some of our customers could experience an inability to pay suppliers, including us, in the event they are unable to access the capital markets to fund their business operations. Likewise, our suppliers may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. Each of these could adversely affect our operations.
 
As a holding company, we depend on our subsidiaries to meet our financial obligations
 
We are a holding company with no significant assets other than the stock of our subsidiaries. In order to meet our financial needs, we rely exclusively on repayments of interest and principal on intercompany loans that we have made to our operating subsidiaries and income from dividends and other cash flow from our subsidiaries. There can be no assurance that our operating subsidiaries will generate sufficient net income to pay us dividends or sufficient cash flow to make payments of interest and principal to us. In addition, from time to time, our operating subsidiaries may enter into financing arrangements that contractually restrict or prohibit these types of upstream payments. There can also be adverse tax consequences associated with paying dividends.
 
Our access to borrowing capacity could be affected by the recent instability in the global financial markets
 
Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by Fitch Ratings, Moody’s Investor Service and Standard & Poor’s and our historical ability to access those markets as needed. A credit downgrade may impact our future ability to access credit markets, which is important for purposes of both meeting our financial obligations and funding capital requirements to finance and grow our businesses.
 
We operate in a highly competitive industry with excess drilling capacity, which may adversely affect our results of operations
 
The oilfield services industry 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 market conditions, which may result in an oversupply of rigs in an area. In many markets where we operate, the number of rigs available for use exceeds the demand for rigs, resulting in price competition. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. The land drilling market generally is more competitive than the offshore drilling market because there are larger numbers of rigs and competitors.
 
The nature of our operations presents inherent risks of loss that could adversely affect our results of operations
 
Our operations are subject to many hazards inherent in the drilling, workover and well-servicing and pressure pumping industries, including blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, 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 and natural resources 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. Our operations are also subject to risks of war, civil disturbances or other political events.


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Accidents may occur, we may be unable to obtain desired contractual indemnities, and our insurance may prove inadequate in certain cases. The occurrence of an event not fully insured or indemnified against, or the failure or inability of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not be available to cover any or all of these risks. Even if available, insurance may be inadequate or insurance premiums or other costs may rise significantly in the future making insurance prohibitively expensive. We expect to continue to face upward pressure in our insurance renewals; our premiums and deductibles may be higher, and some insurance coverage may either be unavailable or more expensive than it has been in the past. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention. 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 our overall costs.
 
Future price declines may result in a writedown of our oil and gas asset carrying values
 
We follow the successful-efforts method of accounting for our consolidated subsidiaries’ oil and gas activities. Under the successful-efforts method, lease acquisition costs and all development costs are capitalized. Our provision for depletion is based on these capitalized costs and is determined on a property-by-property basis using the units-of-production method. Proved property acquisition costs are amortized over total proved reserves. Costs of wells and related equipment and facilities are amortized over the life of proved developed reserves. Proved oil and gas properties are reviewed when circumstances suggest the need for such a review and are written down to their estimated fair value, if required. Unproved properties are reviewed periodically to determine if there has been impairment of the carrying value; any impairment is expensed in that period. The estimated fair value of our proved reserves generally declines when there is a significant and sustained decline in oil and natural gas prices. During 2010, 2009 and 2008, our impairment tests on the wholly owned oil and gas-related assets in our Oil and Gas operating segment resulted in impairment charges of $137.8 million, $48.6 million and $21.5 million, respectively. Any sustained further decline in oil and natural gas prices or reserve quantities could require further writedown of the value of our proved oil and gas properties if the estimated fair value of these properties falls below their net book value.
 
Our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, utilize the full-cost method of accounting for costs related to oil and natural gas properties. Under this method, all of these costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. However, these capitalized costs are subject to a ceiling test which limits the costs to the aggregate of (i) the present value of future net revenues attributable to proved oil and natural gas reserves, discounted at 10%, plus (ii) the lower of cost or market value of unproved properties. The full-cost ceiling was evaluated at December 31, 2010 and 2009 using the 12-month average price, whereas during 2008, the full-cost ceiling was evaluated using year-end prices. During 2010, our unconsolidated oil and gas joint ventures did not record full-cost ceiling test writedowns. During 2009 and 2008, the ventures recorded full-cost ceiling test writedowns of which $237.1 million and $228.3 million, respectively, represented our proportionate share. Any sustained further decline in oil and natural gas prices, or other factors, without other mitigating circumstances, could cause other future writedowns of capitalized costs and asset impairments that could adversely affect our results of operations.
 
Our acquisition of Superior may not be as financially or operationally successful as contemplated
 
In evaluating the acquisition of Superior, we made certain business assumptions and determinations based on our due diligence. However, these assumptions and determinations involve risks and uncertainties that may cause them to be inaccurate. As a result, we may not realize the full benefits that we expect from the acquisition. For example, our assumptions as to future revenue with respect to expanding internationally and achieving synergies in North America by integrating Superior’s pumping services with our drilling and workover offerings may prove to be incorrect. If they are, the financial success of the acquisition may be materially adversely affected.


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The profitability of our operations could be adversely affected by war, civil disturbance, or political or economic turmoil, fluctuation in currency exchange rates and local import and export controls
 
We derive a significant portion of our business from global markets, including major operations in Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. These operations are subject to various risks, including the risk of war, civil disturbances and governmental activities that may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. In some countries, our operations may be subject to the additional risk of fluctuating currency values and exchange controls, such as last year’s currency devaluation in Venezuela. 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 loss of key executives could reduce our competitiveness and prospects for future success
 
The successful execution of our strategies central to our future success will depend, in part, on a few of our key executive officers. We have entered into employment agreements with our Chairman and Chief Executive Officer, Eugene M. Isenberg and our Deputy Chairman, President and Chief Operating Officer, Anthony G. Petrello, with terms through March 30, 2013. If Mr. Isenberg’s employment is terminated in the event of death or disability, or without cause or in the event of a change in control, a cash payment of $100 million will be made by the Company. If Mr. Petrello’s employment is terminated in the event of death or disability, the Company will make a cash payment of $50 million; or in the event of termination without cause or in the event of a change in control, the Company will make a cash payment based on a formula of three times the average of his base salary and annual bonus paid during the three fiscal years preceding the termination. We do not carry significant amounts of key man insurance. The loss of Mr. Isenberg or Mr. Petrello could have an adverse effect on our financial condition or results of operations.
 
Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect our results of operations
 
The drilling of oil and gas wells is subject to various federal, state and local laws, rules and regulations. Our cost of compliance with these laws, rules and regulations may be substantial. For example, federal law imposes on “responsible parties” a variety of regulations related to the prevention of oil spills, and liability for removal costs and natural resource, real or personal property and certain economic damages arising from such spills. Some of these laws may impose strict liability for these costs and damages without regard to the conduct of the parties. 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 materials, some of which are classified as solid or hazardous wastes or hazardous substances. Various state and federal laws govern 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 employ personnel responsible for monitoring environmental compliance and arranging for remedial actions that may be required from time to time and also use consultants 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.
 
The scope of laws protecting the environment has expanded, particularly outside the United States, and this trend is expected to continue. The 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. Violations may also result in liabilities for personal injuries, property and natural resource damage and other costs and claims. We are not always successful in allocating all risks of these environmental liabilities to customers, and it is possible that customers who assume the risks will be financially unable to bear any resulting costs.


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Under the Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or Superfund, and similar state laws and regulations, liability for release of a hazardous substance into the environment 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 of any party that contributed to the release. Liability under CERCLA may include costs of cleaning up the hazardous substances that have been released into the environment and damages to natural resources.
 
Changes in environmental laws and regulations may also negatively impact the operations of oil and natural gas exploration and production companies, which in turn could have an adverse effect on us. For example, legislation has been proposed from time to time in the U.S. Congress that would reclassify some oil and natural gas production wastes as hazardous wastes under the Resources Conservation and Recovery Act, which would make the reclassified wastes subject to more stringent handling, disposal and clean-up requirements. Legislators and regulators in the United States and other jurisdictions where we operate also focus increasingly on restricting the emission of carbon dioxide, methane and other greenhouse gases that may contribute to warming of the Earth’s atmosphere, and other climatic changes. The U.S. Congress has considered legislation designed to reduce emission of greenhouse gases, and some states in which we operate have passed legislation or adopted initiatives, such as the Regional Greenhouse Gas Initiative in the northeastern United States and the Western Regional Climate Action Initiative, which establish greenhouse gas inventories and/or cap-and-trade programs. Some international initiatives have also been adopted, such as the United Nations Framework Convention on Climate Change’s “Kyoto Protocol”, to which the United States is not a party. In addition, the U.S. Environmental Protection Agency (“EPA”) has published findings that emissions of greenhouses gases present an endangerment to public health and the environment, paving the way for regulations that would restrict emissions of greenhouse gases under existing provisions of the Clean Air Act.
 
In October 2009, the EPA enacted rules requiring the reporting of greenhouse gas emissions from large sources and suppliers in the United States. Although we do not believe these rules currently apply to us, the EPA has proposed expanding the rules to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities beginning in 2012 for emissions occurring in 2011. The enactment of such hazardous waste legislation or future or more stringent regulation of greenhouse gases 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 U.S. Oil Pollution Act of 1990, as amended, imposes strict liability on responsible parties for removal costs and damages resulting from discharges of oil into U.S. waters. 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.
 
Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the demand for fracturing and other services
 
Superior performs hydraulic fracturing, a process sometimes used in the completion of oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. In March 2010, the EPA announced that it would study the potential adverse impact that fracturing may have on water quality and public health. Legislation has also been introduced in the U.S. Congress and some states that would require the disclosure of chemicals used in the fracturing process. If enacted, the legislation could require fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping requirements and meet plugging and abandonment requirements. Any new laws regulating fracturing activities could cause operational delays or increased costs in exploration and production, which could adversely affect the demand for fracturing services.


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Because our option, warrant and convertible securities holders have a considerable number of common shares available for issuance and resale, significant issuances or resales in the future could adversely affect the market price of our common shares
 
As of February 24, 2011, we had 800,000,000 authorized common shares, of which 315,558,810 shares were outstanding. In addition, 46,780,820 common shares were reserved for issuance pursuant to option and employee benefit plans, and 39,814,194 shares were reserved for issuance upon conversion or repurchase of outstanding senior exchangeable notes. 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 under the Securities Act) or the conversion into common shares, or repurchase of debentures and notes using common shares, would be dilutive to existing security holders, could adversely affect the prevailing market price of our common shares and could impair our ability to raise additional capital through the sale of equity securities.
 
Provisions in our organizational documents and executive contracts may deter a change of control transaction and decrease the likelihood of a shareholder receiving a change of control premium
 
Our Board of Directors is divided into three classes, with each class serving a staggered three-year term. In addition, the Board of Directors has the authority to issue a significant number of common shares and up to 25,000,000 preferred shares, as well as to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of the preferred shares, in each case without any vote or action by the holders of our common shares. Although we have no current plans to issue preferred shares, our classified Board, as well as its ability to issue preferred shares, may discourage, delay or prevent changes in control of Nabors that are not supported by the Board, thereby preventing some of our shareholders from realizing a premium on their shares. In addition, the requirement in the indenture for our 0.94% senior exchangeable notes due 2011 to pay a make-whole premium in the form of an increase in the exchange rate in certain circumstances could have the effect of making a change in control of Nabors more expensive.
 
We have employment agreements with our Chairman and Chief Executive Officer, Eugene M. Isenberg, and our Deputy Chairman, President and Chief Operating Officer, Anthony G. Petrello. These agreements have change-in-control provisions that could result in significant cash payments to Messrs. Isenberg and Petrello.
 
We may have additional tax liabilities
 
We are subject to income taxes in the United States and numerous other 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 audited 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 what is reflected in income tax provisions and accruals. An audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows in the period or periods challenged. It is also possible that future changes to tax laws (including tax treaties) could impact our ability to realize the tax savings recorded to date.
 
On September 14, 2006, Nabors Drilling International Limited, one of our wholly owned Bermuda subsidiaries (“NDIL”), received a Notice of Assessment (the “Notice”) from Mexico’s federal tax authorities in connection with the audit of NDIL’s Mexico branch for 2003. The Notice proposes to deny depreciation expense deductions relating to drilling rigs operating in Mexico in 2003. The Notice also proposes to deny a deduction for payments made to an affiliated company for the procurement of labor services in Mexico. The amount assessed was approximately $19.8 million (including interest and penalties). Nabors and its tax advisors previously concluded that the deductions were appropriate and more recently that the government’s position lacks merit. NDIL’s Mexico branch took similar deductions for depreciation and labor expenses from 2004 to 2008. On June 30, 2009, the government proposed similar assessments against the Mexico branch of another wholly owned Bermuda subsidiary, Nabors Drilling International II Ltd. (“NDIL II”) for 2006. We anticipate that a similar assessment will eventually be proposed against NDIL for 2004 through 2008 and against NDIL II for 2007 to 2010. We believe that the potential assessments will range from $6 million to


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$26 million per year for the period from 2004 to 2009, and in the aggregate, would be approximately $90 million to $95 million. Although we believe that any assessments related to the 2004 to 2010 years lack merit, a reserve has been recorded in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The statute of limitations for NDIL’s 2004 tax year recently expired. Accordingly, during the fourth quarter of 2010, we released $7.4 million from our tax reserves, which represented the reserve recorded for that tax year. If these additional assessments were to be made and we ultimately did not prevail, we would be required to recognize additional tax for the amount in excess of the current reserve.
 
Proposed tax legislation could mitigate or eliminate the benefits of our 2002 reorganization as a Bermuda company
 
Various bills have been introduced in the U.S. Congress that could reduce or eliminate the tax benefits associated with our reorganization as a Bermuda company. Legislation enacted by the U.S. Congress in 2004 provides that a corporation that reorganized in a foreign jurisdiction on or after March 4, 2003 be treated as a domestic corporation for U.S. federal income tax purposes. Nabors’ reorganization was completed on June 24, 2002. There have been and we expect that there may continue to be legislation proposed by the U.S. Congress from time to time which, if enacted, could limit or eliminate the tax benefits associated with our reorganization.
 
Because we cannot predict whether legislation will ultimately be adopted, no assurance can be given that the tax benefits associated with our reorganization will ultimately accrue to the benefit of the Company and its shareholders. It is possible that future changes to the tax laws (including tax treaties) could impact our ability to realize the tax savings recorded to date, as well as future tax savings, resulting from our reorganization.
 
Legal proceedings could affect our financial condition and results of operations
 
We are subject to legal proceedings and governmental investigations from time to time that include employment, tort, intellectual property and other claims, and purported class action and shareholder derivative actions. We are also subject to complaints and 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 that could have an adverse effect on our financial condition or results of operations.
 
Our financial results could be affected by changes in the value of our investment portfolio
 
We invest our excess cash in a variety of investment vehicles, some of which are subject to market fluctuations resulting from a variety of economic factors or factors associated with a particular investment, including without limitation, overall declines in the equity markets, currency and interest rate fluctuations, volatility in the credit markets, exposures related to concentrations of investments in a particular fund or investment, exposures related to hedges of financial positions, and the performance of a particular fund or investment managers. As a result, events or developments that negatively affect the value of our investments could have an adverse effect on our results of operations.
 
We do not currently intend to pay dividends on our common shares
 
We have not paid any cash dividends on our common shares since 1982 and have no current intention to do so. However, we can give no assurance that we will not reevaluate our position on dividends in the future.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
Not applicable.


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ITEM 2.   PROPERTIES
 
Nabors’ principal executive offices are located in Hamilton, Bermuda. We own or lease executive and administrative office space in Houston, Texas and other areas across the world.
 
Many of the international drilling rigs and some 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, including various helicopters, fixed-wing aircraft and heliportable well-service equipment, which are used to support drilling and logistics operations. 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. The operations of our Oil and Gas operating segment focus on the exploration for and the acquisition, development and production of natural gas, oil and natural gas liquids in the United States, the Canada provinces of Alberta and British Columbia, and Colombia.
 
Our Oil and Gas operating segment includes our wholly owned oil and gas assets and our unconsolidated oil and gas joint ventures. In December 2008, the SEC revised oil and gas reporting disclosures, which clarified that we should consider our equity-method investments when determining whether we have significant oil and gas activities beginning in 2009. A one-year deferral of the disclosure requirements was allowed if an entity became subject to the requirements because of the change to the definition of significant oil and gas activities. When operating results from our wholly owned oil and gas activities were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we determined that we had significant oil and gas activities under the new definition. Accordingly, we are presenting the information with regard to our oil and gas producing activities as of and for the year ended December 31, 2010.
 
The estimates of net proved oil and gas reserves are based on reserve reports as of December 31, 2010, which were prepared by independent petroleum engineers. AJM Petroleum Consultants prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Canada. Miller and Lents, Ltd. prepared reports of estimated proved oil and gas reserves for both our wholly owned assets and our U.S. joint venture’s interests in natural gas and oil properties located in the United States. Netherland, Sewell & Associates, Inc. prepared reports of estimated proved oil reserves for certain oil properties located in Cat Canyon and West Cat Canyon Fields, Santa Barbara County, California. Lonquist & Co., LLC prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Colombia.
 
Summary of Oil and Gas Reserves
 
The table below summarizes the proved reserves in each geographic area and by product type for our wholly owned subsidiaries and our proportionate interests in our equity companies. We report proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Estimates of volumes of proved reserves of natural gas at year end are expressed in billions of cubic feet (“Bcf”) at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (“MMBbls”) for oil and natural gas liquids.
 
For our wholly owned properties in the United States, the prices used in our reserve reports were $3.72 per mcf for the 12-month average of natural gas, $36.43 per barrel for natural gas liquids and $61.12 per barrel for oil at December 31, 2010. The prices used in the reserve reports by our unconsolidated U.S. joint venture were $4.53 per mcf for the 12-month average of natural gas, $39.04 per barrel for natural gas liquids and $70.60 per barrel for oil at December 31, 2010. For our wholly owned properties in Canada, the price used in our reserve reports was $2.81 per mcf for the 12-month average of natural gas at December 31, 2010. The 12-month average price for natural gas used in the reserve report by our unconsolidated Canada joint venture was $2.78 per mcf at December 31, 2010. For our wholly owned properties in Colombia, the price used in our reserve reports was $78.21 per barrel for oil at December 31, 2010. The oil price used in the reserve report by our unconsolidated Colombia joint venture was $76.00 per barrel at December 31, 2010.


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No major discovery or other favorable or adverse event has occurred since December 31, 2010, that would cause a significant change in the estimated proved reserves as of that date.
 
                 
    Reserves  
    Liquids
    Natural Gas
 
Reserve Category   (MMBbls)     (Bcf)  
 
Proved
               
Developed
               
Consolidated Subsidiaries
               
United States
    2.7 (2)     17.1  
Canada
          5.6  
Colombia
    1.6        
                 
Total Consolidated
    4.3       22.7  
Equity Companies (1)
               
United States
    3.0       147.1  
Canada
          5.1  
Colombia
    0.5        
                 
Total Equity Companies
    3.5       152.2  
                 
Total Developed
    7.8       174.9  
Undeveloped
               
Consolidated Subsidiaries
               
United States
    18.5       2.7  
Canada
           
Colombia
    .4        
                 
Total Consolidated
    18.9       2.7  
Equity Companies (1)
               
United States
    4.9       405.7  
Canada
           
Colombia
    1.3        
                 
Total Equity Companies
    6.2       405.7  
                 
Total Proved
    25.1       408.4  
 
 
(1) Represents our proportionate interests in our equity companies.
 
(2) During 2010, we purchased a 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County California for $25 million. At December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls. Workovers on approximately 273 productive wells began in late 2010, and 22 wells were producing as of December 31, 2010. The price used in our reserve report was $65.641 per barrel for oil at December 31, 2010.
 
In the preceding reserve information, consolidated subsidiary and our proportionate interests in our equity company reserves are reported separately. However, we operate our business with the same view of equity company reserves as for reserves from consolidated subsidiaries.
 
The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines. Furthermore, we record proved reserves only for projects that have received significant funding commitments by management made toward the development of the reserves. Although we are reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development


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projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and natural gas price levels.
 
Technologies Used in Establishing Proved Reserves Additions in 2010
 
Proved reserves were based on estimates generated through the integration of available and appropriate data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.
 
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 2-D and 3-D seismic data, calibrated with available well control. Where applicable, surface geological information was also utilized. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software and commercially available data analysis packages.
 
In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.
 
Internal Controls over Proved Reserves
 
Our Oil and Gas operating segment is managed by and staffed with individuals who have an average of more than 20 years of technical experience in the petroleum industry. We maintain computerized records of our reserve estimates and production data. Appropriate controls, including limitations on access and updating capabilities, are in place to ensure data integrity. We engage qualified third-party reservoir engineers and perform reviews to ensure reserve estimations include all properties owned and are based on correct working and net revenue interests. Key components of the reserve estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to reserve estimates unless these changes have been thoroughly reviewed and evaluated by authorized personnel at Nabors. After all changes are made, senior management reviews the estimates for final endorsement.
 
Proved Undeveloped Reserves
 
At December 31, 2010, approximately 559 billion cubic feet equivalent (“Bcfe”) of our proved reserves were classified as proved undeveloped, which represented 71.6% of the 780.7 Bcfe reported in proved reserves. This amount is inclusive of both consolidated subsidiaries and equity company reserves. Progress was made in converting proved undeveloped reserves into proved developed reserves in 2010. During 2010, we completed development work in over 12 fields and participated in numerous major project start-ups that resulted in the transfer of approximately 62 Bcfe from proved undeveloped to proved developed reserves. We estimate that 35% of our current proved undeveloped reserves will be developed by year 2012 and all of our current proved undeveloped reserves will be developed by year 2016.


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Oil and Gas Production, Production Prices and Production Costs
 
Oil and Gas Production
 
The table below summarizes production by final product sold, average production sales price and average production cost, each by geographic area for the year ended December 31, 2010. Production costs are costs to operate and maintain our wells and related equipment and include the cost of labor, well-service and repair, location maintenance, power and fuel, transportation, cost of product, property taxes and production-related general and administrative costs.
 
                                                                 
    United States     Canada     Colombia     Total  
    Liquids
    Natural Gas
    Liquids
    Natural Gas
    Liquids
    Natural Gas
    Liquids
    Natural Gas
 
    (MMBbls)     (Bcf)     (MMBbls)     (Bcf)     (MMBbls)     (Bcf)     (MMBbls)     (Bcf)  
 
Oil and natural gas liquids production
                                                               
Consolidated Subsidiaries
    .073       3.533             3.058       .230             .303       6.591  
                                                                 
Equity Companies(1)
    .249       12.338             1.535       .273             .522       13.873  
Average production sales prices:
                                                               
Consolidated Subsidiaries
  $ 63.77     $ 4.19     $     $ 3.69     $ 72.25     $     $ 70.19     $ 2.71  
                                                                 
Equity Companies(1)
  $ 74.86     $ 4.43     $     $ 3.93     $ 73.90     $     $ 58.59     $ 4.11  
Average production costs:
                                                               
Consolidated Subsidiaries
          $ 2.14/mcfe             $ 2.60/mcfe     $ 34.42/boe                          
                                                                 
Equity Companies(1)
          $ 1.33/mcfe             $ 5.89/mcfe     $ 33.60/boe                          
 
 
(1) Represents our proportionate interests in our equity companies.
 
Drilling and Other Exploratory and Development Activities
 
During 2010, our drilling program focused on proven and emerging oil and natural gas basins in the United States. Our drilling program includes development activities with properties located in Canada and Colombia that are being actively marketed. The following tables provide the number of oil and gas wells completed during 2010.
 
Number of Net Productive and Dry Wells Drilled
 
                 
    For the Year Ended December 31, 2010  
    Net Productive and
    Net Dry Exploratory
 
    Dry Wells Drilled     Wells Drilled  
 
Consolidated Subsidiaries
               
United States
    1.9        
Canada
           
Colombia
    4.2        
                 
Total Consolidated
    6.1        
                 
Equity Companies (1)
               
United States
    0.9        
Canada
           
Colombia
    3.3       2.1  
                 
Total Equity Companies
    4.2       2.1  
                 
 
 
(1) Represents our proportionate interests in our equity companies.


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    For the Year Ended December 31, 2010  
    Net Productive
    Net Dry
 
    Development Wells
    Development
 
    Drilled     Wells Drilled  
 
Consolidated Subsidiaries
               
United States
    1.2       0.1  
Canada
           
Colombia
           
                 
Total Consolidated
    1.2       0.1  
                 
Equity Companies (1)
               
United States
    9.5        
Canada
           
Colombia
    1.6        
                 
Total Equity Companies
    11.1        
                 
 
 
(1) Represents our proportionate interests in our equity companies.
 
Present Activities
 
The following table provides the number of wells in the process of drilling as of December 31, 2010.
 
Wells Drilling
 
                                                                 
    United States   Canada   Colombia   Total
    Gross   Net   Gross   Net   Gross   Net   Gross   Net
 
Consolidated Subsidiaries
    17.0       0.9                               17.0       0.9  
Equity Companies(1)
    2.5       2.5                               2.5       2.5  
 
 
(1) Represents our proportionate interests in our equity companies.
 
Oil and Gas Properties, Wells, Operations and Acreage
 
Gross and Net Productive Wells
 
                 
    For the Year Ended
 
    December 31, 2010  
    Gross     Net  
 
Consolidated Subsidiaries
               
United States
    746.0       139.6  
Canada
    2.0       2.0  
Colombia
    7.0       4.9  
                 
Total Consolidated
    755.0       146.5  
                 
Equity Companies(1)
               
United States
    337.8       225.4  
Canada
    3.0       3.0  
Colombia
    7.0       3.9  
                 
Total Equity Companies
    347.8       232.3  
 
 
(1) Represents our proportionate interests in our equity companies.


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Gross and Net Developed Acreage
 
                                                                 
    December 31, 2010
    United States   Canada   Colombia   Total
    Gross   Net   Gross   Net   Gross   Net   Gross   Net
 
Consolidated Subsidiaries
    157,965       31,879       1,309       715       883       618       160,157       33,212  
Equity Companies(1)
    211,638       112,227       9,801       8,134                   221,439       120,361  
 
 
(1) Represents our proportionate interests in our equity companies.
 
Gross and Net Undeveloped Acreage
 
                                                                 
    December 31, 2010
    United States   Canada   Colombia   Total
    Gross   Net   Gross   Net   Gross   Net   Gross   Net
 
Consolidated Subsidiaries
    347,662       128,244       46,440       34,554       546,384       247,299       940,486       410,097  
Equity Companies(1)
    574,841       218,596       83,821       53,279       739,533       448,185       1,398,195       720,060  
 
 
(1) Represents our proportionate interests in our equity companies.
 
Additional information about our properties can be found in Notes 2 — Summary of Significant Accounting Policies, 8 — Property, Plant and Equipment (each, under the caption Property, Plant and Equipment), 16 — Commitments and Contingencies (under the caption Operating Leases), and 24 — Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. — Financial Statements and Supplementary Data. The revenues and property, plant and equipment by geographic area for the years ended December 31, 2010, 2009 and 2008, can be found in Note 22 — Segment Information. A description of our rig fleet is included under the caption Introduction in Part I, Item 1. — Business.
 
Management believes that our existing equipment and facilities are adequate to support our current level of operations as well as an expansion of drilling operations in those geographical areas where we may expand.
 
ITEM 3.   LEGAL PROCEEDINGS
 
Nabors and its subsidiaries are defendants or otherwise involved in a number of lawsuits in the ordinary course of business. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ from our estimates. In the opinion of management and based on liability accruals provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our consolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particular reporting period.
 
On July 5, 2007, we received an inquiry from the United States Department of Justice relating to its investigation of one of our vendors and compliance with the Foreign Corrupt Practices Act. The inquiry relates to transactions with and involving Panalpina, which provided freight forwarding and customs clearance services to some of our affiliates. To date, the inquiry has focused on transactions in Kazakhstan, Saudi Arabia, Algeria and Nigeria. The Audit Committee of our Board of Directors engaged outside counsel to review some of our transactions with this vendor, has received periodic updates at its regularly scheduled meetings, and the Chairman of the Audit Committee has received updates between meetings as circumstances warrant. The investigation includes a review of certain amounts paid to and by Panalpina in connection with obtaining permits for the temporary importation of equipment and clearance of goods and materials through customs. Both the SEC and the United States Department of Justice have been advised of our investigation.


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The ultimate outcome of this investigation or the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws cannot be determined at this time.
 
A court in Algeria entered a judgment of approximately $19.7 million against us related to alleged customs infractions in 2009. We believe we did not receive proper notice of the judicial proceedings, and that the amount of the judgment is excessive. We have asserted the lack of legally required notice as a basis for challenging the judgment on appeal to the Algeria Supreme Court. Based upon our understanding of applicable law and precedent, we believe that this challenge will be successful. We do not believe that a loss is probable and have not accrued any amounts related to this matter. However, the ultimate resolution and the timing thereof are uncertain. If we are ultimately required to pay a fine or judgment related to this matter, the amount of the loss could range from approximately $140,000 to $19.7 million.
 
In August 2010, Nabors and its wholly owned subsidiary, Diamond Acquisition Corp. (“Diamond”) were sued in three putative shareholder class actions. Two of the cases were dismissed. The remaining case pending, Jordan Denney, Individually and on Behalf of All Others Similarly Situated v. David E. Wallace, et al., Civil Action No. 10-1154, is pending in the United States District Court for the Western District of Pennsylvania. The suits were brought against Superior, the individual members of its board of directors, certain of Superior’s senior officers, Nabors and Diamond. The complaints alleged that Superior’s officers and directors violated various provisions of the Exchange Act and breached their fiduciary duties in connection with the Superior Merger, and that Nabors and Diamond aided and abetted these violations. The complaints sought injunctive relief, including an injunction against the consummation of the Superior Merger, monetary damages, and attorney’s fees and costs. The claim against Superior and its directors is covered by insurance after a deductible amount. We anticipate settling the claims in the first or second quarter of 2011, and that any settlement will be funded by Superior’s insurers to the extent it exceeds our deductible.
 
ITEM 4.   (REMOVED AND RESERVED)


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PART II
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
STOCK PERFORMANCE GRAPH
 
The following graph illustrates comparisons of five-year cumulative total returns among Nabors, the S&P 500 Index and the Dow Jones Oil Equipment and Services Index. Total return assumes $100 invested on December 31, 2005 in shares of Nabors, the S&P 500 Index, and the Dow Jones Oil Equipment and Services Index. It also assumes reinvestment of dividends and is calculated at the end of each calendar year, December 31, 2006 — 2010.
 
(PERFORMANCE GRAPH)
 
                                                   
      2006     2007     2008     2009     2010
Nabors Industries Ltd. 
      79         72         32         58         62  
S&P 500 Index
      116         122         77         97         112  
Dow Jones Oil Equipment and Services Index
      113         164         67         111         141  
                                                   


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I.   Market and Share Prices
 
Our common shares are traded on the New York Stock Exchange under the symbol “NBR”. At February 24, 2011, there were approximately 1,573 shareholders of record. We have not paid any cash dividends on our common shares since 1982 and currently have no intentions to do so. However, 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 New York Stock Exchange for the periods indicated.
 
                 
    Share Price  
Calendar Year   High     Low  
 
2009
               
First quarter
    14.05       8.25  
Second quarter
    19.79       9.38  
Third quarter
    21.48       13.78  
Fourth quarter
    24.07       19.18  
2010
               
First quarter
    27.05       18.74  
Second quarter
    22.82       16.90  
Third quarter
    19.13       15.54  
Fourth quarter
    23.93       17.36  
 
The following table provides information relating to Nabors’ repurchase of common shares during the three months ended December 31, 2010:
 
                                 
                      Approximate Dollar
 
    Total Number
    Average
    Total Number of
    Value of Shares
 
    of Shares
    Price Paid
    Shares Purchased as
    that May Yet Be
 
    Purchased
    per
    Part of Publicly
    Purchased Under the
 
Period   (1)     Share(1)     Announced Program     Program(2)  
    (In thousands, except per share amounts)  
 
October 1 — October 31
                    $ 35,458  
November 1 — November 30
        $ 21.85           $ 35,458  
December 1 — December 31
    3,073     $ 23.15           $ 35,458  
 
 
(1) Shares were withheld from employees and directors to satisfy certain tax withholding obligations due in connection with grants of stock under our 2003 Employee Stock Plan and option exercises from our 1996 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and our 1998 Employee Stock Plan. The 2003 Employee Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and 1996 Employee Stock Plan provide for the withholding of shares to satisfy tax obligations, but do not specify a maximum number of shares that can be withheld for this purpose. These shares were not purchased as part of a publicly announced program to purchase common shares.
 
(2) In July 2006 our Board of Directors authorized a share repurchase program under which we may repurchase up to $500 million of our common shares in the open market or in privately negotiated transactions. Through December 31, 2010, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2010, we had the capacity to repurchase up to an additional $35.5 million of our common shares under the July 2006 share repurchase program.
 
See Part III, Item 12. for a description of securities authorized for issuance under equity compensation plans.
 
II.   Dividend Policy
 
See Part I, Item 1A. — Risk Factors — We do not currently intend to pay dividends on our common shares and Part II, Item 5. — I. Market and Share Prices.


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III. Shareholder Matters
 
Bermuda has exchange controls which apply to residents in respect of the Bermuda dollar. As an exempt company, Nabors is considered to be nonresident for such controls; consequently, there are no Bermuda governmental restrictions on our 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 paid by Nabors to its shareholders. Furthermore, no Bermuda tax is levied on the sale or transfer (including by gift and/or on the death of the shareholder) of Nabors common shares (other than by shareholders resident in Bermuda).
 
ITEM 6.   SELECTED FINANCIAL DATA
 
                                         
    Year Ended December 31,  
Operating Data(1)(2)   2010     2009     2008     2007     2006  
    (In thousands, except per share amounts and ratio data)  
 
Revenues and other income:
                                       
Operating revenues
  $ 4,174,635     $ 3,683,419     $ 5,507,542     $ 4,938,748     $ 4,707,268  
Earnings (losses) from unconsolidated affiliates
    33,257       (155,433 )     (192,548 )     20,980       20,545  
Investment income (loss)
    7,648       25,599       21,412       (16,290 )     101,907  
                                         
Total revenues and other income
    4,215,540       3,553,585       5,336,406       4,943,438       4,829,720  
                                         
Costs and other deductions:
                                       
Direct costs
    2,423,602       2,001,404       3,100,613       2,763,462       2,508,611  
General and administrative expenses
    346,661       428,161       479,194       436,274       416,582  
Depreciation and amortization
    764,253       667,100       614,367       469,669       365,357  
Depletion
    17,943       9,417       22,308       30,904       38,580  
Interest expense
    273,044       266,039       196,718       154,919       120,507  
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net
    47,060       12,559       15,829       11,777       22,092  
Impairments and other charges
    260,931       330,976       176,123       41,017        
                                         
Total costs and other deductions
    4,133,494       3,715,656       4,605,152       3,908,022       3,471,729  
                                         
Income (loss) from continuing operations before income taxes
    82,046       (162,071 )     731,254       1,035,416       1,357,991  
Income tax expense (benefit)
    (24,814 )     (133,803 )     209,660       201,896       407,282  
Subsidiary preferred stock dividend
    750                          
                                         
Income (loss) from continuing operations, net of tax
    106,110       (28,268 )     521,594       833,520       950,709  
Income (loss) from discontinued operations, net of tax
    (11,330 )     (57,620 )     (41,930 )     31,762       24,927  
                                         
Net income (loss)
    94,780       (85,888 )     479,664       865,282       975,636  
Less: Net (income) loss attributable to noncontrolling interest
    (85 )     342       (3,927 )     420       (1,914 )
                                         
Net income (loss) attributable to Nabors
  $ 94,695     $ (85,546 )   $ 475,737     $ 865,702     $ 973,722  
                                         


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    Year Ended December 31,  
Operating Data(1)(2)   2010     2009     2008     2007     2006  
    (In thousands, except per share amounts and ratio data)  
 
Earnings (losses) per share:
                                       
Basic from continuing operations
  $ .37     $ (.10 )   $ 1.84     $ 2.97     $ 3.26  
Basic from discontinued operations
    (.04 )     (.20 )     (.15 )     .11       .09  
                                         
Total Basic
  $ .33     $ (.30 )   $ 1.69     $ 3.08     $ 3.35  
                                         
Diluted from continuing operations
  $ .37     $ (.10 )   $ 1.80     $ 2.89     $ 3.16  
Diluted from discontinued operations
    (.04 )     (.20 )     (.15 )     .11       .08  
                                         
Total Diluted
  $ .33     $ (.30 )   $ 1.65     $ 3.00     $ 3.24  
                                         
Weighted-average number of common shares outstanding:
                                       
Basic
    285,145       283,326       281,622       281,238       291,267  
Diluted
    289,996       283,326       288,236       288,226       300,677  
Capital expenditures and acquisitions of businesses(3)
  $ 1,878,063     $ 990,287     $ 1,578,241     $ 1,945,932     $ 2,006,286  
Interest coverage ratio(4)
    7.0:1       6.3:1       21.0:1       32.6:1       38.2:1  
 
                                         
    As of December 31,
Balance Sheet Data(1)(2)   2010   2009   2008   2007   2006
    (In thousands, except ratio data)
 
Cash, cash equivalents, short-term and long-term investments and other receivables(5)
  $ 841,490     $ 1,191,733     $ 826,063     $ 1,179,639     $ 1,653,285  
Working capital
    458,550       1,568,042       1,037,734       719,674       1,650,496  
Property, plant and equipment, net
    7,815,419       7,646,050       7,331,959       6,669,013       5,423,729  
Total assets
    11,646,569       10,644,690       10,517,899       10,139,783       9,155,931  
Long-term debt
    3,064,126       3,940,605       3,600,533       2,894,659       3,457,675  
Shareholders’ equity
    5,328,162       5,167,656       4,904,106       4,801,579       3,889,100  
Funded debt to capital ratio:
                                       
Gross(6)
    0.42:1       0.41:1       0.41:1       0.39:1       0.43:1  
Net(7)
    0.37:1       0.33:1       0.35:1       0.30:1       0.28:1  
 
 
(1) All periods present the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia and the Sea Mar business as discontinued operations.
 
(2) Our acquisitions’ results of operations and financial position have been included beginning on the respective dates of acquisition and include Superior (September 2010), Energy Contractors (December 2010), Pragma Drilling Equipment Ltd. assets (May 2006), and 1183011 Alberta Ltd. (January 2006).
 
(3) Represents capital expenditures and the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.
 
(4) The interest coverage ratio is a trailing 12-month quotient of the sum of income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, subsidiary preferred stock dividends, depreciation and amortization, depletion expense, impairments and other charges, income tax expense (benefit) and our proportionate share of full-cost ceiling test writedowns from our unconsolidated oil and gas joint ventures less investment income (loss) divided by cash interest

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expense plus subsidiary preferred stock dividends. This ratio is a method for calculating the amount of operating cash flows available to cover interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
 
(5) The December 31, 2008 and 2007 amounts include $1.9 million and $53.1 million, respectively, in cash proceeds receivable from brokers from the sale of certain long-term investments that are included in other current assets. Additionally, the December 31, 2010, 2009 and 2008 amounts include $32.9 million, $92.5 million and $224.2 million, respectively, in oil and gas financing receivables that are included in long-term investments and other receivables.
 
(6) The gross funded debt to capital ratio is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portion of long-term debt and (3) long-term debt. Capital is defined as shareholders’ equity. The gross funded debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
 
(7) The net funded debt to capital ratio is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables. The net funded debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
 
ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Management Overview
 
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to help the reader understand the results of our operations and our financial condition. This information is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the accompanying notes thereto.
 
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 and gas markets in the world. Our worldwide fleet of actively marketed rigs consists of over 550 land drilling rigs, more than 700 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jack-up units, barge rigs and a large component of trucks and fluid hauling vehicles. We invest in oil and gas exploration, development and production activities in the United States, Canada and Colombia.
 
The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, well-servicing and workover operations and pressure pumping, on land and offshore. Our oil and gas exploration, development and production operations are included in our Oil and Gas operating segment. Our operating segments engaged in drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations are aggregated in our Other Operating Segments.
 
Our businesses depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Therefore, a sustained increase or decrease in the price of natural gas or oil, which could have a material impact on exploration, development and production activities, could also materially affect our financial position, results of operations and cash flows.
 
The magnitude of customer spending on new and existing wells is the primary driver of our business. The primary determinant of customer spending is their cash flow and earnings, which (i) in our U.S. Lower 48 Land Drilling and Canadian Drilling operations are largely driven by natural gas prices and (ii) in our Alaskan, International, U.S. Offshore (Gulf of Mexico), Canadian Well-servicing and U.S. Land Well-servicing operations by oil prices. Both natural gas and oil prices impact our customers’ activity levels and spending for our Pressure Pumping operations. Oil and natural gas liquids prices are beginning to be more significant


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factors in some of the traditionally natural-gas-driven operating segments. The following table sets forth natural gas and oil price data per Bloomberg for the last three years:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
 
Commodity prices:
                                                       
Average Henry Hub natural gas spot price ($/thousand cubic feet (mcf))
  $ 4.37     $ 3.94     $ 8.89     $ .43       11 %   $ (4.95 )     (56 )%
Average West Texas intermediate crude oil spot price ($/barrel)
  $ 79.51     $ 61.99     $ 99.92     $ 17.52       28 %   $ (37.93 )     (38 )%
 
Beginning in the fourth quarter of 2008, there was a significant reduction in the demand for natural gas and oil that was caused, at least in part, by the significant deterioration of the global economic environment including the extreme volatility in the capital and credit markets. Weaker demand throughout 2009 resulted in sustained lower natural gas and oil prices, which led to a sharp decline in the demand for drilling and workover services. During 2010, these commodity prices strengthened in the latter half of the year and demand for drilling activity improved. Continued fluctuations in the demand for gas and oil, among other factors including supply, could contribute to continued price volatility which may continue to affect demand for our services and could materially affect our future financial results.
 
Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2010 totaled $4.2 billion, representing an increase of $679.9 million, or 19% as compared to the year ended December 31, 2009. Adjusted income derived from operating activities and net income (loss) attributable to Nabors for the year ended December 31, 2010 totaled $655.4 million and $94.7 million ($.33 per diluted share), respectively, representing increases of 55% and 211%, respectively, compared to the year ended December 31, 2009.
 
Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2009 totaled $3.5 billion, representing a decrease of $1.8 billion, or 34% as compared to the year ended December 31, 2008. Adjusted income derived from operating activities and net income (loss) attributable to Nabors for the year ended December 31, 2009 totaled $421.9 million and $(85.5) million ($(.30) per diluted share), respectively, representing decreases of 62% and 118%, respectively, compared to the year ended December 31, 2008.
 
During 2010, operating results improved as compared to 2009 primarily due to the incremental revenue and positive operating results from our Pressure Pumping operating segment and increased drilling activity in 2010 in our U.S. Lower 48 Land Drilling and Canada Well-servicing operations relating to increased drilling activity in oil and the liquids-oil shale plays. Our U.S. Well-servicing business also improved with continuing strong crude oil prices, which have led to increased activity. However, our operating results and activity levels continued to be negatively impacted in our U.S. Offshore operations in response to uncertainty in the regulatory environment; our Alaskan operations due to key customers’ spending constraints; and elsewhere with less activity in Saudi Arabia and Mexico, two of our key markets. There was also improvement in our operating results for 2010 because there were no full-cost ceiling adjustments recorded by our U.S. oil and gas joint venture.
 
Our U.S. Offshore operations were improving during the first half of 2010 until the Gulf of Mexico explosion and oil spill occurred mid-year, which resulted in temporary suspension of offshore drilling and further delays in our customers’ ability to obtain permits, which has limited the use of our assets. Specifically, operating results have been impacted because our customers have suspended most of their operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. Although the previously issued U.S. deepwater drilling moratorium has been lifted, it is uncertain whether our customers’ ability to obtain government permits will improve in the near term. Our Alaska operating segment has been negatively impacted because the largest operator in the area has curtailed and suspended drilling operations, creating a surplus of rigs in the market and causing price competition. We expect that these conditions will persist and continue to adversely impact our Alaska operating results through 2011. We expect our International results to remain flat in 2011 as the increase of land rig activity is expected to be essentially offset by contract renewals on our jack-up rigs at significantly lower average dayrates.


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During 2010, we recorded impairments and other charges of $260.9 million. We recognized goodwill and long-lived asset impairments of approximately $10.7 million and $27.4 million, respectively, to assets in our U.S. Offshore operating segment, primarily driven by current market conditions in the Gulf of Mexico. Additionally, we recognized long-lived asset impairments of $7.5 million to our aircraft and some drilling equipment in Canada and recorded impairments of $23.2 million relating to asset retirements across our U.S. Lower 48 Land, U.S. Well-servicing and U.S. Offshore Contract Drilling segments. Our Oil and Gas operating segment recorded impairments of $54.3 million relating to an oil and gas financing receivable and $137.8 million under application of the successful-efforts method of accounting for our wholly owned oil and gas-related assets.
 
During 2009 and 2008, our operating results were negatively impacted as a result of charges arising from oil and gas full-cost ceiling test writedowns and other impairments. Earnings (losses) from unconsolidated affiliates includes $(189.3) million and $(207.3) million, respectively, for the years ended December 31, 2009 and 2008, representing our proportionate share of a full-cost ceiling test writedown from our unconsolidated U.S. oil and gas joint venture which utilizes the full-cost method of accounting. During 2009, our joint venture used a 12-month average price in the ceiling test calculation as required by the revised SEC rules whereas during 2008, the ceiling test calculation used the single-day, year-end commodity price that, at December 31, 2008, was near its low point for that year. The full-cost ceiling test writedowns are included in our Oil and Gas operating segment results.
 
During 2009, impairments and other charges of $331.0 million included recognition of other-than-temporary impairments of $54.3 million relating to our available-for-sale securities, and impairments of $64.2 million to long-lived assets that were retired from our U.S. Offshore, Alaska, Canada and International contract drilling segments. We also recognized a goodwill impairment of $14.7 million relating to Nabors Blue Sky Ltd., one of our Canadian subsidiaries, which eliminated the remaining goodwill balance relating to remote aircraft operations in Canada. Additionally, we recorded impairment charges of $48.6 million to our wholly owned assets in our Oil and Gas operating segment under application of the successful-efforts method of accounting for some of our oil and gas-related assets and $149.1 million relating to an oil and gas financing receivable during the year ended December 31, 2009.
 
During 2008, impairments and other charges of $176.1 million included goodwill and intangible asset impairments totaling $154.6 million recorded by our Canada Well-servicing and Drilling operating segment and Nabors Blue Sky Ltd. We recognized these goodwill and intangible asset impairments to reduce the carrying value of these assets to their estimated fair value. We consider these writedowns necessary because of the duration of the industry downturn in Canada and the lack of certainty regarding eventual recovery. We also recorded impairment charges of $21.5 million to our wholly owned assets in our Oil and Gas operating segment for some of our oil and gas-related assets during the year ended December 31, 2008.
 
Our operating results for 2011 are still expected to increase from levels realized during 2010, despite a moderating outlook of lower commodity prices during 2011 and the related impact on drilling and well-servicing activity and dayrates. The major factors that support our expectations of an improved year are:
 
  •  An expected incremental increase from ancillary well-site services, primarily technical pumping services and down-hole surveying services, resulting from our acquisition in the third quarter of 2010, and
 
  •  The anticipated positive impact on our overall level of drilling and well-servicing activity and margins resulting from our new and upgraded rigs added to our fleet over the past five years, which we expect will enhance our competitive position as market conditions improve.


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The following tables set forth certain information with respect to our reportable segments and rig activity:
 
                                                         
    Year Ended December 31,     Increase/(Decrease)  
    2010     2009     2008     2010 to 2009     2009 to 2008  
    (In thousands, except percentages and rig activity)  
 
Reportable segments:
                                                       
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations: (1)
                                                       
Contract Drilling: (2)
                                                       
U.S. Lower 48 Land Drilling
  $ 1,294,853     $ 1,082,531     $ 1,878,441     $ 212,322       20 %   $ (795,910 )     (42 )%
U.S. Land Well-servicing
    444,665       412,243       758,510       32,422       8 %     (346,267 )     (46 )%
Pressure Pumping(3)
    321,295                   321,295       100 %            
U.S. Offshore
    123,761       157,305       252,529       (33,544 )     (21 )%     (95,224 )     (38 )%
Alaska
    179,218       204,407       184,243       (25,189 )     (12 )%     20,164       11 %
Canada
    389,229       298,653       502,695       90,576       30 %     (204,042 )     (41 )%
International
    1,093,608       1,265,097       1,372,168       (171,489 )     (14 )%     (107,071 )     (8 )%
                                                         
Subtotal Contract Drilling(4)
    3,846,629       3,420,236       4,948,586       426,393       12 %     (1,528,350 )     (31 )%
Oil and Gas (5)(6)
    40,611       (158,780 )     (118,533 )     199,391       126 %     (40,247 )     (34 )%
Other Operating Segments (7)(8)
    456,893       446,282       683,186       10,611       2 %     (236,904 )     (35 )%
Other reconciling items(9)
    (136,241 )     (179,752 )     (198,245 )     43,511       24 %     18,493       9 %
                                                         
Total
  $ 4,207,892     $ 3,527,986     $ 5,314,994     $ 679,906       19 %   $ (1,787,008 )     (34 )%
                                                         
Adjusted income (loss) derived from operating activities from continuing operations: (1)(10)
                                                       
Contract Drilling:
                                                       
U.S. Lower 48 Land Drilling
  $ 274,215     $ 294,679     $ 628,579     $ (20,464 )     (7 )%   $ (333,900 )     (53 )%
U.S. Land Well-servicing
    31,597       28,950       148,626       2,647       9 %     (119,676 )     (81 )%
Pressure Pumping(3)
    66,651                   66,651       100 %            
U.S. Offshore
    9,245       30,508       59,179       (21,263 )     (70 )%     (28,671 )     (48 )%
Alaska
    51,896       62,742       52,603       (10,846 )     (17 )%     10,139       19 %
Canada
    22,970       (7,019 )     61,040       29,989       427 %     (68,059 )     (111 )%
International
    254,744       365,566       407,675       (110,822 )     (30 )%     (42,109 )     (10 )%
                                                         
Subtotal Contract Drilling(4)
    711,318       775,426       1,357,702       (64,108 )     (8 )%     (582,276 )     (43 )%
Oil and Gas(5)(6)
    6,329       (190,798 )     (159,931 )     197,127       103 %     (30,867 )     (19 )%
Other Operating Segments (8)(9)
    43,179       34,120       68,572       9,059       27 %     (34,452 )     (50 )%
Other reconciling items(11)
    (105,393 )     (196,844 )     (167,831 )     91,451       46 %     (29,013 )     (17 )%
                                                         
Total
  $ 655,433     $ 421,904     $ 1,098,512     $ 233,529       55 %   $ (676,608 )     (62 %)
Interest expense
    (273,044 )     (266,039 )     (196,718 )     (7,005 )     (3 )%     (69,321 )     (35 )%
Investment income (loss)
    7,648       25,599       21,412       (17,951 )     (70 )%     4,187       20 %
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net
    (47,060 )     (12,559 )     (15,829 )     (34,501 )     (275 )%     3,270       21 %
Impairments and other charges(12)
    (260,931 )     (330,976 )     (176,123 )     70,045       21 %     (154,853 )     (88 )%
                                                         
Income (loss) from continuing operations before income taxes
    82,046       (162,071 )     731,254       244,117       151 %     (893,325 )     (122 )%
Income tax expense (benefit)
    (24,814 )     (133,803 )     209,660       108,989       81 %     (343,463 )     (164 )%
Subsidiary preferred stock dividend
    750                   750       100 %            
                                                         
Income (loss) from continuing operations, net of tax
    106,110       (28,268 )     521,594       134,378       475 %     (549,862 )     (105 )%
Income (loss) from discontinued operations, net of tax
    (11,330 )     (57,620 )     (41,930 )     46,290       80 %     (15,690 )     (37 )%
                                                         
Net income (loss)
    94,780       (85,888 )     479,664       180,668       210 %     (565,552 )     (118 )%
Less: Net (income) loss attributable to noncontrolling interest
    (85 )     342       (3,927 )     (427 )     (125 )%     4,269       109 %
                                                         
Net income (loss) attributable to Nabors
  $ 94,695     $ (85,546 )   $ 475,737     $ 180,241       211 %   $ (561,283 )     (118 )%
                                                         


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    Year Ended December 31,     Increase/(Decrease)  
    2010     2009     2008     2010 to 2009     2009 to 2008  
    (In thousands, except percentages and rig activity)  
 
Rig activity:
                                                       
Rig years: (13)
                                                       
U.S. Lower 48 Land Drilling
    174.5       149.4       247.9       25.1       17 %     (98.5 )     (40 )%
U.S. Offshore
    9.4       11.0       17.6       (1.6 )     (15 )%     (6.6 )     (38 )%
Alaska
    7.4       10.0       10.9       (2.6 )     (26 )%     (0.9 )     (8 )%
Canada
    29.8       19.7       35.5       10.1       51 %     (15.8 )     (45 )%
International(14)
    97.8       100.2       120.5       (2.4 )     (2 )%     (20.3 )     (17 )%
                                                         
Total rig years
    318.9       290.3       432.4       28.6       10 %     (142.1 )     (33 )%
                                                         
Rig hours: (15)
                                                       
U.S. Land Well-servicing
    643,813       590,878       1,090,511       52,935       9 %     (499,633 )     (46 )%
Canada Well-servicing
    172,589       143,824       248,032       28,765       20 %     (104,208 )     (42 )%
                                                         
Total rig hours
    816,402       734,702       1,338,543       81,700       11 %     (603,841 )     (45 )%
                                                         
 
 
(1) All information present the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia as discontinued operations.
 
(2) These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore.
 
(3) Includes operating results of the Superior Merger after September 10, 2010.
 
(4) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $6.9 million, $9.7 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
(5) Represents our oil and gas exploration, development and production operations. Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(189.3) million and $(207.3) million for the years ended December 31, 2009 and 2008, respectively.
 
(6) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $18.7 million, $(182.6) million and $(204.1) million for the years ended December 31, 2010, 2009 and 2008, respectively. Additional information is provided in Note 24 — Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. — Financial Statements and Supplementary Data.
 
(7) Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations.
 
(8) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $7.7 million, $17.5 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
(9) Represents the elimination of inter-segment transactions.
 
(10) Adjusted income (loss) derived from operating activities is computed by subtracting direct costs, general and administrative expenses, depreciation and amortization, and depletion expense from “Operating revenues” and then adding “Earnings (losses) from unconsolidated affiliates.” These amounts should not be used as a substitute for those amounts reported under GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income (loss) derived from operating activities, because it believes that these financial measures are an accurate reflection of our ongoing profitability. A reconciliation of this non-GAAP measure to income (loss) from continuing operations before income taxes, which is a GAAP measure, is provided within the above table.
 
(11) Represents the elimination of inter-segment transactions and unallocated corporate expenses.

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(12) Represents impairments and other charges recorded during the years ended December 31, 2010, 2009 and 2008, respectively.
 
(13) Excludes well-servicing rigs, which are measured in rig hours. Includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates. Rig years represent a measure of the number of equivalent rigs operating during a given period. For example, one rig operating 182.5 days during a 365-day period represents 0.5 rig years.
 
(14) International rig years include our equivalent percentage ownership of rigs owned by unconsolidated affiliates which totaled 2.2 years, 2.5 years and 3.5 years during the years ended December 31, 2010, 2009 and 2008, respectively.
 
(15) Rig hours represents the number of hours that our well-servicing rig fleet operated during the year.
 
Segment Results of Operations
 
Contract Drilling
 
Our Contract Drilling operating segments contain one or more of the following operations: drilling, workover and well-servicing and pressure pumping, on land and offshore.
 
U.S. Lower 48 Land Drilling.  The results of operations for this reportable segment are as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages and rig activity)
 
Operating revenues
  $ 1,294,853     $ 1,082,531     $ 1,878,441     $ 212,322       20 %   $ (795,910 )     (42 )%
Adjusted income derived from operating activities
  $ 274,215     $ 294,679     $ 628,579     $ (20,464 )     (7 )%   $ (333,900 )     (53 )%
Rig years
    174.5       149.4       247.9       25.1       17 %     (98.5 )     (40 )%
 
Operating revenues increased from 2009 to 2010 primarily due to higher average dayrates and utilization. The increase was partially offset by the decrease in early contract termination revenue. Operating revenues related to early contract termination during 2010 included $23.2 million as compared to $108.5 million in 2009.
 
Adjusted income derived from operating activities decreased from 2009 to 2010 due to an increase in operating costs associated with the increased drilling activity. Operating results continued to be negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.
 
Operating results decreased from 2008 to 2009 primarily due to a decline in drilling activity, driven by lower natural gas prices beginning in the fourth quarter of 2008 and diminished demand as customers released rigs and delayed drilling projects in response to the significant drop in natural gas prices and the tightening of the credit markets.
 
U.S. Land Well-servicing.  The results of operations for this reportable segment are as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages and rig activity)
 
Operating revenues
  $ 444,665     $ 412,243     $ 758,510     $ 32,422       8 %   $ (346,267 )     (46 )%
Adjusted income derived from operating activities
  $ 31,597     $ 28,950     $ 148,626     $ 2,647       9 %   $ (119,676 )     (81 )%
Rig hours
    643,813       590,878       1,090,511       52,935       9 %     (499,633 )     (46 )%
 
Operating results increased from 2009 to 2010 primarily due to an increase in rig utilization driven by higher oil prices. The increase in operating results also reflects lower general and administrative costs and depreciation expense.
 
Operating results decreased from 2008 to 2009 primarily due to lower rig utilization and price erosion, driven by lower customer demand for our services due to relatively lower oil prices caused by the


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U.S. economic recession and reduced end product demand. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.
 
Pressure Pumping.  The results of operations for this reportable segment were as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages and rig activity)
 
Operating revenues
  $ 321,295     $     $     $ 321,295       100 %   $        
Adjusted income derived from operating activities
  $ 66,651     $     $     $ 66,651       100 %   $        
 
Operating results reflecting our acquisition of Superior are presented above for the period September 10, 2010 through December 31, 2010. See Note 7 — Acquisitions and Divestitures in Part II, Item 8. — Financial Statements and Supplementary Data.
 
U.S. Offshore.  The results of operations for this reportable segment are as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages and rig activity)
 
Operating revenues
  $ 123,761     $ 157,305     $ 252,529     $ (33,544 )     (21 )%   $ (95,224 )     (38 )%
Adjusted income derived from operating activities
  $ 9,245     $ 30,508     $ 59,179     $ (21,263 )     (70 )%   $ (28,671 )     (48 )%
Rig years
    9.4       11.0       17.6       (1.6 )     (15 )%     (6.6 )     (38 )%
 
The decrease in operating results from 2009 to 2010 primarily resulted from receiving standby rates and lower utilization for the MODS® rigs, SuperSundownertm platform rigs and Sundowner® platform rigs. Drilling activities significantly declined as our customers suspended their operations in the Gulf of Mexico, largely as a result of their inability to procure government permits.
 
The decrease in operating results from 2008 to 2009 primarily resulted from lower average dayrates and utilization for the SuperSundownertm platform rigs, workover jack-up rigs, barge drilling and workover rigs, and Sundowner® platform rigs, partially offset by higher utilization of our MODS® rigs inclusive of a significant term contract for a MODS® rig deployed in January 2009.
 
Alaska.  The results of operations for this reportable segment are as follows:
 
                                                         
    Year Ended December 31,     Increase/(Decrease)  
    2010     2009     2008     2010 to 2009     2009 to 2008  
    (In thousands, except percentages and rig activity)  
 
Operating revenues and Earnings from unconsolidated affiliates
  $ 179,218     $ 204,407     $ 184,243     $ (25,189 )     (12 )%   $ 20,164       11 %
Adjusted income derived from operating activities
  $ 51,896     $ 62,742     $ 52,603     $ (10,846 )     (17 )%   $ 10,139       19 %
Rig years
    7.4       10.0       10.9       (2.6 )     (26 )%     (0.9 )     (8 %)
 
The decrease in operating results from 2009 to 2010 was primarily due to lower average dayrates and drilling activity. While drilling activity levels decreased significantly during 2010, operating results decreased only slightly due to an acceleration of deferred revenues from a significant terminating contract.
 
The increase in operating results from 2008 to 2009 was primarily due to increases in average dayrates and drilling activity. Although drilling activity levels decreased slightly during 2009, operating results reflect the higher average margins as a result of the addition of some high specification rig work. The increase during 2009 was partially offset by higher operating costs and increased depreciation expense as well as increased labor and repair and maintenance costs in 2009 as compared to 2008.


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Canada.  The results of operations for this reportable segment are as follows:
 
                                                                 
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008    
    (In thousands, except percentages and rig activity)
 
Operating revenues and Earnings from unconsolidated affiliates
  $ 389,229     $ 298,653     $ 502,695     $ 90,576       30 %   $ (204,042 )     (41 )%        
Adjusted income (loss) derived from operating activities
  $ 22,970     $ (7,019 )   $ 61,040     $ 29,989       427 %   $ (68,059 )     (111 )%        
Rig years — Drilling
    29.8       19.7       35.5       10.1       51 %     (15.8 )     (45 )%        
Rig hours — Well-servicing
    172,589       143,824       248,032       28,765       20 %     (104,208 )     (42 %)        
 
Operating results increased from 2009 to 2010 primarily as a result of an overall increase in drilling and well-servicing activity, which offset the decline in average drilling dayrates and well-servicing hourly rates. The increased drilling activity in Western Canada is the result of renewed interest in oil exploration supported by sustained improved oil prices. The well-servicing hourly rate decreased during 2010 as a result of customer discounts to maintain market share. Our operating results were also positively impacted during 2010 by cost reduction efforts, mainly in general and administrative expenses.
 
Operating results decreased from 2008 to 2009 primarily as a result of an overall decrease in drilling and well-servicing activity due to lower natural gas prices driving a significant decline of customer demand for drilling and well-servicing operations. Our operating results for 2009 were further negatively impacted by the economic uncertainty in the Canadian drilling market and financial market instability. The Canadian dollar began 2009 in a weak position versus the U.S. dollar, during a period of time when drilling and well-servicing activity was typically at its seasonal peak, which also had an overall negative impact on operating results. These decreases in operating results were partially offset by cost reductions in direct costs, general and administrative expenses and depreciation.
 
International.  The results of operations for this reportable segment are as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages and rig activity)
 
Operating revenues and Earnings from unconsolidated affiliates
  $ 1,093,608     $ 1,265,097     $ 1,372,168     $ (171,489 )     (14 )%   $ (107,071 )     (8 )%
Adjusted income derived from operating activities
  $ 254,744     $ 365,566     $ 407,675     $ (110,822 )     (30 )%   $ (42,109 )     (10 )%
Rig years
    97.8       100.2       120.5       (2.4 )     (2 )%     (20.3 )     (17 )%
 
The decrease in operating results from 2009 to 2010 resulted primarily from year-over-year decreases in average dayrates and lower utilization of rigs in Saudi Arabia, Mexico, Kazakhstan, and Oman, driven by changes in our customers’ drilling programs and longer lead times for formalization of project requirements in our key markets. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.
 
The decrease in operating results from 2008 to 2009 resulted primarily from year-over-year decreases in average dayrates and lower utilization of rigs in Mexico, Libya, Argentina and Colombia, driven by weakening customer demand for drilling services stemming from the drop in oil prices in the fourth quarter of 2008 which continued throughout 2009. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years. These decreases were partially offset by higher average dayrates from two jack-up rigs deployed in Saudi Arabia, increases in average dayrates for our new and incremental rigs added and deployed during 2008 and a start-up floating, drilling, production, storage and offloading vessel off the coast of the Republic of the Congo.


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Oil and Gas.  The results of operations for this reportable segment are as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
Operating revenues and Earnings (losses) from unconsolidated affiliates
  $ 40,611     $ (158,780 )   $ (118,533 )   $ 199,391       126 %   $ (40,247 )     (34 )%
Adjusted income (loss) derived from operating activities
  $ 6,329     $ (190,798 )   $ (159,931 )   $ 197,127       103 %   $ (30,867 )     (19 )%
 
Our operating results increased from 2009 to 2010 primarily because our unconsolidated U.S. oil and gas joint venture recorded a full-cost ceiling test writedown during 2009, of which our proportionate share totaled $189.3 million. Our proportionate share of the full-cost ceiling writedowns recorded by our other unconsolidated oil and gas joint ventures, SMVP and Remora, have been reclassified to discontinued operations. These writedowns resulted from the application of the full-cost method of accounting for costs related to oil and natural gas properties. The full-cost ceiling test limits the carrying value of the capitalized cost of the properties to the present value of future net revenues attributable to proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or market value of unproved properties. The full-cost ceiling test was evaluated using the 12-month average commodity price as required by the revised SEC rules. Operating results for our U.S. oil and gas joint venture, excluding the full-cost ceiling test writedown, improved from 2009 to 2010.
 
Our operating results decreased from 2008 to 2009 primarily as a result of the full-cost ceiling test writedown recorded during 2009 discussed above. Operating results further decreased from 2008 to 2009 due to declines in natural gas prices and production volumes. Additionally, operating results for 2008 included a $12.3 million gain recorded on the sale of leasehold interests.
 
Additional information is provided in Notes 21 — Discontinued Operations and 24 — Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. — Financial Statements and Supplementary Data.
 
Other Operating Segments
 
These operations include our drilling technology and top-drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations. The results of operations for these operating segments are as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
Operating revenues and Earnings from unconsolidated affiliates
  $ 456,893     $ 446,282     $ 683,186     $ 10,611       2 %   $ (236,904 )     (35 )%
Adjusted income derived from operating activities
  $ 43,179     $ 34,120     $ 68,572     $ 9,059       27 %   $ (34,452 )     (50 %)
 
The increase in operating results from 2009 to 2010 primarily resulted from higher demand in the United States and Canada drilling markets for rig instrumentation and data collection services from oil and gas exploration companies and higher third-party rental and rigwatch units, which generate higher margins, partially offset by a continued decline in customer demand for our construction and logistics services in Alaska.
 
The decreases in operating results from 2008 to 2009 primarily resulted from (i) lower demand in the U.S. and Canada drilling markets for rig instrumentation and data collection services from oil and gas exploration companies, (ii) decreases in customer demand for our construction and logistics services in Alaska and (iii) decreased capital equipment unit volumes and lower service and rental activity as a result of the slowdown in the oil and gas industry.


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Discontinued Operations
 
During 2010, we began actively marketing our oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia. These assets also include our 49.7% and 50.0% ownership interests in our investments of Remora and SMVP, respectively, which we account for using the equity method of accounting. All of these assets are included in our oil and gas operating segment. We determined that the plan of sale criteria in the ASC Topic relating to the Presentation of Financial Statements for Assets Sold or Held for Sale had been met during the third quarter of 2010. Accordingly, we reclassified these wholly owned oil and gas assets from our property, plant and equipment, net, as well as our investment balances for Remora and SMVP from investments in unconsolidated affiliates to assets held for sale in our consolidated balance sheet at September 30, 2010.
 
The operating results from these assets for all periods presented are retroactively presented and accounted for as discontinued operations in the accompanying audited consolidated statements of income (loss). Our condensed statements of income (loss) from discontinued operations for the years ended December 31, 2010, 2009 and 2008 were as follows:
 
                                                         
    Year Ended December 31,   Increase/(Decrease)    
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
Revenues
  $ 37,840     $ 8,937     $ 4,354     $ 28,903       323 %   $ 4,583       105 %
Earnings (losses) from unconsolidated affiliates(1)
  $ (10,628 )   $ (59,248 )   $ (37,286 )   $ 48,620       82 %   $ (21,962 )     (59 )%
Income (loss) from discontinued operations, net of tax
                                                       
Income (loss) from discontinued operations, net of tax
  $ (11,330 )   $ (57,620 )   $ (41,930 )   $ 46,290       80 %   $ (15,690 )     (37 )%
 
 
(1) Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million and $21.0 million, for the years ended December 31, 2009 and 2008, respectively.
 
OTHER FINANCIAL INFORMATION
 
General and administrative expenses
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
General and administrative expenses
  $ 346,661     $ 428,161     $ 479,194     $ (81,500 )     (19 )%   $ (51,033 )     (11 )%
General and administrative expenses as a percentage of operating revenues
    8.3 %     11.6 %     8.7 %     (3.3 )%     (28 )%     2.9 %     33 %
 
General and administrative expenses decreased from 2009 to 2010 and from 2008 to 2009 primarily as a result of significant decreases in wage-related expenses and other cost-reduction efforts across all business units. The decrease during 2009 was partially offset by share-based compensation expense, which included $72.1 million of compensation expense related to previously granted restricted stock and option awards held by Messrs. Isenberg and Petrello that was unrecognized as of April 1, 2009. The recognition of this expense resulted from provisions of their respective new employment agreements that effectively eliminated the risk of forfeiture of such awards. There is no remaining unrecognized expense related to their outstanding restricted stock and option awards. Excluding the share-based compensation expense related to the previous awards held by Messrs. Isenberg and Petrello, general and administrative expenses for 2009 and 2010 are substantially below 2008 levels, indicating that the cost-reduction efforts and actions across all business units beginning in late 2008 have had a favorable impact on our operating results.


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Depreciation and amortization, and depletion expense
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
Depreciation and amortization expense
  $ 764,253     $ 667,100     $ 614,367     $ 97,153       15 %   $ 52,733       9 %
Depletion expense
  $ 17,943     $ 9,417     $ 22,308     $ 8,526       91 %   $ (12,891 )     (58 )%
 
Depreciation and amortization expense.  Depreciation and amortization expense increased from 2009 to 2010 and from 2008 to 2009 primarily as a result of projects completed in recent years under our expanded capital expenditure program that commenced in early 2005.
 
Depletion expense.  Depletion expense increased from 2009 to 2010 as a result of increased units-of-production depletion. Depletion expense decreased from 2008 to 2009 primarily as a result of decreased natural gas production volumes during each year.
 
Interest expense
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
Interest expense
  $ 273,044     $ 266,039     $ 196,718     $ 7,005       3 %   $ 69,321       (35 %)
 
Interest expense increased from 2009 to 2010 as a result of the interest expense related to our September 2010 issuance of 5.0% senior notes due September 2020. The increase was partially offset by a reduction to interest expense resulting from our repurchases of approximately $1.2 billion par value of 0.94% senior exchangeable notes during 2009 and 2010.
 
Interest expense increased from 2008 to 2009 as a result of the interest expense related to our January 2009 issuance of 9.25% senior notes due January 2019. The increase was partially offset by a reduction to interest expense due to our repurchases of approximately $1.1 billion par value of 0.94% senior exchangeable notes during 2008 and 2009.
 
Investment income (loss)
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
Investment income (loss)
  $ 7,648     $ 25,599     $ 21,412     $ (17,951 )     (70 )%   $ 4,187       20 %
 
Investment income during 2010 was $7.6 million compared to $25.6 million during the prior year. Investment income in 2010 included interest and dividend income of $7.2 million from our cash, other short-term and long-term investments and $4.9 million from gains on sales of short-term and long-term investments, partially offset by net unrealized losses of $4.4 million from our trading securities.
 
Investment income during 2009 was $25.6 million compared to $21.4 million during 2008. Investment income in 2009 included net unrealized gains of $9.8 million from our trading securities and interest and dividend income of $15.9 million from our cash, other short-term and long-term investments.
 
Investment income during 2008 was $21.4 million and included net unrealized gains of $8.5 million from our trading securities and interest and dividend income of $40.5 million from our short-term and long-term investments, partially offset by losses of $27.4 million from our actively managed funds classified as long-term investments.


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Gains (losses) on sales and retirements of long-lived assets and other income (expense), net
 
                                                         
    Year Ended December 31,   Increase/(Decrease)
    2010   2009   2008   2010 to 2009   2009 to 2008
    (In thousands, except percentages)
 
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net
  $ (47,060 )   $ (12,559 )   $ (15,829 )   $ (34,501 )     (275 )%   $ 3,270       21 %
 
The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2010 represents a net loss of $47.1 million and includes: (i) foreign currency exchange losses of approximately $17.9 million, (ii) litigation expenses of $6.4 million, (iii) net losses on sales and retirements of long-lived assets of approximately $6.6 million, (iv) acquisition-related costs of $7.0 million and (v) losses of $7.0 million recognized on purchases of our 0.94% senior exchangeable notes due 2011.
 
The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2009 represents a net loss of $12.6 million and includes: (i) foreign currency exchange losses of approximately $8.4 million, (ii) litigation expenses of $11.5 million and (iii) net losses on sales and retirements of long-lived assets of approximately $5.9 million. These losses were partially offset by pre-tax gains of $11.5 million recognized on purchases of $964.8 million par value of our 0.94% senior exchangeable notes due 2011.
 
The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2008 represents a net loss of $15.8 million and includes: (i) losses on derivative instruments of approximately $14.6 million, including a $9.9 million loss on a three-month written put option and a $4.7 million loss on the fair value of our range-cap-and-floor derivative, (ii) losses on retirements on long-lived assets of approximately $13.2 million, inclusive of involuntary conversion losses on long-lived assets of approximately $12.0 million, net of insurance recoveries, related to damage sustained from Hurricanes Gustav and Ike during 2008 and (iii) litigation expenses of $3.5 million. These losses were partially offset by a $12.2 million pre-tax gain recognized on our purchase of $100 million par value of 0.94% senior exchangeable notes due 2011.
 
Impairments and Other Charges
 
                                                         
    Year Ended December 31,     Increase/(Decrease)  
    2010     2009     2008     2010 to 2009     2009 to 2008  
    (In thousands, except percentages)  
 
Impairment of oil and gas- related assets
  $ 192,179     $ 197,744     $ 21,537     $ (5,565 )     (3 )%   $ 176,207       818 %
Impairment of long-lived assets
    58,045       64,229             (6,184 )     (10 )%     64,229       100 %
Goodwill impairments
    10,707       14,689       150,008       (3,982 )     (27 )%     (135,319 )     (90 )%
Impairment of other intangible assets
                4,578                   (4,578 )     (100 )%
Other-than-temporary impairment on securities
          54,314             (54,314 )     (100 )%     54,314       100 %
                                                         
Total
  $ 260,931     $ 330,976     $ 176,123     $ (70,045 )     (21 )%   $ 154,853       88 %
                                                         
 
Impairments of Oil and Gas Assets
 
In 2010, we recognized impairments of $192.2 million related to our oil and gas assets. Of this total, $137.8 million represents writedowns to the carrying value of some acreage in the United States, which we do not have future plans to develop due to the sustained low natural gas prices, and certain exploratory wells in Colombia, which we have determined will be uneconomical to develop in the foreseeable future.


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The remaining $54.3 million relates to an impairment of a financing receivable as a result of the continued commodity price deterioration in the Barnett Shale area of north central Texas. We determined that this impairment was necessary using estimates and assumptions based on estimated cash flows for proved and probable reserves and current natural gas prices. We believe the estimates used provide a reasonable estimate of current fair value. We determined that this represented a Level 3 fair value measurement. As of December 31, 2010, the carrying value of this oil and gas financing receivable, which is included in long-term investments, has been reduced to $20.1 million. A further protraction or continued period of lower commodity prices could result in recognition of future impairment charges.
 
In 2009, we recorded impairments totaling $197.7 million to some of our wholly owned oil and gas assets. We recognized an impairment of $149.1 million to a financing receivable as a result of commodity price deterioration and the lower price environment last longer than expected. The prolonged period of lower prices significantly reduced demand for future gas production and development in the Barnett Shale area of north central Texas and influenced our decision not to expend capital to develop on some of the undeveloped acreage. The impairment, which represented a Level 3 fair value measurement, was determined using discounted cash flow models involving assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices. Additionally, our annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $48.6 million to writedown the carrying value of some acreage that we do not have future plans to develop.
 
In 2008, our annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $21.5 million primarily due to the significant decline in oil and natural gas prices at the end of 2008. Additional discussion of our policy pertaining to the calculation of our annual impairment tests is set forth below in “Oil and Gas Properties” and in Note 2 — Summary of Significant Accounting Policies in Part II, Item 8. — Financial Statements and Supplementary Data.
 
Impairments of Long-Lived Assets
 
In 2010, we recognized impairments of $58.0 million in multiple operating segments. These impairments included $23.2 million related to the retirement of certain rig components, comprised of engines, top-drive units, building modules and other equipment that has become obsolete or inoperable in each of these operating segments in our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing and U.S. Offshore Contract Drilling segment. The impairment charges were determined to be necessary as a result of the continued lower commodity price environment and its related impact on drilling and well-servicing activity and our dayrates. A prolonged period of legislative uncertainty in our U.S. Offshore operations, or continued period of lower natural gas and oil prices and its potential impact on our utilization and dayrates could result in the recognition of future impairment charges to additional assets if future cash flow estimates, based upon information then available to management, indicate that the carrying value of those assets may not be recoverable.
 
The remaining $34.8 million in impairment charges recorded during 2010 include $27.3 million related to the impairment of some jack-up rigs in our U.S. Offshore operating segment and $7.5 million to our aircraft and some drilling equipment in Nabors Blue Sky Ltd. These impairment charges stemmed from our annual impairment tests on long-lived assets, which determined that the sum of the estimated future cash flows, on an undiscounted basis, was less than the carrying amount of these assets. The estimated fair values of these assets were calculated using discounted cash flow models involving assumptions based on our utilization of the assets, revenues as well as direct costs, capital expenditures and working capital requirements. The impairment charge relating to our U.S. Offshore segment was deemed necessary due to the economic conditions for drilling in the Gulf of Mexico, as discussed below. The impairment charge relating to Nabors Blue Sky Ltd. was deemed necessary due to the continued duration of the downturn in the oil and gas industry in Canada, which has resulted in diminished demand for the remote access services provided by this subsidiary’s aircraft fleet.
 
In 2009, we recognized impairments of $64.2 million related to retirements of certain assets in our U.S. Offshore, Alaska, Canada and International Contract Drilling segments, which reduced their aggregate carrying value to their estimated aggregate salvage value. The retirements included inactive workover jack-up


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rigs in our U.S. Offshore and International operations, the structural frames of some incomplete coiled tubing rigs in our Canada operations and miscellaneous rig components in our Alaska operations. The impairment charges resulted from the continued deterioration and longer-than-expected downturn in the demand for oil and gas drilling activities.
 
Goodwill Impairments
 
In 2010, we recognized an impairment of approximately $10.7 million relating to our goodwill balance of our U.S. Offshore operating segment. The impairment charge stemmed from our annual impairment test on goodwill, which compared the estimated fair value of each of our reporting units to its carrying value. The estimated fair value of our U.S. Offshore segment was determined using discounted cash flow models involving assumptions based on our utilization of rigs and revenues as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. We determined that the fair value estimated for purposes of this test represented a Level 3 fair value measurement. The impairment charge was deemed necessary due to the uncertainty of utilization of some of our rigs as a result of changes in our customers’ plans for future drilling operations in the Gulf of Mexico. Many of our customers have suspended drilling operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. Although the U.S. deepwater drilling moratorium has been lifted, it is uncertain whether our customers’ ability to obtain government permits will improve in the near term. A significantly prolonged period of lower oil and natural gas prices or changes in laws and regulations could adversely affect the demand for and prices of our services, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our estimate of our future operating results. See Critical Accounting Policies below and Note 2 — Summary of Significant Accounting Policies (included under the caption “Goodwill”) in Part II, Item 8. — Financial Statements and Supplementary Data.
 
In 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd., one of our Canadian subsidiaries who provides access to remote drilling sites by helicopters and fixed-wing aircraft. The impairment charges resulted from our annual impairment tests on goodwill which compared the estimated fair value of each of our reporting units to its carrying value. The estimated fair value of these business units was determined using discounted cash flow models involving assumptions based on our utilization of rigs or aircraft, revenues and earnings from affiliates, as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. We determined that the fair value estimated for purposes of this test represented a Level 3 fair value measurement. The impairment charges were deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn led to reduced capital spending by some of our customers and diminished demand for our drilling services and for immediate access to remote drilling sites.
 
In 2008, we impaired the entire goodwill balance of $145.4 million of our Canada Well-servicing and Drilling operating segment and recorded an impairment of $4.6 million to Nabors Blue Sky Ltd. This impairment was also deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn led to reduced capital spending by some of our customers and diminished demand for our drilling services and for immediate access to remote drilling sites.
 
Other than Temporary Impairments on Debt and Equity Securities
 
In 2009, we recorded other-than-temporary impairments to our available-for-sale securities totaling $54.3 million. Of this, $35.6 million was related to an investment in a corporate bond that was downgraded to non-investment grade level by Standard and Poor’s and Moody’s Investors Service during the year. Our determination that the impairment was other-than-temporary was based on a variety of factors, including the length of time and extent to which the market value had been less than cost, the financial condition of the issuer of the security, and the credit ratings and recent reorganization of the issuer.
 
The remaining $18.7 million related to an equity security of a public company whose operations are driven in large measure by the price of oil and in which we invested approximately $46 million during the


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second and third quarters of 2008. During late 2008, demand for oil and gas began to diminish significantly as part of the general deterioration of the global economic environment, causing a broad decline in value of nearly all oil and gas-related equity securities. Because the trading price per share of this security remained below our cost basis for an extended period of time, we determined the investment was other than temporarily impaired and it was appropriate to write down its carrying value to its estimated fair value.
 
Income tax rate
 
                                                         
                Increase/(Decrease)
    Year Ended December 31,   2010 to
  2009 to
    2010   2009   2008   2009   2008
 
Effective income tax rate from continuing operations
    (30 )%     83 %     29 %     (113 )%     (136 )%     54 %     186 %
 
Our effective income tax rate for 2010 and 2009 reflects the disparity between losses in our U.S. operations (attributable primarily to impairments) and income in our other operations primarily in lower tax jurisdictions. Because the U.S. income tax rate is higher than that of other jurisdictions, the tax benefit from our U.S. losses was not proportionately reduced by the tax expense from our other operations. During 2010 and 2009, the result was a net tax benefit. In 2009, that benefit represented a significant percentage of our consolidated loss from continuing operations before income taxes. Because of the manner in which that number was derived, we do not believe it presents a meaningful basis for comparing our 2009 effective income tax rate to either the 2010 or 2008 effective income tax rate.
 
We are subject to income taxes in the United States and numerous other jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes. One of the most volatile factors in this determination is the relative proportion of our income or loss being recognized in high- versus low-tax jurisdictions. In the ordinary course of our business, there are many transactions and calculations for which the ultimate tax determination is uncertain. We are regularly audited by tax authorities. Although we believe our tax estimates are reasonable, the final outcome of tax audits and any related litigation could be materially different than what is reflected in our income tax provisions and accruals. The results of an audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows.
 
Various bills have been introduced in Congress that could reduce or eliminate the tax benefits associated with our reorganization as a Bermuda company. Legislation enacted by Congress in 2004 provides that a corporation that reorganized in a foreign jurisdiction on or after March 4, 2003 be treated as a domestic corporation for U.S. federal income tax purposes. Nabors’ reorganization was completed June 24, 2002. There have been and we expect that there may continue to be legislation proposed by Congress from time to time which, if enacted, could limit or eliminate the tax benefits associated with our reorganization.
 
Because we cannot predict whether legislation will ultimately be adopted, no assurance can be given that the tax benefits associated with our reorganization will ultimately accrue to the benefit of the Company and its shareholders. It is possible that future changes to the tax laws (including tax treaties) could impact our ability to realize the tax savings recorded to date as well as future tax savings resulting from our reorganization.
 
Liquidity and Capital Resources
 
Cash Flows
 
Our cash flows depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Sustained increases or decreases in the price of natural gas or oil could have a material impact on these activities, and could also materially affect our cash flows. Certain sources and uses of cash, such as the level of discretionary capital expenditures, purchases and sales of investments, issuances and repurchases of debt and of our common shares are within our control and are adjusted as necessary based on market conditions. The following is a discussion of our cash flows for the years ended December 31, 2010 and 2009.
 
Operating Activities.  Net cash provided by operating activities totaled $1.1 billion during 2010 compared to net cash provided by operating activities of $1.6 billion during 2009. Net cash provided by


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operating activities (“operating cash flows”) is our primary source of capital and liquidity. Factors affecting changes in operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as depreciation and amortization, depletion, impairments, share-based compensation, deferred income taxes and our proportionate share of earnings or losses from unconsolidated affiliates. Net income (loss) adjusted for non-cash components was approximately $1.3 billion and $1.1 billion for the years ended December 31, 2010 and 2009, respectively. Additionally, changes in working capital items such as collection of receivables can be a significant component of operating cash flows. Changes in working capital items used $202.4 million in cash flows for the year ended December 31, 2010 and provided $471.9 million in cash flows for the year ended December 31, 2009.
 
Investing Activities.  Net cash used for investing activities totaled $1.7 billion during 2010 compared to net cash used for investing activities of $1.2 billion during 2009. During 2010, we used cash of $680.2 million and $53.4 million, respectively, to acquire Superior (net of the cash acquired) and the assets of Energy Contractors. During 2010 and 2009, we used cash primarily for capital expenditures totaling $930.3 million and $1.1 billion, respectively, and investments in unconsolidated affiliates totaling $40.9 million and $125.1 million, respectively. During 2009, we derived cash from sales of investments, net of purchases, totaling $24.4 million.
 
Financing Activities.  Net cash provided by financing activities totaled $280.3 million during 2010 compared to net cash used for financing activities of $19.4 million during 2009. During 2010, cash was provided from the receipt of $682.3 million in proceeds, net of debt issuance costs, from the September 2010 issuance of 5.0% senior notes due 2020. During 2010, we used cash to purchase $273.9 million of our 0.94% senior exchangeable notes due 2011 and to repay $124.0 million of Superior’s revolving credit facility and second lien notes.
 
During 2009, cash was derived from the receipt of $1.1 billion in proceeds, net of debt issuance costs, from the January 2009 issuance of 9.25% senior notes due 2019, and cash totaling $862.6 million was used to purchase $964.8 million par value of 0.94% senior exchangeable notes due 2011 and $225.2 million was used to redeem the 4.875% senior notes. During 2010 and 2009, cash was provided by our receipt of proceeds totaling $8.2 million and $11.2 million, respectively, from the exercise by our employees of options to acquire our common shares.
 
Future Cash Requirements
 
As of December 31, 2010, we had long-term debt, including current maturities, of $4.4 billion and cash and investments of $841.5 million, including $40.3 million of long-term investments and other receivables. Long-term investments and other receivables include $32.9 million in oil and gas financing receivables.
 
As of December 31, 2010, the current portion of our long-term debt included $1.4 billion par value of Nabors Delaware’s 0.94% senior exchangeable notes that mature in May 2011. We continue to assess our ability to meet this obligation, along with our other operating and capital requirements and other potential opportunities. We expect to do so through a combination of cash on hand, future operating cash flows, possible dispositions of non-core assets, availability under our unsecured revolving credit facility and our ability to access the capital markets, if required. At December 31, 2010, we had $700 million available under a senior unsecured revolving credit facility; in January 2011, we added another lender to the facility raising the amount available to $750 million. On February 11, 2011, one of our subsidiaries established a credit facility, which we unconditionally guarantee, for approximately US$50 million. There are a number of factors that could negatively impact our plans, including our ability to access the financial markets at competitive rates if the financial markets are limited or restricted, a decline in oil and natural gas prices, a decline in demand for our services or market perceptions of us and our industry.


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The senior exchangeable notes would require us upon exchange to pay note holders cash up to the principal amount of the notes and our common shares for any amount by which the exchange value of the notes exceeds their principal amount. The notes can only be exchanged:
 
(i) if our share price exceeds $59.57 (approximately) 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
 
(ii) during the five business days immediately following any ten consecutive trading day period in which the per note trading price for each day of that period is less than 95% of the product of (a) the sale price of our common shares and (b) the then applicable exchange rate for the notes; or
 
(iii) upon the occurrence of specified corporate transactions.
 
On February 24, 2011, the closing market price for our common stock was $27.65 per share. If any of the foregoing conditions were met and the notes were exchanged at a price equal to 100% of their principal amount before maturity, 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. However, management believes that if the price of our shares exceeded $59.57 for the required period of time, note holders would be unlikely to exchange them as it would be more beneficial to sell the notes to other investors on the open market. Nevertheless, there can be no assurance that the holders would not exchange the notes.
 
We expect capital expenditures over the next 12 months to approximate $1.3-1.7 billion. We had outstanding purchase commitments of approximately $754.6 million at December 31, 2010, primarily for rig-related enhancements, construction and sustaining capital expenditures and other operating expenses. We can reduce the planned expenditures if necessary, or increase them if market conditions and new business opportunities warrant it.
 
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 issuing 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 below under Off-Balance Sheet Arrangements (Including Guarantees).
 
The following table summarizes our contractual cash obligations as of December 31, 2010:
 
                                         
    Payments Due by Period  
    Total     < 1 Year     1-3 Years     3-5 Years     Thereafter  
    (In thousands)  
 
Contractual cash obligations:
                                       
Long-term debt:(1)
                                       
Principal
  $ 4,478,455     $ 1,403,455(2 )   $ 275,000(3 )   $     $ 2,800,000(4 )
Interest
    1,720,577       220,434       412,942       398,076       689,125  
Operating leases(5)
    74,128       25,749       32,774       14,673       932  
Capital leases
    4,297       2,201       1,811       285          
Purchase commitments(6)
    754,605       603,960       77,145       73,500        
Employment contracts(5)
    28,319       11,965       16,035       319        
Pension funding obligations
    1,315       1,315                    
Transportation and Processing Contracts(7)
    400,037       29,564       120,344       128,252       121,877  
                                         
Total contractual cash obligations
  $ 7,461,733     $ 2,298,643     $ 936,051     $ 615,105     $ 3,611,934  
                                         


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The table above excludes liabilities for unrecognized tax benefits totaling $124.1 million as of December 31, 2010 because we are unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in Note 12 — Income Taxes in Part II, Item 8. — Financial Statements and Supplementary Data.
 
(1) See Note 11 — Debt in Part II, Item 8. — Financial Statements and Supplementary Data.
 
  (2)  Includes the remaining portion of Nabors Delaware’s 0.94% senior exchangeable notes due May 2011.
 
(3) Includes Nabors Delaware’s 5.375% senior notes due August 2012.
 
  (4)  Represents Nabors Delaware’s aggregate 6.15% senior notes due February 2018, 9.25% senior notes due January 2019 and 5.0% senior notes due September 2020.
 
  (5)  See Note 17 — Commitments and Contingencies in Part II, Item 8. — Financial Statements and Supplementary Data.
 
  (6)  Purchase commitments include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including fixed or minimum quantities to be purchased; fixed, minimum or variable pricing provisions; and the approximate timing of the transaction.
 
  (7)  We have contracts with a pipeline company to pay specified fees based on committed volumes for gas transport and processing, as calculated on a monthly basis. Due to low natural gas prices and our decision to delay drilling, our current available production flowing to pipelines and processing plants does not meet the daily committed volumes required under the contracts. The amounts set forth in the table above reflect the aggregate fees payable under these contracts.
 
We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, both in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
 
In July 2006 our Board of Directors authorized a share repurchase program under which we may repurchase up to $500 million of our common shares in the open market or in privately negotiated transactions. Through December 31, 2010, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2010, we had the capacity to repurchase up to an additional $35.5 million of our common shares under the July 2006 share repurchase program.
 
See Note 17 — Commitments and Contingencies in Part II, Item 8. — Financial Statements and Supplementary Data for discussion of commitments and contingencies relating to (i) new employment agreements, effective April 1, 2009, that could result in significant cash payments of $100 million and $50 million to Messrs. Isenberg and Petrello, respectively, by the Company if their employment is terminated in the event of death or disability or cash payments of $100 million to Mr. Isenberg and a cash payment of approximately $34 million to Mr. Petrello, respectively, by the Company if their employment is terminated without cause or in the event of a change in control and (ii) off-balance sheet arrangements (including guarantees).
 
Financial Condition and Sources of Liquidity
 
Our primary sources of liquidity are cash and cash equivalents, short-term and long-term investments and cash generated from operations. As of December 31, 2010, we had cash and investments of $841.5 million (including $40.3 million of long-term investments and other receivables, inclusive of $32.9 million in oil and gas financing receivables) and working capital of $458.6 million. Oil and gas financing receivables are classified as long-term investments. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment. This compares to cash and investments of $1.2 billion (including $100.9 million of long-term investments and other receivables, inclusive of $92.5 million in oil and gas financing receivables) and working capital of $1.6 billion as of December 31, 2009.


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Our gross funded debt to capital ratio was 0.42:1 as of December 31, 2010 and 0.41:1 as of December 31, 2009. Our net funded debt to capital ratio was 0.37:1 as of December 31, 2010 and 0.33:1 as of December 31, 2009.
 
The gross funded debt to capital ratio is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portion of long-term debt and (3) long-term debt. Capital is shareholders’ equity.
 
The net funded debt to capital ratio is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables. Both of these ratios are used to calculate a company’s leverage in relation to its capital. Neither ratio measures operating performance or liquidity as defined by GAAP and, therefore, may not be comparable to similarly titled measures presented by other companies.
 
Our interest coverage ratio was 7.0:1 as of December 31, 2010 and 6.3:1 as of December 31, 2009. The interest coverage ratio is a trailing 12-month quotient of the sum of income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, subsidiary preferred stock dividends, depreciation and amortization, depletion expense, impairments and other charges, income tax expense (benefit) and our proportionate share of writedowns from our unconsolidated oil and gas joint ventures less investment income (loss) divided by cash interest expense plus subsidiary preferred stock dividends. This ratio is a method for calculating the amount of operating cash flows available to cover cash interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
 
During the third quarter of 2010, we and Nabors Delaware entered into a credit agreement under which the lenders committed to provide up to $700 million under an unsecured revolving credit facility (the “Revolving Credit Facility”) or the (“Facility”). The Facility also provides Nabors Delaware the option to add other lenders and increase the aggregate principal amount of commitments to $850 million by adding new lenders to the Facility or by asking existing lenders under the Facility to increase their commitments (in each case with the consent of the new lenders or the increasing lenders). In January 2011, Nabors Delaware added a new lender to the Facility and increased the total commitments under the Facility to $750 million. We fully and unconditionally guarantee the obligations under the Revolving Credit Facility, which matures in four years.
 
Borrowings under the Revolving Credit Facility bear interest, at Nabors Delaware’s option, at either (x) the “Base Rate” (as defined below) plus the applicable interest margin, calculated on the basis of the actual number of days elapsed in a year of 365 days and payable quarterly in arrears or (y) interest periods of one, two, three or six months at an annual rate equal to the LIBOR for the corresponding deposits of U.S. dollars, plus the applicable interest margin, payable on the last days of the relevant interest periods (but in any event at least every three months). The “Base Rate” is defined, for any day, as a fluctuating rate per annum equal to the highest of (i) the Federal Funds Rate, as published by the Federal Reserve Bank of New York, plus 1/2 of 1%, (ii) the prime commercial lending rate of UBS AG, as established from time to time at its Stamford Branch and (iii) LIBOR for an interest period of one month beginning on such day plus 1%.
 
On September 10, 2010, we completed the Superior Merger, pursuant to which we acquired all of the issued and outstanding shares of Superior’s common stock, at a price per share equal to $22.12 for a cash purchase price of approximately $681.3 million. We paid this amount using cash on hand and proceeds from the Revolving Credit Facility. Nabors Delaware repaid the borrowing under the Revolving Credit Facility using cash on hand and proceeds from the senior notes issued on September 14, 2010, as discussed below.
 
On September 14, 2010, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 5.0% senior notes due 2020, which are unsecured and are fully and unconditionally guaranteed by us. The senior notes have registration rights and will mature on September 15, 2020. Nabors Delaware used a portion of the proceeds to repay the borrowing of $600 million under the Revolving Credit Facility incurred to fund the acquisition of Superior. We and Nabors Delaware are using the remaining proceeds for general corporate purposes.


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On January 20, 2011, in accordance with the registration rights agreement entered into in connection with the issuance of the 5.0% senior notes, Nabors Delaware commenced an exchange offer for the notes pursuant to a registration statement on Form S-4, which was declared effective by the SEC on January 19, 2011. The exchange offer expired on February 23, 2011 and closed on February 28, 2011.
 
On December 31, 2010, we purchased the business of Energy Contractors for a total cash purchase price of $53.4 million. We paid this amount using cash on hand.
 
We had five letter-of-credit facilities with various banks as of December 31, 2010. Availability under our letter-of-credit facilities as of December 31, 2010 was as follows:
 
         
    (In thousands)  
 
Credit available
  $ 270,263  
Letters of credit outstanding, inclusive of financial and performance guarantees
    (70,605 )
         
Remaining availability
  $ 199,658  
         
 
Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by Fitch Ratings, Moody’s Investors Service and Standard & Poor’s and our historical ability to access those markets as needed. While there can be no assurances that we will be able to access these markets in the future, we believe that we will be able to access capital markets or otherwise obtain financing in order to satisfy any payment obligation that might arise upon exchange or purchase of our notes and that any cash payment due, in addition to our other cash obligations, would not ultimately have a material adverse impact on our liquidity or financial position. A credit downgrade may impact our ability to access credit markets.
 
Our current cash and investments, projected cash flows from operations, possible dispositions of non-core assets and our Facility are expected to adequately finance our purchase commitments, our scheduled debt service requirements, and all other expected cash requirements for the next twelve months.
 
See our discussion of the impact of changes in market conditions on our derivative financial instruments under Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
 
Off-Balance Sheet Arrangements (Including Guarantees)
 
We are a party to some 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 under which we provide financial or performance assurance to third parties. Certain of these agreements serve as guarantees, including standby letters of credit issued on behalf of insurance carriers in conjunction with our workers’ compensation insurance program and other financial surety instruments such as bonds. In addition, we have provided indemnifications, which serve as guarantees, to some third parties. These guarantees include indemnification provided by Nabors to our share transfer agent and our insurance carriers. We are not able to estimate the potential future maximum payments that might be due under our indemnification guarantees.
 
Management believes the likelihood that we would be required to perform or otherwise incur any material losses associated with any of these guarantees is remote. The following table summarizes the total maximum amount of financial guarantees issued by Nabors:
 
                                         
    Maximum Amount
    2011   2012   2013   Thereafter   Total
    (In thousands)
 
Financial standby letters of credit and other financial surety instruments
  $ 83,010     $ 525     $ 12,158     $     $ 95,693  


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Other Matters
 
Risk Management
 
In February 2010, our Board of Directors established a Risk Oversight Committee, which is responsible for
 
  •  monitoring management’s identification and evaluation of major strategic, operational, regulatory, information and external risks inherent in our business,
 
  •  reviewing the integrity of our systems of operational controls regarding legal and regulatory compliance, and
 
  •  reviewing our processes for managing and mitigating operational risk.
 
As discussed in Item 1A. Risk Factors, hazards inhere in the drilling, well-servicing and workover industries, including blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, 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. Our operations are also subject to risks arising out of war, civil disturbances or other political events. We seek to mitigate these risks by (i) avoiding them to the degree possible through sound operational and safety practices, (ii) contractual risk allocation and (iii) insurance.
 
We employ a top-down focus on safety as one of our main priorities. From our Chairman and Chief Executive Officer, to the Board’s Technical & Safety Committee, through all levels of operations, a shared focus on safety is reflected in both our historical and ongoing safety performance. Although we strive to implement sound safety and security practices in every aspect of our operations, incidents still occur.
 
Drilling contracts typically apportion the risks of loss between a drilling contractor and the operator, and we seek to obtain indemnification from our customers by contract for some of these risks. Under the standard industry drilling contract, each party bears responsibility for its own people and property, and other commonly accepted significant risks are allocated as follows:
 
  •  risk of damage to the underground reservoir is allocated to the operator;
 
  •  loss of or damage to the hole is allocated to the operator, although the contractor may take responsibility for redrilling the hole at some negotiated discount if the loss is due to the contractor’s negligence or willful misconduct;
 
  •  pollution is allocated to the contractor if it is above the surface of the ground or water and emanates from the contractor’s equipment, with the risk of all other pollution allocated to the operator;
 
  •  the costs associated with bringing a wild well under control are allocated to the operator; and
 
  •  where deemed necessary, some measure of political risk is allocated to the operator.
 
Although we strive to achieve this risk structure in our customer contracts, the actual risk structure may vary considerably from contract to contract, and there can be no assurance that we will be able to assign our risk for catastrophic or other events. Many operators seek to reduce their exposure for major risks in a number of ways, usually by shifting the risk to the contractor when its willful misconduct, gross negligence or even ordinary negligence leads to the damage at issue. We resist the imposition of such liabilities and attempt to negotiate monetary caps when we are unable to assign these risks altogether. Nevertheless, we sometimes accept liability for major risks when we determine from an overall risk-reward analysis, considering both risk inherent in the particular work and available insurance coverage, that such risks are within our risk tolerance.
 
Finally, to the extent that we are unable to transfer risks to our customers through contractual indemnities or our customers fail to honor their contractual responsibilities, we seek to limit our exposure through


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insurance. We maintain coverage for personal injury and property damage, business interruption, political and war risk, contractual liabilities, sudden and accidental pollution, well-control costs and other potential liabilities. We believe that we carry sufficient insurance coverage and limits to protect us against our exposure to major risks. However, there is no assurance that such insurance will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention.
 
Recent Legislation and Actions
 
In February 2009, Congress enacted the American Recovery and Reinvestment Act of 2009 (the “Stimulus Act”). The Stimulus Act is intended to provide a stimulus to the U.S. economy, including relief to companies related to income on debt repurchases and exchanges at a discount, expansion of unemployment benefits to former employees and other social welfare provisions. The Stimulus Act has not had a significant impact on our consolidated financial statements.
 
In March 2010, the EPA announced that it would study the potential adverse impact that hydraulic fracturing may have on water quality and public health. On September 14, 2010, the EPA sent letters to nine companies that perform fracturing services in the United States, including Superior. The letter requests information regarding the chemical composition of fluids used, information about the impacts of the chemicals on human health and the environment, standard operating procedures at fracturing sites and a list of sites where the companies have carried out the process. The EPA has indicated that it plans to perform more detailed analyses based on the information received and would seek to compel submission of the information if necessary. Nabors is and intends to continue providing requested information and cooperating with the EPA’s investigation. Legislation has also been introduced in the U.S. Congress and some states that would require the disclosure of chemicals used in the fracturing process. If enacted, the legislation could require fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping requirements and meet plugging and abandonment requirements. Any new laws regulating fracturing activities could cause operational delays or increased costs in exploration and production, which could adversely affect the demand for fracturing services. We cannot currently predict what the findings of the investigation will be, what regulatory changes might be implemented, or what the ultimate impact may be on the results of our Pressure Pumping operating segment.
 
Recent Accounting Pronouncements
 
In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revises some of the oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act and the Exchange Act, as well as Industry Guide 2. Effective December 31, 2009, the FASB issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. Additionally, this new accounting standard requires that entities use 12-month average natural gas and oil prices when calculating the quantities of proved reserves and performing the full-cost ceiling test calculation. The new standard also clarified that an entity’s equity-method investments must be considered in determining whether it has significant oil and gas activities. The disclosure requirements are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after January 1, 2010. The FASB provided a one-year deferral of the disclosure requirements if an entity became subject to the requirements because of a change to the definition of significant oil and gas activities. When operating results from our wholly owned oil and gas activities are considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we have significant oil and gas activities under the new definition. Our oil and gas disclosures are provided in Note 24 — Supplemental Information on Oil and Gas Exploration and Production Activities in Part II Item 8. — Financial Statements and Supplementary Data.
 
Effective January 1, 2010, we adopted the revised provisions relating to consolidation of variable interest entities within the Consolidations Topic of the ASC. The revised provisions replaced the quantitative approach to identify a variable interest entity with a qualitative approach that focuses on an entity’s control and ability


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to direct the variable interest entity’s activities. The application of these provisions did not have a material impact on our consolidated financial statements.
 
The FASB issued new guidance relating to revenue recognition for contractual arrangements with multiple revenue-generating activities. The ASC Topic for revenue recognition includes identification of a unit of accounting and how arrangement consideration should be allocated to separate the units of accounting, when applicable. The new guidance, including expanded disclosures, will apply to us for contracts entered into after June 15, 2010. We are evaluating the impact this guidance may have on future contracts. Historically, we have not entered into contractual agreements with multiple revenue-generating activities.
 
Related-Party Transactions
 
Nabors and its Chairman and Chief Executive Officer, its Deputy Chairman, President and Chief Operating Officer, and certain other key employees entered into split-dollar life insurance agreements, pursuant to which we paid a portion of the premiums under life insurance policies with respect to these individuals and, in some instances, members of their families. These agreements provide that we are reimbursed the premium payments upon the occurrence of specified events, including the death of an insured individual. Any recovery of premiums paid by Nabors could be limited to the cash surrender value of the policies under certain circumstances. As such, the values of these policies are recorded at their respective cash surrender values in our consolidated balance sheets. We have made premium payments to date totaling $11.7 million related to these policies. The cash surrender value of these policies of approximately $9.5 million and $9.3 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2010 and 2009, 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 could be deemed to be prohibited loans by us to these individuals. Consequently, we have paid no premiums related to our agreements with these individuals since the adoption of the Sarbanes-Oxley Act.
 
In the ordinary course of business, we enter into various rig leases, rig transportation and related oilfield services agreements with our unconsolidated affiliates at market prices. Revenues from business transactions with these affiliated entities totaled $271.6 million, $327.3 million and $285.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. Expenses from business transactions with these affiliated entities totaled $3.4 million, $9.8 million and $9.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. Additionally, we had accounts receivable from these affiliated entities of $97.8 million and $104.2 million as of December 31, 2010 and 2009, respectively. We had accounts payable to these affiliated entities of $12.7 million and $14.8 million as of December 31, 2010 and 2009, respectively, and long-term payables with these affiliated entities of $.8 million as of each of December 31, 2010 and 2009, respectively, which is included in other long-term liabilities.
 
In addition to the equity investment in our unconsolidated U.S. oil and gas joint venture, in April 2010 we purchased $20.0 million face value of NFR Energy LLC’s 9.75% senior notes. These notes mature in 2017 with interest payable semi-annually on February 15 and August 15. During 2010, we recognized $1.4 million in interest income from these notes.
 
We own an interest in Shona Energy Company, LLC (“Shona”), a company of which Mr. Payne, an independent member of our Board of Directors, is the Chairman and Chief Executive Officer. During the fourth quarter of 2008, we purchased 1.8 million common shares of Shona for $.9 million. During the first quarter of 2010, we purchased shares of Shona’s preferred stock and warrants to purchase additional common shares for $.9 million. We currently hold a minority interest of approximately 10% of the issued and outstanding shares of Shona.
 
Critical Accounting Estimates
 
The preparation of our financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and


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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 our estimates. The following is a discussion of our critical accounting estimates. Management considers an accounting estimate to be critical if:
 
  •  it requires assumptions to be made that were uncertain at the time the estimate was made; and
 
  •  changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated financial position or results of operations.
 
For a summary of all of our significant accounting policies, see Note 2 — Summary of Significant Accounting Policies in Part II, Item 8. — Financial Statements and Supplementary Data.
 
Financial Instruments.  As defined in the ASC, fair value is the price that would be received upon a sale of an asset or paid upon a transfer of a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market-corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best information available. Accordingly, we employ valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The use of unobservable inputs is intended to allow for fair value determinations in situations where there is little, if any, market activity for the asset or liability at the measurement date. We are able to classify fair value balances utilizing a fair-value hierarchy based on the observability of those inputs. Under the fair-value hierarchy
 
  •  Level 1 measurements include unadjusted quoted market prices for identical assets or liabilities in an active market;
 
  •  Level 2 measurements include quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and
 
  •  Level 3 measurements include those that are unobservable and of a highly subjective measure.
 
Depreciation of Property, Plant and Equipment.  The drilling, workover and well-servicing and pressure pumping industries are very capital intensive. Property, plant and equipment represented 67% of our total assets as of December 31, 2010, and depreciation constituted 19% of our total costs and other deductions for the year ended December 31, 2010.
 
Depreciation for our primary operating assets, drilling and workover rigs, is calculated based on the units-of-production method. For each day a rig is operating, we depreciate it 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. For each day a rig asset is not operating, it is depreciated over an assumed depreciable life of 20 years, with the exception of our jack-up rigs, where a 30-year depreciable life is typically used, after provision for salvage value.
 
Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, aircraft equipment, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings — 10 to 30 years; well-servicing rigs — 3 to 15 years; marine transportation and supply vessels — 10 to 25 years; aircraft equipment — 5 to 20 years; oilfield hauling and mobile equipment and other machinery and equipment — 3 to 10 years).
 
These depreciation periods and the salvage values of our property, plant and equipment were determined through an analysis of the useful lives of our assets and based on our experience with the salvage values of these assets. Periodically, we review our depreciation periods and salvage values for reasonableness given


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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 estimates do not continue to be appropriate. Accordingly, for the years ended December 31, 2010, 2009 and 2008, 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 and pressure pumping industry is very capital intensive. We review our assets for impairment when events or changes in circumstances indicate that the carrying amounts of property, plant and equipment may not be recoverable. An impairment loss is recorded in the period in which it is determined that the sum of estimated future cash flows, on an undiscounted basis, is less than the carrying amount of the long-lived asset. 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 assets. These long-term forecasts are uncertain because 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 result in future impairments. 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 (loss), 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, 2010, 2009 and 2008, 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. A significantly prolonged period of lower oil and natural gas prices could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges.
 
Impairment of Goodwill and Intangible Assets.  Goodwill represented 4.2% of our total assets as of December 31, 2010. We review goodwill and intangible assets with indefinite lives for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount of such goodwill and intangible assets exceed their fair value. During the second quarter of 2010, we performed our impairment tests of goodwill and intangible assets for all of our reporting units within our operating segments. These reporting units consist of our contract drilling segments: U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, U.S. Offshore, Alaska, Canada and International; our oil and gas segment; and our other operating segments: Canrig Drilling Technology Ltd., Ryan Energy Technologies and Nabors Blue Sky Ltd. The impairment test involves comparing the estimated fair value of the reporting unit to its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, a second step is required to measure the goodwill impairment loss. This second step compares the implied fair value of the reporting unit’s goodwill to the carrying amount of that goodwill. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess. Our impairment test results required the second step measurement for one reporting unit during each of 2010 and 2009.
 
The fair values calculated in these impairment tests are determined using discounted cash flow models involving assumptions based on our utilization of rigs or aircraft, revenues and earnings from affiliates, as well


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as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. Our discounted cash flow projections for each reporting unit were based on financial forecasts. The future cash flows were discounted to present value using discount rates that are determined to be appropriate for each reporting unit. Terminal values for each reporting unit were calculated using a Gordon Growth methodology with a long-term growth rate of 3%. We believe the fair value estimated for purposes of these tests represent a Level 3 fair value measurement.
 
During 2010, 2009 and 2008, we recognized goodwill impairments of approximately $10.7 million, $14.7 million and $150.0 million, respectively. During 2008, we impaired the entire goodwill balance of $145.4 million of our Canada Well-servicing and Drilling operating segment and recorded an impairment of $4.6 million to Nabors Blue Sky Ltd., one of our Canadian subsidiaries reported in our Other Operating segments. During 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd. The impairment charges were deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn has led to reduced capital spending by our customers and diminished demand for our drilling services and for immediate access to remote drilling sites. The impairment charge during 2010 was recorded in our U.S. Offshore operating segment and was deemed necessary due to the uncertainty of utilization of some of our rigs as a result of changes in our customers’ plans for future drilling operations in the Gulf of Mexico. Many of our customers have suspended drilling operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. A significantly prolonged period of lower oil and natural gas prices or changes in laws and regulations could continue to adversely affect the demand for and prices of our services, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our estimate of our future operating results.
 
Oil and Gas Properties.  We follow the successful-efforts method of accounting for our consolidated subsidiaries’ oil and gas activities. Under the successful-efforts method, lease acquisition costs and all development costs are capitalized. Our provision for depletion is based on these capitalized costs and is determined on a property-by-property basis using the units-of-production method. Proved property acquisition costs are amortized over total proved reserves. Costs of wells and related equipment and facilities are amortized over the life of proved developed reserves. Estimated fair value of proved and unproved properties includes the estimated present value of all reasonably expected future production, prices and costs. Proved oil and gas properties are reviewed when circumstances suggest the need for such a review and, are written down to their estimated fair value, if required. Unproved properties are reviewed to determine if there has been impairment of the carrying value and when circumstances suggest an impairment has occurred, are written down to their estimated fair value in that period. The estimated fair value of our proved reserves generally declines when there is a significant and sustained decline in oil and natural gas prices. During 2010, 2009 and 2008, our impairment tests on our wholly owned oil and gas assets of our Oil and Gas operating segment resulted in impairment charges of $137.8 million, $48.6 million and $21.5 million, respectively. As discussed above in Recent Accounting Pronouncements, we adopted new guidance relating to the manner in which our oil and gas reserves are estimated as of December 31, 2009.
 
Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. Other exploratory costs are expensed as incurred.
 
Our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, utilize the full-cost method of accounting for costs related to oil and natural gas properties. Under this method, all such costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or market value of unproved properties. As discussed above in Recent Accounting Pronouncements and in relation to the full-cost ceiling test, our unconsolidated oil and gas joint ventures


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changed the manner in which their oil and gas reserves are estimated and the manner in which they calculate the ceiling limit on capitalized oil and gas costs as of December 31, 2009. Under the new guidance, future revenues for purposes of the ceiling test are valued using a 12-month average price, adjusted for the impact of derivatives accounted for as cash flow hedges as prescribed by the SEC rules. No full-cost ceiling test writedowns were recorded by our unconsolidated oil and gas joint ventures during 2010. During 2009, our proportionate share of those ventures’ full-cost ceiling test writedowns was $237.1 million.
 
During 2008, our unconsolidated oil and gas joint ventures evaluated the full-cost ceiling using then-current prices for oil and natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges. As a result, our proportionate share of those ventures’ full-cost ceiling test writedowns was $228.3 million.
 
A significantly prolonged period of lower oil and natural gas prices or reserve quantities could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges due to the potential impact on our estimate of our future operating results.
 
Oil and Gas Reserves.  Evaluations of oil and gas reserves are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment. Oil and gas reserves include both proved and unproved reserves. Consistent with the definitions provided by the SEC, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, known reservoirs, and under existing economic conditions. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.
 
Estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process involving rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. Although we are reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.
 
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 the Income Taxes Topic of the ASC, the provision for income taxes is the sum of income taxes both currently payable and deferred. Currently payable taxes represent the liability related to our income tax return for the current year while the net deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported on our consolidated balance sheets. The tax effects of unrealized gains and losses on investments and derivative financial instruments are recorded through accumulated other comprehensive income (loss) within equity. The changes in deferred tax assets or liabilities are determined based upon changes in differences between the basis of assets and liabilities for financial reporting purposes and the basis of assets and liabilities for tax purposes as measured by the enacted tax rates that management estimates will be in effect when these differences reverse. Management must make certain assumptions regarding whether tax differences are permanent or temporary and must estimate the timing of their reversal, and whether taxable operating income in future periods will be sufficient to fully recognize any gross deferred tax assets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, management has considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These judgments and estimates are made for each tax jurisdiction in which we operate as the calculation of deferred taxes is completed at that level. Further, under U.S. federal tax law, the amount and availability of loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests applicable to Nabors and our subsidiaries. The utilization of such carryforwards could be limited or effectively lost upon certain changes in ownership. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance


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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 that 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. See Part I, Item 1A. — Risk Factors — We may have additional tax liabilities and Note 12 — Income Taxes in Part II, Item 8. — Financial Statements and Supplementary Data for additional discussion.
 
We are subject to income taxes in both the United States and numerous other 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 audited 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 reflected in historical income tax provisions and accruals. An audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows in the period or periods challenged. However, certain events could occur that would materially affect management’s estimates and assumptions regarding the deferred portion of our income tax provision, including estimates of future tax rates applicable to the reversal of tax differences, the classification of timing differences as temporary or permanent, reserves recorded for uncertain tax positions and any valuation allowance recorded as a reduction to our deferred tax assets. Management’s assumptions related to the preparation of our income tax provision have historically proved to be reasonable in light of the ultimate amount of tax liability due in all taxing jurisdictions.
 
For the year ended December 31, 2010, our provision for income taxes from continuing operations was $(24.8) million, consisting of $(83.8) million of current tax benefit and $59.0 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 and could potentially change the effective tax rate. A 1% change in the effective tax rate from (30.2%) to (29.2%) would increase the current year income tax provision by approximately $.8 million.
 
Self-Insurance Reserves.  Our operations are subject to many hazards inherent in the drilling, workover and well-servicing and pressure pumping industries, including blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, 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 and natural resources damage and damage to the property of others. Our offshore operations are also subject to the hazards of marine operations including capsizing, grounding, collision and other damage from hurricanes and heavy weather or sea conditions and unsound ocean bottom conditions. Our operations are subject to risks of war, civil disturbances or other political events.
 
Accidents may occur, we may be unable to obtain desired contractual indemnities, and our insurance may prove inadequate in certain cases. There is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention.
 
Based on the risks discussed above, it is necessary for us to estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Reserves related to self-insurance are based on the facts and circumstances specific to the claims and our past experience with similar claims. The actual outcome of self-insured claims could differ significantly from estimated amounts. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions for workers’ compensation, employers’ liability, general liability and automobile liability claims. These accruals are based on certain assumptions developed utilizing historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and


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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.
 
Because the determination of our liability for self-insured claims is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, and because such liabilities could be material in nature, management believes that accounting estimates related to self-insurance reserves are critical.
 
During 2010, 2009 and 2008, no significant changes were made to the methodology utilized to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2010 reserves for insurance were adjusted (increased or decreased) by 10%, total costs and other deductions would change by $14.6 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 5 — Fair Value Measurements in Part II, Item 8. — Financial Statements and Supplementary Data. 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 using 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 (loss). 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 is 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. During 2010, 2009 and 2008, no significant changes were made to the methodology utilized to value assets acquired or liabilities assumed. Our estimates of the fair values of assets acquired and liabilities assumed have proved to be reliable in the past.
 
Given the nature of the evaluation of the fair value of assets acquired and liabilities assumed and the application to specific assets and liabilities, it is not possible to reasonably quantify the impact of changes in these assumptions.
 
Share-Based Compensation.  We have historically compensated our executives and employees, in part, with stock options and restricted stock. Based on the requirements of the Stock Compensation Topic of the ASC, we accounted for stock option and restricted stock awards in 2008, 2009 and 2010 using a fair-value based method, resulting in compensation expense for stock-based awards being recorded in our consolidated statements of income (loss). 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 required in estimating the amount of stock-based awards that are expected to be forfeited. Because 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, management believes that accounting estimates related to the valuation of stock-based awards 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. During 2010, 2009 and 2008, no significant changes were made to the methodology utilized to determine the assumptions used in these calculations.


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ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. This risk arises primarily as a result of potential changes in the fair market value of financial instruments due to 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 and foreign currency devaluation risk. The most significant exposures arise in connection with our operations in Venezuela and 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, 2010 would result in a $12.2 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, short-term and long-term investments, oil and gas financing receivables, 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 short-term and long-term investments are managed within established guidelines which limit the amounts that may be invested with any one issuer and provide guidance as to issuer credit quality. We believe that the credit risk in our cash and investment portfolio is minimized as a result of the mix of our investments. In addition, our trade receivables are with a variety of U.S., international and foreign-country national oil and gas companies. Management considers this credit risk to be limited due to the financial resources of these companies. We perform ongoing credit evaluations of our customers and we generally do not require material collateral. We do occasionally require prepayment of amounts from customers whose creditworthiness is in question prior to providing services to them. We maintain reserves for potential credit losses, and these losses historically have been within management’s expectations.
 
Interest Rate, and Marketable and Non-marketable Security Price Risk.   Our financial instruments that are potentially sensitive to changes in interest rates include the 0.94% senior exchangeable notes, our 5.375%, 6.15%, 9.25% and 5.0% senior notes, our range-cap-and-floor derivative instrument, our investments in debt securities (including corporate, asset-backed, mortgage-backed debt and mortgage-CMO debt securities) and our investments in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages), which are classified as long-term investments.
 
We may utilize derivative financial instruments that are intended to manage our exposure to interest rate risks. We account for derivative financial instruments under the Derivatives Topic of the ASC. 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 on 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.
 
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


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notes due 2012, which has been designated as a fair value hedge. Additionally on that date, 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 and any change in the cumulative fair value of this transaction is reflected as a gain or loss in our consolidated statements of income (loss). In June 2004, we unwound $100 million of the $200 million range-cap-and-floor derivative instrument. During the fourth quarter of 2005, we unwound the interest rate swap resulting in a loss of $2.7 million, which has been deferred and will be recognized as an increase to interest expense over the remaining life of our 5.375% senior notes due 2012. During the year ended December 31, 2005, we recorded interest savings of $2.7 million related to our interest rate swap agreement accounted for as a fair value hedge, which served to reduce interest expense.
 
The fair value of our range-cap-and-floor transaction is recorded as a derivative liability and included in other long-term liabilities. It totaled approximately $3.4 million and $3.3 million as of December 31, 2010 and 2009, respectively. During 2010, 2009 and 2008, we recorded gains (losses) of approximately $(.1) million, $1.4 million and $(4.7) million, respectively, related to this derivative instrument; these amounts are included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss).
 
A hypothetical 10% adverse shift in quoted interest rates as of December 31, 2010 would decrease the fair value of our range-cap-and-floor derivative instrument by approximately $.1 million.
 
In September 2008 we entered into a three-month written put option for one million of our common shares with a strike price of $25 per share. We settled this contract during the fourth quarter of 2008 and paid cash of $22.6 million, net of the premium received, and recognized a loss of $9.9 million which is included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss).
 
Fair Value of Financial Instruments.  We estimate the fair value of our financial instruments in accordance with the provisions of the Fair Value Measurements and Disclosures Topic of the ASC. 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 fair value of the subsidiary preferred stock was estimated based on the allocation of the purchase price. See Note 7 — Acquisitions and Divestitures in Part II, Item 8. — Financial Statements and Supplementary Data for additional discussion. The carrying and fair values of these liabilities were as follows:
 
                                                 
    December 31,  
    2010     2009  
    Effective
                Effective
             
    Interest
    Carrying
    Fair
    Interest
    Carrying
    Fair
 
    Rate     Value     Value     Rate     Value     Value  
    (In thousands, except interest rates)  
 
0.94% senior exchangeable notes due May 2011(1)
    6.13 %   $ 1,378,178     $ 1,403,315       6.13 %   $ 1,576,480     $ 1,668,368  
6.15% senior notes due February 2018
    6.42 %     966,276       1,041,008       6.42 %     965,066       992,531  
9.25% senior notes due January 2019
    9.33 %     1,125,000       1,393,943       9.40 %     1,125,000       1,403,719  
5.00% senior notes due September 2020
    5.20 %     697,037       678,335                    
5.375% senior notes due August 2012(2)
    5.61 %     273,977       291,500       5.69 %     273,350       289,072  
Subsidiary preferred stock
    4.0 %     69,188       68,625                    
Other
            2,676       2,676       4.50 %     872       872  
                                                 
            $ 4,512,332     $ 4,879,402             $ 3,940,768     $ 4,354,562  
                                                 


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(1) During 2010 and 2009, we purchased $281.8 million and $964.8 million, respectively, par value of these notes in the open market.
 
(2) Includes $.7 million and $1.1 million as of December 31, 2010 and 2009, respectively, related to the unamortized loss on the interest rate swap that was unwound during the fourth quarter of 2005.
 
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, cash equivalents, short-term and long-term investments and other receivables are included in the table below:
 
                                         
    December 31,  
    2010     2009  
              Weighted-
              Weighted-
 
              Average
              Average
 
    Fair
    Interest
  Life
    Fair
    Interest
  Life
 
    Value     Rates   (Years)     Value     Rates   (Years)  
    (In thousands, except interest rates)  
 
Cash and cash equivalents
  $ 641,702     0% - .28%     0.00     $ 927,815     0% - 1.55%     0.00  
                                         
Short-term investments:
                                       
Trading equity securities
    19,630               24,014          
                                         
Available-for-sale equity securities
    79,698               93,651          
                                         
Available-for-sale debt securities:
                                       
Commercial paper and CDs
    1,275     .75%     .6       1,284     .25%     .6  
Corporate debt securities
    52,022     10.01% - 13.99%     3.6       33,852     .38% -14.00%     2.6  
Mortgage-backed debt securities
    372     2.79%     2.7       861     5.15% - 5.18%     3.0  
Mortgage-CMO debt securities
    3,015     .42% - 5.9%     .3       5,411     2.58% -6.23%     1.9  
Asset-backed debt securities
    3,476     .56% - 4.81%     1.3       3,963     2.64% -6.22%     2.1  
                                         
Total available-for-sale debt securities
    60,160                   45,371              
                                         
Total available-for-sale securities
    139,858                   139,022              
                                         
Total short-term investments
    159,488                   163,036              
                                         
Long-term investments and other receivables:
                                       
Actively managed funds
    7,427     N/A             8,341     N/A        
Oil and gas financing receivables
    32,873     13.10% - 13.52%             92,541     13.10% -13.52%        
                                         
Total long-term investments and other receivables
    40,300                   100,882              
                                         
Total cash, cash equivalents, short-term and long-term investments and other receivables
  $ 841,490                 $ 1,191,733              
                                         
 
Our investments in debt securities listed in the above table and a portion of our long-term investments are sensitive to changes in interest rates. Additionally, our investment portfolio of debt and equity securities, which are carried at fair value, exposes us to price risk. A hypothetical 10% decrease in the market prices for all securities as of December 31, 2010 would decrease the fair value of our trading securities and available-for-sale securities by $2.0 million and $14.0 million, respectively.


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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX
 
         
    Page No.
 
    63  
    65  
    66  
    67  
    68  
    70  


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Report of Independent Registered Public Accounting Firm
 
To the Board of Directors and Shareholders
of Nabors Industries Ltd.
 
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss), changes in equity and cash flows present fairly, in all material respects, the financial position of Nabors Industries Ltd. and its subsidiaries (the Company) at December 31, 2010 and December 31, 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which their oil and gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and gas costs as of December 31, 2009.
 
As described in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, management has excluded Superior Well Services, Inc. (“Superior”) from its assessment of internal control over financial reporting as of December 31, 2010 because Superior was acquired by the Company in a purchase business combination during 2010. We have also excluded Superior from our audit of internal control over financial reporting. Superior is a wholly-owned subsidiary whose total assets and total revenues represent 10 and 8 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2010.
 
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


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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 1, 2011


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NABORS INDUSTRIES LTD. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2010     2009  
    (In thousands, except per share amounts)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 641,702     $ 927,815  
Short-term investments
    159,488       163,036  
Assets held for sale
    352,048        
Accounts receivable, net
    1,116,510       724,040  
Inventory
    158,836       100,819  
Deferred income taxes
    31,510       125,163  
Other current assets
    152,836       135,791  
                 
Total current assets
    2,612,930       2,176,664  
Long-term investments and other receivables
    40,300       100,882  
Property, plant and equipment, net
    7,815,419       7,646,050  
Goodwill
    494,372       164,265  
Investment in unconsolidated affiliates
    267,723       306,608  
Other long-term assets
    415,825       250,221  
                 
Total assets
  $ 11,646,569     $ 10,644,690  
                 
 
LIABILITIES AND EQUITY
Current liabilities:
               
Current portion of long-term debt
  $ 1,379,018     $ 163  
Trade accounts payable
    355,282       226,423  
Accrued liabilities
    394,292       346,337  
Income taxes payable
    25,788       35,699  
                 
Total current liabilities
    2,154,380       608,622  
Long-term debt
    3,064,126       3,940,605  
Other long-term liabilities
    245,765       240,057  
Deferred income taxes
    770,247       673,427  
                 
Total liabilities
    6,234,518       5,462,711  
                 
Commitments and contingencies (Note 17)
               
Subsidiary preferred stock (Notes 7 and 14)
    69,188        
Equity:
               
Shareholders’ equity:
               
Common shares, par value $.001 per share:
               
Authorized common shares 800,000; issued 315,034 and 313,915, respectively
    315       314  
Capital in excess of par value
    2,255,787       2,239,323  
Accumulated other comprehensive income
    342,052       292,706  
Retained earnings
    3,707,881       3,613,186  
Less: treasury shares, at cost, 29,414 common shares
    (977,873 )     (977,873 )
                 
Total shareholders’ equity
    5,328,162       5,167,656  
Noncontrolling interest
    14,701       14,323  
                 
Total equity
    5,342,863       5,181,979  
                 
Total liabilities and equity
  $ 11,646,569     $ 10,644,690  
                 
 
The accompanying notes are an integral part of these consolidated financial statements.


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NABORS INDUSTRIES LTD. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per share amounts)  
 
Revenues and other income:
                       
Operating revenues
  $ 4,174,635     $ 3,683,419     $ 5,507,542  
Earnings (losses) from unconsolidated affiliates
    33,257       (155,433 )     (192,548 )
Investment income (loss)
    7,648       25,599       21,412  
                         
Total revenues and other income
    4,215,540       3,553,585       5,336,406  
                         
Costs and other deductions:
                       
Direct costs
    2,423,602       2,001,404       3,100,613  
General and administrative expenses
    346,661       428,161       479,194  
Depreciation and amortization
    764,253       667,100       614,367  
Depletion
    17,943       9,417       22,308  
Interest expense
    273,044       266,039       196,718  
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net
    47,060       12,559       15,829  
Impairments and other charges
    260,931       330,976       176,123  
                         
Total costs and other deductions
    4,133,494       3,715,656       4,605,152  
                         
Income (loss) from continuing operations before income taxes
    82,046       (162,071 )     731,254  
                         
Income tax expense (benefit):
                       
Current
    (83,816 )     69,532       188,832  
Deferred
    59,002       (203,335 )     20,828  
                         
Total income tax expense (benefit)
    (24,814 )     (133,803 )     209,660  
Subsidiary preferred stock dividend
    750              
                         
Income (loss) from continuing operations, net of tax
    106,110       (28,268 )     521,594  
Income (loss) from discontinued operations, net of tax
    (11,330 )     (57,620 )     (41,930 )
                         
Net income (loss)
    94,780       (85,888 )     479,664  
Less: Net (income) loss attributable to noncontrolling interest
    (85 )     342       (3,927 )
                         
Net income (loss) attributable to Nabors
  $ 94,695     $ (85,546 )   $ 475,737  
                         
Earnings (losses) per share:
                       
Basic from continuing operations
  $ .37     $ (.10 )   $ 1.84  
Basic from discontinued operations
    (.04 )     (.20 )     (.15 )
                         
Total Basic
  $ .33     $ (.30 )   $ 1.69  
                         
Diluted from continuing operations
  $ .37     $ (.10 )   $ 1.80  
Diluted from discontinued operations
    (.04 )     (.20 )     (.15 )
                         
Total Diluted
  $ .33     $ (.30 )   $ 1.65  
                         
Weighted-average number of common shares outstanding:
                       
Basic
    285,145       283,326       281,622  
Diluted
    289,996       283,326       288,236  
 
The details of credit-related impairments to investments for the year ended December 31, 2009 is presented below:
 
         
    (In thousands)  
 
Other-than-temporary impairment on debt security
  $ 40,300  
Less: other-than-temporary impairment recognized in accumulated other comprehensive income (loss)
    (4,651 )
         
Credit-related impairment on investment(1)
  $ 35,649  
         
 
 
(1) Included in Impairments and other charges (Note 3)
 
The accompanying notes are an integral part of these consolidated financial statements.


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NABORS INDUSTRIES LTD. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income (loss) attributable to Nabors
  $ 94,695     $ (85,546 )   $ 475,737  
Adjustments to net income (loss):
                       
Depreciation and amortization
    766,519       668,415       614,367  
Depletion
    27,002       11,078       25,442  
Deferred income tax expense (benefit)
    55,964       (218,760 )     17,315  
Deferred financing costs amortization
    5,431       6,133       7,661  
Pension liability amortization and adjustments
    664       844       160  
Discount amortization on long-term debt
    70,719       86,802       123,739  
Amortization of loss on hedges
    786       580       548  
Impairments and other charges
    260,931       339,129       176,123  
Losses (gains) on long-lived assets, net
    (1,050 )     12,339       9,644  
Losses (gains) on investments, net
    191       (9,954 )     18,736  
Losses (gains) on debt retirement, net
    7,042       (11,197 )     (12,248 )
Losses (gains) on derivative instruments
    2,471       338       4,783  
Share-based compensation
    13,746       106,725       45,401  
Foreign currency transaction losses (gains), net
    17,880       8,372       (2,718 )
Equity in (earnings) losses of unconsolidated affiliates, net of dividends
    (13,630 )     229,813       236,763  
Changes in operating assets and liabilities, net of effects from acquisitions:
                       
Accounts receivable
    (249,725 )     450,530       (157,697 )
Inventory
    (15,201 )     52,995       (26,774 )
Other current assets
    6,589       205,108       </