10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

    x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

    For the fiscal year ended December 31, 2011

    ¨ 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.)
Crown House Second Floor 4 Par-la-Ville Road Hamilton, HM08 Bermuda	N/A
(Address of principal executive offices)	(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  ¨

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  ¨        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  ¨

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  ¨

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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer  þ             Accelerated Filer  ¨ Non-accelerated Filer  ¨             Smaller Reporting Company   ¨

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

The aggregate market value of the 265,089,538 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, 2011, of $24.64 per share as reported on the New York Stock Exchange, was $6,531,806,216. 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, 2012 was 288,679,432.

DOCUMENTS INCORPORATED BY REFERENCE (to the extent indicated herein)

Specified portions of the definitive Proxy

Statement to be distributed in connection with our 2012 Annual General Meeting of Shareholders (Part III).

NABORS INDUSTRIES LTD.

Form 10-K Annual Report

For the Year Ended December 31, 2011

Table of Contents

	PART I
Item 1.	Business	4
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	18
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	27
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	145
Item 9A.	Controls and Procedures	145
Item 9B.	Other Information	146
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	147
Item 11.	Executive Compensation	147
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	147
Item 13.	Certain Relationships and Related Transactions and Director Independence	149
Item 14.	Principal Accounting Fees and Services	149
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	150

2

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; 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., together with our subsidiaries where the context requires, including Nabors Industries, Inc., a Delaware corporation (“Nabors Delaware”).

3

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 499 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Middle East, the Far East, the South Pacific, Russia and Africa.

• We actively market approximately 581 rigs for land well-servicing and workover work in the United States and approximately 174 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 39 platform, 12 jackup and four barge rigs in the United States, including the Gulf of Mexico, and multiple international markets.

In addition to the foregoing services:

• We provide hydraulic fracturing, cementing, nitrogen and acid pressure pumping services with over 730,000 hydraulic horsepower in key basins throughout the United States and Canada.

• We offer a wide range of ancillary well-site services, including engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select U.S. 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 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 have invested in oil and gas exploration, development and production activities through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests.

Nabors was formed as a Bermuda exempted 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 Crown House, 4 Par-la-Ville Road, Second Floor, Hamilton, HM08, Bermuda, and our phone number there is (441) 292-1510.

Our Rig Fleet

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

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

4

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.

• Jackup Rigs.     Jackup 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 jackup 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 jackup rigs generally are subject to a maximum water depth of approximately 125 feet, while some of our jackup rigs may drill in water depths as shallow as 13 feet. Nabors also has deeper water jackup 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.

Types of Drilling Contracts

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

5

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).

Pressure Pumping Services

We provide 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 oil production, and down-hole surveying services. Other technical services include completion, production and rental tool services. Additionally, we provide fluid logistics services, including those related to the transportation, storage and disposal of fluids that are used in the drilling, development and production of hydrocarbons.

During the year ended December 31, 2011 approximately 2.9% of revenues from our Pressure Pumping operating segment came from a Nabors’ consolidated entity and an unconsolidated Nabors affiliate. Our proportionate share of any profits resulting from sales to affiliates were eliminated in consolidation.

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

6

involve selectively perforating the well casing at the depth of discrete producing zones, stimulating and testing these zones and installing down-hole equipment. The completion process may take a few days to several weeks. We are paid an hourly rate and work is generally performed seven days a week, 24 hours a day.

• Production and Other Specialized Services.     We also can provide other specialized services, including onsite temporary fluid storage; 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.

Oil and Gas Investments

In our Oil and Gas operating segment, we have invested in oil and gas exploration, development and production operations in the United States, Canada and Colombia.

During 2007, three joint ventures were formed for operations in these areas. Our joint venture in Canada was dissolved in June 2011, and our joint venture in Colombia monetized its assets during 2011. In addition, we hold a 49.7% ownership interest in a U.S. entity, NFR Energy LLC (“NFR Energy”). We account for these investments using the equity method of accounting. Our joint ventures pursue 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 exploration, development and production operations have focused on the exploration for and the acquisition, development and production of natural gas, oil and natural gas liquids in Alaska, Arkansas, California, Louisiana, Oklahoma, Mississippi, Montana, North Dakota, Texas, Utah and Wyoming. Outside of the United States, we own or have interests in the Canadian provinces of Alberta and British Columbia and in Colombia.

During the fourth quarter of 2011, we announced our intention to dispose of a significant portion of our oil and gas investment portfolio. In addition to the sales of certain of our oil and gas assets in Colombia during 2011, we sold our working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California.

Additional information about our oil and gas activities can be found in Part II, Item 2. — Properties and Item 8. — Notes — 4 Discontinued Operations and 24 — Supplemental Information on Oil and Gas Exploration and Production Activities.

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 RIGWATCH^TM software and computerized equipment that monitors a rig’s real-time performance. Our ROCKIT^TM directional drilling system 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 which are installed on both onshore and offshore drilling rigs. Ryan Directional Services, 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. Peak Oilfield Service Company (“Peak”), one of our subsidiaries in Alaska, 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. Peak also provides construction and maintenance for ice roads, pads, facilities, equipment, drill sites and pipelines. Nabors also has a 50%

7

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.

Our Customers

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 2011 or 2010.

Our Employees

As of December 31, 2011, we employed approximately 26,080 people, of whom approximately 2,666 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, our 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 those 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, pressure pumping and well-servicing market is generally more competitive than the offshore market due to the larger number of rigs and market participants.

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

8

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 the latter half of 2010 and during 2011, gas prices remained depressed, while oil prices steadily rose, which increased demand for our drilling and well-servicing activities in North America as the market shifted to oil-and liquids-rich shale plays. Gas prices are likely to remain weak throughout 2012, principally due to a warm winter exacerbated by increasing supply attributable to rigs associated with the increased oil- and liquids-rich production. Our International markets were much slower to respond to the improving oil prices of 2010 and early 2011 and were further dampened when we renewed three of the four expiring contracts relating to our Arabian Gulf jackup rigs at lower rates due to a more competitive market. Our International markets are improving, and the deployment of several large projects and other rigs returning to work should improve results in 2012.

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 our 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, Inc., Forbes Energy Services Ltd. 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, Inc. and Tesco Corporation. Its largest competitors in the manufacture of rig instrumentation systems are Pason Systems Inc. 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 principally competes with CH2M_Hill for drilling support services. Other competitors include ASR Energy Services and Alaska Frontier Constructors. Peak is one of the premier ice road contractors with the largest fleet of all terrain vehicles used during the winter exploration months. Alaska Interstate Construction principally competes with large general contractors, including Granite Construction Company and Quality Asphalt Paving & Sealcoating Inc. on public works projects and Alaska Frontier Constructors, ASRC and CH2M_Hill on resource development projects.

Our Business Strategy

Our strategy is to position Nabors to grow and prosper when market conditions are good and to mitigate adverse effects when market conditions are bad. We have maintained a financial posture that allows us to

9

capitalize on market weakness and strength by adding to our business base, thereby enhancing our upside potential. The principal elements of our strategy to build shareholder value are to:

• Maintain a strong and flexible balance sheet;

• Take advantage of opportunities as they arise;

• Leverage our global infrastructure;

• Achieve superior health, safety and environmental performance;

• Achieve superior operational performance;

• Focus on delivering value-added services to our customers;

• Enhance and leverage our technology position; and

• Achieve returns well above our cost of capital.

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 U.S. Lower 48 Land 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 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. During 2011, oil commodity prices steadily rose and the related impact on demand for our drilling and well-servicing activities increased especially in the oil- and liquids-rich shale plays. We believe the deployment of our newer and higher-margin rigs under long-term contracts enhances our competitive position as market conditions improve.

Our current focus is to improve flexibility in our balance sheet, increase earnings and reduce our net debt. We are evaluating each business line for its strategic fit, execution effectiveness and return hurdles. In addition, we are:

• Emphasizing term contracts and execution in core businesses;

• Imposing higher hurdles for new projects;

• Optimizing intra-company synergies and technological advancements;

• Improving capital allocation and return on capital expenditures; and

• Monetizing nonperforming and nonstrategic assets.

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 499 land drilling rigs, 755 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jackup 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.

10

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

Acquisitions

In September 2010, we acquired through a tender offer and merger all of the outstanding common stock of Superior Well Services, Inc. (“Superior”) 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.

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 $4.2 million.

In June 2011, the equity owners of Stone Mountain Venture Partnership (“SMVP”) dissolved the partnership in Canada, and a proportionate share of the assets and liabilities were conveyed to us in exchange for our ownership interest. The assets are presented as held for sale and the operating results in discontinued operations for all periods presented.

On July 31, 2011, we paid $65 million in cash to acquire the remaining 50 percent equity interest of Peak, making it a wholly owned subsidiary on this date. Previously, we held a 50 percent equity interest with a carrying value of $38.1 million that we had accounted for as an equity method investment. As a result of the acquisition, we consolidated the assets and liabilities of Peak during the third quarter of 2011 based on their respective fair values. The excess of the estimated fair value of the assets and liabilities over the net carrying value of our previously held equity interest resulted in a gain of $13.1 million and is reflected in losses (gains) on sales and retirements of long-lived assets and other expense (income) for the year ended December 31, 2011.

Divestitures

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 construction contract. The operating results of this business for years ended December 31, 2007 and before are accounted for as discontinued operations.

On April 28, 2011, we sold some of our wholly owned oil and gas assets, previously included in our oil and gas operating segment, in Colombia. We received proceeds of $89.2 million from this sale and recognized a gain of approximately $39.6 million.

During the second quarter of 2011, our unconsolidated oil and gas joint venture, Remora Energy International LP (“Remora”), completed sales of its oil and gas assets in Colombia. Remora received gross proceeds of approximately $333.1 million from these sales and made cash distributions to us in the amount of $143.0 million with a final distribution expected upon dissolution of the joint venture.

On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received proceeds of approximately $71.6 million from the sale and a commitment from the purchaser to continue utilizing our rigs. We recognized a gain of approximately $7.2 million. These assets were previously included in our oil and gas operating segment.

11

The accompanying consolidated statements of income (loss) and notes to the consolidated financial statements have been updated to retroactively reclassify the operating results of the divested assets as discontinued operations for all periods presented. See Note 4 — Discontinued Operations for additional discussion in Part II, Item 8. — Financial Statements and Supplementary Data.

Environmental Compliance

We do not currently anticipate that compliance with currently applicable environmental regulations and controls will significantly change our competitive position, capital spending or earnings during 2012. We believe we are in material compliance with applicable environmental rules and regulations, and the cost of such compliance is not material to our business or financial condition. For a more detailed description of the environmental laws and regulations applicable to our 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.

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. Volatility in oil and natural gas prices is likely to continue in the foreseeable 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, which could result in a corresponding decline in demand for our services. 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 sustained or further decline in oil and natural gas prices could adversely impact our cash forecast models used to determine whether the carrying value of our long-lived assets exceed our future cash flows, which could result in future impairment to our long-lived 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 substantial volatility and extended declines in oil and natural gas prices in recent years in response to a weakened global economic environment have adversely affected our results of operations. In addition, economic

12

conditions have resulted in substantial uncertainty in the capital markets and both access to and terms of available financing. During 2009 through the first half of 2010, many of our customers curtailed their drilling programs, which, in many cases, resulted in a decrease in demand for drilling rigs and a reduction in dayrates and utilization. Additionally, some customers 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.

We have a substantial amount of debt outstanding

As of December 31, 2011, we had long-term debt outstanding of approximately $4.6 billion, including $275.3 million in current maturities, and cash and cash equivalents and short-term investments of $539.5 million. 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 facilities and our ability to access the capital markets. As of December 31, 2011, we had $540 million available under revolving credit facilities. 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 investments.

At December 31, 2011, our gross funded debt to capital ratio was 0.43:1 and our net funded debt to capital ratio was 0.40:1.

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.

13

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.

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.

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 Middle East, the Far East, the South Pacific, 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. 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 an employment agreement with our Deputy Chairman, President and Chief

14

Executive Officer, Anthony G. Petrello, with a term through March 30, 2014. 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. 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.

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

15

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. In November 2010, the EPA expanded these rules to include offshore oil and natural gas production and 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. The EPA and certain other federal agencies have announced that they would study the potential adverse impact that fracturing may have on water quality and public health. On August 11, 2011, the U.S. Department of Energy released its report on hydraulic fracturing, recommending the implementation of a variety of measures to reduce the environmental impacts from shale-gas production. These studies could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. Legislation has also been introduced in the U.S. Congress and adopted or introduced in 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.

Future price declines may result in a writedown of our oil and gas asset carrying values

Our wholly owned oil and gas investment portfolio and our unconsolidated ownership interest in Remora is reflected in assets held for sale. Historically, our proved and unproved properties have been reviewed for impairment of the carrying value based on the successful efforts method of accounting for oil and gas properties; any impairment was expensed in that period. 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.

The estimated fair value of our proved reserves generally declines when there is a significant and sustained decline in oil and natural gas prices. 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 or our ownership interests in unconsolidated affiliates if the estimated fair value of these properties falls below their net book value, which could cause other future writedowns of capitalized costs and asset impairments that could adversely affect our results of operations.

16

Significant exercises of stock options could adversely affect the market price of our common shares

As of February 24, 2012, we had 800,000,000 authorized common shares, of which 318,092,267 shares were outstanding. In addition, 39,129,225 common shares were reserved for issuance pursuant to stock option and employee benefit plans. 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 options (and, where applicable, sales pursuant to Rule 144 under the Securities Act), 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

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. In addition, our Board of Directors is divided into three classes, with each class serving a staggered three-year term. Although we have announced plans to declassify the Board, its current structure, 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.

We have an employment agreement with our Deputy Chairman, President and Chief Executive Officer, Anthony G. Petrello. The agreement has a change-in-control provision that could result in a significant cash payment to Mr. 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 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 2005 through 2008 and against NDIL II for 2007 to 2010. We believe that the potential assessments will range from $6 million to $26 million per year for the period from 2005 to 2009, and in the aggregate, would be approximately $90 million to $95 million. Although we believe that any assessments related to the 2003 and 2005 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

17

statute of limitations for NDIL’s 2004 tax year 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.

The profitability of our operations could be adversely affected by turmoil in the global financial markets

The changes in general financial and political conditions, including the U.S. government budget, the downgrade by Standard & Poor’s of the credit rating of U.S. government securities and concerns over the European sovereign debt crisis and banking industry has created a great deal of uncertainty in the recovery of the world economy. If global economic uncertainties continue over a prolonged period of time or develop adversely, there could be a material adverse impact on our credit ratings and liquidity and those of our customers and other worldwide business partners. If global oil and gas prices were to decline rapidly, it could lead our customers to curtail their operations or expansion and cause difficulties for us and our customers to forecast future capital expenditures, which in turn could negatively impact the worldwide rig count and our future financial results.

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.

ITEM 2. PROPERTIES

Nabors’ principal executive offices are located in Hamilton, Bermuda. We own or lease executive and administrative office space in Dubai in the United Arab Emirates; Anchorage, Alaska; Calgary, Canada; Indiana, Pennsylvania and Houston, Texas.

18

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, which are used to support our 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 at December 31, 2009. Accordingly after the one-year deferral, we began presenting the information with regard to our oil and gas producing activities for the year ended December 31, 2010.

The estimates of net proved oil and gas reserves as of December 31, 2011 were based on reserve reports prepared by independent petroleum engineers. AJM Deloitte 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. Cawley, Gillespie & Associates, Inc. prepared reports of estimated proved oil reserves for wholly owned assets located in the Eagle Ford Shale and Giddings field in Grimes County, Texas.

The estimates of net proved oil and gas reserves as of December 31, 2010 were based on reserve reports prepared by the following 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 properties located in the Cat Canyon and West Cat Canyon fields in 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 of natural gas (“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 and the properties of our unconsolidated U.S. joint venture, the prices used in the reserve reports were $4.12 per thousand cubic feet of natural gas (“Mcf”) for the 12-month average of natural gas, $57.71 per barrel for natural gas liquids and $96.19 per barrel for oil at December 31, 2011. For our wholly owned properties in Canada, the price used in our reserve reports was $3.85 per mcf for the 12-month average of natural gas at December 31, 2011.

19

No major discovery or other favorable or adverse event has occurred since December 31, 2011, that would cause a significant change in the estimated proved reserves as of that date.

	Reserves
Reserve category	Liquids (MMBbls)			Natural Gas (Bcf)
As of December 31, 2011:
Proved
Developed
Consolidated Subsidiaries
United States		.9	(2)		13.6
Canada		—			8.2
Colombia		—			—
Total Consolidated		.9			21.8
Equity Companies(1)
United States		6.3			256.4	(3)
Canada		—			—	(4)
Colombia		—	(5)		—
Total Equity Companies		6.3			256.4
Total Developed		7.2			278.2
Undeveloped
Consolidated Subsidiaries
United States		.9			3.3
Canada		—			—
Colombia		—			—
Total Consolidated		.9			3.3
Equity Companies(1)
United States		9.6			326.1
Canada		—			—
Colombia		—			—
Total Equity Companies		9.6			326.1
Total Undeveloped		10.5			329.4
Total Proved		17.7			607.6
As of December 31, 2010:
Proved
Developed
Consolidated Subsidiaries
United States		2.7	(2)		17.1
Canada		—			5.5
Colombia		1.6			—
Total Consolidated		4.3			22.6
Equity Companies(1)
United States		3.0			147.1
Canada		—			5.2
Colombia		0.5			—
Total Equity Companies		3.5			152.3
Total Developed		7.8			174.9
Undeveloped
Consolidated Subsidiaries
United States		18.5			2.7
Canada		—			—
Colombia		0.4			—
Total Consolidated		18.9			2.7
Equity Companies(1)
United States		4.9			405.7
Canada		—			—
Colombia		1.4			—
Total Equity Companies		6.3			405.7
Total Undeveloped		25.2			408.4
Total Proved		33.0			583.3

(1) Represents our proportionate interests in our equity companies.

20

(2) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(3) Relates to acquisitions of properties with 360.4 Bcfe and drilling of non-proved properties of 122.2 Bcfe. In addition, negative revisions of 384 Bcfe were noted primarily resulting from proved undeveloped reserves being reclassified to non-proved status in accordance with the SEC five-year guidance for recording proved reserves.

(4) Relates to SMVP that was dissolved in June 2011, and of proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

(5) Relates to the sale of Remora’s assets which resulted in a decrease in proved reserves of 9.5 Bcfe.

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 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 2011

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

21

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, 2011, approximately 392 billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or natural gas liquids, (“Bcfe”) of our proved reserves were classified as proved undeveloped, which represented 55% of the 714 Bcfe reported in proved reserves. This amount is inclusive of both consolidated subsidiaries and equity company reserves. At December 31, 2011, our wholly owned reserves are reported as assets held for sale. Our unconsolidated U.S. joint venture only adds PUDs that will be developed within a five-year time horizon. Progress was made in converting proved undeveloped reserves into proved developed reserves in 2011. During 2011, we completed development work that resulted in the transfer of approximately 63.047 Bcfe from proved undeveloped to proved developed reserves. We spent approximately $.4 million and our unconsolidated U.S. joint venture provided approximately $89 million associated with the development of PUDs in 2011.

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 years ended December 31, 2011 and 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 (MMBbls)		Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)
As of December 31, 2011:
Oil and natural gas liquids production
Consolidated Subsidiaries		.140		2.944			—		2.117		.111			.011		.251		5.072
Equity Companies(1)		.409		18.634			—		.380		.316			—		.725		19.014
Average production sales prices:
Consolidated Subsidiaries	$	88.94	$	4.09		$	—	$	3.33	$	111.57		$	5.00	$	98.91	$	3.77
Equity Companies(1)	$	58.16	$	4.03		$	—	$	3.48	$	84.47		$	—	$	69.63	$	4.02
Average production costs ($/bce):
Consolidated Subsidiaries			$	3.35/Mcfe	(2)			$	12.96/Mcfe	$	32.98/Boe	(2)
Equity Companies(1)			$	1.32/Mcfe				$	11.99/Mcfe	$	33.49/Boe
As of December 31, 2010:
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 ($/bce):
Consolidated Subsidiaries			$	2.14/Mcfe				$	2.60/Mcfe	$	34.42Bboe
Equity Companies(1)			$	1.33/Mcfe				$	5.89/Mcfe	$	33.60/Boe

(1) Represents our proportionate interests in our equity companies.

(2) Reflects the thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or natural gas liquids, or as “Mcfe” and reflects the barrel of oil equivalent or as “Boe”.

22

Drilling and Other Exploratory and Development Activities

During 2011 and 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 the United States, Canada and Colombia that are being actively marketed. The following tables provide the number of oil and gas wells completed during 2011 and 2010.

Number of Net Productive and Exploratory Wells Drilled

	Net Productive  Exploratory Wells Drilled		Net Dry Exploratory Wells Drilled
For the year ended December 31, 2011:
Consolidated Subsidiaries
United States		5.14		3.63
Canada		3.00		4.00
Colombia		—		—
Total Consolidated		8.14		7.63
Equity Companies(1)
United States		—		—
Canada		—		—
Colombia		—		—
Total Equity Companies		—		—
For the year ended December 31, 2010:
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.

23

	Net Productive  Development Wells Drilled		Net Dry Development Wells Drilled
For the year ended December 31, 2011:
Consolidated Subsidiaries
United States		2.04		3.28
Canada		—		—
Colombia		2.00		1.40
Total Consolidated		4.04		4.68
Equity Companies(1)
United States		10.45		—
Canada		—		—
Colombia		—		—
Total Equity Companies		10.45		—
For the year ended December 31, 2010:
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, 2011.

Wells Drilling

	United States				Canada				Colombia				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Consolidated Subsidiaries		13.00		4.11		—		—		—		—		13.00		4.11
Equity Companies(1)		10.45		10.45		—		—		—		—		10.45		10.45

(1) Represents our proportionate interests in our equity companies.

24

Oil and Gas Properties, Wells, Operations and Acreage

Gross and Net Productive Wells

	For the year ended December 31, 2011
	Gross		Net
Consolidated Subsidiaries
United States		419.0		48.9
Canada		7.0		7.0
Colombia		3.0		1.5
Total Consolidated		429.0		57.4
Equity Companies(1)
United States		537.1		408.7
Canada		—		—
Colombia		—		—
Total Equity Companies		537.1		408.7

(1) Represents our proportionate interests in our equity companies.

Gross and Net Developed Acreage

	December 31, 2011
	United States				Canada				Colombia				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Consolidated Subsidiaries		201,414		26,577		5,197		4,877		—		—		206,611		31,454
Equity Companies(1)		225,743		123,896		—		—		—		—		225,743		124,394

(1) Represents our proportionate interests in our equity companies.

Gross and Net Undeveloped Acreage

	December 31, 2011
	United States				Canada				Colombia				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Consolidated Subsidiaries		586,701		202,187		50,673		44,402		581,450		280,946		1,218,824		527,535
Equity Companies(1)		368,767		189,002		—		—		—		—		368,767		189,002

(1) Represents our proportionate interests in our equity companies.

Lease Expirations of Net Acreage

	United States						Canada						Colombia
	2012		2013		2014		2012		2013		2014		2012		2013		2014
Consolidated Subsidiaries(2)		36,327		16,811		11,749		12,517		—		—		—		—		—
Equity Companies(1)(3)		33,916		57,251		26,036		—		—		—		—		—		—

(1) Represents our proportionate interests in our equity companies.

(2) The carrying value of leases at December 31, 2011 was approximately $105.8 million.

(3) The carrying value of our proportionate share of leases at December 31, 2011 was approximately $103.7 million.

25

Although our drilling program includes development activities with properties that are being actively marketed, we plan to continue the terms of some of these licenses and concession areas through operational or administrative actions. We believe the amount of undeveloped acreage that will be abandoned or lease allowed to expire at the end of the lease term is immaterial to our operations.

Additional information about our properties can be found in Notes 2 — Summary of Significant Accounting Policies, 9 — Property, Plant and Equipment (each, under the caption Property, Plant and Equipment), 18 — 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, 2011, 2010 and 2009, 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. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure. 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 U.S. 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. 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 Department of Justice have been advised of our investigation. 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. In November 2011, we received a notice from the Algeria Supreme Court that a decision is expected in March 2012. 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.

26

In March 2011, the Court of Ouargla (in Algeria), sitting at first instance, entered a judgment of approximately $39.1 million against NDIL relating to alleged violations of Algeria’s foreign currency exchange controls, which require that goods and services provided locally be invoiced and paid in local currency. The case relates to certain foreign currency payments made to NDIL by CEPSA, a Spanish operator, for wells drilled in 2006. Approximately $7.5 million of the total contract amount was paid offshore in foreign currency, and approximately $3.2 million was paid in local currency. The judgment includes fines and penalties of approximately four times the amount at issue, and is not payable pending appeal. We have appealed the ruling based on our understanding that the law in question applies only to resident entities incorporated under Algerian law. An intermediate court of appeals has upheld the lower court’s ruling, and we have appealed the matter to the Algeria Supreme Court. While our payments were consistent with our historical operations in the country, and, we believe, those of other multinational corporations there, and interpretations of the law by the Central Bank of Algeria, the ultimate resolution of this matter could result in a loss of up to $31.1 million in excess of amounts accrued.

On September 21, 2011, we received an informal inquiry from the SEC related to perquisites and personal benefits received by the officers and directors of Nabors, including their use of non-commercial aircraft. Our Audit Committee and Board of Directors have been apprised of this inquiry and we are cooperating with the SEC. The ultimate outcome of this process cannot be determined at this time.

Nabors Industries Ltd. and its Board of Directors have been sued by purported shareholders in three separate shareholder’s derivative lawsuits filed in federal and state court in Houston, Texas. The cases were filed on November 18, 2011, January 9, 2012, and November 30, 2011, and are pending, respectively, before Judges Ewing Werlein and Gray Miller in the United States Southern District of Texas, Houston Division, and Judge Mike Miller of the 11th Judicial District Court of Harris County, Texas. The case filed on January 9, 2012 was voluntarily dismissed on January 31, 2012. The other cases remain pending. The allegations of each lawsuit were substantially similar, alleging that the members of the Board breached their fiduciary duties to the Company, wasted corporate assets, and committed oppressive conduct against the shareholders by agreeing to and/or acquiescing in certain compensation arrangements with two senior officers of the Company, Eugene M. Isenberg and Anthony G. Petrello. The remaining lawsuits seek relief that includes an award of monetary damages in an unspecified amount, disgorgement by Messrs. Isenberg and Petrello of allegedly excessive compensation in an unspecified amount of at least $90 million, and equitable relief to reform Nabors’ compensation practices. The ultimate outcome of these lawsuits cannot be determined at this time.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

27

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, 2006 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, 2007 — 2011.

	2007	2008	2009	2010	2011
Nabors Industries Ltd.	92	40	74	79	58
S&P 500 Index	105	66	84	97	99
Dow Jones Oil Equipment and Services Index	145	59	97	124	109

28

Market and Share Prices

Our common shares are traded on the New York Stock Exchange under the symbol “NBR”. At February 24, 2012, there were approximately 1,427 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
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
2011
First quarter		30.70		21.50
Second quarter		32.47		22.43
Third quarter		27.63		12.26
Fourth quarter		20.69		11.05

The following table provides information relating to Nabors’ repurchase of common shares during the three months ended December 31, 2011:

Period	Total Number of Shares Purchased(1)		Average Price Paid per Share(1)		Total Number of Shares Purchased as Part of Publicly Announced Program		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program(2)
	(In thousands, except per share amounts)
October 1 — October 31		—		—		—		—
November 1 — November 30		<1	$	18.69		—		—
December 1 — December 31		420	$	18.24		—		—

(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. 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) We do not intend to make further purchases of our common shares under a share repurchase program that was authorized by the Board of Directors in July 2006.

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

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.

29

Shareholder Matters

Bermuda has exchange controls which apply to residents in respect of the Bermuda dollar. As an exempted 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)	2011			2010			2009			2008			2007
	(In thousands, except per share amounts and ratio data)
Revenues and other income:
Operating revenues	$	6,060,351		$	4,134,483		$	3,662,220		$	5,394,225		$	4,755,957
Earnings (losses) from unconsolidated affiliates		56,647			33,267			(155,432	)		(192,548	)		20,980
Investment income (loss)		19,940			7,263			25,522			21,383			(16,301	)
Total revenues and other income		6,136,938			4,175,013			3,532,310			5,223,060			4,760,636
Costs and other deductions:
Direct costs		3,775,964			2,400,519			1,981,504			3,063,257			2,720,898
General and administrative expenses		489,892			338,720			421,492			473,885			429,994
Depreciation and amortization		924,094			760,962			663,958			609,155			463,985
Interest expense		256,633			272,712			266,047			196,726			154,934
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		4,514			47,238			11,982			15,143			11,614
Impairments and other charges		198,072			61,292			118,543			145,447			—
Total costs and other deductions		5,649,169			3,881,443			3,463,526			4,503,613			3,781,425
Income (loss) from continuing operations before income taxes		487,769			293,570			68,784			719,447			979,211
Income tax expense (benefit)		142,605			36,950			(63,937	)		200,186			178,655
Subsidiary preferred stock dividend		3,000			750			—			—			—
Income (loss) from continuing operations, net of tax		342,164			255,870			132,721			519,261			800,556
Income (loss) from discontinued operations, net of tax		(97,440	)		(161,090	)		(218,609	)		(39,597	)		64,726
Net income (loss)		244,724			94,780			(85,888	)		479,664			865,282
Less: Net (income) loss attributable to noncontrolling interest		(1,045	)		(85	)		342			(3,927	)		420
Net income (loss) attributable to Nabors	$	243,679		$	94,695		$	(85,546	)	$	475,737		$	865,702
Earnings (losses) per share:
Basic from continuing operations	$	1.19		$	.90		$	.47		$	1.83		$	2.85
Basic from discontinued operations		(.34	)		(.57	)		(.77	)		(.14	)		.23
Total Basic	$	.85		$	.33		$	(.30	)	$	1.69		$	3.08
Diluted from continuing operations	$	1.17		$	.88		$	.46		$	1.79		$	2.78
Diluted from discontinued operations		(.34	)		(.55	)		(.76	)		(.14	)		.22
Total Diluted	$	.83		$	.33		$	(.30	)	$	1.65		$	3.00
Weighted-average number of common shares outstanding:
Basic		287,118			285,145			283,326			281,622			281,238
Diluted		292,484			289,996			286,502			288,236			288,226
Capital expenditures and acquisitions of businesses(3)	$	2,247,735		$	1,878,063		$	990,287		$	1,578,241		$	1,945,932
Interest coverage ratio(4)		8.1:1			7.0:1			7.4:1			22.6:1			37.3:1

30

	As of December 31,
Balance Sheet Data(1)(2)	2011		2010		2009		2008		2007
	(In thousands, except ratio data)
Cash, cash equivalents and short-term investments(5)	$	539,489	$	801,190	$	1,090,851	$	586,111	$	820,105
Working capital		1,285,752		458,550		1,568,042		1,037,734		719,674
Property, plant and equipment, net		8,629,946		7,815,419		7,646,050		7,331,959		6,669,013
Total assets		12,912,140		11,646,569		10,644,690		10,517,899		10,139,783
Long-term debt		4,348,490		3,064,126		3,940,605		3,600,533		2,894,659
Shareholders’ equity		5,587,815		5,328,162		5,167,656		4,904,106		4,801,579
Funded debt to capital ratio:
Gross(6)		0.43:1		0.42:1		0.41:1		0.41:1		0.39:1
Net(7)		0.40:1		0.38:1		0.33:1		0.37:1		0.33:1

(1) All periods present the operating activities of our wholly owned oil and gas assets in the United States, Canada and Colombia, including equity interests in Canada and Colombia, as well as the Nabors Blue Sky Ltd. and Sea Mar businesses as discontinued operations.

(2) Our acquisitions’ results of operations and financial position have been included beginning on the respective dates of acquisition and include Peak (July 2011), SMVP (June 2011), Energy Contractors (December 2010) and Superior (September 2010).

(3) Represents capital expenditures and the total purchase price of acquisitions.

(4) The interest coverage ratio is a trailing 12-month quotient of the sum of (x) income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, subsidiary preferred stock dividends, depreciation and amortization, impairments and other charges, income tax expense (benefit) and our proportionate share of writedowns from our unconsolidated oil and gas joint venture less investment income (loss) divided by (y) the sum of cash interest expense and 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.

(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.

(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 investments. 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

This section 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.

31

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 499 land drilling rigs, 755 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jackup units, barge rigs and a large component of trucks and fluid hauling vehicles. We have invested in oil and gas exploration, development and production activities in the United States, Canada and Colombia, but have announced our intention to dispose of a significant portion of our oil and gas portfolio in an expeditious and prudent manner.

The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, well-servicing and workover operations, on land and offshore. Our hydraulic fracturing and downhole surveying services are included in our Pressure Pumping operating segment. Our oil and gas exploration, development and production operations are included in our Oil and Gas operating segment, or in discontinued operations in some cases. Our operating segments engaged in drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction 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. Our customers’ spending is determined principally by their internally generated cash flow and to a lesser extent by joint venture arrangements and funding from the capital markets. In our U.S. Lower 48 Land Drilling, Canadian Drilling and Pressure Pumping business units, operations have traditionally been driven by natural gas prices but the majority of current activity is being driven by the price of oil and natural gas liquids from unconventional reservoirs (shales). In our Alaskan, International, U.S. Offshore (Gulf of Mexico), Canadian Well-servicing and U.S. Land Well-servicing business units, operations are driven by oil prices. The following table sets forth natural gas and oil price data per Bloomberg for the last three years:

	Year Ended December 31,						Increase / (Decrease)
	2011		2010		2009		2011 to 2010					2010 to 2009
Commodity prices:
Average Henry Hub natural gas spot price ($/thousand cubic feet (mcf))	$	4.00	$	4.37	$	3.94	$	(.37	)	(8	)%	$	.43	11	%
Average West Texas intermediate crude oil spot price ($/barrel)	$	95.05	$	79.51	$	61.99	$	15.54		20	%	$	17.52	28	%

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 and into the first half of 2010 resulted in sustained lower natural gas and oil prices, which led to a sharp decline in the demand for drilling and workover services. During the latter half of 2010 and throughout 2011, commodity prices strengthened and demand for drilling activity improved. Continued fluctuations in the demand for natural 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, 2011 totaled $6.1 billion, representing an increase of $1.9 billion, or 47% as compared to the year ended December 31, 2010. Adjusted income derived from operating activities and net income (loss) from continuing operations for the year ended December 31, 2011 totaled $927.0 million and $342.2 million ($1.17 per diluted share), respectively, representing increases of 39% and 34%, respectively, compared to the year ended December 31, 2010.

32

Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2010 totaled $4.2 billion, representing an increase of $661.0 million, or 19% as compared to the year ended December 31, 2009. Adjusted income derived from operating activities and net income (loss) from continuing operations for the year ended December 31, 2010 totaled $667.5 million and $255.9 million ($.88 per diluted share), respectively, representing increases of 52% and 93%, respectively, compared to the year ended December 31, 2009.

During 2011, operating results improved as compared to 2010 primarily due to the incremental revenue and positive operating results from the addition of our Pressure Pumping operating segment beginning in September 2010, increased drilling activity in oil- and liquids-rich shale plays in our drilling operations in both our U.S. Lower 48 Land and Canada Drilling business units and increased well-servicing activity in the U.S. and Canada. 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 in the Gulf of Mexico; our Alaskan operations due to key customers’ spending constraints; and in Saudi Arabia due to downtime and reduced rates on several jackup rigs.

Our net income from continuing operations during 2011 was negatively impacted by $198.1 million in impairments and other charges, $100 million of which related to a provision for a contingent liability that existed on December 31, 2011 for a potential termination payment to our former Chief Executive Officer. See Note 3 for further discussion and subsequent developments. The remaining $98.1 million was comprised of a provision for retirement of long-lived assets recorded by multiple operating segments. This related to the decommissioning and retirement of assets previously utilized in our U.S. Lower 48 Land Drilling, International and U.S. Well-servicing operations and the amounts are reflected in the Impairments and other charges line in our consolidated statements of income (loss).

During 2010, operating results improved over 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 led to increased activity. However, our operating results and activity levels were negatively impacted in our U.S. Offshore, Alaska and International operations.

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 limited the use of our assets. Specifically, operating results were impacted because our customers suspended most of their operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. Our Alaska operating segment was negatively impacted because the largest operator in the area curtailed and suspended drilling operations, creating a surplus of rigs in the market and causing price competition. Our International results were flat as the increase of land rig activity was essentially offset by contract renewals on our jackup rigs at significantly lower average dayrates.

Our net income from continuing operations during 2010 was negatively impacted by impairments and other charges of $61.3 million. We recognized goodwill impairment and recorded provisions for retirement of long-lived assets 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 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. Discontinued operations include 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.

Our net income from continuing operations during 2009 was negatively impacted by impairments and other charges of $118.5 million. The impairments and other charges included recognition of other-than-temporary impairments of $54.3 million relating to our available-for-sale securities, and a provision for retirement totaling

33

$64.2 million to long-lived assets from our U.S. Offshore, Alaska, Canada and International contract drilling segments.

During 2011, we sold some of our wholly owned oil and gas assets in Colombia and received proceeds of $89.2 million. Additionally, Remora completed sales of its oil and gas assets in Colombia for gross proceeds of $333.1 million and has made cash distributions to us totaling $143.0 million during 2011 with a final distribution expected upon dissolution of the joint venture. We sold our working interest in properties located in California and received proceeds of $71.6 million. Our discontinued operations also include impairments of $255.0 million relating to oil and gas-centered assets and $7.9 million relating to carrying value aircraft and other drilling equipment.

We expect our operating results for 2012 to increase from levels realized during 2011, driven by the anticipated sustained higher oil prices and the related impact on drilling and well-servicing activity and dayrates, along with the contributions from our Pressure Pumping operating segment. The key factors supporting our projections are:

• An increase in drilling in oil- and liquids-rich areas incremental to traditional dry gas regions by our U.S. Lower 48 Land and Canada Drilling and Well-servicing operations;

• The extent of current term contracts in both our Lower 48 rig and pressure-pumping segments, combined with new deployments in 2012, should serve to mitigate the impact of a potentially more rapid reduction in gas drilling activity arising from weaker natural gas pricing;

• Our expectation of a continued increase from ancillary well-site services, primarily technical pumping services and down-hole surveying services, resulting from our Pressure Pumping operating segment; and

• The anticipated positive impact on our overall level of drilling and well-servicing activity and margins resulting from our new and upgraded rigs and equipment added to our fleet over the past five years, which we expect will enhance our competitive position as market conditions improve.

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

	Year Ended December 31,									Increase/(Decrease)
	2011			2010			2009			2011 to 2010					2010 to 2009
	(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	$	1,698,620		$	1,294,853		$	1,082,531		$	403,767		31	%	$	212,322		20	%
U.S. Land Well-servicing		701,223			444,665			412,243			256,558		58	%		32,422		8	%
U.S. Offshore		170,727			123,761			157,305			46,966		38	%		(33,544	)	(21	)%
Alaska		129,894			179,218			204,407			(49,324	)	(28	)%		(25,189	)	(12	)%
Canada		574,754			389,229			298,653			185,525		48	%		90,576		30	%
International		1,104,461			1,093,608			1,265,097			10,853		1	%		(171,489	)	(14	)%
Subtotal Contract Drilling(3)		4,379,679			3,525,334			3,420,236			854,345		24	%		105,098		3	%
Pressure Pumping(4)		1,237,306			321,295			—			916,011		285	%		321,295		100	%
Oil and Gas(5)(6)		59,685			18,657			(182,654	)		41,028		220	%		201,311		110	%
Other Operating Segments(7)(8)		674,206			427,154			417,531			247,052		58	%		9,623		2	%
Other reconciling items(9)		(233,878	)		(124,690	)		(148,325	)		(109,188	)	(88	)%		23,635		16	%
Total	$	6,116,998		$	4,167,750		$	3,506,788		$	1,949,248		47	%	$	660,962		19	%

34

	Year Ended December 31,									Increase/(Decrease)
	2011			2010			2009			2011 to 2010					2010 to 2009
	(In thousands, except percentages and rig activity)
Adjusted income (loss) derived from operating activities from continuing operations:(1)(10)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	414,317		$	274,215		$	294,679		$	140,102		51	%	$	(20,464	)	(7	)%
U.S. Land Well-servicing		74,725			31,597			28,950			43,128		136	%		2,647		9	%
U.S. Offshore		843			9,245			30,508			(8,402	)	(91	)%		(21,263	)	(70	)%
Alaska		27,671			51,896			62,742			(24,225	)	(47	)%		(10,846	)	(17	)%
Canada		94,637			22,970			(7,019	)		71,667		312	%		29,989		427	%
International		123,813			254,744			365,566			(130,931	)	(51	)%		(110,822	)	(30	)%
Subtotal Contract Drilling(3)		736,006			644,667			775,426			91,339		14	%		(130,759	)	(17	)%
Pressure Pumping(4)		229,125			66,651			—			162,474		244	%		66,651		100	%
Oil and Gas(5)(6)		59,685			18,657			(182,654	)		41,028		220	%		201,311		110	%
Other Operating Segments(8)(9)		55,617			42,401			35,319			13,216		31	%		7,082		20	%
Other reconciling items(11)		(153,385	)		(104,827	)		(188,257	)		(48,558	)	(46	)%		83,430		44	%
Total	$	927,048		$	667,549		$	439,834		$	259,499		39	%	$	227,715		52	%
Interest expense		(256,633	)		(272,712	)		(266,047	)		16,079		6	%		(6,665	)	(3	)%
Investment income (loss)		19,940			7,263			25,522			12,677		175	%		(18,259	)	(72	)%
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net		(4,514	)		(47,238	)		(11,982	)		42,724		90	%		(35,256	)	(294	)%
Impairments and other charges(12)		(198,072	)		(61,292	)		(118,543	)		(136,780	)	(223	)%		57,251		48	%
Income (loss) from continuing operations before income taxes		487,769			293,570			68,784			194,199		66	%		224,786		327	%
Income tax expense (benefit)		142,605			36,950			(63,937	)		105,655		286	%		100,887		158	%
Subsidiary preferred stock dividend		3,000			750			—			2,250		300	%		750		100	%
Income (loss) from continuing operations, net of tax		342,164			255,870			132,721			86,294		34	%		123,149		93	%
Income (loss) from discontinued operations, net of tax		(97,440	)		(161,090	)		(218,609	)		63,650		40	%		57,519		26	%
Net income (loss)		244,724			94,780			(85,888	)		149,944		158	%		180,668		210	%
Less: Net (income) loss attributable to noncontrolling interest		(1,045	)		(85	)		342			(960	)	n/m	(16)		(427	)	(125	)%
Net income (loss) attributable to Nabors	$	243,679		$	94,695		$	(85,546	)	$	148,984		157	%	$	180,241		211	%
Rig activity:
Rig years:(13)
U.S. Lower 48 Land Drilling		200.2			174.5			149.4			25.7		15	%		25.1		17	%
U.S. Offshore		9.6			9.4			11.0			0.2		2	%		(1.6	)	(15	)%
Alaska		4.9			7.4			10.0			(2.5	)	(34	)%		(2.6	)	(26	)%
Canada		39.8			29.8			19.7			10.0		34	%		10.1		51	%
International(14)		105.3			97.8			100.2			7.5		8	%		(2.4	)	(2	)%
Total rig years		359.8			318.9			290.3			40.9		13	%		28.6		10	%
Rig hours:(15)
U.S. Land Well-servicing		791,956			643,813			590,878			148,143		23	%		52,935		9	%
Canada Well-servicing		184,908			172,589			143,824			12,319		7	%		28,765		20	%
Total rig hours		976,864			816,402			734,702			160,462		20	%		81,700		11	%

(1) All periods present the operating activities of our wholly owned oil and gas assets in the United States, Canada and Colombia, including equity interests in Canada and Colombia, as well as the Nabors Blue Sky Ltd. business as discontinued operations.

(2) These segments include our drilling, workover and well-servicing operations, on land and offshore.

35

(3) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.2) million, $6.9 million and $9.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.

(4) Includes operating results of the Superior acquisition beginning September 10, 2010.

(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 $(15.6) million and $(189.3) million for the years ended December 31, 2011 and 2009, respectively.

(6) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $59.7 million, $18.7 million and $(182.6) million for the years ended December 31, 2011, 2010 and 2009, 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 operations.

(8) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.9) million, $7.7 million and $17.5 million for the years ended December 31, 2011, 2010 and 2009, 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 in accordance with 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 accurately reflect 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 in the above table.

(11) Represents the elimination of inter-segment transactions and unallocated corporate expenses.

(12) Represents impairments and other charges recorded during the years ended December 31, 2011, 2010 and 2009, 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 2.1 years, 2.2 years and 2.5 years during the years ended December 31, 2011, 2010 and 2009, respectively.

(15) Rig hours represents the number of hours that our well-servicing rig fleet operated during the year.

(16) The percentage is so large that it is not meaningful.

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.

36

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

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010				2010 to 2009
	(In thousands, except percentages and rig activity)
Operating revenues	$	1,698,620	$	1,294,853	$	1,082,531	$	403,767	31	%	$	212,322		20	%
Adjusted income derived from operating activities	$	414,317	$	274,215	$	294,679	$	140,102	51	%	$	(20,464	)	(7	)%
Rig years		200.2		174.5		149.4		25.7	15	%		25.1		17	%

Operating results increased from 2010 to 2011 primarily due to higher average dayrates and increases in drilling activity, driven by deployment of rigs into oil- and liquids-rich shale areas. The increase was partially offset by higher operating costs associated with increased drilling activity, as well as higher depreciation expense related to new rigs placed into service since January 2010.

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 were $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 were negatively impacted by higher depreciation expense related to capital expansion projects completed in previous years.

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

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010				2010 to 2009
	(In thousands, except percentages and rig activity)
Operating revenues	$	701,223	$	444,665	$	412,243	$	256,558	58	%	$	32,422	8	%
Adjusted income derived from operating activities	$	74,725	$	31,597	$	28,950	$	43,128	136	%	$	2,647	9	%
Rig hours		791,956		643,813		590,878		148,143	23	%		52,935	9	%

Operating results increased from 2010 to 2011 primarily due to increases in rig and truck utilization facilitated by capital invested to increase rig and truck fleets as well as frac tank counts. Equipment utilization and price improvements experienced in 2011 were primarily driven by sustained higher oil prices.

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.

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

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010					2010 to 2009
	(In thousands, except percentages and rig activity)
Operating revenues	$	170,727	$	123,761	$	157,305	$	46,966		38	%	$	(33,544	)	(21	)%
Adjusted income derived from operating activities	$	843	$	9,245	$	30,508	$	(8,402	)	(91	)%	$	(21,263	)	(70	)%
Rig years		9.6		9.4		11.0		0.2		2	%		(1.6	)	(15	)%

Operating revenues increased from 2010 to 2011 as a result of higher workover activities by the Sundowner^® platform and jackup rigs and from profits related to a major construction project. Adjusted income

37

derived from operating activities decreased from 2010 to 2011 primarily due to lower utilization for the MODS^® rigs and SuperSundowner^TM platform rigs. Drilling permits have been subject to a lengthy and stringent safety and environmental review process since the Gulf of Mexico blowout in mid-2010.

The decrease in operating results from 2009 to 2010 primarily resulted from receiving standby rates and lower utilization for the MODS^® rigs, SuperSundowner^TM 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.

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

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010					2010 to 2009
	(In thousands, except percentages and rig activity)
Operating revenues and Earnings from unconsolidated affiliates	$	129,894	$	179,218	$	204,407	$	(49,324	)	(28	)%	$	(25,189	)	(12	)%
Adjusted income derived from operating activities	$	27,671	$	51,896	$	62,742	$	(24,225	)	(47	)%	$	(10,846	)	(17	)%
Rig years		4.9		7.4		10.0		(2.5	)	(34	)%		(2.6	)	(26	)%

The decreases in operating results from 2010 to 2011 and from 2009 to 2010 were primarily due to lower average dayrates and drilling activity. While drilling activity levels decreased significantly during 2010, operating results decreased only slightly due to the acceleration of recognized deferred revenues from a significant contract that terminated.

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

	Year Ended December 31,							Increase/(Decrease)
	2011		2010		2009			2011 to 2010				2010 to 2009
	(In thousands, except percentages and rig activity)
Operating revenues	$	574,754	$	389,229	$	298,653		$	185,525	48	%	$	90,576	30	%
Adjusted income (loss) derived from operating activities	$	94,637	$	22,970	$	(7,019	)	$	71,667	312	%	$	29,989	427	%
Rig years — Drilling		39.8		29.8		19.7			10.0	34	%		10.1	51	%
Rig hours — Well-servicing		184,908		172,589		143,824			12,319	7	%		28,765	20	%

Operating results increased from 2010 to 2011 primarily as a result of increases in drilling and well-servicing activity and drilling dayrates and well-servicing hourly rates. The increased drilling and well-servicing activity in Western Canada is the result of renewed interest in oil exploration, supported by strong oil commodity prices. Operating results were negatively impacted by higher drilling costs for well-servicing in 2011 for preparing service rigs for high utilization and additional labor costs for crew travel, retention and training.

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 was 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.

38

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

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010					2010 to 2009
	(In thousands, except percentages and rig activity)
Operating revenues and Earnings from unconsolidated affiliates	$	1,104,461	$	1,093,608	$	1,265,097	$	10,853		1	%	$	(171,489	)	(14	)%
Adjusted income derived from operating activities	$	123,813	$	254,744	$	365,566	$	(130,931	)	(51	)%	$	(110,822	)	(30	)%
Rig years		105.3		97.8		100.2		7.5		8	%		(2.4	)	(2	)%

Operating revenues and Earnings from unconsolidated affiliates increased from 2010 to 2011 as a result of increases in the utilization of our overall rig fleet albeit at lower margins. Adjusted income derived from operating activities decreased from 2010 to 2011 primarily from the decreases in average dayrates and lower utilization of our jackup rigs in Saudi Arabia and other drilling activities in Qatar and Australia.

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.

Pressure Pumping.     The results of operations for this segment were as follows:

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010				2010 to 2009
	(In thousands, except percentages and rig activity)
Operating revenues	$	1,237,306	$	321,295	$	—	$	916,011	285	%	$	321,295	100	%
Adjusted income derived from operating activities	$	229,125	$	66,651	$	—	$	162,474	244	%	$	66,651	100	%

Operating results reflect our acquisition of Superior for the year ended December 31, 2011 and the period September 10, 2010 through December 31, 2010. See Note 5 — Acquisitions in Part II, Item 8. — Financial Statements and Supplementary Data.

Oil and Gas.     The results of operations for this segment reflect our proportionate share of earnings and losses from our unconsolidated U.S. oil and gas joint venture. The results were as follows:

	Year Ended December 31,							Increase/(Decrease)
	2011		2010		2009			2011 to 2010				2010 to 2009
	(In thousands, except percentages)
Earnings (losses) from unconsolidated affiliates	$	59,685	$	18,657	$	(182,654	)	$	41,028	220	%	$	201,311	110	%

Earnings (losses) from unconsolidated affiliates increased from 2010 to 2011 as a result of operating activities from our unconsolidated U.S. oil and gas joint venture. During 2011, operating results included bargain purchase gains from multiple acquisitions of developed and undeveloped acreage. Our proportionate share of the gains totaled $49.5 million. A full-cost ceiling writedown of $15.6 million, representing our proportionate share, partially offset the positive operating results.

Earnings (losses) from unconsolidated affiliates increased from 2009 to 2010 because our unconsolidated U.S. oil and gas joint venture recorded a full-cost ceiling test writedown during 2009, of which our proportionate

39

share totaled $189.3 million. The writedown resulted from the application of the full-cost method of accounting for costs related to oil and natural gas properties. Operating results for our U.S. oil and gas joint venture, excluding the full-cost ceiling test writedown, improved from 2009 to 2010.

Other Operating Segments

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

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2010 to 2009				2009 to 2008
	(In thousands, except percentages)
Operating revenues and Earnings from unconsolidated affiliates	$	674,206	$	427,154	$	417,531	$	247,052	58	%	$	9,623	2	%
Adjusted income derived from operating activities	$	55,617	$	42,401	$	35,319	$	13,216	31	%	$	7,082	20	%

The increase in operating results from 2010 to 2011 and from 2009 to 2010 primarily resulted from higher demand in the United States and Canada drilling markets for top-drives, 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 services in Alaska.

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 included our 49.7% ownership interest in Remora, and then 50.0% ownership interest in SMVP, both of which we accounted for using the equity method of accounting. All of these assets are included in our Oil and Gas operating segment.

In June 2011, the equity owners of SMVP dissolved the partnership and a proportionate share of the assets and liabilities were conveyed to us in exchange for our ownership interest. We continue to market these assets for sale and believe that they are properly reflected in our assets held for sale balances at December 31, 2011.

During 2011, we sold some of our wholly owned oil and gas assets in Colombia. We received proceeds of $89.2 million from this sale and recognized a gain of approximately $39.6 million. Additionally during 2011, Remora completed sales of its oil and gas assets in Colombia. Remora received gross proceeds of approximately $333.1 million from these sales and has made cash distributions to us in the amount of $143.0 million, with a final distribution expected upon dissolution of the joint venture.

During the fourth quarter of 2011, we announced our intention to dispose of a significant portion of our oil and gas portfolio, and accordingly reclassified the carrying value of our wholly owned U.S. oil and gas assets to assets held for sale at December 31, 2011. During the fourth quarter of 2011, we also determined that one of our Canadian subsidiaries that provides logistics services for onshore drilling using helicopter and fixed-wing aircraft met the accounting criteria of assets held for sale. Based on quoted market prices, the carrying value of the assets was adjusted to its fair value, resulting in an impairment of $7.9 million, which is included in discontinued operations for the year ended December 31, 2011. We reclassified the adjusted carrying value of these assets to assets held for sale at December 31, 2011.

On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received proceeds of approximately $71.6 million from the sale and recognized a gain of approximately $7.2 million.

40

At December 31, 2011, our consolidated balance sheet included a current liability of discontinued operations of $54.3 million that is included in other liabilities and a noncurrent liability of discontinued operations of $71.4 million that is included in other long-term liabilities.

The operating results from the assets discussed above 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, 2011, 2010 and 2009 were as follows:

	Year Ended December 31,									Increase/(Decrease)
	2011			2010			2009			2011 to 2010				2010 to 2009
	(In thousands, except percentages)
Revenues	$	78,826		$	77,992		$	30,136		$	834	1	%	$	47,856	159	%
Earnings (losses) from unconsolidated affiliates	$	76,541	(1)	$	(10,638	)	$	(59,249	)(2)	$	87,179	820	%	$	48,611	82	%
Income (loss) from discontinued operations, net of tax
Income (loss) from discontinued operations, net of tax	$	(97,440	)(3)	$	(161,090	)(4)(7)	$	(218,609	)(5)(6)	$	63,650	40	%	$	57,519	26	%

(1) Includes approximately $83 million of equity in earnings during 2011 for our proportionate share of Remora’s net income, inclusive of the gains recognized for asset sales during 2011.

(2) Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million in 2009.

(3) Includes impairments of $255.0 million to write down the carrying value of our wholly owned oil and gas-centered assets, including $27.2 million related to an oil and gas financing receivable that was deemed uncollectible.

(4) Includes impairments of $192.2 million related to our wholly owned oil and gas assets. Of this total, $137.8 million represented writedowns to the carrying value of some acreage in the United States, which we currently do not have future plans to develop due to sustained low natural gas prices, and certain exploratory wells in Colombia, which we determined were uneconomical to develop in the foreseeable future. The remaining $54.3 million related to impairment of an oil and gas financing receivable and was determined using discounted cash flow models, a Level 3 measurement, and involved assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices.

(5) Includes impairments totaling $205.9 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 lasting 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. Annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $56.8 million to write down the carrying value of some acreage that we do not have future plans to develop.

(6) Includes $14.7 million to impair the remaining goodwill balance of Nabors Blue Sky Ltd. as a result of our annual goodwill impairment tests. We determined the impairment charge was 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.

(7) Includes $7.5 million of impairment to our aircraft and some drilling equipment during the year ended December 31, 2010. These impairment charges resulted from annual impairment tests on long-lived assets.

41

Additional discussion of our policy pertaining to the calculations of our annual impairment tests, including any impairment of goodwill, is set forth in Critical Accounting Estimates below in this section or in Note 2 — Summary of Significant Accounting Policies in Part II, Item 8. — Financial Statements and Supplementary Data. Additional information relating to discontinued operations is provided in Notes 4 — Discontinued Operations and 24 — Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. —Financial Statements and Supplementary Data. A further protraction of lower commodity prices or an inability to sell these assets in a timely manner could result in recognition of future impairment charges.

OTHER FINANCIAL INFORMATION

General and administrative expenses

	Year Ended December 31,									Increase/(Decrease)
	2011			2010			2009			2011 to 2010				2010 to 2009
	(In thousands, except percentages)
General and administrative expenses	$	489,892		$	338,720		$	421,492		$	151,172	45	%	$	(82,772)	(20	)%
General and administrative expenses as a percentage of operating revenues		8.1	%		8.2	%		11.5	%		(.1)%	1	%		(3.3)%	(29	)%

General and administrative expenses increased from 2010 to 2011 primarily as a result of increases in wages to support a higher headcount as a result of (i) our Superior acquisition in September 2010 and (ii) increased operations for a majority of our operating segments. As a percentage of operating revenues, general and administrative expenses decreased from 2010 to 2011.

General and administrative expenses decreased from 2009 to 2010 primarily as a result of significant decreases in wage-related expenses and other cost-reduction efforts across all business units.

Depreciation and amortization, and depletion expense

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010				2010 to 2009
	(In thousands, except percentages)
Depreciation and amortization expense	$	924,094	$	760,962	$	663,958	$	163,132	21	%	$	97,004	15	%

Depreciation and amortization expense increased from 2010 to 2011 and from 2009 to 2010 as a result of the incremental depreciation expense from (i) pressure pumping assets acquired in September 2010, (ii) newly constructed rigs recently placed into service and (iii) rig upgrades and other capital expenditures made during 2010 and 2011.

Interest expense

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010				2010 to 2009
	(In thousands, except percentages)
Interest expense	$	256,633	$	272,712	$	266,047	$	(16,079	)	(6)%	$	6,665	3	%

Interest expense decreased from 2010 to 2011 as a result of repurchases during 2010 and the redemption in May 2011 for a total of $2.6 billion in par value of the 0.94% senior exchangeable notes over 2010 and 2011. The decrease was partially offset by additional interest related to our August 2011 issuance of 4.625% senior notes due September 2021, a full year of interest on our September 2010 issuance of 5.0% senior notes due September 2020 and interest on amounts outstanding on our revolving credit facilities.

42

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.

Investment income (loss)

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010				2010 to 2009
	(In thousands, except percentages)
Investment income (loss)	$	19,940	$	7,263	$	25,522	$	12,677	175	%	$	(18,259	)	(72	)%

Investment income during 2011 was $19.9 million and included (i) a $12.9 million realized gain relating to one of our overseas fund investments classified as long-term investments, (ii) $5.1 million realized gains from short-term and other long-term investments and (iii) $9.9 million interest and dividend income from our cash, other short-term and long-term investments. Investment income was partially offset by net unrealized losses of $8.0 million from our trading securities.

Investment income during 2010 was $7.3 million and included interest and dividend income of $7.5 million from our cash, other short-term and long-term investments and $4.2 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 $25.5 million and included net unrealized gains of $9.8 million from our trading securities and interest and dividend income of $15.8 million from our cash, other short-term and long-term investments.

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

	Year Ended December 31,									Increase/(Decrease)
	2011			2010			2009			2011 to 2010					2010 to 2009
	(In thousands, except percentages)
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net	$	(4,514	)	$	(47,238	)	$	(11,982	)	$	(42,724	)	(90	)%	$	35,256	294	%

The amount of losses (gains) on sales and retirements of long-lived assets and other expense (income), net for 2011 was a net loss of $4.5 million and was comprised of (i) increases to our litigation reserves of $11.3 million, (ii) foreign currency exchange losses of approximately $5.5 million and (iii) a net loss on sales and retirements of long-lived assets of approximately $1.9 million. The net loss was partially offset by a $13.1 million gain recognized in connection with our acquisition of the remaining 50 percent equity interest of Peak.

The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2010 represented a net loss of $47.2 million and included: (i) foreign currency exchange losses of approximately $18.1 million, (ii) litigation expenses of $6.4 million, (iii) net losses on sales and retirements of long-lived assets of approximately $6.4 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 represented a net loss of $12.0 million and included: (i) foreign currency exchange losses of approximately $8.0 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.

43

Impairments and Other Charges

	Year Ended December 31,						Increase/(Decrease)
	2011		2010		2009		2011 to 2010					2010 to 2009
	(In thousands, except percentages)
Provision for termination payment	$	100,000	$	—	$	—	$	100,000		100	%	$	—		—
Provision for retirement of long-lived assets		98,072		23,213		64,229		74,859		322	%		(41,016	)	(64	)%
Impairment of long-lived assets		—		27,372		—		(27,372	)	(100	)%		27,372		100	%
Goodwill impairments		—		10,707		—		(10,707	)	(100	)%		10,707		100	%
Other-than-temporary impairment of equity security		—		—		18,665		—		—			(18,665	)	(100	)%
Other-than-temporary impairment of securities		—		—		35,649		—		—			(35,649	)	(100	)%
Total	$	198,072	$	61,292	$	118,543	$	136,780		223	%	$	(57,251	)	(48	)%

Provision for termination payment

During the fourth quarter of 2011, we recorded a provision for a contingent liability that existed on December 31, 2011 related to the change of our Chief Executive Officer that occurred in October. This charge resulted from the potential termination payment to our former Chief Executive Officer, Mr. Isenberg, under the terms of his employment contract. Subsequent to December 31, 2011, Mr. Isenberg elected to forego triggering that payment, and as a result, the Company does not owe the termination payment. In connection with that development, the Company announced plans to make charitable contributions to benefit the needs of its employees and other community-based causes. The Company contributed one million Nabors’ common shares previously held by an affiliate to the Nabors Charitable Foundation, a 501(c)(3) organization, in support of this objective. The election of Mr. Isenberg to forego triggering the potential payment, offset by the charitable contributions described above, will be recorded as a capital contribution during the first quarter of 2012.

Provision for retirement of long-lived assets

During 2011, we recorded a provision for retirement of long-lived assets totaling $98.1 million in multiple operating segments. This related to the decommissioning and retirement of one jackup rig, 116 land rigs, and a number of rigs for well-servicing and trucks. Our U.S. Lower 48 Land Drilling, International and U.S. Land Well-servicing operations recorded $63.2 million, $26.1 million and $8.9 million, respectively. These assets were deemed to be functionally or economically non-competitive for today’s market and are being dismantled for parts and scrap.

During 2010, we recorded a provision for retirement of long-lived assets totaling $23.2 million related to the abandonment of certain rig components, comprised of engines, top-drive units, building modules and other equipment that has become obsolete or inoperable in our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing and U.S. Offshore Contract Drilling operating segments.

During 2009, we recorded a provision for retirement of long-lived assets totaling $64.2 million related to assets in our U.S. Offshore, Alaska, Canada and International Contract Drilling operating segments. The retirements included inactive workover jackup 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.

44

Impairments of Long-Lived Assets

We did not record any impairment of long-lived assets in 2011. During 2010, we recognized $27.3 million in impairment charges related to some jackup rigs in our U.S. Offshore operating segment. These impairment charges stemmed from our annual impairment tests on long-lived assets.

The impairments and other charges, inclusive of the provisions for retirement and impairments of long-lived assets, recognized during 2011, 2010 and 2009 were determined necessary as a result of continued lower commodity prices and uncertainty in the oil and gas 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.

Goodwill Impairments

We did not record any goodwill impairment in 2011. 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 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, our customers have continued to encounter delays in obtaining government permits. It is uncertain when this will improve. 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.

Other than Temporary Impairments of Debt and Equity Securities

We did not record any other-than-temporary impairments in 2011 or 2010. During 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 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.

45

Income tax rate

	Year Ended December 31,								Increase/(Decrease)
	2011			2010			2009		2011 to 2010					2010 to 2009
Effective income tax rate from continuing operations		29	%		13	%		(93)%		16	%	123	%		106	%	114	%

The increase in our effective tax rate from 2010 to 2011 is mainly a result of the increase in the proportion of income generated in the United States versus the international jurisdictions in which we operate. Income generated in the United States is generally taxed at a higher rate than international jurisdictions.

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 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 is derived, we do not believe it presents a meaningful basis for comparing our 2009 effective income tax rate to the 2010 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, 2011 and 2010.

46

Operating Activities.     Net cash provided by operating activities totaled $1.5 billion during 2011 compared to net cash provided by operating activities of $1.1 billion during 2010. Net cash provided by 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 $1.5 billion and $1.3 billion for the years ended December 31, 2011 and 2010, 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 $36.7 million and $202.4 million, respectively, in cash flows for the years ended December 31, 2011 and 2010.

Investing Activities.     Net cash used for investing activities totaled $1.9 billion during 2011 compared to net cash used for investing activities of $1.7 billion during 2010. The primary use of cash for investing activities is for capital expenditures related to rig-related enhancements, new construction and equipment, as well as sustaining capital expenditures. During 2011 and 2010, we used cash for capital expenditures totaling $2.0 billion and $930.3 million, respectively.

During 2011, we used cash of $55.5 million to acquire the remaining equity interest of Peak. 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 2011, cash of $71.6 million and $89.2 million was provided in proceeds from sales of our oil and gas assets in the United States and Colombia, respectively. During 2011 and 2010, we provided cash of $112.3 million and $40.9 million, respectively, to our unconsolidated affiliates. Additionally during 2011, we received distributions of $143.0 million from Remora related to proceeds it received from the sale of its oil and gas assets in Colombia.

Financing Activities.     Net cash provided by financing activities totaled $163.2 million during 2011 compared to net cash provided by financing activities of $280.3 million during 2010. During 2011, we have drawn $1.6 billion from our revolving credit facilities primarily for the redemption of the remaining $1.4 billion of our 0.94% senior exchangeable notes. During 2011, cash was provided from the receipt of $690.4 million in proceeds, net of debt issuance costs, from the issuance by Nabors Delaware of its 4.625% senior notes due September 2021 in August 2011 and was used to repay amounts then outstanding under the revolving credit facilities.

During 2010, cash was provided from the receipt of $682.3 million in proceeds, net of debt issuance costs, from the issuance by Nabors Delaware of its 5.0% senior notes due September 2020 in September 2010 and we used cash to purchase $273.9 million of our 0.94% senior exchangeable notes and to repay $124.0 million of Superior’s revolving credit facility and second lien notes.

During 2011 and 2010, cash was provided by our receipt of proceeds totaling $11.6 million and $8.2 million, respectively, from the exercise by our employees of options to acquire our common shares.

Future Cash Requirements

We expect capital expenditures over the next 12 months to approximate $1.5-1.7 billion. We had outstanding purchase commitments of approximately $1.0 billion at December 31, 2011, primarily for rig-related enhancements, new construction and equipment, as well as sustaining capital expenditures, other operating expenses and purchases of inventory. This amount could change significantly based on market conditions and new business opportunities. The level of our outstanding purchase commitments and our expected level of capital expenditures over the next 12 months represent a number of capital programs that are currently underway or planned. These programs will result in an expansion in the number of land drilling rigs, pressure pumping and well-servicing equipment that we own and operate. We can reduce the planned expenditures if necessary, or increase them if market conditions and new business opportunities warrant it.

47

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 debt or our common shares. Future acquisitions may be paid for using existing cash or by issuing debt or additional shares of our stock. 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, 2011:

	Payments due by Period
	Total		< 1 Year			1-3 Years			3-5 Years		Thereafter
	(In thousands)
Contractual cash obligations:
Long-term debt:(1)
Principal	$	4,635,000	$	275,000	(2)	$	860,000	(3)	$	—	$	3,500,000	(4)
Interest		1,823,925		246,213			462,911			462,826		651,975
Operating leases(5)		80,861		25,288			34,423			11,293		9,857
Purchase commitments(6)		962,235		774,617			128,648			58,970		—
Employment contracts(5)		14,158		9,752			3,905			501		—
Pension funding obligations		1,508		1,508			—			—		—
Transportation and Processing Contracts(7)		388,699		54,287			134,429			113,175		86,808
Total contractual cash obligations	$	7,906,386	$	1,386,665		$	1,624,316		$	646,765	$	4,248,640

The table above excludes liabilities for unrecognized tax benefits totaling $97.0 million as of December 31, 2011 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 13 — Income Taxes in Part II, Item 8. — Financial Statements and Supplementary Data.

(1) See Note 12 — Debt in Part II, Item 8. — Financial Statements and Supplementary Data.

(2) Includes Nabors Delaware’s 5.375% senior notes due August 2012.

(3) Represents amounts drawn on revolving credit facilities, which expire September 2014.

(4) Represents Nabors Delaware’s aggregate 6.15% senior notes due February 2018, 9.25% senior notes due January 2019, 5.0% senior notes due September 2020 and 4.625% senior notes due September 2021.

(5) See Note 18 — 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 pipeline companies 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. See Note 18 — Commitments and Contingencies in Part II, Item 8. — Financial Statements and Supplementary Data.

48

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.

See Note 18 — Commitments and Contingencies in Part II, Item 8. — Financial Statements and Supplementary Data for discussion of commitments and contingencies relating to (i) our employment agreement with Mr. Petrello that could result in a significant cash payment of $50 million by the Company if his employment were terminated in the event of death or disability or a cash payment of approximately $31.1 million if his employment were 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, availability under our various revolving credit facilities, and cash generated from operations. As of December 31, 2011, we had cash and investments of $539.5 million and working capital of $1.3 billion. We also had $540 million of availability remaining from a combined total of $1.4 billion under revolving credit facilities. At December 31, 2010, we had cash and investments of $801.2 million and working capital of $458.6 million.

On August 23, 2011, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 4.625% senior notes due 2021, which are unsecured and fully and unconditionally guaranteed by us. The notes have registration rights. The notes rank equal in right of payment to all of Nabors Delaware’s existing and future unsubordinated indebtedness, and senior in right of payment to all of Nabors Delaware’s existing and future senior subordinated and subordinated indebtedness. Our guarantee of the notes is unsecured and an unsubordinated obligation and ranks equal in right of payments to all of our unsecured and unsubordinated indebtedness from time to time outstanding. In the event of a change of control triggering event, as defined in the indenture, the holders of the notes may require Nabors Delaware to purchase all or a portion of the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture. We used a substantial portion of the proceeds from this offering to repay borrowings outstanding under our revolving credit facilities.

As of December 31, 2011, we had $540 million of remaining availability from a combined total of $1.4 billion under our existing revolving credit facilities. The existing revolving credit facilities mature in September 2014, and can be used for general corporate purposes, including capital expenditures and working capital.

During 2011, we sold some of our wholly owned oil and gas assets and received cash proceeds of $160.8 million. Additionally, Remora completed sales of its oil and gas assets and made cash distributions to us in the amount of $143.0 million.

We had six letter-of-credit facilities with various banks as of December 31, 2011. Availability under these facilities as of December 31, 2011 was as follows:

	(In thousands)
Credit available	$	215,901
Letters of credit outstanding, inclusive of financial and performance guarantees		(80,408	)
Remaining availability	$	135,493

49

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 gross funded debt to capital ratio was 0.43:1 as of December 31, 2011 and 0.42:1 as of December 31, 2010. Our net funded debt to capital ratio was 0.40:1 as of December 31, 2011 and 0.38:1 as of December 31, 2010.

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 investments. 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 8.1:1 as of December 31, 2011 and 7.0:1 as of December 31, 2010. The interest coverage ratio is a trailing 12-month quotient of the sum of (x) income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, subsidiary preferred stock dividends, depreciation and amortization, impairments and other charges, income tax expense (benefit) and our proportionate share of writedowns from our unconsolidated oil and gas joint venture less investment income (loss) divided by (y) the sum of cash interest expense and 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.

Our current cash and investments, projected cash flows from operations, possible dispositions of non-core assets and our revolving credit facilities are expected to adequately finance our purchase commitments, scheduled debt service requirements, and all other expected cash requirements for the next 12 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.

50

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
	2012		2013		2014		Thereafter		Total
	(In thousands)
Financial standby letters of credit and other financial surety instruments	$	105,055	$	38	$	—	$	—	$	105,093

Other Matters

Recent Accounting Pronouncements

In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revised 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 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 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 were effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. 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 were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we had significant oil and gas activities under the new definition. Our oil and gas disclosures for the years ending December 31, 2011 and 2010 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 FASB’s Accounting Standards Codification (“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 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, became applicable to us for contracts entered into after June 15, 2010. The adoption of these rules did not have a significant impact on our consolidated financial statements.

In May 2011, the FASB issued an Accounting Standards Update (“ASU”) to clarify the application of some of the existing fair value measurement and disclosure requirements. These changes are effective for interim and annual periods that begin after December 15, 2011. The disclosure requirements did not have a significant impact on our consolidated financial statements.

In June 2011, the FASB issued an ASU relating to the presentation of other comprehensive income (“OCI”). This ASU does not change the items that are reported in OCI, but does remove the option to present the components of OCI within the statement of changes in equity. In addition, this ASU will require OCI presentation on the face of the financial statements. These changes are effective for interim and annual periods

51

that begin after December 15, 2011, and are applied retrospectively to all periods presented. Early adoption is permitted. We adopted the ASU beginning January 1, 2012, and it did not have an impact on our consolidated financial statements.

In September 2011, the FASB issued a revised ASU relating to goodwill impairment tests. An entity is allowed to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on its qualitative assessment, that it is more likely than not that the fair value is less than its carrying amount. The amendment is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. We adopted the ASU beginning January 1, 2012 and will apply it to our goodwill impairment tests.

Related-Party Transactions

The Company and Nabors Delaware entered into an agreement with Eugene M. Isenberg, the Chairman of our Board of Directors, on February 2, 2012 but effective December 31, 2011, pursuant to which:

• Mr. Isenberg voluntarily terminated both his employment with the Company and his Employment Agreement, and forwent any right to payment in connection with such termination, including a possible payment of $100 million in connection with the Company’s appointment of a new chief executive officer on October 28, 2011, which Mr. Isenberg could have treated as a constructive termination under his employment agreement;

• Mr. Isenberg will continue as Chairman of the Board, but will not stand for reelection as a director when his term expires in June 2012; at that time, he will be appointed Chairman Emeritus for a three-year term, which will be extended for additional one-year terms unless terminated by him or by the Company, and receive cash compensation equal to other nonemployee directors;

• Nabors Delaware will pay $6,600,000 into an escrow account, which will bear interest at the guaranteed rate of 6% per annum compounded daily and will be distributed either to Mr. Isenberg’s estate or to the trustees of his revocable trust;

• Mr. Isenberg ceases participation in the Company’s benefit plans and forfeits any benefits available to him thereunder (including forfeiture of the balance in his deferred bonus account), except as stated below or otherwise required by law:

• he and his spouse continue to participate in medical, dental and life insurance coverage until either receives equivalent coverage and benefits under the plans and programs of a subsequent employer or their death;

• he remains entitled to distribution of vested account balances in the Company’s 401(k) plan and its Deferred Compensation Plan;

• he retains certain benefits under the split-dollar life insurance agreements in effect between him and Nabors Delaware

• all of Mr. Isenberg’s stock option and restricted stock awards were already fully vested and remain subject to the applicable plans and agreements governing them; and

• Mr. Isenberg waives all claims or other liabilities related to his Employment Agreement or his termination of employment, and the Company waives certain claims against Mr. Isenberg.

Nabors and certain key employees, including Messrs. Isenberg and Petrello, 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

52

individual. We will not be reimbursed for the premium payments paid on behalf of Mr. Isenberg as provided by the agreement entered into on February 2, 2012. 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 $6.3 million related to these policies. The cash surrender value of these policies of approximately $5.8 million and $9.5 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2011 and 2010, respectively.

Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors under the agreements with Messrs. Isenberg and Petrello 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 $218.4 million, $271.6 million and $327.3 million for the years ended December 31, 2011, 2010 and 2009, respectively. Expenses from business transactions with these affiliated entities totaled $.9 million, $3.4 million and $9.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. Additionally, we had accounts receivable from these affiliated entities of $110.7 million and $97.8 million as of December 31, 2011 and 2010, respectively. We had accounts payable to these affiliated entities of $46.1 million and $12.7 million as of December 31, 2011 and 2010, respectively, and long-term payables with these affiliated entities of $.8 million as of each of December 31, 2011 and 2010, 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 2011 and 2010, we recognized $2.0 million and $1.4 million, respectively, 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 first quarter of 2010, we purchased shares of Shona’s preferred stock and warrants to purchase additional common shares for $.9 million, which we had accounted for under the cost method of accounting. During 2011, Shona became a public company in Canada, with voting common shares listed on the TSX Venture Exchange. As of December 31, 2011, we held a minority interest of approximately 7.55% of the issued and outstanding common shares of Shona. The fair value of this equity security investment is $10.5 million.

Critical Accounting Estimates

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

53

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, 2011, and depreciation constituted 16.4% of our total costs and other deductions for the year ended December 31, 2011.

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 jackup 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 jackup 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 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

54

December 31, 2011, 2010 and 2009, 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 annually or 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. Impairment charges are recorded using discounted cash flows, which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or 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, 2011, 2010 and 2009, 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 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 3.9% of our total assets as of December 31, 2011. 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 2011, 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 Pressure Pumping segment; our oil and gas segment; and our other operating segments: Canrig Drilling Technology Ltd., Ryan Directional Services Inc. 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. During 2011, we concluded that all our operating segment’s fair values were substantially in excess of their carrying value with the exception of the U.S. Land Well-servicing and International segments. These operating segments had an excess of fair value over carrying value of approximately 20%. 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 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

55

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 and 2009, we recognized goodwill impairments of approximately $10.7 million and $14.7 million, respectively. 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 had suspended drilling operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. 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 led to reduced capital spending by our customers and diminished demand for our drilling services and for immediate access to remote drilling sites. 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.

As further discussed above in Recent Accounting Pronouncements, we changed the manner in which we initially assess goodwill for impairment during 2012. Under new guidance, we will assess qualitative factors to determine whether to perform the two-step quantitative goodwill impairment tests.

Oil and Gas Properties.     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. 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. During 2011 and 2009, our proportionate share of those ventures’ full-cost ceiling test writedowns was $15.6 million and $237.1 million, respectively. No full-cost ceiling test writedowns were recorded by our unconsolidated oil and gas joint ventures during 2010.

Our wholly owned oil and gas investment portfolio and our unconsolidated ownership interest in Remora is reflected as Assets held for sale in our consolidated balance sheet at December 31, 2011. We evaluate the carrying value of our assets held for sale to the fair value of the assets less costs to sale to determine whether impairment is indicated.

A significantly prolonged period of lower oil and natural gas prices or a reduction to the estimation of reserve quantities could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges to our oil and gas properties.

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.

56

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 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 13 — 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.

57

For the year ended December 31, 2011, our provision for income taxes from continuing operations was $142.6 million, consisting of $109.7 million of current tax benefit and $32.9 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 29% to 30% would increase the current year income tax provision by approximately $4.7 million.

Litigation and 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 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 2011, 2010 and 2009, no significant changes were made to the methodology utilized to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2011 reserves for insurance were adjusted (increased or decreased) by 10%, total costs and other deductions would change by $16.4 million, or .3%.

Fair Value of Assets Acquired and Liabilities Assumed.     We have completed a number of acquisitions in recent years as discussed in Note 7 — 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

58

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 2011, 2010 and 2009, 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 account for stock option and restricted stock awards 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 2011, 2010 and 2009, no significant changes were made to the methodology utilized to determine the assumptions used in these calculations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. This risk arises primarily as a result of potential changes in the fair market value of financial instruments 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

59

value of all our foreign currencies relative to the U.S. dollar as of December 31, 2011 would result in a $11.1 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 that 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 our 5.375%, 6.15%, 9.25%, 5.0% and 4.625% 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 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 to help mitigate and manage 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 $1.3 million and $3.4 million as of December 31, 2011 and 2010, respectively. During 2011, 2010 and 2009, we recorded gains (losses) of approximately $2.2 million, $(.1)

60

million and $1.4 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, 2011 would decrease the fair value of our range-cap-and-floor derivative instrument by approximately $.1 million.

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 and subsidiary preferred stock is estimated based on quoted market prices or prices quoted from third-party financial institutions. The carrying and fair values of these liabilities were as follows:

	December 31,
	2011							2010
	Effective Interest Rate			Carrying Value		Fair Value		Effective Interest Rate			Carrying Value		Fair Value
	(In thousands, except interest rates)
5.375% senior notes due August 2012(1)		5.61	%	$	274,604	$	281,188		5.61	%	$	273,977	$	291,500
6.15% senior notes due February 2018		6.42	%		967,490		1,113,986		6.42	%		966,276		1,041,008
9.25% senior notes due January 2019		9.33	%		1,125,000		1,419,514		9.33	%		1,125,000		1,393,943
5.00% senior notes due September 2020		5.20	%		697,343		734,475		5.20	%		697,037		678,335
4.625% senior notes due September 2021		4.75	%		697,667		708,176		—			—		—
0.94% senior exchangeable notes due May 2011		—			—		—		6.13	%		1,378,178		1,403,315
Subsidiary preferred stock		4.0	%		69,188		68,625		4.0	%		69,188		68,625
Revolving credit facilities		2.35	%		860,000		860,000		—			—		—
Other		—			1,712		1,712		—			2,676		2,676
				$	4,693,004	$	5,187,676				$	4,512,332	$	4,879,402

(1) Includes $.3 million and $.7 million as of December 31, 2011 and 2010, respectively, related to the unamortized loss on the interest rate swap that was unwound during the fourth quarter of 2005.

61

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,
	2011					2010
	Fair Value		Interest Rates	Weighted- Average Life (Years)		Fair Value		Interest Rates	Weighted- Average Life (Years)
	(In thousands, except interest rates)
Cash and cash equivalents	$	398,575	0 - .21%		0.00	$	641,702	0 - .28%		0.00
Short-term investments:
Trading equity securities		11,600	—		—		19,630	—		—
Available-for-sale equity securities		71,433	—		—		79,698	—		—
Available-for-sale debt securities:
Commercial paper and CDs		1,230	1.0%		.6		1,275	.75%		.6
Corporate debt securities		51,300	10.01 - 13.98%		2.5		52,022	10.01 - 13.99%		3.6
Mortgage-backed debt securities		309	2.4%		1.7		372	2.79%		2.7
Mortgage-CMO debt securities		2,547	.44 - 5.9%		.2		3,015	.42 - 5.9%		.3
Asset-backed debt securities		2,495	.78 - 4.8%		.8		3,476	.56 - 4.81%		1.3
Total available-for-sale debt securities		57,881					60,160
Total available-for-sale securities		129,314					139,858
Total short-term investments		140,914					159,488
Long-term investments and other receivables:
Actively managed funds		5,941	N/A				7,427	N/A
Oil and gas financing receivables		5,183	13.10%				32,873	13.10 -13.52%
Total long-term investments and other receivables		11,124					40,300
Total cash, cash equivalents, short-term and long-term investments and other receivables	$	550,613				$	841,490

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, 2011 would decrease the fair value of our trading securities and available-for-sale securities by $1.2 million and $12.9 million, respectively.

62

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX

	Page No.
Report of Independent Registered Public Accounting Firm		64
Consolidated Balance Sheets as of December 31, 2011 and 2010		65
Consolidated Statements of Income (Loss) for the Years Ended December 31, 2011, 2010 and 2009		66
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		67
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2011, 2010 and 2009		68
Notes to Consolidated Financial Statements		70

63

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, 2011 and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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.

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

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

/s/    PricewaterhouseCoopers LLP

Houston, Texas

February 29, 2012

64

NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(In thousands, except per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	398,575		$	641,702
Short-term investments		140,914			159,488
Assets held for sale		401,500			352,048
Accounts receivable, net		1,576,555			1,116,510
Inventory		272,852			158,836
Deferred income taxes		127,874			31,510
Other current assets		170,044			152,836
Total current assets		3,088,314			2,612,930
Long-term investments and other receivables		11,124			40,300
Property, plant and equipment, net		8,629,946			7,815,419
Goodwill		501,258			494,372
Investment in unconsolidated affiliates		371,021			267,723
Other long-term assets		310,477			415,825
Total assets	$	12,912,140		$	11,646,569
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	275,326		$	1,379,018
Trade accounts payable		782,753			355,282
Accrued liabilities		716,773			394,292
Income taxes payable		27,710			25,788
Total current liabilities		1,802,562			2,154,380
Long-term debt		4,348,490			3,064,126
Other long-term liabilities		292,758			245,765
Deferred income taxes		797,925			770,247
Total liabilities		7,241,735			6,234,518
Commitments and contingencies (Note 18)
Subsidiary preferred stock (Notes 5 and 15)		69,188			69,188
Equity:
Shareholders’ equity:
Common shares, par value $.001 per share:
Authorized common shares 800,000; issued 317,042 and 315,034, respectively		317			315
Capital in excess of par value		2,287,743			2,255,787
Accumulated other comprehensive income		321,264			342,052
Retained earnings		3,956,364			3,707,881
Less: treasury shares, at cost, 29,414 common shares		(977,873	)		(977,873	)
Total shareholders’ equity		5,587,815			5,328,162
Noncontrolling interest		13,402			14,701
Total equity		5,601,217			5,342,863
Total liabilities and equity	$	12,912,140		$	11,646,569

The accompanying notes are an integral part of these consolidated financial statements.

65

NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

	Year Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Revenues and other income:
Operating revenues	$	6,060,351		$	4,134,483		$	3,662,220
Earnings (losses) from unconsolidated affiliates		56,647			33,267			(155,432	)
Investment income (loss)		19,940			7,263			25,522
Total revenues and other income		6,136,938			4,175,013			3,532,310
Costs and other deductions:
Direct costs		3, 775,964			2,400,519			1,981,504
General and administrative expenses		489,892			338,720			421,492
Depreciation and amortization		924,094			760,962			663,958
Interest expense		256,633			272,712			266,047
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		4,514			47,238			11,982
Impairments and other charges		198,072			61,292			118,543
Total costs and other deductions		5,649,169			3,881,443			3,463,526
Income (loss) from continuing operations before income taxes		487,769			293,570			68,784
Income tax expense (benefit):
Current		109,702			(77,209	)		71,458
Deferred		32,903			114,159			(135,395	)
Total income tax expense (benefit)		142,605			36,950			(63,937	)
Subsidiary preferred stock dividend		3,000			750			—
Income (loss) from continuing operations, net of tax		342,164			255,870			132,721
Income (loss) from discontinued operations, net of tax		(97,440	)		(161,090	)		(218,609	)
Net income (loss)		244,724			94,780			(85,888	)
Less: Net (income) loss attributable to noncontrolling interest		(1,045	)		(85	)		342
Net income (loss) attributable to Nabors	$	243,679		$	94,695		$	(85,546	)
Earnings (losses) per share:
Basic from continuing operations	$	1.19		$	.90		$	.47
Basic from discontinued operations		(.34	)		(.57	)		(.77	)
Total Basic	$	.85		$	.33		$	(.30	)
Diluted from continuing operations	$	1.17		$	.88		$	.46
Diluted from discontinued operations		(.34	)		(.55	)		(.76	)
Total Diluted	$	.83		$	.33		$	(.30	)
Weighted-average number of common shares outstanding:
Basic		287,118			285,145			283,326
Diluted		292,484			289,996			286,502

The details of credit-related impairments to investments is presented below:

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.

66

NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Cash flows from operating activities:
Net income (loss) attributable to Nabors	$	243,679		$	94,695		$	(85,546	)
Adjustments to net income (loss):
Depreciation and amortization		927,460			766,519			668,415
Depletion and other exploratory expenses		44,551			27,002			11,078
Deferred income tax expense (benefit)		(34,739	)		55,964			(218,760	)
Deferred financing costs amortization		5,107			5,431			6,133
Pension liability amortization and adjustments		818			664			844
Discount amortization on long-term debt		27,042			70,719			86,802
Amortization of loss on hedges		927			786			580
Impairments and other charges		460,971			260,931			339,129
Losses (gains) on long-lived assets, net		(51,945	)		(1,050	)		12,339
Losses (gains) on investments, net		(12,486	)		191			(9,954	)
Losses (gains) on debt retirement, net		58			7,042			(11,197	)
Losses (gains) on derivative instruments		234			2,471			338
Gain on acquisition		(13,114	)		—			—
Share-based compensation		21,244			13,746			106,725
Foreign currency transaction losses (gains), net		5,725			17,880			8,372
Equity in (earnings) losses of unconsolidated affiliates, net of dividends		(132,388	)		(13,630	)		229,813
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(459,455	)		(249,725	)		450,530
Inventory		(114,896	)		(15,201	)		52,995
Other current assets		(24,820	)		6,589			205,108
Other long-term assets		71,867			7,509			(22,233	)
Trade accounts payable and accrued liabilities		517,615			70,463			(146,470	)
Income taxes payable		999			(19,208	)		(62,535	)
Other long-term liabilities		(27,967	)		(2,804	)		(5,534	)
Net cash provided by operating activities		1,456,487			1,106,984			1,616,972
Cash flows from investing activities:
Purchases of investments		(11,746	)		(34,147	)		(32,674	)
Sales and maturities of investments		39,063			34,613			57,033
Cash paid for acquisition of businesses, net		(55,459	)		(733,630	)		—
Investment in unconsolidated affiliates		(112,262	)		(40,936	)		(125,076	)
Distribution of proceeds from asset sales of unconsolidated affiliates		142,984			—			—
Capital expenditures		(2,042,617	)		(930,277	)		(1,093,435	)
Proceeds from sales of assets and insurance claims		180,558			31,072			31,375
Net cash used for investing activities		(1,859,479	)		(1,673,305	)		(1,162,777	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		6,375			(6,298	)		(18,157	)
Proceeds from issuance of long-term debt		697,578			696,948			1,124,978
Debt issuance costs		(7,141	)		(8,934	)		(8,832	)
Payments for (proceeds from) hedge transactions		—			(5,667	)		—
Proceeds from revolving credit facilities		1,560,000			600,000			—
Proceeds from issuance of common shares		11,605			8,201			11,249
Reduction in long-term debt		(1,404,281	)		(398,514	)		(1,081,801	)
Reduction in revolving credit facilities		(700,000	)		(600,000	)		—
Repurchase of equity component of convertible debt		(12	)		(4,712	)		(6,586	)
Settlement of call options and warrants, net		—			1,134			—
Purchase of restricted stock		(2,626	)		(1,935	)		(1,515	)
Tax benefit related to share-based awards		1,747			31			37
Net cash provided by financing activities		163,245			280,254			19,373
Effect of exchange rate changes on cash and cash equivalents		(3,380	)		(46	)		12,160
Net increase (decrease) in cash and cash equivalents		(243,127	)		(286,113	)		485,728
Cash and cash equivalents, beginning of period		641,702			927,815			442,087
Cash and cash equivalents, end of period	$	398,575		$	641,702		$	927,815

The accompanying notes are an integral part of these consolidated financial statements.

67

NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

				Common Shares					Capital in Excess of Par Value			Accumulated Other Comprehensive Income			Retained Earnings			Treasury Shares			Non- controlling Interest			Total Equity
				Shares			Par Value
				(In thousands)
Balances, December 31, 2008					312,343		$	312	$	2,129,415		$	53,520		$	3,698,732		$	(977,873	)	$	14,318		$	4,918,424
Comprehensive income (loss):
Net income (loss) attributable to Nabors	$	(85,546	)													(85,546	)								(85,546	)
Translation adjustment attributable to Nabors		150,290											150,290												150,290
Unrealized gains/(losses) on marketable securities, net of income benefit of $839		36,727											36,727												36,727
Unrealized gains/(losses) on adjusted basis for marketable debt security, net of income taxes of $1,199		1,956											1,956												1,956
Less: Reclassification adjustment for (gains)/losses included in net income (loss), net of income tax benefit of $4,921		49,386											49,386												49,386
Pension liability amortization, net of income taxes of $325		519											519												519
Pension liability adjustment, net of income taxes of $89		130											130												130
Unrealized gains/(losses) and amortization of (gains)/losses on cash flow hedges, net of income tax benefit of $18		178											178												178
Comprehensive income (loss) attributable to Nabors	$	153,640
Net income (loss) attributable to noncontrolling interest		(342	)																			(342	)		(342	)
Translation adjustment attributable to noncontrolling interest		2,024																				2,024			2,024
Comprehensive income (loss) attributable to noncontrolling interest		1,682
Total comprehensive income (loss)	$	155,322
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options					1,476			2		11,247															11,249
Nabors Exchangeco shares exchanged					105																				—
Share-based compensation										106,725															106,725
Other					(9	)				(8,064	)											(1,677	)		(9,741	)
Balances, December 31, 2009					313,915		$	314	$	2,239,323		$	292,706		$	3,613,186		$	(977,873	)	$	14,323		$	5,181,979
Balances, December 31, 2009					313,915		$	314	$	2,239,323		$	292,706		$	3,613,186		$	(977,873	)	$	14,323		$	5,181,979
Comprehensive income (loss):
Net income (loss) attributable to Nabors	$	94,695														94,695									94,695
Translation adjustment attributable to Nabors		60,897											60,897												60,897
Unrealized gains/(losses) on marketable securities, net of income taxes of $7,435		(7,157	)										(7,157	)											(7,157	)
Less: Reclassification adjustment for (gains)/losses included in net income (loss), net of income taxes of $693		(1,001	)										(1,001	)											(1,001	)
Pension liability amortization, net of income taxes of $259		405											405												405
Pension liability adjustment, net of income tax benefit of $405		(635	)										(635	)											(635	)
Unrealized gains/(losses) and amortization of (gains)/losses on cash flow hedges, net of income tax benefit of $2,119		(3,163	)										(3,163	)											(3,163	)
Comprehensive income (loss) attributable to Nabors	$	144,041
Net income (loss) attributable to noncontrolling interest		85																				85			85
Translation adjustment attributable to noncontrolling interest		723																				723			723
Comprehensive income (loss) attributable to noncontrolling interest		808
Total comprehensive income (loss)	$	144,849
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options					714			1		8,200															8,201
Share-based compensation										13,746															13,746
Other					405					(5,482	)											(430	)		(5,912	)
Balances, December 31, 2010					315,034		$	315	$	2,255,787		$	342,052		$	3,707,881		$	(977,873	)	$	14,701		$	5,342,863

The accompanying notes are an integral part of these consolidated financial statements.

68

NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY — (Continued)

				Common Shares				Capital in Excess of Par Value			Accumulated Other Comprehensive Income			Retained Earnings		Treasury Shares			Non- controlling Interest			Total Equity
				Shares		Par Value
				(In thousands)
Balances, December 31, 2010					315,034	$	315	$	2,255,787		$	342,052		$	3,707,881	$	(977,873	)	$	14,701		$	5,342,863
Comprehensive income (loss):
Net income (loss) attributable to Nabors	$	243,679													243,679								243,679
Translation adjustment attributable to Nabors		(20,257	)									(20,257	)										(20,257	)
Unrealized gains/(losses) on marketable securities, net of income taxes of $86		5,270										5,270											5,270
Less: Reclassification adjustment for (gains)/losses included in net income (loss), net of income taxes of $0		(3,036	)									(3,036	)										(3,036	)
Pension liability amortization, net of income taxes of $319		499										499											499
Pension liability adjustment, net of income tax benefit of $2,421		(3,788	)									(3,788	)										(3,788	)
Unrealized gains/(losses) and amortization of (gains)/losses on cash flow hedges, net of income tax benefit of $239		524										524											524
Comprehensive income (loss) attributable to Nabors	$	222,891
Net income (loss) attributable to noncontrolling interest		1,045																		1,045			1,045
Translation adjustment attributable to noncontrolling interest		(185	)																	(185	)		(185	)
Comprehensive income (loss) attributable to noncontrolling interest		860
Total comprehensive income (loss)	$	223,751
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options					1,116		1		11,604														11,605
Share-based compensation									21,244														21,244
Other					892		1		(892	)					4,804					(2,159	)		1,754
Balances, December 31, 2011					317,042	$	317	$	2,287,743		$	321,264		$	3,956,364	$	(977,873	)	$	13,402		$	5,601,217

The accompanying notes are an integral part of these consolidated financial statements.

69

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1    Nature of Operations

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 499 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Middle East, the Far East, the South Pacific, Russia and Africa.

• We actively market approximately 581 rigs for land well-servicing and workover work in the United States and approximately 174 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 39 platform, 12 jackup and four barge rigs in the United States, including the Gulf of Mexico, and multiple international markets.

In addition to the foregoing services:

• We provide hydraulic fracturing, cementing, nitrogen and acid pressure pumping services with over 730,000 hydraulic horsepower in key basins throughout the United States and Canada.

• We offer a wide range of ancillary well-site services, including engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select U.S. 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 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 have invested in oil and gas exploration, development and production activities through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests.

The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, well-servicing, fluid logistics and workover operations, on land and offshore. Our hydraulic fracturing and downhole surveying services are included in our Pressure Pumping operating segment. Our oil and gas exploration, development and production operations are included in our Oil and Gas operating segment, or in discontinued operations in some cases. Our operating segments engaged in drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction operations are aggregated in our Other Operating Segments.

The consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications have been made to prior periods to conform to the current period presentation, with no effect on our consolidated financial position, results of operations or cash flows.

Note 2    Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of Nabors, as well as all majority owned and non-majority owned subsidiaries required to be consolidated under GAAP. Our consolidated financial statements

70

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

exclude majority owned entities for which we do not have either (1) the ability to control the operating and financial decisions and policies of that entity or (2) a controlling financial interest in a variable interest entity. All significant intercompany accounts and transactions are eliminated in consolidation.

Investments in operating entities where we have the ability to exert significant influence, but where we do not control operating and financial policies, are accounted for using the equity method. Our share of the net income (loss) of these entities is recorded as earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss), and our investment in these entities is included as a single amount in our consolidated balance sheets. Investments in unconsolidated affiliates accounted for using the equity method totaled $371.0 million and $265.8 million as of December 31, 2011 and 2010, respectively. Investments in unconsolidated affiliates accounted for using the cost method totaled $1.9 million as of December 31, 2010. At December 31, 2011 and 2010, assets held for sale included investments in unconsolidated affiliates accounted for using the equity method totaling $13.7 million and $79.5 million, respectively. See Note 4 — Discontinued Operations for additional information.

We have investments in offshore funds, which are classified as long-term investments and are accounted for using the equity method of accounting based on our ownership interest in each fund. The carrying value of these investments totaled $5.9 million and $7.4 million as of December 31, 2011 and 2010, respectively.

Cash and Cash Equivalents

Cash and cash equivalents include demand deposits and various other short-term investments with original maturities of three months or less.

Investments

Short-term investments

Short-term investments consist of equity securities, certificates of deposit, corporate debt securities, mortgage-backed debt securities and asset-backed debt securities. Securities classified as available-for-sale or trading are stated at fair value. Unrealized holding gains and temporary losses for available-for-sale securities are excluded from earnings and, until realized, are reported net of taxes in a separate component of equity. Unrealized holding losses are included in earnings during the period for which the loss is determined to be other-than-temporary. Gains and losses from changes in the market value of securities classified as trading are reported in earnings currently.

In computing realized gains and losses on the sale of equity securities, the specific-identification method is used. In accordance with this method, the cost of the equity securities sold is determined using the specific cost of the security when originally purchased.

Long-term investments and other receivables

We have 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). These investments are non-marketable and do not have published fair values. We account for these funds under the equity method of accounting based on our percentage ownership interest and recognize gains or losses as investment income (loss), currently based on changes in the net asset value of our investment during the current period.

71

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our oil and gas financing receivables, previously included in long-term investments, have been reclassified to assets held for sale. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment.

Inventory

Inventory is stated at the lower of cost or market. Cost is determined using the first-in, first-out method and includes the cost of materials, labor and manufacturing overhead. Inventory included the following:

	December 31, 2011		December 31, 2010
	(In thousands)
Raw materials	$	133,480	$	81,308
Work-in-progress		50,951		23,629
Finished goods		88,421		53,899
	$	272,852	$	158,836

Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We provide for the depreciation of our drilling and workover rigs using 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 jackup 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 jackup rigs, where a 30-year depreciable life is used, after provision for salvage value.

Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings — 10 to 30 years; well-servicing rigs — 3 to 15 years; marine transportation and supply vessels — 10 to 25 years; oilfield hauling and mobile equipment and other machinery and equipment — 3 to 10 years). Amortization of capitalized leases is included in depreciation and amortization expense. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations.

We review our assets for impairment annually or 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. Impairment charges are recorded using discounted cash flows which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could result in future impairments. A significantly prolonged period of lower oil and natural gas prices could adversely affect the demand for and prices of our services, which could result in future impairment charges. 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.

72

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil and Gas Properties

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 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. 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 Securities and Exchange Commission (“SEC”) rules. During 2011 and 2009, our proportionate share of those ventures’ full-cost ceiling test writedowns was $15.6 million and $237.1 million, respectively. No full-cost ceiling test writedowns were recorded by our unconsolidated oil and gas joint ventures during 2010.

Our wholly owned oil and gas investment portfolio and our unconsolidated ownership interest in Remora is reflected in Assets held for sale in our consolidated balance sheet at December 31, 2011. We evaluate the carrying value of our assets held for sale to the fair value of the assets less costs to sale to determine whether impairment is indicated.

A significantly prolonged period of lower oil and natural gas prices or a reduction to the estimation of reserve quantities could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges to our oil and gas properties.

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.

Goodwill

Goodwill represents the cost in excess of fair value of the net assets of companies acquired. 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 the reporting unit exceeds its fair value. All our operating segment’s fair values were substantially in excess of their carrying value with the exception of the U.S. Land Well-servicing and International segments. These operating segments had an excess of fair value over carrying value of approximately 20%. As further discussed below in Recent Accounting Pronouncements, we

73

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

changed the manner in which we initially assess goodwill for impairment during 2012. Under new guidance, we will assess qualitative factors to determine whether to perform the two-step quantitative goodwill impairment tests. A significantly prolonged period of lower oil and natural gas prices 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 Note 3 — Impairments and Other Charges for discussion of goodwill impairments.

The change in the carrying amount of goodwill for our various Contract Drilling segments, Pressure Pumping segment and Other Operating segments for the years ended December 31, 2011 and 2010 was as follows:

	Balance as of December 31, 2009		Acquisitions and Purchase Price Adjustments			Impairments			Cumulative Translation Adjustment		Balance as of December 31, 2010
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—		$	—	$	30,154
U.S. Land Well-servicing		50,839		5,000	(1)		—			—		55,839
U.S. Offshore		18,003		—			(10,707	)(2)		—		7,296
Alaska		19,995		—			—			—		19,995
International		18,983		—			—			—		18,983
Subtotal Contract Drilling		137,974		5,000			(10,707	)		—		132,267
Pressure Pumping		—		334,992	(3)		—			—		334,992
Other Operating Segments		26,291		—			—			822		27,113
Total	$	164,265	$	339,992		$	(10,707	)	$	822	$	494,372

	Balance as of December 31, 2010		Acquisitions and Purchase Price Adjustments			Impairments		Cumulative Translation Adjustment			Balance as of December 31, 2011
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—	$	—		$	30,154
U.S. Land Well-servicing		55,839		(767	)(1)		—		—			55,072
U.S. Offshore		7,296		—			—		—			7,296
Alaska		19,995		—			—		—			19,995
International		18,983		—			—		—			18,983
Subtotal Contract Drilling		132,267		(767	)		—		—			131,500
Pressure Pumping		334,992		—			—		—			334,992
Other Operating Segments		27,113		8,000	(4)		—		(347	)		34,766
Total	$	494,372	$	7,233		$	—	$	(347	)	$	501,258

(1) Represents the goodwill recorded in connection with our acquisition of Energy Contractors during 2010 and an adjustment to the goodwill recorded during 2011. See Note 5 — Acquisitions for additional discussion.

74

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2) Represents goodwill impairment associated with our U.S. Offshore operating segment. 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. See Note 3 — Impairments and Other Charges for additional information.

(3) Represents the goodwill recorded in connection with our acquisition of Superior. See Note 5 — Acquisitions for additional discussion.

(4) Represents goodwill recorded in connection with our acquisition of the remaining 50 percent equity interest of Peak. See Note 5 — Acquisitions for additional discussion.

Our Oil and Gas segment does not have any goodwill. Goodwill for the consolidated company, totaling approximately $12.9 million, is expected to be deductible for tax purposes.

Derivative Financial Instruments

We record derivative financial instruments (including certain derivative instruments embedded in other contracts) in our consolidated balance sheets at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Any change in fair value of derivative financial instruments that are speculative in nature and do not qualify for hedge accounting treatment is also recognized immediately in earnings. Proceeds received upon termination of derivative financial instruments qualifying as fair value hedges are deferred and amortized into income over the remaining life of the hedged item using the effective interest rate method.

Litigation and Insurance Reserves

We estimate our reserves related to litigation and insurance based on the facts and circumstances specific to the litigation and insurance claims and our past experience with similar claims. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions. See Note 18 — Commitments and Contingencies regarding self-insurance accruals. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can reasonably 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. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure.

Revenue Recognition

We recognize revenues and costs on daywork contracts daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. We defer revenue

75

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

related to mobilization periods and recognize the revenue over the term of the related drilling contract. Costs incurred related to a mobilization period for which a contract is secured are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. We defer recognition of revenue on amounts received from customers for prepayment of services until those services are provided.

We recognize revenue for top drives and instrumentation systems we manufacture when the earnings process is complete. This generally occurs when products have been shipped, title and risk of loss have been transferred, collectability is probable, and pricing is fixed and determinable.

In connection with the performance of our cementing services, we recognize product and service revenue when the products are delivered or services are provided to the customer and collectability is reasonably assured. Product sale prices are determined by published price lists provided to our customers.

We recognize, as operating revenue, proceeds from business interruption insurance claims in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements in excess of the carrying value of damaged assets are recognized in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements that are expected to be less than the carrying value of damaged assets are recognized at the time the loss is incurred and recorded in losses (gains) on sales and retirements of long-lived assets and other expense (income), net.

We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.

We recognize revenue on our interests in oil and gas properties as production occurs and title passes. We apply the entitlement method of accounting for natural gas revenue. Under this method, revenues are recognized based on our revenue interest of production from our properties in which sales are disproportionately allocated to owners because of marketing or other contractual arrangements. Accordingly, revenue is not recognized for deliveries in excess of our net revenue interest, while revenue is recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. Production volume is monitored to minimize these natural gas imbalances.

Share-Based Compensation

We record compensation expense for all share-based awards granted. The amount of compensation expense recognized is based on the grant-date fair value. See Note 8 — Share-Based Compensation for additional discussion.

Income Taxes

We are a Bermuda exempted company and are not subject to income taxes in Bermuda. Consequently, income taxes have been provided based on the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income taxes in these jurisdictions vary substantially. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year because our operations are conducted in different taxing jurisdictions.

We recognize increases to our tax reserves for uncertain tax positions along with interest and penalties as an increase to other long-term liabilities.

76

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For U.S. and other jurisdictional income tax purposes, we have net operating and other loss carryforwards that we are required to assess quarterly for potential valuation allowances. We consider the sufficiency of existing temporary differences and expected future earnings levels in determining the amount, if any, of valuation allowance required against such carryforwards and against deferred tax assets.

Nabors realizes an income tax benefit associated with certain awards issued under our stock plans. We recognize the benefits related to tax deductions up to the amount of the compensation expense recorded for the award in the consolidated statements of income (loss). Any excess tax benefit (i.e., tax deduction in excess of compensation expense) is reflected as an increase in capital in excess of par. Any shortfall is recorded as a reduction to capital in excess of par to the extent of our aggregate accumulated pool of windfall benefits, beyond which the shortfall would be recognized in the consolidated statements of income (loss).

Foreign Currency Translation

For certain of our foreign subsidiaries, such as those in Canada and Argentina, the local currency is the functional currency, and therefore translation gains or losses associated with foreign-denominated monetary accounts are accumulated in a separate section of the consolidated statements of changes in equity. For our other international subsidiaries, the U.S. dollar is the functional currency, and therefore local currency transaction gains and losses, arising from remeasurement of payables and receivables denominated in local currency, are included in our consolidated statements of income (loss).

Cash Flows

We treat the redemption price, including accrued original issue discount, on our convertible debt instruments as a financing activity for purposes of reporting cash flows in our consolidated statements of cash flows.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:

• financial instruments;

• depreciation of property, plant and equipment;

• impairment of long-lived assets;

• impairment of goodwill and intangible assets;

• impairment of oil and gas properties;

• valuation of oil and gas reserves;

• income taxes;

• litigation and self-insurance reserves;

• fair value of assets acquired and liabilities assumed; and

• share-based compensation.

77

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Recent Accounting Pronouncements

In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revised 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 Financial Accounting Standards Board (“FASB”) issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The 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 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 were effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. 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 were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we had significant oil and gas activities under the new definition. Our oil and gas disclosures for the years ended December 31, 2011 and 2010 are provided in Note 24 — Supplementary Information on Oil and Gas Exploration and Production Activities.

Effective January 1, 2010, we adopted the revised provisions relating to consolidation of variable interest entities within the Consolidations Topic of the FASB’s Accounting Standards Codification (“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 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, became applicable to us for contracts entered into after June 15, 2010. The adoption of these rules did not have a significant impact on our consolidated financial statements.

In May 2011, the FASB issued an Accounting Standards Update (“ASU”) to clarify the application of some of the existing fair value measurement and disclosure requirements. These changes are effective for interim and annual periods that begin after December 15, 2011. The disclosure requirements did not have a significant impact on our consolidated financial statements.

In June 2011, the FASB issued an ASU relating to the presentation of other comprehensive income (“OCI”). This ASU does not change the items that are reported in OCI, but does remove the option to present the components of OCI within the statement of changes in equity. In addition, this ASU will require OCI presentation on the face of the financial statements. These changes are effective for interim and annual periods that begin after December 15, 2011, and are applied retrospectively to all periods presented. Early adoption is permitted. We adopted the ASU beginning January 1, 2012 and it did not have an impact on our consolidated financial statements.

In September 2011, the FASB issued a revised ASU relating to goodwill impairment tests. An entity is allowed to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on its qualitative assessment, that it is more likely than not that the fair value is less than its

78

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

carrying amount. The amendment is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. We adopted the ASU beginning January 1, 2012 and will apply it to our goodwill impairment tests.

Note 3    Impairments and Other Charges

The following table provides the components of impairments and other charges recorded during the years ended December 31, 2011, 2010 and 2009:

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Provision for termination payment	$	100,000	$	—	$	—
Provision for retirement of long-lived assets		98,072		23,213		64,229
Impairment of long-lived assets		—		27,372		—
Goodwill impairments		—		10,707		—
Other-than-temporary impairment of equity security		—		—		18,665
Other-than-temporary impairment of debt security		—		—		40,300
Less other-than-temporary impairment recognized in accumulated other comprehensive income (loss)		—		—		(4,651	)
Credit-related impairment of investment		—		—		35,649
Impairments and other charges	$	198,072	$	61,292	$	118,543

Provision for termination payment

During the fourth quarter of 2011, we recorded a provision for a contingent liability that existed on December 31, 2011 related to the change of our Chief Executive Officer that occurred in October. This charge resulted from the potential termination payment to our former Chief Executive Officer, Mr. Isenberg, under the terms of his employment contract. Subsequent to December 31, 2011, Mr. Isenberg elected to forego triggering that payment, and as a result, the Company does not owe the termination payment. In connection with that development, the Company announced plans to make charitable contributions to benefit the needs of its employees and other community-based causes. The Company contributed one million Nabors’ common shares previously held by an affiliate to the Nabors Charitable Foundation, a 501(c)(3) organization, in support of this objective. The election of Mr. Isenberg to forego triggering the potential payment, offset by the charitable contributions described above, will be recorded as a capital contribution during the first quarter of 2012.

Provision for retirement of long-lived assets

During 2011, we recorded a provision for retirement of long-lived assets totaling $98.1 million in multiple operating segments. This related to the decommissioning and retirement of one jackup rig, 116 land rigs, and a number of rigs for well-servicing and trucks. Our U.S. Lower 48 Land Drilling, International and U.S. Land Well-servicing operations recorded $63.2 million, $26.1 million and $8.9 million, respectively. These assets were deemed to be functionally or economically non-competitive for today’s market and are being dismantled for parts and scrap.

During 2010, we recorded a provision for retirement of long-lived assets totaling $23.2 million related to the abandonment of certain rig components, comprised of engines, top-drive units, building modules and other equipment that had become obsolete or inoperable in our U.S. Lower 48 Land Drilling, U.S. Well-servicing and U.S. Offshore Contract Drilling operating segments.

79

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During 2009, we recorded a provision for retirement of long-lived assets totaling $64.2 million related to assets in our U.S. Offshore, Alaska, Canada and International Contract Drilling operating segments. The retirements included inactive workover jackup 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.

Impairments of Long-Lived Assets

We did not record any impairment of long-lived assets in 2011. During 2010, we recognized $27.3 million in impairment charges related to some jackup rigs in our U.S. Offshore operating segment. These impairment charges stemmed from annual impairment tests on long-lived assets.

The impairments and other charges, inclusive of the provisions for retirement and impairments of long-lived assets, recognized during 2011, 2010 and 2009 were determined necessary as a result of continued lower commodity prices and uncertainty in the oil and gas 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.

Goodwill Impairments

We did not record any goodwill impairment in 2011. 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 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, our customers have continued to encounter delays in obtaining government permits. It is uncertain when this will improve. 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 Note 2 — Summary of Significant Accounting Policies (included under the caption “Goodwill”) for amounts of goodwill related to each of our reporting units.

Other than Temporary Impairments of Debt and Equity Securities

We did not record any other-than-temporary impairments in 2011 or 2010. During 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

80

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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.

Note 4     Discontinued Operations

During 2010, we began actively marketing our oil and gas assets in Canada and Colombia, including our 49.7% and then 50.0% ownership interests in our investments of Remora and SMVP, respectively. All of these assets are included in our Oil and Gas operating segment.

In June 2011, the equity owners of SMVP dissolved the partnership and a proportionate share of the assets and liabilities were conveyed to us in exchange for our ownership interest. The exchange was not a material transaction to us and we accounted for it as a business combination. We continue to market these assets for sale, and believe that they are properly reflected in our assets held for sale balances at December 31, 2011.

In April 2011, we sold some of our wholly owned oil and gas assets in Colombia to an unrelated third party. We received proceeds of $89.2 million from this sale and recognized a gain of approximately $39.6 million. Additionally during the second quarter of 2011, Remora completed sales of its oil and gas assets in Colombia. Remora received gross proceeds of approximately $333.1 million from these sales and has made cash distributions to us in the amount of $143.0 million, with a final distribution expected upon dissolution of the joint venture.

During the fourth quarter of 2011, we announced our intention to dispose of a significant portion of our oil and gas portfolio in an expeditious and prudent manner, and accordingly, reclassified the carrying value of our wholly owned U.S. oil and gas assets to assets held for sale at December 31, 2011. During the fourth quarter of 2011, we also determined that one of our Canadian subsidiaries that provides logistic services for onshore drilling using helicopter and fixed-wing aircraft met the accounting criteria of assets held for sale. Based on quoted market prices, the carrying value of the assets was adjusted to its fair value, resulting in an impairment of $7.9 million, which is included in discontinued operations for the year ended December 31, 2011. We reclassified the adjusted carrying value of these assets to assets held for sale at December 31, 2011.

On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received proceeds of approximately $71.6 million from the sale and recognized a gain of approximately $7.2 million.

At December 31, 2011, our assets held for sale included suspended wells that have capitalized costs for more than one year. Specifically, on the north slope of Alaska, five wells, including two drilled in 2007, one drilled in 2008 and two drilled in 2010, were suspended with total capitalized costs of $42.8 million. Further drilling is needed over the area to determine if the discovery holds sufficient quantities of reserves to justify future investment of infrastructure. One well remains in the process of drilling with total capitalized costs of $12.1 million at December 31, 2011.

81

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2011, our consolidated balance sheet included a current liability of discontinued operations of $54.3 million that is included in other liabilities and a noncurrent liability of discontinued operations of $71.4 million that is included in other long-term liabilities.

The operating results from the assets discussed above for all periods presented are retroactively presented and accounted for as discontinued operations in the accompanying audited consolidated statements of income (loss) and the respective accompanying notes to the consolidated financial statements. Our condensed statements of income (loss) from discontinued operations for each operating segment for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Year Ended December 31,
Condensed Statements of Income — Oil and Gas Operating segment	2011			2010			2009
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates
Oil and Gas	$	125,654	(1)	$	37,615		$	(57,864	)(2)
Income (loss) from discontinued operations
Income (loss) from discontinued operations	$	18.660		$	(26,139	)	$	(81,678	)
Impairment on wholly owned assets		(255,046	)(3)		(192,179	)(4)		(205,897	)(5)
Gain (loss) on disposal of assets		46,811			—			—
Less: income tax expense (benefit)		(98,181	)		(62,028	)		(85,431	)
Income (loss) from discontinued operations, net of tax	$	(91,394	)	$	(156,290	)	$	(202,144	)

(1) Includes approximately $83 million of equity in earnings during 2011 for our proportionate share of Remora’s net income, inclusive of the gains recognized for asset sales during 2011.

(2) Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million during 2009.

(3) Includes impairments of $255.0 million to write down the carrying value of our wholly owned oil and gas-centered assets, including $27.2 million related to an oil and gas financing receivable that was deemed uncollectible.

(4) Includes impairments of $192.2 million related to our wholly owned oil and gas assets. Of this total, $137.8 million represented writedowns to the carrying value of some acreage in the United States, which we currently do not have future plans to develop due to sustained low natural gas prices, and certain exploratory wells in Colombia, which we determined were uneconomical to develop in the foreseeable future. The remaining $54.3 million related to impairment of an oil and gas financing receivable was determined using discounted cash flow models, a Level 3 measurement, and involved assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices.

(5) Includes impairments totaling $205.9 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 lasting 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. Annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $56.8 million to write down the carrying value of some acreage that we do not have future plans to develop.

82

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31,
Condensed Statements of Income — Other Operating Segments	2011			2010			2009
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates
Other Operating Segments	$	29,713		$	29,739		$	28,751
Income (loss) from discontinued operations
Income (loss) from discontinued operations	$	(210	)	$	1,059		$	(1,636	)
Goodwill impairment		—			—			(14,689	)(6)
Impairment of long-lived assets		(7,853	)		(7,460	)(7)		—
Gain (loss) on disposal of assets		—			—			—
Less: income tax expense (benefit)		(2,017	)		(1,601	)		140
Income (loss) from discontinued operations, net of tax	$	(6,046	)	$	(4,800	)	$	(16,465	)

(6) Includes $14.7 million to impair the remaining goodwill balance of Nabors Blue Sky Ltd. as a result of our annual goodwill impairment tests. We determined the impairment charge was 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.

(7) Includes $7.5 million of impairment to our aircraft and some drilling equipment during the year ended December 31, 2010. These impairment charges resulted from annual impairment tests on long-lived assets.

Additional discussion of our policy pertaining to the calculations of our annual impairment tests, including any impairment to goodwill, is set forth in Note 2 — Summary of Significant Accounting Policies. A further protraction of lower commodity prices or an inability to sell these assets in a timely manner could result in recognition of future impairment charges.

Note 5    Acquisitions

2011 Acquisitions

In July 2011, we paid $65 million in cash to acquire the remaining 50 percent equity interest of Peak, making it a wholly owned subsidiary on this date. Peak operates in Alaska, providing construction and rig moving services in icy conditions as well as light and heavy-duty moving, hauling and maintenance services. Previously, we held a 50 percent equity interest with a carrying value of $38.1 million that we had accounted for as an equity method investment. As a result of the acquisition, we consolidated the assets and liabilities of Peak during the third quarter of 2011 based on their respective fair values, in accordance with Topic 805 — Business Combinations. The excess of the estimated fair value of the assets and liabilities over the net carrying value of our previously held equity interest resulted in a gain of $13.1 million and is reflected in losses (gains) on sales and retirements of long-lived assets and other expense (income) for the year ended December 31, 2011.

In June 2011, the equity owners of SMVP dissolved the partnership and a proportionate share of the assets and liabilities were conveyed to us in exchange for our ownership interest. The assets continued to be presented as held for sale and the operating results in discontinued operations for all periods presented. See Note 4 — Discontinued Operations for additional discussion.

83

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2010 Acquisitions

In September 2010, we acquired through a tender offer and merger all of the outstanding common stock of Superior at a price per share equal to $22.12, for a cash purchase price of approximately $681.3 million. The effects of the Superior acquisition and the operating results are included in the accompanying consolidated financial statements for the period subsequent to the effective date of the acquisition. Superior contributed revenues of $1.2 billion to our consolidated revenues for the year ended December 31, 2011.

As part of this acquisition, we recognized $7.0 million of acquisition-related transaction costs in losses (gains) on sales and retirements of long-lived assets and other expense (income) for the year ended December 31, 2010. The acquisition-related transaction costs consisted primarily of investment banking fees and legal and accounting costs. The acquisition enhanced our well-servicing, including the addition of hydraulic fracturing to our services, and workover capacity work throughout the Appalachian, Mid-Continent, Rocky Mountain, Southeast and Southwest regions of the United States.

The following table provides the allocation of the purchase price as of the acquisition date. The purchase price for Superior was allocated to the net tangible and intangible assets acquired and liabilities assumed based on fair value. The excess of the purchase price over such fair values was recorded as goodwill.

	Estimated Fair Value
	(In thousands)
Assets:
Cash and cash equivalents	$	1,045
Accounts receivable		143,842
Inventory		33,963
Other current assets		7,612
Property, plant and equipment		415,000
Intangible assets		131,811
Goodwill		334,992
Other long-term assets		14,726
Total assets		1,082,991
Liabilities:
Current liabilities	$	78,277
Deferred income taxes		119,201
Long-term debt		124,792
Other long-term liabilities		10,258
Total liabilities		332,528
Preferred stock		69,188
Net assets acquired	$	681,275

84

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Intangible assets

We identified other intangible assets associated with fracturing and fluid logistics services, including trade name, technology, employment contracts and non-compete agreements and customer relationships. The amortization of the intangible assets is calculated on a straight-line basis, which estimates the consumption of economic benefits. The following table summarizes the intangible assets recognized at the acquisition date, the monthly amortization expense as well as their estimated useful lives:

	Estimated Fair Value		Monthly Amortization		Estimated Useful Life
	(In thousands)
Superior trade name	$	88,767	$	740		10 years
Technology		5,294		88		5 years
Employment contracts and non-compete agreements		675		33		1-3 years
Customer relationships		37,075		308		10 years
Total identifiable intangible assets	$	131,811	$	1,169

Goodwill

Goodwill of $335.0 million arising from the Superior acquisition consisted largely of the expected synergies and economies of scale from combining the operations of Nabors and Superior. We have allocated the goodwill to our Pressure Pumping operating segment. See Note 2 — Summary of Significant Account Policies for additional information.

Long-term debt

Long-term debt included a secured revolving credit facility and second lien notes at the acquisition date. As of December 31, 2010, all amounts outstanding had been repaid. See Note 12 — Debt for additional information.

On December 31, 2010, we purchased the business of Energy Contractors for a total cash purchase price of $53.4 million. The assets were comprised of vehicles and rig equipment and have been included in our U.S. Well-servicing operating segment. The purchase price was allocated to the net tangible and intangible assets acquired based on their fair value as of December 31, 2010. The excess of the purchase price over the fair values of the assets acquired was recorded as goodwill in the amount of $4.2 million.

Note 6    Cash and Cash Equivalents and Short-term Investments

Our cash and cash equivalents and short-term investments consisted of the following:

	December 31,		December 31,
	2011		2010
	(In thousands)
Cash and cash equivalents	$	398,575	$	641,702
Short-term investments:
Trading equity securities		11,600		19,630
Available-for-sale equity securities		71,433		79,698
Available-for-sale debt securities		57,881		60,160
Total short-term investments	$	140,914	$	159,488

85

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Certain information related to our cash and cash equivalents and short-term investments follows:

	December 31,
	2011							2010
	Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses
	(In thousands)
Cash and cash equivalents	$	398,575	$	—	$	—		$	641,702	$	—	$	—
Short-term investments:
Trading equity securities		11,600		5,876		—			19,630		13,906		—
Available-for-sale equity securities		71,433		33,075		—			79,698		38,176		(2,274	)
Available-for-sale debt securities:
Commercial paper and CDs		1,230		—		—			1,275		—		—
Corporate debt securities		51,300		22,494		(2,095	)		52,022		15,274		(18	)
Mortgage-backed debt securities		309		10		—			372		16		—
Mortgage-CMO debt securities		2,547		13		(15	)		3,015		21		(6	)
Asset-backed debt securities		2,495		—		(238	)		3,476		—		(268	)
Total available-for-sale debt securities		57,881		22,517		(2,348	)		60,160		15,311		(292	)
Total available-for-sale securities		129,314		55,592		(2,348	)		139,858		53,487		(2,566	)
Total short-term investments		140,914		61,468		(2,348	)		159,488		67,393		(2,566	)
Total cash, cash equivalents and short-term investments	$	539,489	$	61,468	$	(2,348	)	$	801,190	$	67,393	$	(2,566	)

Certain information related to the gross unrealized losses of our cash and cash equivalents and short-term investments follows:

	As of December 31, 2011
	Less Than 12 Months				More Than 12 Months
	Fair Value		Gross Unrealized Loss		Fair Value		Gross Unrealized Loss
	(In thousands)
Available-for-sale equity securities	$	—	$	—	$	—	$	—
Available-for-sale debt securities:(1)
Corporate debt securities		17,700		2,095		—		—
Mortgage-CMO debt securities		2,217		7		83		8
Asset-backed debt securities		—		—		2,494		238
Total available-for-sale debt securities		19,917		2,102		2,577		246
Total	$	19,917	$	2,102	$	2,577	$	246

(1) Our unrealized losses on available-for-sale debt securities held for more than one year are comprised of various types of securities. Each of these securities have a rating ranging from “A” to “AAA” from Standard & Poor’s and ranging from “A2” to “Aaa” from Moody’s Investors Service and is considered of high credit quality. In each case, we do not intend to sell these investments, and it is less likely than not that we will be required to sell them to satisfy our own cash flow and working capital requirements. We believe that we will be able to collect all amounts due according to the contractual terms of each investment and, therefore, do not consider the decline in value of these investments to be other-than-temporary at December 31, 2011.

86

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The estimated fair values of our corporate, mortgage-backed, mortgage-CMO and asset-backed debt securities at December 31, 2011, classified by time to contractual maturity, are shown below. Expected maturities differ from contractual maturities because the issuers of the securities may have the right to repay obligations without prepayment penalties and we may elect to sell the securities prior to the contractual maturity date.

	Estimated Fair Value
	December 31, 2011
	(In thousands)
Debt securities:
Due in one year or less	$	1,230
Due after one year through five years		—
Due in more than five years		56,651
Total debt securities	$	57,881

Certain information regarding our debt and equity securities is presented below:

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Available-for-sale:
Proceeds from sales and maturities	$	12,672	$	13,062	$	23,411
Realized gains (losses), net		3,036		1,692		(54,311	)(1)

(1) Includes other-than-temporary impairments of $18.7 million related to an equity security and a $35.6 million credit-related impairment to a corporate debt security.

Note 7    Fair Value Measurements

As defined in the ASC, fair value is the price that would be received upon sale of an asset or paid upon 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 subjective measure.

87

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2011. Our debt securities could transfer into or out of a Level 1 or 2 measure depending on the availability of independent and current pricing at the end of each quarter. Our financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Recurring Fair Value Measurements

	Fair Value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Short-term investments:
Available-for-sale equity securities — energy industry	$	60,923	$	10,510	$	—	$	71,433
Available-for-sale debt securities
Commercial paper and CDs		1,230		—		—		1,230
Corporate debt securities		—		51,300		—		51,300
Mortgage-backed debt securities		—		309		—		309
Mortgage-CMO debt securities		—		2,547		—		2,547
Asset-backed debt securities		2,495		—		—		2,495
Trading securities — energy industry		11,600		—		—		11,600
Total short-term investments	$	76,248	$	64,666	$	—	$	140,914
Liabilities:
Derivative contract	$	—	$	1,281	$	—	$	1,281

Nonrecurring Fair Value Measurements

Fair value measurements were applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis, which would consist of measurements primarily to goodwill, oil and gas financing receivables, intangible assets and other long-lived assets, assets acquired and liabilities assumed in a business combination, and asset retirement obligations.

88

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value of Financial Instruments

The fair value of our financial instruments has been estimated in accordance with GAAP. The fair value of our long-term debt and subsidiary preferred stock is estimated based on quoted market prices or prices quoted from third-party financial institutions. The carrying and fair values of these liabilities were as follows:

	December 31,
	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
5.375% senior notes due August 2012(1)	$	274,604	$	281,188	$	273,977	$	291,500
6.15% senior notes due February 2018		967,490		1,113,986		966,276		1,041,008
9.25% senior notes due January 2019		1,125,000		1,419,514		1,125,000		1,393,943
5.00% senior notes due September 2020		697,343		734,475		697,037		678,335
4.625% senior notes due September 2021		697,667		708,176		—		—
0.94% senior exchangeable notes due May 2011		—		—		1,378,178		1,403,315
Subsidiary preferred stock		69,188		68,625		69,188		68,625
Revolving credit facilities		860,000		860,000		—		—
Other		1,712		1,712		2,676		2,676
	$	4,693,004	$	5,187,676	$	4,512,332	$	4,879,402

(1) Includes $.3 million and $.7 million as of December 31, 2011 and 2010, 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.

As of December 31, 2011, our short-term investments were carried at fair market value and included $129.3 million and $11.6 million in securities classified as available-for-sale and trading, respectively. As of December 31, 2010, our short-term investments were carried at fair market value and included $139.9 million and $19.6 million in securities classified as available-for-sale and trading, respectively. The carrying values of our long-term investments that are accounted for using the equity method of accounting approximate fair value. The fair value of these long-term investments totaled $5.9 million and $7.4 million as of December 31, 2011 and 2010, respectively.

Note 8    Share-Based Compensation

Total share-based compensation expense, which includes both stock options and restricted stock, totaled $21.2 million, $13.7 million and $106.7 million for the years ended December 31, 2011, 2010 and 2009, respectively. Compensation expense related to awards of restricted stock totaled $13.4 million, $10.5 million and $88.9 million for the years ended December 31, 2011, 2010 and 2009, respectively, and is included in direct costs and general and administrative expenses in our consolidated statements of income (loss). Share-based compensation expense has been allocated to our various operating segments. See Note 22 — Segment Information. Total share-based compensation expense for 2009 included the recognition of $72.1 million of compensation expense related to previously granted restricted stock and option awards held by Nabors’ Chairman and then Chief Executive Officer, Eugene M. Isenberg, and its Deputy Chairman, President and then Chief Operating Officer, Anthony G. Petrello, that was unrecognized as of April 1, 2009. The recognition of this expense resulted from provisions of their respective new employment agreements which effectively eliminated the risk of forfeiture of such awards. See Note 18 — Commitments and Contingencies for additional information.

89

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The cash flows resulting from tax deductions in excess of the compensation cost recognized for share-based awards (excess tax benefits) are classified as financing cash flows. The actual tax benefit realized from share-based awards during the years ended December 31, 2011, 2010 and 2009 was $.2 million, $.1 million and $.3 million, respectively.

Stock Option Plans

As of December 31, 2011, we had several stock plans under which options to purchase our common shares could be granted to key officers, directors and managerial employees of Nabors and its subsidiaries. Options granted under the plans generally are at prices equal to the fair market value of the shares on the date of the grant. Options granted under the plans generally are exercisable in varying cumulative periodic installments after one year. In the case of certain key executives, options granted may vest immediately on the grant date. Options granted under the plans cannot be exercised more than ten years from the date of grant. Options to purchase 15.5 million and 17.3 million Nabors common shares remained available for grant as of December 31, 2011 and 2010, respectively. Of the common shares available for grant as of December 31, 2011, approximately 15.5 million of these shares are also available for issuance in the form of restricted shares.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model which uses assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatilities are based on implied volatilities from traded options on Nabors’ common shares, historical volatility of Nabors’ common shares, and other factors. We do not assume any dividend yield, since we do not pay dividends. We use historical data to estimate the expected term of the options and employee terminations within the option-pricing model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of the options represents the period of time that the options granted are expected to be outstanding.

We also consider an estimated forfeiture rate for these option awards, and we recognize compensation cost only for those shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of three to five years. The forfeiture rate is based on historical experience. Estimated forfeitures have been adjusted to reflect actual forfeitures during 2011.

Stock option transactions under our various stock-based employee compensation plans are presented below:

Options	Shares			Weighted-Average Exercise Price		Weighted- Average Remaining Contractual Term		Aggregate Intrinsic Value
	(In thousands, except exercise price)
Options outstanding as of December 31, 2010		28,932		$	18.73
Granted		931			15.67
Exercised		(1,116	)		12.50
Surrendered(1)		(418	)		13.53
Forfeited		(459	)		20.74
Options outstanding as of December 31, 2011		27,870		$	18.94		3.65 years	$	83,306
Options exercisable as of December 31, 2011		24,939		$	19.83		3.14 years	$	65,949

(1) Represents unexercised vested stock options that were surrendered by key officers and directors, to satisfy the option exercise price and related income taxes. See related discussion at Note 14 — Common Shares.

90

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Of the options outstanding, 24.9 million, 24.9 million and 27.2 million were exercisable at weighted-average exercise prices of $19.83, $20.19 and $21.04, as of December 31, 2011, 2010 and 2009, respectively.

During the years ended December 31, 2011, 2010 and 2009, respectively, we awarded options vesting over periods up to four years to purchase 930,753, 32,115 and 10,015,883 of our common shares to our employees, executive officers and directors.

The fair value of stock options granted during 2011, 2010 and 2009 was calculated using the Black-Scholes option pricing model and the following weighted-average assumptions:

	Year Ended December 31,
	2011			2010			2009
Weighted average fair value of options granted:	$	6.24		$	6.62		$	2.85
Weighted average risk free interest rate:		.65	%		1.49	%		1.75	%
Dividend yield:		0	%		0	%		0	%
Volatility:(1)		51.09	%		41.44	%		34.78	%
Expected life:		4.0 years			4.0 years			4.0 years

(1) Expected volatilities are based on implied volatilities from publicly traded options to purchase Nabors’ common shares, historical volatility of Nabors’ common shares and other factors.

A summary of our unvested stock options as of December 31, 2011, and the changes during the year then ended is presented below:

Unvested Stock Options	Outstanding			Weighted-Average Grant-Date Fair Value
	(In thousands, except fair values)
Unvested as of December 31, 2010		3,941		$	2.81
Granted		931			6.24
Vested		(1,800	)		2.87
Forfeited		(172	)		2.73
Unvested as of December 31, 2011		2,900		$	3.88

The total intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was $18.3 million, $6.9 million and $19.7 million, respectively. The total fair value of options that vested during the years ended December 31, 2011, 2010 and 2009 was $5.2 million, $5.6 million and $10.8 million, respectively.

As of December 31, 2011, there was $4.0 million of total future compensation cost related to unvested options that are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately two years.

Restricted Stock and Restricted Stock Units

Our stock plans allow grants of restricted stock. Restricted stock is issued on the grant date, but cannot be sold or transferred. Restricted stock vests in varying periodic installments ranging from three to five years.

91

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of our restricted stock as of December 31, 2011, and the changes during the year then ended, is presented below:

Restricted Stock	Outstanding			Weighted-Average Grant-Date Fair Value
	(In thousands, except fair values)
Unvested as of December 31, 2010		1,945		$	19.23
Granted		1,096			27.32
Vested		(1,400	)		17.43
Forfeited		(85	)		28.11
Unvested as of December 31, 2011		1,556		$	26.07

During 2011 and 2010, we awarded 1,096,379 and 538,496 shares of restricted stock, respectively, to our employees and directors. These awards had an aggregate value at their date of grant of $30.0 million and $11.9 million, respectively, and were scheduled to vest over a period of up to four years. The fair value of restricted stock that vested during the years ended December 31, 2011, 2010 and 2009 was $21.4 million, $26.7 million and $23.9 million, respectively.

As of December 31, 2011, there was $28.9 million of total future compensation cost related to unvested restricted stock awards that are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately two years.

Note 9    Property, Plant and Equipment

The major components of our property, plant and equipment are as follows:

	December 31,
	2011			2010
	(In thousands)
Land	$	22,120		$	12,087
Buildings		132,753			122,635
Drilling, workover and well-servicing rigs, and related equipment		11,150,927			10,632,968
Marine transportation and supply vessels		14,023			13,663
Oilfield hauling and mobile equipment		1,171,930			551,892
Other machinery and equipment		248,938			143,976
Oil and gas properties(1)		42,033			664,289
Construction in process(2)		815,987			349,455
		13,598,711			12,490,965
Less: accumulated depreciation and amortization		(4,928,781	)		(4,182,122	)
accumulated depletion on oil and gas properties		(39,984	)		(493,424	)
	$	8,629,946		$	7,815,419

(1) A significant portion of our oil and gas properties have been reclassified to assets held for sale at December 31, 2011. Information relating to suspended wells that have capitalized costs for more than one year on this date is located at Note 4 — Discontinued Operations.

(2) Relates to amounts capitalized for new or substantially new drilling, workover and well-servicing rigs that were under construction and had not yet been placed in service as of December 31, 2011 or 2010.

92

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Repair and maintenance expense included in direct costs in our consolidated statements of income (loss) totaled $586.4 million, $382.5 million and $277.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Interest costs of $24.0 million, $12.4 million and $29.9 million were capitalized during the years ended December 31, 2011, 2010 and 2009, respectively.

Note 10    Investments in Unconsolidated Affiliates

Our principal investments in unconsolidated affiliates accounted for using the equity method include drilling and workover operations located in Saudi Arabia (51% ownership) and an oil and gas exploration, development and production joint venture in the United States (49.7%). These unconsolidated affiliates are integral to our operations in those locations. See Note 17 — Related-Party Transactions for a discussion of transactions with all of these related parties.

As of December 31, 2011 and 2010, our consolidated balance sheets reflect our investments in unconsolidated affiliates accounted for using the equity method totaling $371.0 million and $265.8 million, respectively, and at December 31, 2010, our investments in unconsolidated affiliates accounted for using the cost method totaling $1.9 million. Assets held for sale include investments in unconsolidated affiliates accounted for using the equity method totaling $13.7 million and $79.5 million at December 31, 2011 and 2010, respectively.

Combined condensed financial data for investments in unconsolidated affiliates, including assets classified as held for sale, are summarized as follows:

	December 31,
	2011		2010
	(In thousands)
Current assets	$	311,972	$	322,086
Long-term assets		1,728,399		1,332,212
Current liabilities		275,171		345,279
Long-term liabilities		800,444		460,198

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Gross revenues	$	832,774	$	901,742	$	960,823
Gross margin		278,019		241,831		223,005
Net income (loss)		270,161		48,426		(462,613	)
Nabors’ earnings (losses) from unconsolidated affiliates(1)		56,647		33,267		(155,432	)

(1) Nabors’ earnings (losses) from unconsolidated affiliates included in discontinued operations, net of tax was $76.5 million, $(10.6) million, and $(59.2) million, respectively, for the years ended December 31, 2011, 2010 and 2009.

Cumulative undistributed (losses) earnings of our unconsolidated affiliates included in our retained earnings as of December 31, 2011 and 2010 totaled approximately $(404.6) million and $(373.9) million, respectively. The Earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss) for the years ended December 31, 2011 and 2009 include our proportionate share of full-cost ceiling test writedowns of $15.6 million and $189.3 million, respectively, from our unconsolidated U.S. oil and gas joint venture. This writedown

93

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

is included in our Oil and Gas operating segment results. Our proportionate share of a full-cost ceiling test writedown of $47.8 million recorded for the year ended December 31, 2009 by unconsolidated oil and gas joint ventures is reflected in discontinued operations. See Note 4 — Discontinued Operations for additional information.

Note 11    Financial Instruments and Risk Concentration

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

Foreign Currency Risk

We operate in a number of international areas and are involved in transactions denominated in currencies other than U.S. dollars, which exposes us to foreign exchange rate risk or 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.

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 that 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 our 5.375%, 6.15%, 9.25%, 5.0% and 4.625% 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.

94

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We may utilize derivative financial instruments that are intended to manage our exposure to interest rate risks. The use of derivative financial instruments could expose us to further credit risk and market risk. Credit risk in this context is the failure of a counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty would owe us, which can create credit risk for us. When the fair value of a derivative contract is negative, we would owe the counterparty, and therefore, we would not be exposed to credit risk. We attempt to minimize credit risk in derivative instruments by entering into transactions with major financial institutions that have a significant asset base. Market risk related to derivatives is the adverse effect 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 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 to help mitigate and manage 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 will be 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 $1.3 million and $3.4 million as of December 31, 2011 and 2010, respectively. During 2011, 2010 and 2009, we recorded gains or (losses) of approximately $2.2 million, $(.1) million and $1.4 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).

Note 12    Debt

Long-term debt consisted of the following:

	December 31, 2011		December 31, 2010
	(In thousands)
5.375% senior notes due August 2012	$	274,604	$	273,977
6.15% senior notes due February 2018		967,490		966,276
9.25% senior notes due January 2019		1,125,000		1,125,000
5.00% senior notes due September 2020		697,343		697,037
4.625% senior notes due September 2021		697,667		—
0.94% senior exchangeable notes due May 2011		—		1,378,178
Revolving credit facilities		860,000		—
Other		1,712		2,676
		4,623,816		4,443,144
Less: current portion		275,326		1,379,018
	$	4,348,490	$	3,064,126

95

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2011, the maturities of our primary debt for each of the five years after 2011 and thereafter are as follows:

	Paid at Maturity
	(In thousands)
2012	$	275,000	(1)
2013		—
2014		860,000	(2)
2015		—
2016		—
Thereafter		3,500,000	(3)
	$	4,635,000

(1) Represents our 5.375% senior notes due August 2012.

(2) Represents amounts drawn on revolving credit facilities, which expire September 2014.

(3) Represents our 6.15% senior notes due February 2018, 9.25% senior notes due January 2019, 5.0% senior notes due September 2020 and 4.625% senior notes due September 2021.

5.375% Senior Notes Due August 2012

At December 31, 2011, the current portion of our long-term debt included Nabors Delaware’s 5.375% senior notes of $274.6 million.

On August 22, 2002, Nabors Delaware issued $275 million aggregate principal amount of 5.375% senior notes due 2012, which are fully and unconditionally guaranteed by us. The notes were resold by a placement agent to qualified institutional buyers under Rule 144A of the Securities Act of 1933. Interest on the notes is payable semi-annually on February 15 and August 15 of each year.

The notes are unsecured and are effectively junior in right of payment to any of Nabors Delaware’s future secured debt. The notes rank equal in right of payment with any of Nabors Delaware’s future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s subordinated debt. The guarantee of Nabors with respect to the notes issued by Nabors Delaware, is similarly unsecured and has a similar ranking to the series of notes so guaranteed.

Subject to certain qualifications and limitations, the indentures governing the notes issued by Nabors Delaware limit the ability of Nabors and its subsidiaries to incur liens and to enter into sale and lease-back transactions. In addition, the indentures limit our ability to enter into mergers, consolidations or transfers of all or substantially all of our assets unless the successor company assumes their obligations under the applicable indenture.

6.15% Senior Notes Due February 2018

On February 20, 2008, Nabors Delaware completed a private placement of $575 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. On July 22, 2008, Nabors Delaware completed an additional private placement under the same indenture of $400 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. These new notes are

96

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

subject to the same rates, terms and conditions and together will be treated as a single class of debt securities under the indenture (together $975 million 6.15% senior notes due 2018). The issue of notes was resold by the initial purchasers to qualified institutional buyers under Rule 144A of the Securities Act and to certain investors outside of the United States under Regulation S of the Securities Act. The notes bear interest at a rate of 6.15% per year, payable semi-annually on February 15 and August 15 and will mature on February 15, 2018.

The notes are unsecured and are effectively junior in right of payment to any of Nabors Delaware’s future secured debt. The senior notes rank equally with any of Nabors Delaware’s other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s future senior subordinated debt. Our guarantee of the senior notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The notes are subject to redemption by Nabors Delaware, in whole or in part, at any time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes then outstanding to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest, determined in the manner set forth in the indenture. In the event of a change in control triggering event, as defined in the indenture, the holders of notes may require Nabors Delaware to purchase all or any part of each note in cash equal to 101% of the principal amount plus accrued and unpaid interest, if any, to the date of purchase, except to the extent Nabors Delaware has exercised its right to redeem the notes.

9.25% Senior Notes Due January 2019

On January 12, 2009, Nabors Delaware completed a private placement of $1.125 billion aggregate principal amount of 9.25% senior notes due 2019 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The notes bear interest at a rate of 9.25% per year, payable semi-annually on January 15 and July 15 and will mature on January 15, 2019.

The notes are unsecured and are junior in right of payment to any of Nabors Delaware’s future secured debt. The notes rank equally with any of Nabors Delaware’s other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s future senior subordinated debt. Our guarantee of the notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The notes are subject to redemption by Nabors Delaware, in whole or in part, at any time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes then outstanding to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest, determined in the manner set forth in the applicable indenture. In the event of a change in control triggering event, as defined in the indenture, the holders of notes may require Nabors Delaware to purchase all or any part of each note in cash equal to 101% of the principal amount plus accrued and unpaid interest, if any, to the date of purchase, except to the extent Nabors Delaware has exercised its right to redeem the notes.

5.0% Senior Notes Due September 2020

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 fully and unconditionally guaranteed by us. The notes are subject to registration rights. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The notes pay interest semi-annually on March 15 and September 15, beginning on March 15, 2011 and will mature on September 15, 2020.

97

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The notes rank equal in right of payment to all of Nabors Delaware’s existing and future unsubordinated indebtedness, and senior in right of payment to all of Nabors Delaware’s existing and future senior subordinated and subordinated indebtedness. Our guarantee of the notes is unsecured and an unsubordinated obligation and ranks equal in right of payments to all of our unsecured and unsubordinated indebtedness from time to time outstanding. In the event of a change of control triggering event, as defined in the indenture, the holders of the notes may require Nabors Delaware to purchase all or a portion of the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture. Nabors Delaware used a portion of the proceeds to repay the borrowing under a revolving credit facility incurred to fund the Superior Merger.

Prior to the issuance of the notes during September 2010, we entered into a Treasury rate lock with a total notional amount of $500 million to hedge the risk of changes in semiannual interest payments. We designated the Treasury rate lock derivative as a cash flow hedge and upon settlement paid $5.7 million, due to the change in the fair value of the derivative. The loss was recognized as a component of accumulated other comprehensive income in our consolidated statement of changes in equity and is being amortized as additional interest expense over the life of the notes. There was no ineffectiveness associated with this hedge during the year ended December 31, 2010.

4.625% Senior Notes Due September 2021

On August 23, 2011, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 4.625% senior notes due 2021, which are unsecured and fully and unconditionally guaranteed by us. The notes have registration rights. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The notes pay interest semi-annually on March 15 and September 15, beginning on March 15, 2012 and will mature on September 15, 2021.

The notes rank equal in right of payment to all of Nabors Delaware’s existing and future unsubordinated indebtedness, and senior in right of payment to all of Nabors Delaware’s existing and future senior subordinated and subordinated indebtedness. Our guarantee of the notes is unsecured and an unsubordinated obligation and ranks equal in right of payments to all of our unsecured and unsubordinated indebtedness from time to time outstanding. In the event of a change of control triggering event, as defined in the indenture, the holders of the notes may require Nabors Delaware to purchase all or a portion of the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture. Nabors Delaware used a portion of the proceeds to pay back borrowings on our revolving credit facilities and for other general corporate purposes.

On November 21, 2011, we and Nabors Delaware filed a registration statement on Form S-4 under the Securities Act. The registration statement related to the exchange offer to noteholders required under the registration rights agreement related to the 4.625% senior notes. On December 19, 2011, the registration statement was declared effective by the SEC. On January 17, 2012, we and Nabors Delaware filed a prospectus and commenced the exchange offer. The exchange offer expired on February 13, 2012 and the exchange closed on February 15, 2012.

98

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Senior Exchangeable Notes

On May 16, 2011, the remaining aggregate principal amount of $1.4 billion of our 0.94% senior exchangeable notes matured and we redeemed them with $1.2 billion of borrowings under our revolving credit facilities and available cash. During 2011, 2010 and 2009, we recognized pre-tax gains (losses) of $(.1) million, $(7.0) million and $11.5 million, respectively, all of which 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) for the respective year.

Revolving Credit Facilities

As of December 31, 2011, we had $540 million of remaining availability from a combined total of $1.4 billion under our existing revolving credit facilities. The existing revolving credit facilities mature in September 2014, and can be used for general corporate purposes, including capital expenditures and working capital. The weighted average interest rate on borrowings at December 31, 2011 was 1.8%. We fully and unconditionally guarantee the obligations under all of these credit facilities.

Nabors Delaware has two senior unsecured revolving credit facilities, which total $1.35 billion, and, as of December 31, 2011, $810 million had been utilized. A third unsecured revolving credit facility for $50 million exists with one of our other subsidiaries and, as of December 31, 2011, had been fully utilized. We have the option to increase the aggregate principal amount of commitments by an additional $200 million by either adding new lenders to these facilities or by requesting existing lenders under the facilities to increase their commitments (in each case with the consent of the new lenders or the increasing lenders).

Borrowings under the senior unsecured revolving credit facilities bear interest, at Nabors Delaware’s option, for 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 LIBOR for the corresponding deposits of U.S. dollars, plus the applicable interest margin. 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 the administrative agent, as established from time to time and (iii) LIBOR for an interest period of one month beginning on such day plus 1%.

The revolving credit facilities contain various covenants and restrictive provisions that limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain a net funded indebtedness to total capitalization ratio, as defined in each agreement. We were in compliance with all covenants under the agreement at December 31, 2011. If we should fail to perform our obligations under the covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable.

Other Debt Transactions

In January and February 2009, Nabors Holdings 1, ULC, one of our wholly owned subsidiaries (“Nabors Holdings”), repurchased $56.6 million par value of the $225 million principal amount of its 4.875% senior notes due August 2009 in the open market for cash totaling $56.8 million. In August 2009, Nabors Holdings paid $168.4 million to redeem the remaining notes. The redemption resulted in no gain or loss as the notes were redeemed at a price equal to their carrying value.

99

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Short-Term Borrowings

We had six letter-of-credit facilities with various banks as of December 31, 2011. Availability and borrowings under our letter-of-credit facilities are as follows:

	December 31,
	2011			2010
	(In thousands)
Credit available	$	215,901		$	270,263
Letters of credit outstanding, inclusive of financial and performance guarantees		(80,408	)		(70,605	)
Remaining availability	$	135,493		$	199,658

Note 13    Income Taxes

We apply the provisions of the Income Taxes Topic in the ASC relating to uncertain tax positions. The change in our unrecognized tax benefits for years ended December 31, 2011, 2010 and 2009 were as follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Balance as of January 1,	$	81,174		$	69,048		$	51,819
Additions based on tax positions related to the current year(1)		1,850			1,026			4,787
Additions for tax positions of prior years(1)		11,748			17,060			12,889
Reductions for tax positions of prior years		(11,082	)		(4,709	)		(447	)
Settlements(2)		(14,842	)		(1,251	)		—
Balance as of December 31,	$	68,848		$	81,174		$	69,048

(1) Includes an unrecognized tax benefit of $10.8 million related to an Algeria audit assessment.

(2) Includes $8.6 million related to a settlement of the 1995 to 1997 income tax audits with the Canada Revenue Agency.

The balance also represents the amount of unrecognized tax benefits that, if recognized, would favorably impact the effective income tax rate in future periods. As of December 31, 2011, 2010 and 2009, we had approximately $28.2 million, $42.9 million and $38.5 million, respectively, of interest and penalties related to our total gross unrecognized tax benefits. During the years ended December 31, 2011, 2010 and 2009, we accrued and recognized estimated interest related to unrecognized tax benefits and penalties of approximately $4.6 million, $5.1 million and $5.2 million, respectively. We recognize interest and penalties related to income tax matters in the income tax expense line item in our consolidated statements of income (loss).

We are subject to income taxes in the United States and numerous other jurisdictions. A number of our United States and non-United States income tax returns from 1998 through 2010 are currently under audit examination. We anticipate that several of these audits could be finalized within the next 12 months. It is possible that the benefit relating to our unrecognized tax positions could significantly increase or decrease within the next 12 months. However, based on the current status of examinations, and the protocol for finalizing audits with the relevant tax authorities, which could include formal legal proceedings, it is not possible to estimate the future impact of the amount of changes, if any, to recorded uncertain tax positions at December 31, 2011.

100

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income (loss) from continuing operations before income taxes was comprised of the following:

	Year Ended December 31,
	2011		2010			2009
	(In thousands)
United States and Other Jurisdictions:
United States	$	178,270	$	(82,723	)	$	(505,264	)
Other jurisdictions		309,499		376,293			574,048
Income (loss) before income taxes from continuing operations	$	487,769	$	293,570		$	68,784

Income taxes have been provided based upon the tax laws and rates in the countries where we operate. We are a Bermuda exempted company. Bermuda does not impose corporate income taxes. Our U.S. subsidiaries are subject to a U.S. federal tax rate of 35%.

Income tax expense (benefit) from continuing operations consisted of the following:

	2011			2010			2009
	(In thousands)
Current:
U.S. federal	$	27,649		$	(137,847	)	$	(15,434	)
Outside the U.S.		43,732			54,779			84,221
State		38,321			5,859			2,671
		109,702			(77,209	)		71,458
Deferred:
U.S. federal		41,540			97,114			(80,353	)
Outside the U.S.		4,413			13,607			(46,603	)
State		(13,050	)		3,438			(8,439	)
		32,903			114,159			(135,395	)
Income tax expense (benefit)	$	142,605		$	36,950		$	(63,937	)

Nabors is not subject to tax in Bermuda. A reconciliation of the differences between taxes on income (loss) before income taxes computed at the appropriate statutory rate and our reported provision for income taxes follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Income tax provision at statutory rate (Bermuda rate of 0%)	$	—		$	—		$	—
Taxes on U.S. and other international earnings (losses) at greater than the Bermuda rate		112,094			18,686			(60,741	)
Increase (decrease) in valuation allowance		(6,450	)		2,407			6,062
Effect of change in tax rate		(258	)		40			(9,248	)
Tax reserves and interest		11,948			8,808			14,652
State income taxes		25,271			7,009			(14,662	)
Income tax expense (benefit)	$	142,605		$	36,950		$	(63,937	)
Effective tax rate		29.2	%		12.6	%		(93.0	)%

The increase in our effective tax rate from 2010 to 2011 is mainly a result of the increase in the proportion of income generated in the United States versus the international jurisdictions in which we operate. Income

101

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

generated in the United States is generally taxed at a higher rate than international jurisdictions.

Our effective income tax rate for 2010 and 2009 reflected 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 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 represents a meaningful basis for comparing our 2009 effective income tax rate to the 2010 effective income tax rate.

The significant components of our deferred tax assets and liabilities were as follows:

	December 31,
	2011			2010
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	2,009,318		$	1,848,956
Equity compensation		25,937			19,262
Deferred revenue		32,200			13,428
Tax credit and other attribute carryforwards		90,297			89,141
Insurance loss reserve		24,598			28,537
Other		114,043			62,324
Subtotal		2,296,393			2,061,648
Valuation allowance		(1,485,540	)		(1,514,153	)
Deferred tax assets	$	810,853		$	547,495
Deferred tax liabilities:
Depreciation, amortization and depletion for tax in excess of book expense	$	1,317,256		$	1,123,622
Variable interest investments		116,005			75,204
Other		34,822			54,738
Deferred tax liability		1,468,083			1,253,564
Net deferred assets (liabilities)	$	(657,230	)	$	(706,069	)
Balance Sheet Summary
Net current deferred asset	$	127,874		$	31,510
Net noncurrent deferred asset(1)		13,090			33,694
Net current deferred liability(2)		(269	)		(1,027	)
Net noncurrent deferred liability		(797,925	)		(770,246	)
Net deferred asset (liability)	$	(657,230	)	$	(706,069	)

(1) This amount is included in other long-term assets.

(2) This amount is included in accrued liabilities.

102

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For U.S. federal income tax purposes, we have net operating loss (“NOL”) carryforwards of approximately $1.2 billion that, if not utilized, will expire between 2016 and 2031. The NOL carryforwards for alternative minimum tax purposes are approximately $680 million. Additionally, we have NOL carryforwards in other jurisdictions of approximately $5.4 billion of which $408 million that, if not utilized, will expire at various times from 2012 to 2031. We provide a valuation allowance against NOL carryforwards in various tax jurisdictions based on our consideration of existing temporary differences and expected future earning levels in those jurisdictions. We have recorded a deferred tax asset of approximately $1.45 billion as of December 31, 2011 relating to NOL carryforwards that have an indefinite life in several non-U.S. jurisdictions. A valuation allowance of approximately $1.45 billion has been recognized because we believe it is more likely than not that substantially all of the deferred tax asset will not be realized.

The NOL carryforwards by year of expiration:

Year Ended December 31,	Total		U.S. Federal		Non-U.S.
	(In thousands)
2012	$	8,778	$		$	8,778
2013		30,348				30,348
2014		3,980				3,980
2015		12,824				12,824
2016		50,176		7,504		42,672
2017		26,601		5,423		21,178
2018		68,888		33,111		35,777
2019		35,986		17,722		18,264
2020		14,612				14,612
2021		7,895				7,895
2027		2,014				2,014
2028		31,237				31,237
2029		184,463		130,842		53,621
2030		533,825		485,648		48,177
2031		626,288		549,795		76,493
Subtotal: expiring NOLs		1,637,915		1,230,045		407,870
Non-expiring NOLs		5,021,678		—		5,021,678
Total	$	6,659,593	$	1,230,045	$	5,429,548

In addition, for state income tax purposes, we have net operating loss carryforwards of approximately $649 million that, if not utilized, will expire at various times from 2012 to 2031.

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 these carryforwards could be limited or effectively lost upon certain changes in our shareholder base. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given that they will be available in the future.

Various bills have been introduced in the U.S. Congress that could reduce or eliminate the U.S. 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 United States federal income tax purposes. Our reorganization was completed June 24, 2002.

103

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

There has been and we expect that there may continue to be legislation proposed in 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 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.

Note 14    Common Shares

Our authorized share capital consists of 800 million common shares, par value $.001 per share, and 25 million preferred shares, par value $.001 per share. Common shares issued were 317,042,324 and 315,034,436 at $.001 par value as of December 31, 2011 and 2010, respectively. No preferred shares have been issued. The preferred stock is issuable in one or more classes or series, full, limited or no voting rights, designations, preferences, special rights, qualifications, limitations and restrictions as may be determined by Nabors Industries Ltd.’s board.

From time to time, treasury shares may be reissued. When shares are reissued, we use the weighted-average-cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from our capital in excess of par value account. No shares have been purchased during the years ended December 31, 2011, 2010 and 2009.

During 2011, 2010 and 2009 our outstanding shares increased by 82,138, 110,805 and 218,835, respectively, pursuant to a share settlement of stock options exercised by Mr. Petrello. As part of these transactions, Mr. Petrello surrendered unexercised vested stock options to the Company with a value of approximately $7.6 million, $24.5 million and $5.6 million, respectively, to satisfy the option exercise price and related income taxes for 2011, 2010 and 2009. During 2010 our outstanding shares also increased by 22,385, pursuant to a similar share settlement of stock options exercised by Mr. Isenberg. As part of these transactions, Mr. Isenberg surrendered unexercised vested stock options to the Company with a value of approximately $50.1 million to satisfy the option exercise price and related income taxes for 2010.

For the years ended December 31, 2011, 2010 and 2009 the Compensation Committee of our Board of Directors granted restricted stock awards to some of our executive officers, other key employees, and independent directors. We awarded 1,096,379, 538,496 and 85,000 restricted shares at an average market price of $27.32, $22.15 and $11.55 to these individuals for 2011, 2010 and 2009, respectively. See Note 8 — Share-Based Compensation for a summary of our restricted stock and option awards as of December 31, 2011.

For the years ended December 31, 2011, 2010 and 2009 our employees exercised vested options to acquire 1.1 million, .7 million and 1.5 million of our common shares, respectively, resulting in proceeds of $11.6 million, $8.2 million and $11.2 million, respectively.

Note 15    Subsidiary Preferred Stock

Superior had 75,000 shares of Series A Preferred Stock (“preferred stock”), $0.01 par value per share, outstanding at December 31, 2011. There are 10,000,000 shares authorized. The preferred stock is issuable in series with such voting rights, if any, designations, powers, preferences and other rights and such qualifications, limitations and restrictions as may be determined by Superior’s board; the board may also fix the number of shares constituting each series and increase or decrease the number of shares of any series.

104

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The preferred stock is perpetual and ranks senior to Superior’s common stock with respect to payment of dividends, and amounts upon liquidation, dissolution or winding up.

We have presented the preferred stock within the mezzanine section of our consolidated balance sheets and have accounted for the preferred stock under the ASC Topic for Distinguishing Liabilities from Equity.

Dividends

Holders of the preferred stock are entitled to receive, when and if declared by Superior’s board, out of assets legally available therefor, cumulative cash dividends at the rate per annum of $40.00 per share of preferred stock. Dividends on the preferred stock are payable quarterly in arrears on December 1, March 1, June 1 and September 1 of each year (and, in the case of any undeclared and unpaid dividends, at such additional times and for such interim periods, if any, as determined by Superior’s board), at such annual rate. Dividends are cumulative from the date of the original issuance of the preferred stock, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.

As of December 31, 2011, dividends on outstanding shares of preferred stock had been declared and paid in full with respect to each quarter since its issuance.

Liquidation Preference

Holders of preferred stock are entitled to receive, in the event that Superior is liquidated, dissolved or wound up, whether voluntarily or involuntarily, $1,000 per share (the “Liquidation Value”) plus an amount per share equal to all dividends undeclared and unpaid thereon to the date of final distribution (the “Liquidation Preference”), and no more. Until the holders of preferred stock have been paid the Liquidation Preference in full, Superior may not make any payment to any holder of stock that ranks junior to the preferred stock upon liquidation, dissolution or winding up. As of December 31, 2011, the preferred stock had a total Liquidation Preference of $75.0 million.

Redemption

The preferred stock is redeemable, in whole or in part and at Superior’s option, at any time on or after November 18, 2013, for a redemption price of 101% of the Liquidation Value, plus all accrued dividends. The redemption price is payable in cash.

As a result of the Superior acquisition, each share of preferred stock is convertible, at the option of the holder thereof, into $22.12 for each share of Superior common stock into which the preferred share would have been convertible prior to the Superior acquisition (a “deemed common share”). The preferred shares had a conversion price of $25.00 per deemed common share prior to the Superior acquisition (equivalent to a conversion rate of 40 deemed common shares for each share of preferred stock), representing 3,000,000 deemed common shares. This results in a redemption value of $66.4 million at December 31, 2011, payable in cash. The right to convert shares of preferred stock that may be called for redemption will terminate at the close of business on the day preceding a redemption date.

Voting Rights

Except as otherwise required from time to time by applicable law or upon certain events of default, the holders of preferred stock have no voting rights, and their consent is not required for taking any corporate action. When and if the holders of the preferred stock are entitled to vote, each holder will be entitled to one vote per share.

105

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 16    Pension, Postretirement and Postemployment Benefits

Pension Plans

In conjunction with our acquisition of Pool Energy Services Co. (“Pool”) in November 1999, we acquired the assets and liabilities of a defined benefit pension plan, the Pool Company Retirement Income Plan (the “Pool Pension Plan”). Benefits under the Pool Pension Plan are frozen and participants were fully vested in their accrued retirement benefit on December 31, 1998.

Summarized information on the Pool Pension Plan is as follows:

	Pension Benefits
	2011			2010
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	20,628		$	18,865
Remeasurement		1,517			—
Interest cost		1,198			1,116
Actuarial loss (gain)		3,975			1,289
Benefit payments		(659	)		(642	)
Benefit obligation at end of year(1)	$	26,659		$	20,628
Change in plan assets:
Fair value of plan assets at beginning of year	$	15,219		$	14,058
Actual (loss) return on plan assets		480			1,364
Employer contribution		1,312			439
Benefit payments		(659	)		(642	)
Fair value of plan assets at end of year	$	16,352		$	15,219
Funded status:
Underfunded status at end of year	$	(10,307	)	$	(5,409	)
Amounts recognized in consolidated balance sheets:
Other long-term liabilities	$	(10,307	)	$	(5,409	)

	Year Ended December 31,
	2011			2010			2009
Components of net periodic benefit cost (recognized in our consolidated statements of income):
Interest cost	$	1,198		$	1,116		$	1,093
Expected return on plan assets		(1,008	)		(909	)		(794	)
Recognized net actuarial loss		628			457			545
Net periodic benefit cost	$	818		$	664		$	844
Weighted-average assumptions:
Weighted-average discount rate		4.25	%		5.50	%		6.00	%
Expected long-term rate of return on plan assets		6.50	%		6.50	%		6.50	%

(1) As of December 31, 2011 and 2010, the accumulated benefit obligation was the same as the projected benefit obligation.

For the years ended December 31, 2011, 2010 and 2009, the net actuarial loss amounts included in accumulated other comprehensive income (loss) in the consolidated statements of changes in equity were

106

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

approximately $(12.1) million, $(6.7) million and $(6.3) million, respectively. There were no other components, such as prior service costs or transition obligations relating to pension costs recorded within accumulated other comprehensive income (loss) during 2011, 2010 and 2009.

The amount included in accumulated other comprehensive income (loss) in the consolidated statements of changes in equity that is expected to be recognized as a component of net periodic benefit cost during 2012 is approximately $1.0 million.

We analyze the historical performance of investments in equity and debt securities, together with current market factors such as inflation and interest rates to help us make assumptions necessary to estimate a long-term rate of return on plan assets. Once this estimate is made, we review the portfolio of plan assets and make adjustments thereto that we believe are necessary to reflect a diversified blend of investments in equity and debt securities that is capable of achieving the estimated long-term rate of return without assuming an unreasonable level of investment risk.

The following table sets forth, by level within the fair value hierarchy, the investments in the Pool Pension Plan as of December 31, 2011. The investments’ fair value measurement level within the fair value hierarchy is classified in its entirety based on the lowest level of input that is significant to the measurement.

	Fair Value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:(1)
Cash	$	—	$	396	$	—	$	396
Short-term investments:
Available-for-sale equity securities(2)		—		9,166		—		9,166
Available-for-sale debt securities(3)		—		6,790		—		6,790
Total investments		—		15,956		—		15,956
Total	$	—	$	16,352	$	—	$	16,352

(1) Includes investments in collective trust funds that are valued based on the fair value of the underlying investments using quoted prices in active markets or other significant inputs that are deemed observable.

(2) Includes funds that invest primarily in U.S. common stocks and foreign equity securities.

(3) Includes funds that invest primarily in investment grade debt.

The measurement date used to determine pension measurements for the plan is December 31.

Our weighted-average asset allocations as of December 31, 2011 and 2010, by asset category are as follows:

	Pension Benefits
	2011			2010
Cash		2	%		2	%
Equity securities		56	%		56	%
Debt securities		42	%		42	%
Total		100	%		100	%

107

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We invest plan assets based on a total return on investment approach, pursuant to which the plan assets include a diversified blend of investments in equity and debt securities toward a goal of maximizing the long-term rate of return without assuming an unreasonable level of investment risk. We determine the level of risk based on an analysis of plan liabilities, the extent to which the value of the plan assets satisfies the plan liabilities and our financial condition. Our investment policy includes target allocations approximating 55% investment in equity securities and 45% investment in debt securities. The equity portion of the plan assets represents growth and value stocks of small, medium and large companies. We measure and monitor the investment risk of the plan assets both on a quarterly basis and annually when we assess plan liabilities.

We expect to contribute approximately $1.5 million to the Pool Pension Plan in 2012. This is based on the sum of (1) the minimum contribution for the 2011 plan year that will be made in 2011 and (2) the estimated minimum required quarterly contributions for the 2012 plan year. We made contributions to the Pool Pension Plan in 2011 and 2010 totaling $1.3 million and $.1 million, respectively.

As of December 31, 2011, we expect that benefits to be paid in each of the next five years after 2011 and in the aggregate for the five years thereafter will be as follows:

	(In thousands)
2012	$	791
2013		890
2014		1,004
2015		1,117
2016		1,193
2017 — 2021		7,428

Some of our employees are covered by defined contribution plans. Our contributions to the plans totaled $22.9 million and $13.6 million for the years ended December 31, 2011 and 2010, respectively. Nabors does not provide post-employment benefits to its employees, except for employees covered under the Pool Pension Plan.

Post-retirement Benefits Other Than Pensions

Prior to the date of our acquisition, Pool provided certain post-retirement healthcare and life insurance benefits to eligible retirees who had attained specific age and years of service requirements. Nabors terminated this plan at the date of acquisition (November 24, 1999). A liability of approximately $.2 million was recorded in our consolidated balance sheets as of each of December 31, 2011 and 2010, to cover the estimated costs of beneficiaries covered by the plan at the date of acquisition.

Note 17    Related-Party Transactions

The Company and Nabors Delaware entered into an agreement with Eugene M. Isenberg, the Chairman of our Board of Directors, on February 2, 2012 but effective December 31, 2011, pursuant to which:

• Mr. Isenberg voluntarily terminated both his employment with the Company and his Employment Agreement, and forwent any right to payment in connection with such termination, including a possible payment of $100 million in connection with the Company’s appointment of a new chief executive officer on October 28, 2011, which Mr. Isenberg could have treated as a constructive termination under his employment agreement;

• Mr. Isenberg will continue as Chairman of the Board, but will not stand for reelection as a director when his term expires in June 2012; at that time, he will be appointed Chairman Emeritus for a three-year

108

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

term, which will be extended for additional one-year terms unless terminated by him or by the Company, and receive cash compensation equal to other nonemployee directors;

• Nabors Delaware will pay $6,600,000 into an escrow account, which will bear interest at the guaranteed rate of 6% per annum compounded daily and will be distributed either to Mr. Isenberg’s estate or to the trustees of his revocable trust;

• Mr. Isenberg ceases participation in the Company’s benefit plans and forfeits any benefits available to him thereunder (including forfeiture of the balance in his deferred bonus account), except as stated below or otherwise required by law:

• he and his spouse continue to participate in medical, dental and life insurance coverage until either receives equivalent coverage and benefits under the plans and programs of a subsequent employer or their death;

• he remains entitled to distribution of vested account balances in the Company’s 401(k) plan and its Deferred Compensation Plan;

• he retains certain benefits under the split-dollar life insurance agreements in effect between him and Nabors Delaware

• all of Mr. Isenberg’s stock option and restricted stock awards were already fully vested and remain subject to the applicable plans and agreements governing them; and

• Mr. Isenberg waives all claims or other liabilities related to his Employment Agreement or his termination of employment, and the Company waives certain claims against Mr. Isenberg.

Nabors and certain key employees, including Messrs. Isenberg and Petrello, entered into split-dollar life insurance agreements, pursuant to which we pay a portion of the premiums under life insurance policies with respect to these individuals and, in some instances, members of their families. These agreements provide that we are reimbursed for the premium payments upon the occurrence of specified events, including the death of an insured individual. We will not be reimbursed for the premium payments paid on behalf of Mr. Isenberg as provided by the agreement entered into on February 2, 2012. 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 $6.3 million related to these policies. The cash surrender value of these policies of approximately $5.8 million and $9.5 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2011 and 2010, respectively.

Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors under the agreements with Messrs. Isenberg and Petrello 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 $218.4 million, $271.6 million and $327.3 million for the years ended December 31, 2011, 2010 and 2009, respectively. Expenses from business transactions with these affiliated entities totaled $.9 million, $3.4 million and $9.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. Additionally, we had accounts receivable from these affiliated entities of $110.7 million and $97.8 million as of December 31, 2011 and 2010, respectively. We had accounts payable to these affiliated entities of

109

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$46.1 million and $12.7 million as of December 31, 2011 and 2010, respectively, and long-term payables with these affiliated entities of $.8 million as of each of December 31, 2011 and 2010, which are 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 2011 and 2010, we recognized $2.0 million and $1.4 million, respectively, 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 first quarter of 2010, we purchased shares of Shona’s preferred stock and warrants to purchase additional common shares for $.9 million, which we had accounted for under the cost method of accounting. During 2011, Shona became a public company in Canada, with voting common shares listed on the TSX Venture Exchange. As of December 31, 2011, we held a minority interest of approximately 7.55% of the issued and outstanding common shares of Shona. The fair value of this equity security investment is $10.5 million.

Note 18    Commitments and Contingencies

Commitments

Leases

Nabors and its subsidiaries occupy various facilities and lease certain equipment under various lease agreements.

The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2011, were as follows:

	(In thousands)
2012	$	25,288
2013		20,060
2014		14,363
2015		7,273
2016		4,020
Thereafter		9,857
	$	80,861

The above amounts do not include property taxes, insurance or normal maintenance that the lessees are required to pay. Rental expense relating to operating leases with terms greater than 30 days amounted to $36.3 million, $26.7 million and $25.5 million for the years ended December 31, 2011, 2010 and 2009, respectively.

110

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Minimum Volume Commitment

We have contracts with pipeline companies to pay specified fees based on committed volumes for gas transport and processing. At the end of the term or annually, we are invoiced for any shortfalls in the volume deliveries at the rate specified in the agreement. Volume commitments remaining under the contracts as of December 31, 2011 were as follows:

	(In thousands)
2012	$	54,287
2013		68,056
2014		66,373
2015		64,845
2016		48,330
Thereafter(1)		86,808
	$	388,699

(1) Final commitment period is for the period ending October 2029.

Employment Contracts

We have entered into employment contracts with certain of our employees. Our minimum salary and bonus obligations under these contracts as of December 31, 2011 were as follows:

	(In thousands)
2012	$	9,752
2013		3,905
2014		501
2015		—
2016		—
Thereafter		—
	$	14,158

Nabors’ Deputy Chairman, President and Chief Executive Officer, Anthony G. Petrello, had an employment agreement (“prior employment agreement”) in effect through the first quarter of 2009. Effective April 1, 2009, the Company entered into an amended and restated employment agreement (“new employment agreement”) with him, which extended the terms through March 30, 2013. Pursuant to its provisions, the term of the new employment agreement has subsequently extended through March 30, 2014.

For the three months ended March 31, 2009, the prior employment agreement provided for an annual cash bonus in an amount equal to 2% of Nabors’ net cash flow (as defined in the employment agreements) in excess of 15% of the average shareholders’ equity for each fiscal year. The bonus was subject to a minimum of $700,000 per year.

The new employment agreement increased Mr. Petrello’s base salary to $1.3 million and provides for an extension of the employment term through March 30, 2013, with automatic one-year extensions beginning April 1, 2011, unless either party gives notice of non-renewal. On June 29, 2009, the new employment agreement was amended to provide for a reduction in the annual rate of base salary payable to $990,000 per year for the period from June 29, 2009 to December 27, 2009. On December 28, 2009, the agreement was further amended to extend through June 27, 2010 the previously agreed salary reduction.

111

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In addition to a base salary, the new employment agreement provides for an annual cash bonus in an amount equal to 1.5% of Nabors’ net cash flow (as defined in the new employment agreement) in excess of 15% of the average shareholders’ equity for each fiscal year. As provided in the new employment agreement, the 1.5% of Nabors’ net cash flow was replaced with 2.0% on October 28, 2011 in connection with his appointment as Chief Executive Officer. For 2011, the annual cash bonus pursuant to the formula was $13.6 million. The new employment agreement also provides a quarterly deferred bonus of $.25 million to Mr. Petrello’s account under Nabors’ executive deferred compensation plan for each quarter he is employed beginning June 30, 2009 and ending March 30, 2019.

Mr. Petrello is also eligible for awards under Nabors’ equity plans, may participate in annual long-term incentive programs and pension and welfare plans on the same basis as other executives, and may receive special bonuses from time to time as determined by the Board of Directors. The new employment agreement effectively eliminated the risk of forfeiture of outstanding stock awards. Accordingly, we recognized compensation expense during the second quarter of 2009 with respect to all previously granted unvested awards to him.

Termination in the event of death, disability, or termination without cause (including in the event of a Change in Control).     The new employment agreement provides for a severance payment in the event that it is terminated (i) upon death or disability, (ii) by Nabors prior to its expiration date for any reason other than for Cause (as defined in the agreement), or (iii) by Mr. Petrello for Constructive Termination Without Cause, as defined in the agreement. Termination in the event of a Change in Control (as defined in the new employment agreement) is considered a Constructive Termination Without Cause. Mr. Petrello would be entitled to receive within 30 days of his death or disability a payment of $50 million or in the event of Termination Without Cause or Constructive Termination Without Cause, a payment based on a formula of three times the average of his base salary and annual bonus (calculated as though the bonus formula under the new employment agreement had been in effect) paid during the three fiscal years preceding the termination. If, by way of example, Mr. Petrello were Terminated Without Cause subsequent to December 31, 2011, his payment would be approximately $31.1 million. The formula will be further reduced to two times the average stated above effective April 1, 2015.

The Company does not have insurance to cover its obligations in the event of Mr. Petrello’s death, disability, or termination without cause, and the Company has not recorded an expense or accrued a liability relating to the potential obligation.

In addition, under the new employment agreement, Mr. Petrello would be entitled to receive (a) any unvested restricted stock or stock options outstanding, which would immediately and fully vest; (b) any amounts earned, accrued or owing to him but not yet paid (including executive benefits, life insurance, disability benefits and reimbursement of expenses and perquisites), which would be continued through the later of the expiration date or three years after the termination date; (c) continued participation in medical, dental and life insurance coverage until he received equivalent benefits or coverage through a subsequent employer or until his death or the death of his spouse, whichever were later; and (d) any other or additional benefits in accordance with applicable plans and programs of Nabors. The vesting of unvested equity awards would not result in the recognition of any additional compensation expense, as all compensation expense related to his outstanding awards had been recognized by December 31, 2011. In addition, the new employment agreement eliminates all tax gross-ups, including tax gross-ups on golden parachute excise taxes, which applied under the prior employment agreement. Estimates of the cash value of Nabors’ obligations to Mr. Petrello under (b), (c) and (d) above are included in the payment amounts above.

Other Obligations.     In addition to salary and bonus, Mr. Petrello receives group life insurance at an amount at least equal to three times his base salary, various split-dollar life insurance policies, reimbursement of expenses, various perquisites and a personal umbrella insurance policy in the amount of $5 million. Premiums payable under the split-dollar life insurance policies were suspended as a result of the adoption of the Sarbanes-Oxley Act of 2002.

112

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Nabors’ Chairman, Eugene M. Isenberg, had an employment agreement in effect through the first quarter of 2009, which was amended and restated effective April 1, 2009. The provisions of the amended and restated employment agreement were similar to Mr. Petrello’s new employment agreement, but provided for a $100 million payment in the event of death, disability, or termination without cause (including in the event of a Change in Control). Mr. Isenberg was also eligible for awards under Nabors’ equity plans, participation in annual long-term incentive programs and pension and welfare plans and special bonuses from time to time as determined by the Board of Directors.

Effective April 1, 2009, Mr. Isenberg’s base salary was $1.3 million. He agreed to donate the after-tax proceeds to an educational fund benefiting Company employees or to other worthy candidates. His annual cash bonus equaled 2.25% of Nabors’ net cash flow (as defined in the employment agreement) in excess of 15% of the average shareholders’ equity for each fiscal year. For 2011, the annual cash bonus pursuant to the formula was $19.5 million. Mr. Isenberg’s employment agreement also provided a quarterly deferred bonus of $.6 million to an account under Nabors’ executive deferred compensation plan for each quarter he was employed beginning June 30, 2009.

Effective December 31, 2011, Mr. Isenberg voluntarily terminated both his employment with the Company and his Employment Agreement, and forwent any right to payment in connection with such termination. See Note 17 — Related-Party Transactions for additional discussion.

Contingencies

Income Tax Contingencies

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 possible that future changes to 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 2002 corporate reorganization. See Note 13 — Income Taxes for additional discussion.

On September 14, 2006, Nabors Drilling International Limited, one of our wholly owned Bermuda subsidiaries (“NDIL”), received a Notice of Assessment 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 2005 through 2008 and against NDIL II for 2007 to 2010. We believe that the potential assessments will range from $6 million to $26 million per year for the period

113

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

from 2005 to 2009, and in the aggregate, would be approximately $90 million to $95 million. Although we believe that any assessments related to the 2003 and 2005 to 2010 years lack merit, a reserve has been recorded in accordance with GAAP. The statute of limitations for NDIL’s 2004 tax year 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 made and we ultimately did not prevail, we would be required to recognize additional tax for the amount in excess of the current reserve.

Self-Insurance

We estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Our estimates are based on the facts and circumstances specific to existing claims and our past experience with similar 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. Although we believe our insurance coverage and reserve estimates are reasonable, a significant accident or other event that is not fully covered by insurance or contractual indemnity could occur and could materially affect our financial position and results of operations for a particular period.

We self-insure for certain losses relating to workers’ compensation, employers’ liability, general liability, automobile liability and property damage. Some workers’ compensation claims are subject to a minimum $1.0 million deductible liability, plus an additional $3.0 million corridor deductible. Some employers’ liability and marine employers’ liability claims are subject to a $2.0 million per-occurrence deductible. Some automobile liability is subject to a $.5 million per-occurrence deductible, plus an additional $1.0 million corridor deductible. General liability claims are subject to a $5.0 million per-occurrence deductible.

In addition, we are subject to a $5.0 million deductible for all land rigs and for offshore rigs. This applies to all kinds of risks of physical damage except for named windstorms in the U.S. Gulf of Mexico for which we are self-insured.

Political risk insurance is procured for select operations in South America, Africa, the Middle East and Asia. Losses are subject to a $.25 million deductible, except for Colombia, which is subject to a $.5 million deductible. There is no assurance that such coverage will adequately protect Nabors against liability from all potential consequences.

As of December 31, 2011 and 2010, our self-insurance accruals totaled $157.8 million and $145.6 million, respectively, and our related insurance recoveries/receivables were $18.7 million and $9.0 million, respectively.

Litigation

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. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure. In the opinion of management and based on liability accruals provided, our ultimate exposure with

114

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 U.S. 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. The inquiry has focused on transactions in Kazakhstan, Saudi Arabia, Algeria and Nigeria. The Audit Committee of our Board of Directors has 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 Department of Justice have been advised of our investigation. 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. In November 2011, we received a notice from the Algeria Supreme Court that a decision is expected in March 2012. 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 March 2011, the Court of Ouargla (in Algeria), sitting at first instance, entered a judgment of approximately $39.1 million against NDIL relating to alleged violations of Algeria’s foreign currency exchange controls, which require that goods and services provided locally be invoiced and paid in local currency. The case relates to certain foreign currency payments made to NDIL by CEPSA, a Spanish operator, for wells drilled in 2006. Approximately $7.5 million of the total contract amount was paid offshore in foreign currency, and approximately $3.2 million was paid in local currency. The judgment includes fines and penalties of approximately four times the amount at issue, and is not payable pending appeal. We have appealed the ruling based on our understanding that the law in question applies only to resident entities incorporated under Algerian law. An intermediate court of appeals has upheld the lower court’s ruling, and we have appealed the matter to the Algeria Supreme Court. While our payments were consistent with our historical operations in the country, and, we believe, those of other multinational corporations there, and interpretations of the law by the Central Bank of Algeria, the ultimate resolution of this matter could result in a loss of up to $31.1 million in excess of amounts accrued.

On September 21, 2011, we received an informal inquiry from the SEC related to perquisites and personal benefits received by the officers and directors of Nabors, including their use of non-commercial aircraft. Our Audit Committee and Board of Directors have been apprised of this inquiry and we are cooperating with the SEC. The ultimate outcome of this process cannot be determined at this time.

Nabors Industries Ltd. and its Board of Directors have been sued by purported shareholders in three separate shareholder’s derivative lawsuits filed in federal and state court in Houston, Texas. The cases were filed on November 18, 2011, January 9, 2012, and November 30, 2011, and are pending, respectively, before Judges

115

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Ewing Werlein and Gray Miller in the United States Southern District of Texas, Houston Division, and Judge Mike Miller of the 11th Judicial District Court of Harris County, Texas. The case filed on January 9, 2012 was voluntarily dismissed on January 31, 2012. The other cases remain pending. The allegations of each lawsuit were substantially similar, alleging that the members of the Board breached their fiduciary duties to the Company, wasted corporate assets, and committed oppressive conduct against the shareholders by agreeing to and/or acquiescing in certain compensation arrangements with two senior officers of the Company, Eugene M. Isenberg and Anthony G. Petrello. The remaining lawsuits seek relief that includes an award of monetary damages in an unspecified amount, disgorgement by Messrs. Isenberg and Petrello of allegedly excessive compensation in an unspecified amount of at least $90 million, and equitable relief to reform Nabors’ compensation practices. The ultimate outcome of these lawsuits cannot be determined at this time.

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
	2012		2013		2014		Thereafter		Total
	(In thousands)
Financial standby letters of credit and other financial surety instruments	$	105,055	$	38	$	—	$	—	$	105,093

Note 19    Earnings (Losses) Per Share

We include unvested restricted stock awards in the calculation of basic and diluted earnings per share using the two-class method as required by the Earnings Per Share Topic of the ASC.

116

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A reconciliation of the numerators and denominators of the basic and diluted earnings (losses) per share computations is as follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Net income (loss) (numerator):
Income (loss) from continuing operations, net of tax	$	342,164		$	255,870		$	132,721
Less: net (income) loss attributable to noncontrolling interest		(1,045	)		(85	)		342
Net income (loss) from continuing operations — basic		341,119			255,785			133,063
Add interest expense on assumed conversion of our 0.94% senior exchangeable notes, net of tax(1)		—			—			—
Adjusted net income (loss) attributable to Nabors — diluted	$	341,119		$	255,785		$	133,063
Earnings (losses) per share:
Basic from continuing operations	$	1.19		$	.90		$	.47
Diluted from continuing operations	$	1.17		$	.88		$	.46
Income from discontinued operations, net of tax	$	(97,440	)	$	(161,090	)	$	(218,609	)
Earnings (losses) per share, discontinued operations:
Basic from discontinued operations	$	(.34	)	$	(.57	)	$	(.77	)
Diluted from discontinued operations	$	(.34	)	$	(.55	)	$	(.76	)
Shares (denominator):
Weighted-average number of shares outstanding — basic(2)		287,118			285,145			283,326
Net effect of dilutive stock options, warrants and restricted stock awards based on the if-converted method		5,366			4,851			3,176
Assumed conversion of our 0.94% senior exchangeable notes(1)		—			—			—
Weighted-average number of shares outstanding — diluted		292,484			289,996			286,502

(1) At maturity in May 2011, we redeemed the remaining aggregate principal amount of $1.4 billion of our 0.94% senior exchangeable notes. Prior to maturity, we had purchased $1.4 billion par value of these notes in the open market for cash of $1.2 billion. Diluted earnings (losses) per share for the years ended December 31, 2010 and 2009 exclude any incremental shares that would have been issuable upon exchange of these notes based on a calculation using our stock price. Our stock price did not exceed the threshold during any period for the years ended December 31, 2010 and 2009.

(2) On July 31, 2009, the exchangeable shares of Nabors Exchangeco were exchanged for Nabors’ common shares on a one-for-one basis. Basic shares outstanding includes the following weighted-average number of common shares and restricted stock of Nabors and weighted-average number of exchangeable shares of Nabors Exchangeco, respectively: 287.1 million shares for the year ended December 31, 2011; 285.1 million shares for the year ended December 31, 2010; and 283.3 million shares for the year ended December 31, 2009.

For all periods presented, the computation of diluted earnings (losses) per Nabors’ share excludes outstanding stock options and warrants with exercise prices greater than the average market price of Nabors’ common shares, because their inclusion would be anti-dilutive and because they are not considered participating securities. The average number of options and warrants that were excluded from diluted earnings (losses) per share that would potentially dilute earnings per share in the future was 9,241,543, 14,004,749 and 34,113,887

117

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

shares during the years ended December 31, 2011, 2010 and 2009, respectively. In any period during which the average market price of Nabors’ common shares exceeds the exercise prices of these stock options and warrants, such stock options and warrants will be included in our diluted earnings (losses) per share computation using the if-converted method of accounting. Restricted stock will be included in our basic and diluted earnings (losses) per share computation using the two-class method of accounting in all periods because such stock is considered participating securities.

Note 20    Supplemental Balance Sheet, Income Statement and Cash Flow Information

At December 31, 2010, other long-term assets included a deposit of $40 million of restricted funds held at a financial institution to assure future credit availability for an unconsolidated affiliate.

Accrued liabilities include the following:

	December 31, 2011		December 31, 2010
	(In thousands)
Accrued compensation	$	173,732	$	116,680
Deferred revenue		172,578		88,389
Other taxes payable		44,652		25,227
Workers’ compensation liabilities		22,645		31,944
Interest payable		99,869		89,276
Due to joint venture partners		6,041		6,030
Warranty accrual		5,237		3,376
Litigation reserves		23,687		12,301
Provision for termination payment(1)		100,000		—
Current liability to discontinued operations		54,287		—
Professional fees		6,413		3,222
Current deferred tax liability		269		1,027
Other accrued liabilities		7,363		16,820
	$	716,773	$	394,292

(1) Represents a $100 million provision for a termination payment. See Note 3 — Impairments and Other Charges for additional discussion.

Investment income (loss) includes the following:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Interest and dividend income	$	9,930		$	7,457		$	15,700
Gains (losses) on investments, net		10,010	(1)		(194	)(2)		9,822	(3)
	$	19,940		$	7,263		$	25,522

(1) Reflects gain (loss) on sale of debt securities and gains (losses) from our long-term investments of $18.0 million, partially offset by net unrealized losses of $8.0 million from our trading securities.

(2) Includes net unrealized losses of $4.4 million from our trading securities, partially offset by gains on the sale of debt securities and gains from our long-term investments of $4.2 million.

(3) Reflects net unrealized gains of $9.8 million from our trading securities.

118

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Losses (gains) on sales and retirements of long-lived assets and other expense (income), net includes the following:

	Year Ended December 31,
	2011			2010		2009
	(In thousands)
Losses (gains) on sales, retirements and involuntary conversions of long-lived assets	$	(11,155	)(1)	$	6,430	$	5,927
Acquisition-related costs		151			7,021		—
Litigation expenses		11,301			6,356		11,474
Foreign currency transaction losses (gains)		5,499			18,100		7,993
Losses (gains) on derivative instruments		(2,159	)		119		(1,399	)
Losses (gains) on debt extinguishment(2)		58			7,042		(11,197	)
Other losses (gains)		819			2,170		(816	)
	$	4,514		$	47,238	$	11,982

(1) Includes a $13.1 million pre-tax gain from our acquisition of Peak during the year ended December 31, 2011 representing the excess of the estimated fair value of the assets and liabilities over the net carrying value of our previously held equity interest. See Note 5 — Acquisitions for additional discussion.

(2) Includes $.1 million, $(7.0) million and $11.5 million pre-tax (losses) gains on our purchases of our 0.94% senior exchangeable notes in the open market during 2011, 2010 and 2009, respectively.

Supplemental cash flow information for the years ended December 31, 2011, 2010 and 2009 is as follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Cash paid for income taxes	$	53,759		$	58,574		$	107,994
Cash paid for interest, net of capitalized interest		208,212			180,731			126,796
Acquisitions of businesses:
Fair value of assets acquired		80,585			796,399			—
Goodwill		8,000			339,992			—
Liabilities assumed		(10,471	)		(332,528	)		—
Common stock of acquired company previously owned		—			—			—
Subsidiary preferred stock obligation		—			(69,188	)		—
Gain on acquisition		(13,114	)		—			—
Cash paid for acquisitions of businesses		65,000			734,675			—
Cash acquired in acquisitions of businesses		(9,541	)		(1,045	)		—
Cash paid for acquisitions of businesses, net	$	55,459		$	733,630		$	—

119

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 21    Unaudited Quarterly Financial Information

	Year Ended December 31, 2011
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(1)	$	1,389,842		$	1,352,950		$	1,642,227		$	1,731,979
Income (loss) from continuing operations, net of tax	$	94,552		$	70,887		$	87,190		$	89,535
Income from discontinued operations, net of tax		(12,396	)		121,167			(12,226	)		(193,985	)
Less: Net (income) loss attributable to noncontrolling interest		669			394			(708	)		(1,400	)
Net income (loss) attributable to Nabors	$	82,825		$	192,448		$	74,256		$	(105,850	)
Earnings (loss) per share:(2)
Basic from continuing operations	$	.33		$	.25		$	.30		$	.31
Basic from discontinued operations		(.04	)		.42			(.04	)		(.68	)
Total Basic	$	.29		$	.67		$	.26		$	(.37	)
Diluted from continuing operations	$	.33		$	.24		$	.30		$	.30
Diluted from discontinued operations		(.05	)		.41			(.05	)		(.66	)
Total Diluted	$	.28		$	.65		$	.25		$	(.36	)
	Year Ended December 31, 2010
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(3)	$	890,469		$	898,169		$	1,068,870		$	1,310,242
Income (loss) from continuing operations, net of tax	$	46,477		$	44,949		$	12,347		$	152,097
Income from discontinued operations, net of tax		(7,379	)		(1,887	)		(51,501	)		(100,323	)
Less: Net (income) loss attributable to noncontrolling interest		1,102			559			(453	)		(1,293	)
Net income (loss) attributable to Nabors	$	40,200		$	43,621		$	(39,607	)	$	50,481
Earnings per share:(2)
Basic from continuing operations	$	.17		$	.16		$	.04		$	.53
Basic from discontinued operations		(.03	)		(.01	)		(.18	)		(.35	)
Total Basic	$	.14		$	.15		$	(.14	)	$	.18
Diluted from continuing operations	$	.16		$	.16		$	.04		$	.52
Diluted from discontinued operations		(.02	)		(.01	)		(.18	)		(.35	)
Total Diluted	$	.14		$	.15		$	(.14	)	$	.17

(1) Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $16.3 million, $9.3 million, $33.7 million and $(2.7) million, respectively.

120

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2) Earnings per share is computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the total computed for the year.

(3) Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $7.7 million, $8.9 million, $11.8 million and $4.9 million, respectively.

Note 22    Segment Information

As of December 31, 2011, we operated our business out of 10 operating segments. Our six Contract Drilling operating segments are engaged in drilling, workover and well-servicing operations, on land and offshore, and represent reportable segments. These operating segments consist of our Alaska, U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, U.S. Offshore, Canada and International business units. Our hydraulic fracturing and downhole surveying services are included in our Pressure Pumping operating segment. Our oil and gas operating segment includes our unconsolidated U.S. oil and gas joint venture. This segment is engaged in the exploration for, and the development of and production of oil and natural gas. Our Other Operating Segments, consisting of Canrig Drilling Technology Ltd. and Ryan Directional Services, Inc., are engaged in the manufacturing of top drives, manufacturing of drilling instrumentation systems, construction services, trucking and logistics services, manufacturing and marketing of directional drilling and rig instrumentation systems, directional drilling, and rig instrumentation and data collection services. These Other Operating Segments do not meet the criteria for disclosure, individually or in the aggregate, as reportable segments.

The accounting policies of the segments are the same as those described in Note 2 — Summary of Significant Accounting Policies. Inter-segment sales are recorded at cost or cost plus a profit margin. We evaluate the performance of our segments based on several criteria, including adjusted income (loss) derived from operating activities.

The following table sets forth financial information with respect to our reportable segments:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Operating revenues and earnings (losses) from unconsolidated affiliates from continuing operations:(1)
Contract Drilling:(2)
U.S. Lower 48 Land Drilling	$	1,698,620		$	1,294,853		$	1,082,531
U.S. Land Well-servicing		701,223			444,665			412,243
U.S. Offshore		170,727			123,761			157,305
Alaska		129,894			179,218			204,407
Canada		574,754			389,229			298,653
International		1,104,461			1,093,608			1,265,097
Subtotal Contract Drilling(3)		4,379,679			3,525,334			3,420,236
Pressure Pumping(4)		1,237,306			321,295			—
Oil and Gas(5)(6)		59,685			18,657			(182,654	)
Other Operating Segments(7)(8)		674,206			427,154			417,531
Other reconciling items(9)		(233,878	)		(124,690	)		(148,325	)
Total	$	6,116,998		$	4,167,750		$	3,506,788

121

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Depreciation and amortization, and depletion:(1)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	288,373		$	241,258		$	226,875
U.S. Land Well-servicing		78,314			65,561			69,557
U.S. Offshore		37,242			37,059			37,204
Alaska		34,989			37,195			29,946
Canada		75,919			74,735			65,883
International		273,315			247,134			208,949
Subtotal Contract Drilling		788,152			702,942			638,414
Pressure Pumping(4)		102,009			32,204			—
Oil and Gas		—			—			—
Other Operating Segments		34,162			28,452			27,441
Other reconciling items(9)		(229	)		(2,636	)		(1,897	)
Total depreciation and amortization, and depletion	$	924,094		$	760,962		$	663,958
Adjusted income (loss) derived from operating activities from continuing operations:(1)(10)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	414,317		$	274,215		$	294,679
U.S. Land Well-servicing		74,725			31,597			28,950
U.S. Offshore		843			9,245			30,508
Alaska		27,671			51,896			62,742
Canada		94,637			22,970			(7,019	)
International		123,813			254,744			365,566
Subtotal Contract Drilling(3)		736,006			644,667			775,426
Pressure Pumping(4)		229,125			66,651			—
Oil and Gas(5)(6)		59,685			18,657			(182,654	)
Other Operating Segments(7)(8)		55,617			42,401			35,319
Other reconciling items(11)		(153,385	)		(104,827	)		(188,257	)
Total adjusted income derived from operating activities	$	927,048		$	667,549		$	439,834
Interest expense		(256,633	)		(272,712	)		(266,047	)
Investment income (loss)		19,940			7,263			25,522
Gains (losses) on sales and retirements of long-lived assets and other (income) expense, net		(4,514	)		(47,238	)		(11,982	)
Impairments and other charges(12)		(198,072	)		(61,292	)		(118,543	)
Income (loss) from continuing operations before income taxes		487,769			293,570			68,784
Income tax expense (benefit)		142,605			36,950			(63,937	)
Subsidiary preferred stock dividend		3,000			750			—
Income (loss) from continuing operations, net of tax		342,164			255,870			132,721
Income (loss) from discontinued operations, net of tax		(97,440	)		(161,090	)		(218,609	)
Net income (loss)		244,724			94,780			(85,888	)
Less: Net income (loss) attributable to noncontrolling interest		(1,045	)		(85	)		342
Net income (loss) attributable to Nabors	$	243,679		$	94,695		$	(85,546	)

122

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Capital expenditures and acquisitions of businesses:(13)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	650,342		$	294,239		$	327,269
U.S. Land Well-servicing		165,953			84,657			16,671
U.S. Offshore		63,817			23,625			48,694
Alaska		5,582			891			55,426
Canada		95,001			53,834			29,214
International		653,759			365,597			328,252
Subtotal Contract Drilling		1,634,454			822,843			805,526
Pressure Pumping(4)		285,304			924,693			—
Oil and Gas		208,995			113,361			184,185
Other Operating Segments		136,515			28,799			20,446
Other reconciling items(11)(17)		(17,533	)		(11,633	)		(19,870	)
Total capital expenditures and acquisitions of businesses	$	2,247,735		$	1,878,063		$	990,287

	December 31,
	2011		2010		2009
	(In thousands)
Total assets:
Contract Drilling:(14)
U.S. Lower 48 Land Drilling	$	3,216,803	$	2,762,362	$	2,609,101
U.S. Land Well-servicing		812,049		630,518		594,456
U.S. Offshore		402,506		379,292		440,556
Alaska		288,253		313,123		373,146
Canada		962,239		1,065,268		984,740
International		3,702,611		3,279,763		3,151,513
Subtotal Contract Drilling		9,384,461		8,430,326		8,153,512
Pressure Pumping(4)		1,503,298		1,163,236		—
Oil and Gas(15)		796,327		805,410		835,465
Other Operating Segments(16)		720,775		539,373		502,501
Other reconciling items(11)(17)		507,279		708,224		1,153,212
Total assets	$	12,912,140	$	11,646,569	$	10,644,690

(1) All periods present the operating activities of our wholly owned oil and gas assets in the United States, Canada and Colombia, including equity interests in Canada and Colombia, as well as the Nabors Blue Sky Ltd. business as discontinued operations.

(2) These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore.

(3) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.2) million, $6.9 million and $9.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.

(4) Includes operating results of the Superior acquisition beginning September 10, 2010.

123

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(5) Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(15.6) million and $(189.3) million for the years ended December 31, 2011 and 2009, respectively.

(6) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $59.7 million, $18.7 million and $(182.6) million for the years ended December 31, 2011, 2010 and 2009, respectively. Additional information is provided in Note 24 — Supplemental Information on Oil and Gas Exploration and Production Activities.

(7) Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction operations.

(8) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.9) million, $7.7 million and $17.5 million for the years ended December 31, 2011, 2010 and 2009, 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 in accordance with 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 accurately reflect 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 in the above table.

(11) Represents the elimination of inter-segment transactions and unallocated corporate expenses, assets and capital expenditures.

(12) Represents impairments and other charges recorded during the years ended December 31, 2011, 2010 and 2009, respectively.

(13) Includes the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.

(14) Includes $51.5 million, $54.8 million and $49.8 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(15) Includes $294.1 million, $146.5 million and $190.1 million investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(16) Includes $25.4 million, $64.5 million and $65.8 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(17) Includes $1.9 million and $.9 million of investments in unconsolidated affiliates accounted for using the cost method as of December 31, 2010 and 2009, respectively.

124

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth financial information with respect to Nabors’ operations by geographic area:

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Operating revenues and earnings (losses) from unconsolidated affiliates from continuing operations:
U.S.	$	4,329,079	$	2,612,954	$	1,817,374
Outside the U.S.		1,787,919		1,554,796		1,689,414
	$	6,116,998	$	4,167,750	$	3,506,788
Property, plant and equipment, net:
U.S.	$	4,974,239	$	4,447,388	$	4,107,250
Outside the U.S.		3,655,707		3,368,031		3,538,800
	$	8,629,946	$	7,815,419	$	7,646,050
Goodwill:
U.S.	$	466,794	$	459,560	$	130,275
Outside the U.S.		34,464		34,812		33,990
	$	501,258	$	494,372	$	164,265

Note 23    Condensed Consolidating Financial Information

Nabors has fully and unconditionally guaranteed all of the issued public debt securities of Nabors Delaware, and Nabors and Nabors Delaware fully and unconditionally guaranteed the 4.875% senior notes due August 2009 issued by Nabors Holdings 1, ULC, an unlimited liability company formed under the Companies Act of Nova Scotia, Canada and a subsidiary of Nabors (“Nabors Holdings”). During 2009, we paid the balance of Nabors Holdings 1, ULC’s 4.875% senior notes. Effective September 30, 2009, Nabors Holdings 1, ULC was amalgamated with Nabors Drilling Canada ULC, the successor company.

The following condensed consolidating financial information is included so that separate financial statements of Nabors Delaware and Nabors Holdings are not required to be filed with the SEC. The condensed consolidating financial statements present investments in both consolidated and unconsolidated affiliates using the equity method of accounting.

The following condensed consolidating financial information presents condensed consolidating balance sheets as of December 31, 2011 and 2010, statements of income (loss) for the years ended December 31, 2011, 2010 and 2009 and the consolidating statements of cash flows for the years ended December 31, 2011, 2010 and 2009 of (a) Nabors, parent/guarantor, (b) Nabors Delaware, issuer of public debt securities guaranteed by Nabors and guarantor of the 4.875% senior notes issued by Nabors Holdings, (c) Nabors Holdings, issuer of the 4.875% senior notes, (d) the non-guarantor subsidiaries, (e) consolidating adjustments necessary to consolidate Nabors and its subsidiaries and (f) Nabors on a consolidated basis.

125

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Balance Sheets

	December 31, 2011
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)		Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments			Consolidated Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	203	$	21	$	—	$	398,351	$	—		$	398,575
Short-term investments		—		—		—		140,914		—			140,914
Assets held for sale		—		—		—		401,500		—			401,500
Accounts receivable, net		—		—		—		1,576,555		—			1,576,555
Inventory		—		—		—		272,852		—			272,852
Deferred income taxes		—		—		—		127,874		—			127,874
Other current assets		50		671		—		169,323		—			170,044
Total current assets		253		692		—		3,087,369		—			3,088,314
Long-term investments and other receivables		—		—		—		11,124		—			11,124
Property, plant and equipment, net		—		40,792		—		8,589,154		—			8,629,946
Goodwill		—		—		—		501,258		—			501,258
Intercompany receivables		164,760		—		—		537,881		(702,641	)		—
Investment in unconsolidated affiliates		5,429,029		6,084,868		—		1,843,654		(12,986,530	)		371,021
Other long-term assets		—		32,037		—		278,440		—			310,477
Total assets	$	5,594,042	$	6,158,389	$	—	$	14,848,880	$	(13,689,171	)	$	12,912,140
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	274,604	$	—	$	722	$	—		$	275,326
Trade accounts payable		42		23		—		782,688		—			782,753
Accrued liabilities		6,185		100,101		—		556,200		—			662,486
Asset held for sale		—		—		—		54,287		—			54,287
Income taxes payable		—				—		27,710		—			27,710
Total current liabilities		6,227		374,728		—		1,421,607		—			1,802,562
Long-term debt		—		4,297,500		—		50,990		—			4,348,490
Asset held for sale		—		—		—		71,375		—			71,375
Other long-term liabilities		—		32,303		—		189,079		—			221,382
Deferred income taxes		—		11,221		—		786,705		—			797,926
Intercompany payable		—		379,400		—		323,241		(702,641	)		—
Total liabilities		6,227		5,095,152		—		2,842,997		(702,641	)		7,241,735
Subsidiary preferred stock		—		—		—		69,188		—			69,188
Shareholders’ equity		5,587,815		1,063,237		—		11,923,293		(12,986,530	)		5,587,815
Noncontrolling interest		—		—		—		13,402		—			13,402
Total equity		5,587,815		1,063,237		—		11,936,695		(12,986,530	)		5,601,217
Total liabilities and equity	$	5,594,042	$	6,158,389	$	—	$	14,848,880	$	(13,689,171	)	$	12,912,140

126

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	December 31, 2010
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)		Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments			Consolidated Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,847	$	20	$	—	$	630,835	$	—		$	641,702
Short-term investments		—		—		—		159,488		—			159,488
Assets held for sale		—		—		—		352,048		—			352,048
Accounts receivable, net		—		—		—		1,116,510		—			1,116,510
Inventory		—		—		—		158,836		—			158,836
Deferred income taxes		—		—		—		31,510		—			31,510
Other current assets		50		16,366		—		136,420		—			152,836
Total current assets		10,897		16,386		—		2,585,647		—			2,612,930
Long-term investments and other receivables		—		—		—		40,300		—			40,300
Property, plant and equipment, net		—		44,270		—		7,771,149		—			7,815,419
Goodwill		—		—		—		494,372		—			494,372
Intercompany receivables		160,250		—		—		322,697		(482,947	)		—
Investment in unconsolidated affiliates		5,160,800		5,814,219		—		1,665,459		(12,372,755	)		267,723
Other long-term assets		—		36,538		—		379,287		—			415,825
Total assets	$	5,331,947	$	5,911,413	$	—	$	13,258,911	$	(12,855,702	)	$	11,646,569
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	1,378,178	$	—	$	840	$	—		$	1,379,018
Trade accounts payable		—		—		—		355,282		—			355,282
Accrued liabilities		3,785		89,480		—		301,027		—			394,292
Income taxes payable		—		6,859		—		18,929		—			25,788
Total current liabilities		3,785		1,474,517		—		676,078		—			2,154,380
Long-term debt		—		3,062,291		—		1,835		—			3,064,126
Other long-term liabilities		—		12,787		—		232,978		—			245,765
Deferred income taxes		—		71,815		—		698,432		—			770,247
Intercompany payable		—		301,451		—		181,496		(482,947	)		—
Total liabilities		3,785		4,922,861		—		1,790,819		(482,947	)		6,234,518
Subsidiary preferred stock		—		—		—		69,188		—			69,188
Shareholders’ equity		5,328,162		988,552		—		11,384,203		(12,372,755	)		5,328,162
Noncontrolling interest		—		—		—		14,701		—			14,701
Total equity		5,328,162		988,552		—		11,398,904		(12,372,755	)		5,342,863
Total liabilities and equity	$	5,331,947	$	5,911,413	$	—	$	13,258,911	$	(12,855,702	)	$	11,646,569

127

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statements of Income (Loss)

	Year Ended December 31, 2011
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—	$	—		$	—	$	6,060,351		$	—		$	6,060,351
Earnings (losses) from unconsolidated affiliates		—		—			—		56,647			—			56,647
Earnings (losses) from consolidated affiliates		256,245		214,308			—		107,536			(578,089	)		—
Investment income (loss)		4		68			—		19,868			—			19,940
Intercompany interest income		—		69,437			—		—			(69,437	)		—
Total revenues and other income		256,249		283,813			—		6,244,402			(647,526	)		6,136,938
Costs and other deductions:
Direct costs		—		—			—		3,775,964			—			3,775,964
General and administrative expenses		11,970		348			—		478,174			(600	)		489,892
Depreciation and amortization		—		3,532			—		920,562			—			924,094
Interest expense		—		278,657			—		(22,024	)		—			256,633
Intercompany interest expense		—		—			—		69,437			(69,437	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		600		(1,904	)		—		5,218			600			4,514
Impairments and other charges		—		—			—		198,072			—			198,072
Total costs and other deductions		12,570		280,633			—		5,425,403			(69,437	)		5,649,169
Income (loss) from continuing operations before income taxes		243,679		3,180			—		818,999			(578,089	)		487,769
Income tax expense (benefit)		—		(78,118	)		—		220,723			—			142,605
Subsidiary preferred stock dividend		—		—			—		3,000			—			3,000
Income (loss) from continuing operations, net of tax		243,679		81,298			—		595,276			(578,089	)		342,164
Income (loss) from discontinued operations, net of tax		—		—			—		(97,440	)		—			(97,440	)
Net income (loss)		243,679		81,298			—		497,836			(578,089	)		244,724
Less: Net (income) loss attributable to noncontrolling interest		—		—			—		(1,045	)		—			(1,045	)
Net income (loss) attributable to Nabors	$	243,679	$	81,298		$	—	$	496,791		$	(578,089	)	$	243,679

128

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2010
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—		$	—		$	—	$	4,134,483		$	—		$	4,134,483
Earnings (losses) from unconsolidated affiliates		—			—			—		33,267			—			33,267
Earnings (losses) from consolidated affiliates		68,749			(183,242	)		—		(316,657	)		431,150			—
Investment income (loss)		15			—			—		7,248			—			7,263
Intercompany interest income		—			72,435			—		—			(72,435	)		—
Total revenues and other income		68,764			(110,807	)		—		3,858,341			358,715			4,175,013
Costs and other deductions:
Direct costs		—			—			—		2,400,519			—			2,400,519
General and administrative expenses		9,165			445			—		330,067			(957	)		338,720
Depreciation and amortization		—			3,303			—		757,659			—			760,962
Interest expense		—			283,396			—		(10,684	)		—			272,712
Intercompany interest expense		—			—			—		72,435			(72,435	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		(35,096	)		42,504			—		38,873			957			47,238
Impairments and other charges		—			—			—		61,292			—			61,292
Total costs and other deductions		(25,931	)		329,648			—		3,650,161			(72,435	)		3,881,443
Income (loss) from continuing operations before income taxes		94,695			(440,455	)		—		208,180			431,150			293,570
Income tax expense (benefit)		—			(95,168	)		—		132,118			—			36,950
Subsidiary preferred stock dividend		—			—			—		750			—			750
Income (loss) from continuing operations, net of tax		94,695			(345,287	)		—		75,312			431,150			255,870
Income (loss) from discontinued operations, net of tax		—			—			—		(161,090	)		—			(161,090	)
Net income (loss)		94,695			(345,287	)		—		(85,778	)		431,150			94,780
Less: Net (income) loss attributable to noncontrolling interest		—			—			—		(85	)		—			(85	)
Net income (loss) attributable to Nabors	$	94,695		$	(345,287	)	$	—	$	(85,863	)	$	431,150		$	94,695

129

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2009
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—		$	—		$	—		$	3,662,220		$	—		$	3,662,220
Earnings (losses) from unconsolidated affiliates		—			—			—			(155,432	)		—			(155,432	)
Earnings (losses) from consolidated affiliates		(74,204	)		(316,443	)		(86,751	)		(441,133	)		918,531			—
Investment income (loss)		58			2,357			101			23,006			—			25,522
Intercompany interest income		—			66,150			5,558			—			(71,708	)		—
Total revenues and other income		(74,146	)		(247,936	)		(81,092	)		3,088,661			846,823			3,532,310
Costs and other deductions:
Direct costs		—			—			—			1,981,504			—			1,981,504
General and administrative expenses		28,350			336			1			393,375			(570	)		421,492
Depreciation and amortization		—			3,594			—			660,364			—			663,958
Interest expense		—			288,715			5,634			(28,302	)		—			266,047
Intercompany interest expense		—			—			—			71,708			(71,708	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		(16,950	)		4,145			5,069			37,395			(17,677	)		11,982
Impairments and other charges		—			—			—			118,543			—			118,543
Total costs and other deductions		11,400			296,790			10,704			3,234,587			(89,955	)		3,463,526
Income (loss) from continuing operations before income taxes		(85,546	)		(544,726	)		(91,796	)		(145,926	)		936,778			68,784
Income tax expense (benefit)		—			(84,465	)		15,744			4,784			—			(63,937	)
Income (loss) from continuing operations, net of tax		(85,546	)		(460,261	)		(107,540	)		(150,710	)		936,778			132,721
Income (loss) from discontinued operations, net of tax		—			—			—			(218,609	)		—			(218,609	)
Net income (loss)		(85,546	)		(460,261	)		(107,540	)		(369,319	)		936,778			(85,888	)
Less: Net (income) loss attributable to noncontrolling interest		—			—			—			342			—			342
Net income (loss) attributable to Nabors	$	(85,546	)	$	(460,261	)	$	(107,540	)	$	(368,977	)	$	936,778		$	(85,546	)

130

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2011
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	6,612		$	(31,178	)	$	—	$	1,481,053		$			$	1,456,487
Cash flows from investing activities:
Purchases of investments		—			—			—		(11,746	)		—			(11,746	)
Sales and maturities of investments		—			—			—		39,063			—			39,063
Cash paid for acquisition of businesses, net		—			—			—		(55,459	)		—			(55,459	)
Investment in unconsolidated affiliates		—			—			—		(112,262	)		—			(112,262	)
Distribution of proceeds from asset sales of unconsolidated affiliates		—			—			—		142,984			—			142,984
Capital expenditures		—			—			—		(2,042,617	)		—			(2,042,617	)
Proceeds from sales of assets and insurance claims		—			—			—		180,558			—			180,558
Cash paid for investments in consolidated affiliates		(26,235	)		(65,000	)		—		—			91,235			—
Net cash provided by (used for) investing activities		(26,235	)		(65,000	)		—		(1,859,479	)		91,235			(1,859,479	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—		6,375			—			6,375
Proceeds from long-term debt		—			697,578			—		—			—			697,578
Debt issuance costs		—			(7,141	)		—		—			—			(7,141	)
Proceeds from revolving credit facilities		—			1,510,000			—		50,000			—			1,560,000
Proceeds from issuance of common shares		11,605			—			—		—			—			11,605
Reduction in long-term debt		—			(1,404,246	)		—		(35	)		—			(1,404,281	)
Reduction in revolving credit facilities		—			(700,000	)		—		—			—			(700,000	)
Repurchase of equity component of convertible debt		—			(12	)		—		—			—			(12	)
Purchase of restricted stock		(2,626	)		—			—		—			—			(2,626	)
Tax benefit related to share-based awards		—			—			—		1,747			—			1,747
Proceeds from parent contributions		—			—			—		91,235			(91,235	)		—
Net cash (used for) provided by financing activities		8,979			96,179			—		149,322			(91,235	)		163,245
Effect of exchange rate changes on cash and cash equivalents		—			—			—		(3,380	)		—			(3,380	)
Net (decrease) increase in cash and cash equivalents		(10,644	)		1			—		(232,484	)		—			(243,127	)
Cash and cash equivalents, beginning of period		10,847			20			—		630,835			—			641,702
Cash and cash equivalents, end of period	$	203		$	21		$	—	$	398,351		$	—		$	398,575

131

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2010
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	115,179		$	757,345		$	—	$	504,460		$	(270,000	)	$	1,106,984
Cash flows from investing activities:
Purchases of investments		—			—			—		(34,147	)		—			(34,147	)
Sales and maturities of investments		—			—			—		34,613			—			34,613
Cash paid for acquisition of businesses, net		—			—			—		(733,630	)		—			(733,630	)
Investment in unconsolidated affiliates		—			—			—		(40,936	)		—			(40,936	)
Capital expenditures		—			—			—		(930,277	)		—			(930,277	)
Proceeds from sales of assets and insurance claims		—			—			—		31,072			—			31,072
Cash paid for investments in consolidated affiliates		(122,300	)		(1,027,134	)		—		—			1,149,434			—
Net cash provided by (used for) investing activities		(122,300	)		(1,027,134	)		—		(1,673,305	)		1,149,434			(1,673,305	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—		(6,298	)		—			(6,298	)
Proceeds from long-term debt		—			696,948			—		—			—			696,948
Debt issuance costs		—			(8,934	)		—		—			—			(8,934	)
Payments for hedge transactions		—			(5,667	)		—		—			—			(5,667	)
Proceeds from revolving credit facilities		—			600,000			—		—			—			600,000
Proceeds from issuance of common shares		8,201			—			—		—			—			8,201
Reduction in long-term debt		—			(274,095	)		—		(124,419	)		—			(398,514	)
Reduction in revolving credit facilities		—			(600,000	)		—		—			—			(600,000	)
Repurchase of equity component of convertible debt		—			(4,712	)		—		—			—			(4,712	)
Settlement of call options and warrants, net		—			1,134			—		—			—			1,134
Purchase of restricted stock		(1,935	)		—			—		—			—			(1,935	)
Tax benefit related to share-based awards		—			—			—		31			—			31
Cash dividends paid		—			(135,000	)		—		(135,000	)		270,000			—
Proceeds from parent contributions		—			—			—		1,149,434			(1,149,434	)		—
Net cash (used for) provided by financing activities		6,266			269,674			—		883,748			(879,434	)		280,254
Effect of exchange rate changes on cash and cash equivalents		—			—			—		(46	)		—			(46	)
Net (decrease) increase in cash and cash equivalents		(855	)		(115	)		—		(285,143	)		—			(286,113	)
Cash and cash equivalents, beginning of period		11,702			135			—		915,978			—			927,815
Cash and cash equivalents, end of period	$	10,847		$	20		$	—	$	630,835		$	—		$	641,702

132

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2009
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	40,589		$	646,645		$	608		$	1,089,086		$	(159,956	)	$	1,616,972
Cash flows from investing activities:
Purchases of investments		—			—			—			(32,674	)		—			(32,674	)
Sales and maturities of investments		—			—			—			57,033			—			57,033
Investment in unconsolidated affiliates		—			—			—			(125,076	)		—			(125,076	)
Capital expenditures		—			—			—			(1,093,435	)		—			(1,093,435	)
Proceeds from sales of assets and insurance claims		—			—			—			31,375			—			31,375
Proceeds from sale of consolidated affiliates		—			—			239,421			(239,421	)		—			—
Cash paid for investments in consolidated affiliates		(46,912	)		(900,000	)		—			—			946,912			—
Net cash provided by (used for) investing activities		(46,912	)		(900,000	)		239,421			(1,402,198	)		946,912			(1,162,777	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—			(18,157	)		—			(18,157	)
Proceeds from long-term debt		—			1,124,978			—			—			—			1,124,978
Debt issuance costs		—			(8,832	)		—			—			—			(8,832	)
Intercompany debt		—			—			143,859			(143,859	)		—			—
Proceeds from issuance of common shares		11,249			—			—			—			—			11,249
Reduction in long-term debt		—			(856,203	)		(225,191	)		(407	)		—			(1,081,801	)
Repurchase of equity component of convertible debt		—			(6,586	)		—			—			—			(6,586	)
Purchase of restricted stock		(1,515	)		—			—			—			—			(1,515	)
Tax benefit related to share-based awards		—			37			—			—			—			37
Cash dividends paid		—			—			(159,956	)		—			159,956			—
Proceeds from parent contributions		—			—			—			946,912			(946,912	)		—
Net cash (used for) provided by financing activities		9,734			253,394			(241,288	)		784,489			(786,956	)		19,373
Effect of exchange rate changes on cash and cash equivalents		—			—			—			12,160			—			12,160
Net (decrease) increase in cash and cash equivalents		3,411			39			(1,259	)		483,537			—			485,728
Cash and cash equivalents, beginning of period		8,291			96			1,259			432,441			—			442,087
Cash and cash equivalents, end of period	$	11,702		$	135		$	—		$	915,978		$	—		$	927,815

133

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 24    Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited)

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 Canadian 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 at December 31, 2009. Accordingly after the one-year deferral, we are presenting the information with regard to our oil and gas producing activities for the years ended December 31, 2011 and 2010.

The estimates of net proved oil and gas reserves as of December 31, 2011 were based on reserve reports prepared by independent petroleum engineers. AJM Deloitte 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. Cawley, Gillespie & Associates, Inc. prepared reports of estimated proved oil reserves for wholly owned assets located in the Eagle Ford Shale and Giddings field in Grimes County, Texas.

The estimates of net proved natural gas and oil reserves as of December 31, 2010 were based on reserve reports prepared by the following 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 properties located in the Cat Canyon and West Cat Canyon Fields in Santa Barbara County, California. Lonquist & Co., LLC prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Colombia.

The following supplementary information includes our results of operations for oil and gas production activities; capitalized costs related to oil and gas producing activities; and costs incurred in oil and gas property acquisition, exploration and development. Supplemental information is also provided for the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

Results of Operations

Results of operations consist of all activities within our Oil and Gas operating segment, or in discontinued operations in some cases. Net revenues from production include only the revenues from the production and sale of natural gas, oil, and natural gas liquids. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization (“DD&A”) allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

134

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	United States			Canada			Colombia			Total
	(in thousands)
Results of Operations
For the year ended December 31, 2011:
Consolidated Subsidiaries
Revenue	$	25,684		$	7,046		$	12,378		$	45,108
Production costs		12,682			27,432	(3)		3,704			43,818
Exploration expenses		23,768			3,324			122			27,214
Depreciation and depletion		22,350			104			949			23,403
Impairment of oil and gas properties		71,392			183,654						255,046
Loss (gain) on dispositions		(6,642	)		—			(39,599	)		(46,241	)
Related income tax expense (benefit)		(38,707	)		(54,979	)		15,577			(78,109	)
Results of producing activities for consolidated subsidiaries	$	(59,159	)	$	(152,489	)	$	31,625		$	(180,023	)
Equity Companies(1)
Revenue	$	98,933		$	1,335		$	26,730		$	126,998
Production costs		27,790			4,600			10,598			42,988
Depreciation and depletion		39,564			1,032			9,806			50,402
Impairment of oil and gas properties		15,624			—			—			15,624
Realized loss (gain) on derivative instruments		(33,969	)		(84	)		—			(34,053	)
Loss (gain) on acquisitions/dispositions		(49,484	)		—			(95,301	)		(144,785	)
Related income tax expense (benefit)(2)		—			—			6,055			6,055
Results of producing activities for equity companies	$	99,408		$	(4,213	)	$	95,572		$	190,767
Total results of operations	$	40,249		$	(156,702	)	$	127,197		$	10,744
For the year ended December 31, 2010:
Consolidated Subsidiaries
Revenue	$	19,180		$	11,276		$	16,619		$	47,075
Production costs		8,510			7,965			7,918			24,393
Exploration expenses		—			—			39,047			39,047
Depreciation and depletion		20,092			5,424			3,737			29,253
Impairment of oil and gas properties		110,165			—			—			110,165
Related income tax expense (benefit)		(15,856	)		(3,078	)		610			(18,324	)
Results of producing activities for consolidated subsidiaries	$	(103,731	)	$	965		$	(34,693	)	$	(137,459	)
Equity Companies(1)
Revenue	$	64,736		$	6,038		$	20,176		$	90,950
Production costs		18,460			9,036			9,174			36,670
Depreciation and depletion		24,221			6,033			7,058			37,312
Impairment of oil and gas properties		851			—			—			851
Realized gain on derivative instruments		(25,424	)		(2,543	)		—			(27,967	)
Related income tax expense (benefit)(2)		—			—			—			—
Results of producing activities for equity companies	$	46,628		$	(6,488	)	$	3,944		$	44,084
Total results of operations	$	(57,103	)	$	(5,523	)	$	(30,749	)	$	(93,375	)

135

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(1) Represents our proportionate share of interests in our equity companies.

(2) Equity companies are pass-through entities for tax purposes.

(3) Includes $24.2 million of transportation costs from pipeline commitments.

Capitalized Cost

Capitalized costs include the cost of properties, equipment and facilities for oil and gas-producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or for active completion, and costs of exploratory wells suspended or waiting for completion.

	United States			Canada			Colombia			Total
	(in thousands)
Capitalized Costs
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	587,385		$	101,402		$	—		$	688,787
Property acquisition costs, unproved		101,611			92,750			23,767			218,128
Total acquisition costs		688,996			194,152			23,767			906,915
Accumulated depreciation and depletion		(539,380	)		(28,838	)		(741	)		(568,959	)
Net capitalized costs for consolidated subsidiaries	$	149,616		$	165,314		$	23,026		$	337,956
Equity Companies(1)
Property acquisition costs, proved	$	1,141,393		$	—		$	—		$	1,141,393
Property acquisition costs, unproved		103,657			—			—			103,657
Total acquisition costs		1,245,050			—			—			1,245,050
Accumulated depreciation and depletion		(512,503	)		—			—			(512,503	)
Net capitalized costs for equity companies	$	732,547		$	—		$	—		$	732,547
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	480,618		$	62,109		$	57,251		$	599,978
Property acquisition costs, unproved		136,625			89,785			1,174			227,584
Total acquisition costs		617,243			151,894			58,425			827,562
Accumulated depreciation and depletion		(463,330	)		(7,344	)		(3,782	)		(474,456	)
Net capitalized costs for consolidated subsidiaries	$	153,913		$	144,550		$	54,643		$	353,106
Equity Companies(1)
Property acquisition costs, proved	$	749,515		$	78,224		$	98,629		$	926,368
Property acquisition costs, unproved		108,541			28,884			883			138,308
Total acquisition costs		858,056			107,108			99,512			1,064,676
Accumulated depreciation and depletion		(460,622	)		(72,338	)		(31,825	)		(564,785	)
Net capitalized costs for equity companies	$	397,434		$	34,770		$	67,687		$	499,891

(1) Represents our proportionate share of interests in our equity companies.

136

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense during 2011 and 2010, respectively, for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs include the costs of drilling and equipping successful exploration wells, as well as dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

	United States		Canada		Colombia			Total
	(in thousands)
Costs incurred in property acquisitions, exploration and development activities
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	23,051	$	7,748	$	—		$	30,799
Property acquisition costs, unproved		37,272		26,099		—			63,371
Exploration costs		49,156		—		122			49,278
Development costs		43,780		184		19,605			63,569
Asset retirement costs		496		750		254			1,500
Total costs incurred for consolidated subsidiaries	$	153,755	$	34,781	$	19,981		$	208,517
Equity Companies(1)
Property acquisition costs, proved	$	232,410	$	—	$	—		$	232,410
Property acquisition costs, unproved		14,268		—		4,395			18,663
Exploration costs		252		—		—			252
Development costs		136,711		—		—			136,711
Asset retirement costs		2,834		—		—			2,834
Total costs incurred for equity companies	$	386,475	$	—	$	4,395		$	390,870
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	25,080	$	—	$	—		$	25,080
Property acquisition costs, unproved		25,202		—		1,000			26,202
Exploration costs		8,199		—		33,599			41,798
Development costs		19,118		3,876		—			22,994
Asset retirement costs		—		—		770			770
Total costs incurred for consolidated subsidiaries	$	77,599	$	3,876	$	35,369		$	116,844
Equity Companies(1)
Property acquisition costs, proved	$	29,975	$	—	$	—		$	29,975
Property acquisition costs, unproved		34,207		—		—			34,207
Exploration costs		108		—		29,927			30,035
Development costs		118,828		1,056		11,805			131,689
Asset retirement costs		296		—		(104	)		192
Total costs incurred for equity companies	$	183,414	$	1,056	$	41,628		$	226,098

(1) Represents our proportionate share of interests in equity companies.

137

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil and Gas Reserves

The reserve disclosures that follow reflect estimates of proved reserves for our consolidated subsidiaries and equity companies of natural gas, oil, and natural gas liquids owned at December 31, 2011 and 2010 and changes in proved reserves during 2011 and 2010. Our year-end reserve volumes in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserve quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Estimates of volumes of proved reserves of natural gas at year end are expressed in billions of cubic feet of natural gas (“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 and the properties of our unconsolidated U.S. joint venture, the prices used in our reserve reports were $4.12 per mcf for the 12-month average of natural gas, $57.71 per barrel for natural gas liquids and $96.19 per barrel for oil at December 31, 2011. For our wholly owned properties in Canada, the price used in our reserve reports was $3.85 per mcf for the 12-month average of natural gas at December 31, 2011.

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 liquid natural gas and $61.12 per barrel for oil at December 31, 2010. The prices used in our 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 liquid natural gas 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.

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, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in average prices and year-end costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.

Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and our ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others.

In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, we do not view equity company reserves any differently than those of our consolidated subsidiaries.

138

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

	United States						Canada					Colombia					Total
Reserves	Liquids (MMBbls)			Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)			Liquids (MMBbls)			Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)
Net proved reserves of consolidated subsidiaries
January 1, 2011		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Revisions		0.1			(3.9	)		—		0.9			—			—		0.1			(3.0	)
Extensions, additions and discoveries		1.6			4.0			—		—			—			—		1.6			4.0
Production		(0.2	)		(3.0	)		—		(2.1	)		(0.1	)		—		(0.3	)		(5.1	)
Purchases in place		—			—			—		3.9			—			—		—			3.9
Sales in place		(20.9	)(2)		—			—		—			(1.9	)		—		(22.8	)		—
December 31, 2011		1.8			16.9			—		8.2			—			—		1.8			25.1
January 1, 2010		0.4			29.6			—		5.0			0.9			—		1.3			34.6
Revisions		0.1			(11.7	)		—		3.6			(0.7	)		—		(0.6	)		(8.1	)
Extensions, additions and discoveries		—			5.0			—		—			2.0			—		2.0			5.0
Production		(0.1	)		(3.1	)		—		(3.1	)		(0.2	)		—		(0.3	)		(6.2	)
Purchases in place		20.8	(2)		—			—		—			—			—		20.8			—
Sales in place		—			—			—		—			—			—		—			—
December 31, 2010		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Proportional interest in proved reserves of equity companies
January 1, 2011		7.9			552.8			—		5.2			1.9			—		9.8			558.0
Revisions		(4.2	)		(359.0	)		—		—			—			—		(4.2	)		(359.0	)
Extensions, additions and discoveries		3.2			103.1			—		—			—			—		3.2			103.1
Production		(0.4	)		(18.6	)		—		(0.4	)		(0.3	)		—		(0.7	)		(19.0	)
Purchases in place		9.4			304.2	(3)		—		—			—			—		9.4			304.2
Sales in place		—			—			—		(4.8	)(4)		(1.6	)(5)		—		(1.6	)		(4.8	)
December 31, 2011		15.9			582.5			—		—			—			—		15.9			582.5
January 1, 2010		5.2			466.9			—		7.5			0.6			—		5.8			474.4
Revisions		1.5			(119.1	)		—		(0.8	)		0.5			—		2.0			(119.9	)
Extensions, additions and discoveries		0.6			108.5			—		—			1.3			—		1.9			108.5
Production		(0.2	)		(12.3	)		—		(1.5	)		(0.3	)		—		(0.5	)		(13.8	)
Purchases in place		0.8			109.8			—		—			—			—		0.8			109.8
Sales in place		—			(1.0	)		—		—			(0.2	)		—		(0.2	)		(1.0	)
December 31, 2010		7.9			552.8			—		5.2			1.9			—		9.8			558.0

139

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	United States				Canada				Colombia				Total
Reserves	Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)
Total proved reserves at December 31, 2009		5.6		496.5		—		12.5		1.5		—		7.1		509.0
Total proved reserves at December 31, 2010		29.1		572.6		—		10.7		3.9		—		33.0		583.3
Total proved reserves at December 31, 2011		17.7		599.4		—		8.2		—		—		17.7		607.6
Proved Developed Reserves at January 1, 2010
Consolidated subsidiaries		0.2		18.4		—		5.0		0.6		—		0.8		23.4
Equity companies(1)		1.8		106.6		—		7.5		0.5		—		2.3		114.1
Proved Developed Reserves at December 31, 2010
Consolidated subsidiaries		2.7		17.1		—		5.5		1.6		—		4.3		22.6
Equity companies(1)		3.0		147.1		—		5.2		0.5		—		3.5		152.3
Proved Developed Reserves at December 31, 2011
Consolidated subsidiaries		0.9		13.6		—		8.2		—		—		0.9		21.8
Equity companies(1)		6.3		256.4		—		—		—		—		6.3		256.4
Proved Undeveloped Reserves at January 1, 2010
Consolidated subsidiaries		0.2		11.2		—		—		0.3		—		0.5		11.2
Equity companies(1)		3.4		360.3		—		—		0.1		—		3.5		360.3
Proved Undeveloped Reserves at December 31, 2010
Consolidated subsidiaries		18.5		2.7		—		—		0.4		—		18.9		2.7
Equity companies(1)		4.9		405.7		—		—		1.4		—		6.3		405.7
Proved Undeveloped Reserves at December 31, 2011
Consolidated subsidiaries		0.9		3.3		—		—		—		—		0.9		3.3
Equity companies(1)		9.6		326.1		—		—		—		—		9.6		326.1

(1) Represents our proportionate share of interests in equity companies.

(2) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(3) Relates to acquisitions of properties with 360.4 Bcfe and drilling of non-proved properties of 122.2 Bcfe. In addition, negative revisions of 384 Bcfe were noted primarily resulting from proved undeveloped reserves being reclassified to non-proved status in accordance with the SEC five-year guidance for recording proved reserves.

(4) Relates to SMVP that was dissolved in June 2011, and of proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

(5) Relates to the sale of Remora’s assets which resulted in a decrease in proved reserves of 9.5 Bcfe.

Standardized Measure of Discounted Future Cash Flows

For the years ended December 31, 2011 and 2010, the standardized measure of discounted future net cash flow was computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and

140

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

a discount factor of 10 percent to proved reserves. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and global, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The 10-percent discount factor is prescribed by GAAP.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our consolidated subsidiaries and equity companies’ proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Significant changes in estimated reserve volumes or commodity prices could have a material effect on our consolidated financial statements.

	United States			Canada			Colombia			Total
	(in thousands)
Standardized Measure of Discounted Future Cash Flows
For the year ended December 31, 2011:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	225,141		$	20,906		$	—		$	246,047
Future production costs		(66,448	)		(5,761	)		—			(72,209	)
Future development costs		(45,505	)		(1,607	)		—			(47,112	)
Future income tax expense(2)		—			—			—			—
Future net cash inflows		113,188			13,538			—			126,726
Effect of discounting net cash flows at 10%		(55,886	)		(2,527	)		—			(58,413	)
Discounted future net cash flows	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Future cash flows from sales of oil and gas	$	3,347,348		$	—		$	—		$	3,347,348
Future production costs		(1,005,922	)		—			—			(1,005,922	)
Future development costs		(660,509	)		—			—			(660,509	)
Future income tax expense(3)		—			—			—			—
Future net cash inflows		1,680,917			—			—			1,680,917
Effect of discounting net cash flows at 10%		(1,098,854	)		—			—			(1,098,854	)
Discounted future net cash flows	$	582,063		$	—		$	—		$	582,063
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	639,365		$	11,011		$	—		$	650,376
For the year ended December 31, 2010:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	1,468,944		$	16,435		$	156,921		$	1,642,300
Future production costs		(481,487	)		(5,600	)		(83,556	)		(570,643	)
Future development costs		(152,309	)		(360	)		(16,216	)		(168,885	)
Future income tax expense(2)		(268,774	)		—			—			(268,774	)
Future net cash inflows		566,374			10,475			57,149			633,998
Effect of discounting net cash flows at 10%		(353,232	)		(2,046	)		(10,256	)		(365,534	)
Discounted future net cash flows	$	213,142		$	8,429		$	46,893		$	268,464
Equity Companies(1)
Future cash flows from sales of oil and gas	$	2,889,308		$	14,713		$	141,410		$	3,045,431
Future production costs		(752,792	)		(6,463	)		(56,837	)		(816,092	)
Future development costs		(850,053	)		(992	)		(12,307	)		(863,352	)
Future income tax expense (3)		—			—			—			—
Future net cash inflows		1,286,463			7,258			72,266			1,365,987
Effect of discounting net cash flows at 10%		(995,091	)		(1,477	)		(14,313	)		(1,010,881	)
Discounted future net cash flows	$	291,372		$	5,781		$	57,953		$	355,106
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	504,514		$	14,210		$	104,846		$	623,570

141

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table reflects the estimate of changes in the standardized measure of discounted future net cash flows from proved reserves:

	United States			Canada			Colombia			Total
	(in thousands)
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries
Discounted future net cash flows as of December 31, 2009	$	38,345		$	6,527		$	11,741		$	56,613
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		8,037			—			45,072			53,109
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(10,670	)		(3,311	)		(8,701	)		(22,682	)
Development costs incurred during the year		8,359			—			—			8,359
Net change in prices and production costs		96,662			46			(2,555	)		94,153
Net change in future development costs		4,155			(192	)		285			4,248
Revisions of previous reserves estimates		(27,501	)		5,628			(7,093	)		(28,966	)
Purchases of reserves		196,613	(4)		—			—			196,613
Accretion of discount		3,562			496			1,030			5,088
Other		(17,357	)		(765	)		7,114			(11,008	)
Net change in income taxes(2)		(87,063	)		—			—			(87,063	)
Total change in the standardized measure for consolidated subsidiaries	$	174,797		$	1,902		$	35,152		$	211,851
Discounted future net cash flows as of December 31, 2010	$	213,142		$	8,429		$	46,893		$	268,464
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		32,838			—			—			32,838
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(14,247	)		(5,848	)		(8,674	)		(28,769	)
Development costs incurred during the year		360			—			—			360
Net change in prices and production costs		(15,274	)		1,221			—			(14,053	)
Net change in future development costs		775			—			—			775
Revisions of previous reserves estimates		(5,285	)		1,219			19,859			15,793
Purchases of reserves					4,557						4,557
Divestiture of reserves		(272,448	)(4)					(58,078	)(5)		(330,526	)
Accretion of discount		30,021			843						30,864
Other		356			590						946
Net change in income taxes(2)		87,064									87,064
Total change in the standardized measure for consolidated subsidiaries	$	(155,840	)	$	2,582		$	(46,893	)	$	(200,151	)

142

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	United States			Canada			Colombia			Total
	(in thousands)
Discounted future net cash flows as of December 31, 2011	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Discounted future net cash flows as of December 31, 2009	$	52,941		$	9,569		$	13,706		$	76,216
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		20,230			—			40,664			60,894
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(46,276	)		2,998			(11,002	)		(54,280	)
Development costs incurred during the year		69,207			—			—			69,207
Net change in prices and production costs		90,974			(5,205	)		3,032			88,801
Net change in future development costs		—			(374	)		(847	)		(1,221	)
Revisions of previous reserves estimates		76,723			(1,077	)		17,289			92,935
Purchases of reserves		5,453			—			—			5,453
Sales of reserves		(1,446	)		—			(5,418	)		(6,864	)
Accretion of discount		5,294			794			529			6,617
Other		18,272			(924	)		—			17,348
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	238,431		$	(3,788	)	$	44,247		$	278,890
Discounted future net cash flows as of December 31, 2010	$	291,372		$	5,781		$	57,953		$	355,106
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		83,692			—			—			83,692
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(71,143	)		3,245			(16,132	)		(84,030	)
Development costs incurred during the year		44,294			—			—			44,294
Net change in prices and production costs		(20,856	)		—			—			(20,856	)
Net change in future development costs		(51,098	)		—			—			(51,098	)
Revisions of previous reserves estimates		20,178			—			—			20,178
Purchases of reserves		262,719			—			—			262,719
Divestiture of reserves		—			(9,026	)(6)		(41,821	)(5)		(50,847	)
Sales of reserves		—			—			—			—
Accretion of discount		29,155			—			—			29,155
Other		(6,250	)		—			—			(6,250	)
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	290,691		$	(5,781	)	$	(57,953	)	$	226,957
Discounted future net cash flows as of December 31, 2011	$	582,063		$	—		$	—		$	582,063

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

143

Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(4) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(5) In April 2011, some of our wholly owned oil and gas assets in Colombia were sold. Remora completed sales of its oil and gas assets in Colombia, resulting in a decrease of proved reserves of 9.5 Bcfe, in the second quarter of 2011.

(6) In June 2011, SMVP that was dissolved in June 2011, resulting in a decrease in proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

144

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

ITEM 9A.    CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures. We maintain a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. We have investments in certain unconsolidated entities that we do not control or manage. Because we do not control or manage these entities, our disclosure controls and procedures with respect to these entities are necessarily more limited than those we maintain with respect to our consolidated subsidiaries.

The Company’s management, with the participation of the Company’s Deputy Chairman, President and Chief Executive Officer and its Principal Accounting and Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on this evaluation, the Company’s Deputy Chairman, President and Chief Executive Officer and its Principal Accounting and Financial Officer have concluded that, as of the end of the period, the Company’s disclosure controls and procedures are effective, at the reasonable assurance level, in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Company in reports that it files or submits under the Exchange Act and are effective, at the reasonable assurance level, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the Company’s Deputy Chairman, President and Chief Executive Officer and its Principal Accounting and Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company’s internal control over financial reporting (identified in connection with the evaluation required by paragraph (d) in Rules 13a-15 and 15d-15 under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

145

Management’s Report on Internal Control Over Financial Reporting

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

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

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011. PricewaterhouseCoopers LLP has issued a report on the effectiveness of internal control over financial reporting, which is included in Part II, Item 8 of this report.

ITEM 9B.    OTHER INFORMATION

Not applicable.

146

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information called for by this item will be contained in the definitive Proxy Statement to be distributed in connection with our 2012 annual general meeting of shareholders under the captions “Election of Directors”, “Other Executive Officers”, “Section 16(a) Beneficial Ownership Reporting Compliance”, and is incorporated into this document by reference.

We have adopted a Code of Business Conduct that applies to all employees, including our principal executive officer, principal financial officer, and principal accounting officer. The Code of Ethics satisfies the SEC’s definition of a “Code of Ethics” and is posted on our website at www.nabors.com. We intend to disclose on our website any amendments to the Code of Conduct and any waivers of the Code that apply to our principal executive officer, principal financial officer, or principal accounting officer.

On June 27, 2011, we filed with the New York Stock Exchange the Annual CEO Certification regarding our compliance with the Exchange’s Corporate Governance listing standards as required by Section 303A-12(a) of the Exchange’s Listed Company Manual.

ITEM 11.    EXECUTIVE COMPENSATION

The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2012 annual general meeting of shareholders under the caption “Management Compensation” and except as specified in the following sentence, is incorporated into this document by reference. Information in Nabors’ 2012 proxy statement not deemed to be “soliciting material” or “filed” with the Commission under its rules, including the Compensation Committee Report, is not deemed to be incorporated by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

We maintain five different equity compensation plans: 1996 Employee Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and 2003 Employee Stock Plan pursuant to which we may grant equity awards to eligible persons. The terms of our equity compensation plans are described more fully below.

The following table gives information about these equity compensation plans as of December 31, 2011:

Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of  securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders		24,117,560	$	18.2095		15,526,990
Equity compensation plans not approved by security holders		3,751,746	$	23.6976		842,191
Total

(1) The 1996 Employee Stock Plan incorporated an evergreen formula pursuant to which on each January 1, the aggregate number of shares reserved for issuance under the plan were increased by an amount equal to

147

1.5% of the common shares outstanding on September 30 of the immediately preceding fiscal year. Effective January 1, 2006, no new awards could be granted under this plan but there are outstanding awards that were granted before this date.

(2) The 2003 Employee Stock Plan provides, commencing on June 1, 2006 and expiring June 1, 2013, on each January 1 for an automatic increase in the number of shares reserved and available for issuance under the Plan by an amount equal to two percent (2%) of the Company’s outstanding common shares as of each June 1 or January 1 date.

Following is a brief summary of the material terms of the plans that have not been approved by our shareholders. Unless otherwise indicated, (1) each plan is administered by an independent committee appointed by the Company’s Board of Directors; (2) the exercise price of options granted under each plan must be no less than 100% of the fair market value per common share on the date of the grant of the option; (3) the term of an award granted under each plan may not exceed 10 years; (4) options granted under the plan are nonstatutory options (“NSOs”) not intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended (the “IRC”); and (5) unless otherwise determined by the committee in its discretion, options may not be exercised after the optionee has ceased to be employed by the Company.

1998 Employee Stock Plan

The plan reserved for issuance up to 35,000,000 common shares of the Company pursuant to the exercise of options granted under the plan. The persons eligible to participate in the plan were employees and consultants of the Company. Options granted to employees were either awards of shares, non-qualified stock options (each, an “NQSO”), incentive stock options (each, an “ISO”) or stock appreciation rights (each, an “SAR”). An optionee may reduce the option exercise price by paying the Company in cash, shares, options, or the equivalent, an amount equal to the difference between the exercise price and the reduced exercise price of the option. The administrative committee established performance goals for stock awards in writing and not later than the date required for compliance under Section 162(m) of the IRC, and vesting of these shares was contingent upon the attainment of such performance goals. Stock awards vest over a period determined by the committee. The Plan expired on January 8, 2008 and effective that date, no new awards could be granted even though there are outstanding awards that were granted before this date. The committee could grant ISOs of not less than 100% of the fair market value per common share on the date of grant; except that in the event the optionee owns on the date of grant, securities possessing more than 10% of the total combined voting power of all classes of securities of the Company or of any subsidiary of the Company, the price per share must not have been less than 110% of the fair market value per common share on the date of the grant. The option must expire five years from the date it is granted. SARs may be granted in conjunction with all or part of any option granted under the plan, in which case the exercise of the SAR must require the cancellation of a corresponding portion of the option; conversely, the exercise of the option will result in cancellation of a corresponding portion of the SAR. In the case of a NQSO, SARs may be granted either at or after the time of grant of the option. In the case of an ISO, SARs may be granted only at the time of grant of the option. A SAR may also be granted on a stand-alone basis. The term of a SAR must be established by the committee. The exercise price of a SAR cannot be less than 100% of the fair market value per common share on the date of grant. The committee has the authority to make provisions in its award and grant agreements to address vesting and other issues arising in connection with a change of control.

1999 Stock Option Plan for Non-Employee Directors

The plan reserves for issuance up to 3,000,000 common shares of the Company pursuant to the exercise of options granted under the plan. The plan is administered by the Board of Directors or a committee appointed by the Board. Eligible directors may not consider or vote on the administration of the plan or serve as a member of the committee. Options may be granted under the plan to non-employee directors of the Company. Options vest and become non-forfeitable on the first anniversary of the option grant if the optionee has continued to serve as a director until that day, unless otherwise provided. In the event of termination of an optionee’s service as a

148

director by reason of voluntary retirement, declining to stand for re-election or becoming a full-time employee of the Company or a subsidiary of the Company, all unvested options granted under the Plan automatically expire and are not exercisable, and all unexercised options continue to be exercisable until their stated expiration date. In the event of death or disability of an optionee while the optionee is a director, the then-outstanding options of such optionee become exercisable for two years from the date of the death or disability. All unvested options automatically vest and become non-forfeitable as of the date of death or disability and become exercisable for two years from the date of the death of the optionee or until the stated expiration date, whichever is earlier. In the event of the termination of an optionee’s service as a director by the Board of Directors for cause or the failure of such director to be re-elected, the administrator of the plan in its sole discretion can cancel the then-outstanding options of the optionee, including options that have vested, and those options automatically expire and become non-exercisable on the effective date of the termination.

The remainder of the information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2012 annual general meeting of shareholders under the caption “Share Ownership of Management and Principal Shareholders” and is incorporated into this document by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2012 annual general meeting of shareholders under the caption “Certain Relationships and Related Transactions” and is incorporated into this document by reference.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2012 annual general meeting of shareholders under the caption “Independent Auditor Fees” and is incorporated into this document by reference.

149

PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULE

(a) The following documents are filed as part of this report:

(1) Financial Statements

	Page No.
Consolidated Balance Sheets as of December 31, 2011 and 2010		65
Consolidated Statements of Income (Loss) for the Years Ended December 31, 2011, 2010 and 2009		66
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		67
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2011, 2010 and 2009		68

(2) Financial Statement Schedule

	Page No.
Schedule II — Valuation and Qualifying Accounts		157

All other supplemental schedules are omitted because of the absence of the conditions under which they would be required or because the required information is included in the financial statements or related notes.

(b) Exhibits

Exhibit No.	Description
2.1	Agreement and Plan of Merger among Nabors Industries, Inc., Nabors Acquisition Corp. VIII, Nabors Industries Ltd. and Nabors US Holdings Inc. (incorporated by reference to Annex I to the proxy statement/prospectus included in our Registration Statement on Form S-4 (File No. 333-76198) filed with the SEC on May 10, 2002, as amended).
2.2	Agreement and Plan of Merger, by and among Nabors Industries Ltd., Diamond Acquisition Corp., and Superior, dated as of August 6, 2010 (incorporated by reference to Exhibit 2.2 to our Form 8-K (File No. 001-32657) filed with the SEC on August 9, 2010).
3.1	Memorandum of Association of Nabors Industries Ltd. (incorporated by reference to Annex II to the proxy statement/prospectus included in our Registration Statement on Form S-4 (File No. 333-76198) filed with the SEC on May 10, 2002, as amended).
3.2	Amended and Restated Bye-Laws of Nabors Industries Ltd. (incorporated by reference to Exhibit 4.2 to our Form 10-Q (File No. 000-49887) filed with the SEC on August 3, 2005).
3.2(a)	Amendment to Amended and Restated Bye-Laws of Nabors Industries Ltd. (incorporated by reference to Exhibit A of our Proxy Statement (File No. 001-32657) filed with the SEC on February 24, 2006).
3.3	Form of Resolutions of our Board of Directors authorizing the issue of the Special Voting Preferred Share (incorporated by reference to Exhibit 3.3 to our Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (File No. 333-85228-99) filed with the SEC on June 11, 2002).
4.1	Indenture, dated August 22, 2002, among Nabors Industries, Inc., as issuer, Nabors Industries Ltd., as guarantor, and Bank One, N.A., with respect to Nabors Industries, Inc.’s Series A and Series B 5.375% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to Nabors Industries, Inc.’s Registration Statement on Form S-4 (File No. 333-10049201) filed with the SEC on October 11, 2002).

150

Exhibit No.	Description
4.2	Purchase Agreement, dated February 14, 2008, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on February 25, 2008).
4.2(a)	Indenture, dated February 20, 2008, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (including form of 6.15% Senior Note due 2018) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on February 25, 2008).
4.2(b)	Registration Rights Agreement, dated as of February 20, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.3 to our Form 8-K (File No. 001-32657) filed with the SEC on February 25, 2008).
4.3	Purchase Agreement, dated July 17, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on July 23, 2008).
4.3(a)	Registration Rights Agreement, dated July 22, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on July 23, 2008).
4.4	Purchase Agreement, dated January 7, 2009, among Nabors Industries, Inc., Nabors Industries Ltd., Goldman, Sachs & Co., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Howard Weil Incorporated, J.P. Morgan Securities Inc., Morgan Stanley & Co. Incorporated, Tudor, Pickering, Holt & Co. Securities, Inc. and Wells Fargo Securities, LLC, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on January 14, 2009).
4.4(a)	Indenture related to the Senior Notes due 2019, dated as of January 12, 2009, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (including form of 9.25% Senior Note due 2019) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on January 14, 2009).
4.4(b)	Registration Rights Agreement, dated as of January 12, 2009, among Nabors Industries, Inc., Nabors Industries Ltd., Goldman, Sachs & Co., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Howard Weil Incorporated, J.P. Morgan Securities Inc., Morgan Stanley & Co. Incorporated, Tudor, Pickering, Holt & Co. Securities, Inc. and Wells Fargo Securities, LLC, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on January 14, 2009).
4.5	Purchase Agreement, dated September 9, 2010, among Nabors Industries, Inc., Nabors Industries Ltd., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Mizuho Securities USA Inc., Banc of America Securities LLC, Morgan Stanley & Co. Incorporated, HSBC Securities (USA) Inc., PNC Capital Markets LLC and Scotia Capital (USA) Inc. with respect to Nabors Industries, Inc.’s 5.0% Senior Notes due 2020 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on September 15, 2010).

151

Exhibit No.	Description
4.5(a)	Indenture dated as of September 14, 2010, among Nabors Industries, Inc., Nabors Industries Ltd., Wilmington Trust Company, as trustee and Citibank, N.A. as securities administrator, with respect to Nabors Industries, Inc.’s 5.0% Senior Notes due 2020 (including form of 5.0% Senior Note due 2020) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on September 15, 2010).
4.5(b)	Registration Rights Agreement, dated as of September 14, 2010, among Nabors Industries, Inc., Nabors Industries Ltd., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Mizuho Securities USA Inc., Banc of America Securities LLC, Morgan Stanley & Co. Incorporated, HSBC Securities (USA) Inc., PNC Capital Markets LLC and Scotia Capital (USA) Inc. with respect to Nabors Industries, Inc.’s 5.0% Senior Notes due 2020 (incorporated by reference to Exhibit 4.3 to our Form 8-K (File No. 001-32657) filed with the SEC on September 15, 2010).
4.6	Tender and Voting Agreement, by and among Nabors Industries Ltd., Diamond Acquisition Corp, and certain Superior stockholders, dated as of August 6, 2010 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on August 9, 2010).
4.7	Purchase Agreement, dated August 16, 2011, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc., Mizuho Securities USA Inc., UBS Securities LLC, Morgan Stanley & Co. LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, HSBC Securities (USA) Inc. and PNC Capital Markets LLC with respect to Nabors Industries, Inc.’s 4.625% Senior Notes due 2021 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on August 17, 2011).
4.7(a)	Indenture dated as of August 23, 2011, among Nabors Industries, Inc., Nabors Industries Ltd., Wilmington Trust, National Association, as trustee and Citibank, N.A. as securities administrator, with respect to Nabors Industries, Inc.’s 4.625% Senior Notes due 2021 (including form of 4.625% Senior Note due 2021) (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on August 24, 2011).
4.7(b)	Registration Rights Agreement, dated as of August 23, 2011, among Nabors Industries, Inc., Nabors Industries Ltd., and Citigroup Global Markets Inc. as representative of the Initial Purchasers, with respect to Nabors Industries, Inc.’s 4.625% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on August 24, 2011).
10.1(+)	Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of April 1, 2009 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on April 30, 2009).
10.1(a) (+)	First Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of June 29, 2009 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on July 1, 2009).
10.1(b) (+)	Second Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of December 28, 2009 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on December 28, 2009).
10.2(+)	Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of April 1, 2009 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on April 30, 2009).

152

Exhibit No.	Description
10.2(a) (+)	First Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of June 29, 2009 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on July 1, 2009).
10.2(b) (+)	Second Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of December 28, 2009 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on December 28, 2009).
10.2(c) (+)	Employment Agreement effective October 1, 1996, among Nabors Industries, Inc. and Anthony G. Petrello (incorporated by reference to Exhibit 10.8 to our Form 10-Q (File No. 1-9245) filed May 16, 1997).
10.3	Form of Indemnification Agreement entered into between Nabors Industries Ltd. and the directors and executive officers identified in the schedule thereto (incorporated by reference to Exhibit 10.28 to our Form 10-K (File No. 000-49887) filed with the SEC on March 31, 2003).
10.4(+)	Form of Stock Option Agreement — Isenberg/Petrello (incorporated by reference to Exhibit 10.03 to our Form 8-K (File No. 000-49887) filed with the SEC on March 2, 2005).
10.5(+)	Form of Stock Option Agreement — Others (incorporated by reference to Exhibit 10.04 to our Form 8-K (File No. 000-49887) filed with the SEC on March 2, 2005).
10.6(+)	2003 Employee Stock Plan (incorporated by reference to Annex D of our Proxy Statement (File No. 000-49887) filed with the SEC on May 8, 2003).
10.6(a) (+)	First Amendment to 2003 Employee Stock Plan (incorporated by reference to Exhibit 4.1 to our Form 10-Q (File No. 000-49887) filed with the SEC on August 3, 2005).
10.6(b) (+)	Amended and Restated 2003 Employee Stock Plan (incorporated by reference to Exhibit A of our Proxy Statement (File No. 001-32657) filed with the SEC on May 4, 2006).
10.6(c) (+)	Nabors Industries Ltd. Amended and Restated 2003 Employee Stock Plan (incorporated by reference to Exhibit A of our Revised Definitive Proxy Statement on Schedule 14A (File No. 001-32657) filed with the SEC on May 4, 2006) (incorporated by reference to Exhibit 99.1 to our Form S-8 filed with the SEC on November 12, 2008).
10.7(+)	1996 Employee Stock Plan (incorporated by reference to Nabors Industries Inc.’s Registration Statement on Form S-8 (File No. 333-11313) filed with the SEC on September 3, 1996).
10.8(+)	Nabors Industries, Inc. 1997 Executive Officers Incentive Stock Plan (incorporated by reference to Exhibit 10.20 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed with the SEC on December 29, 1997).
10.9(+)	Nabors Industries, Inc. 1998 Employee Stock Plan (incorporated by reference to Exhibit 10.19 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed with the SEC on March 31, 1999).
10.10(+)	Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.21 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed with the SEC March 31, 1999).
10.10(a) (+)	Amendment to Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.19 to Nabors Industries Inc.’s Form 10-K (File No. 1-09245) filed with the SEC on March 19, 2002).

153

Exhibit No.	Description
10.10(b) (+)	Amended and Restated 1999 Stock Option Plan for Non-Employee Directors (amended on May 2, 2003) (incorporated by reference to Exhibit 10.29 to our Form 10-Q (File No. 000-49887) filed with the SEC on May 12, 2003).
10.11	Purchase and Sale Agreement (Red River) by and among El Paso Production Company and El Paso Production GOM Inc., jointly and severally as Seller and Ramshorn Investments, Inc., as Purchaser dated October 8, 2003 (incorporated by reference to Exhibit 10.23 to our Form 10-K (File No. 000-49887) filed with the SEC on March 15, 2004).
10.12	Purchase and Sale Agreement (USA) between El Paso Production Oil & Gas USA, L.P., as Seller and Ramshorn Investments, Inc., as Purchaser dated October 8, 2003 (incorporated by reference to Exhibit 10.24 to our Form 10-K (File No. 000-49887) filed with the SEC on March 15, 2004).
10.13	Credit Agreement, dated as of September 7, 2010, among Nabors Industries, Inc., as borrower, Nabors Industries Ltd., as guarantor, UBS Securities LLC, Citibank, N.A., Deutsche Bank AG New York Branch and Mizuho Corporate Bank (USA), as Joint Lead Arrangers and Joint Bookrunners, UBS Securities LLC, as Documentation Agent and syndication agent, UBS AG, Stamford Branch, as administrative agent, the lenders party thereto from time to time and UBS Loan Finance, LLC, as Swingline Lender (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on September 7, 2010).
10.14	Credit Agreement, dated as of April 20, 2011, among Nabors Industries, Inc., as borrower, Nabors Industries Ltd., as guarantor, Citigroup Global Markets Inc., Mizuho Corporate Bank, Ltd., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC as Joint Lead Arrangers and Joint Bookrunners, Mizuho Corporate Bank, Ltd., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as Documentation Agents, Citibank, N.A., as Administrative Agent and Swingline Lender and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on April 20, 2011).
12	Computation of Ratios.*
14	Code of Business Conduct (incorporated by reference to Exhibit 14 to our Form 10-K (File No. 000-49887) filed with the SEC on March 15, 2004).
18	Preference Letter of Independent Accountants Regarding Change in Accounting Principle (incorporated by reference to Exhibit 18 to our Form 10-Q (File No. 000-49887) filed with the SEC on November 2, 2005).
21	Significant Subsidiaries*
23.1	Consent of Independent Registered Public Accounting Firm – PricewaterhouseCoopers LLP - Houston.*
23.2	Consent of Miller and Lents, Ltd.*
23.3	Consent of AJM Deloitte*
23.4	Consent of Cawley, Gillespie & Associates, Inc.*
23.5	Consent of Miller and Lents, Ltd.- NFR Energy LLC*
31.1	Rule 13a-14(a)/15d-14(a) Certification of Anthony G. Petrello, Deputy Chairman, President and Chief Executive Officer*

154

Exhibit No.	Description
31.2	Rule 13a-14(a)/15d-14(a) Certification of R. Clark Wood, Principal Accounting and Financial Officer*
32.1	Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Anthony G. Petrello, Deputy Chairman, President and Chief Executive Officer and R. Clark Wood, Principal Accounting and Financial Officer (furnished herewith).
99.1	Report of Miller and Lents, Ltd.*
99.2	Report of AJM Deloitte*
99.3	Report of Cawley, Gillespie & Associates, Inc.*
99.4	Report of Miller and Lents, Ltd. — NFR Energy LLC*
99.5	Financial Statements and Notes for NFR Energy LLC*
99.6	Letter from AJM Deloitte*
101.INS	XBRL Instance Document*
101.SCH	XBRL Schema Document*
101.CAL	XBRL Calculation Linkbase Document*
101.LAB	XBRL Label Linkbase Document*
101.PRE	XBRL Presentation Linkbase Document*
101.DEF	XBRL Definition Linkbase Document*

* Filed herewith.

(+) Management contract or compensatory plan or arrangement.

155

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NABORS INDUSTRIES LTD.
By:	/s/ Anthony G. Petrello
	Anthony G. Petrello
	Deputy Chairman, President and
	Chief Executive Officer
By:	/s/ R. Clark Wood
	R. Clark Wood
	Principal Accounting and
	Financial Officer

Date: February 29, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Anthony G. Petrello Anthony G. Petrello	Deputy Chairman, President and Chief Executive Officer	February 29, 2012
/s/ R. Clark Wood R. Clark Wood	Principal Accounting and Financial Officer	February 29, 2012
/s/ William T. Comfort William T. Comfort	Director	February 29, 2012
/s/ John V. Lombardi John V. Lombardi	Director	February 29, 2012
/s/ James L. Payne James L. Payne	Director	February 29, 2012
/s/ Myron M. Sheinfeld Myron M. Sheinfeld	Director	February 29, 2012
/s/ John Yearwood John Yearwood	Director	February 29, 2012

156

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2011, 2010 and 2009

	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
	(In thousands)
2011
Allowance for doubtful accounts	$	22,507	$	5,352		$	(29	)	$	13,873		$	41,703
Inventory reserve		6,784		(1,185	)		1,889			(504	)		6,984
Valuation allowance on deferred tax assets		1,514,153		—			—			(28,613	)		1,485,540
2010
Allowance for doubtful accounts	$	23,681	$	1,545		$	167		$	(2,886	)	$	22,507
Inventory reserve		4,824		(182	)		1,695			447			6,784
Valuation allowance on deferred tax assets		1,570,890		—			—			(56,737	)		1,514,153
2009
Allowance for doubtful accounts	$	23,224	$	5,793		$	239		$	(5,575	)	$	23,681
Inventory reserve		4,483		1,429			—			(1,088	)		4,824
Valuation allowance on deferred tax assets		132,262		1,438,628			—			—			1,570,890

157

Exhibit Index

Exhibits	Description
12	Computation of Ratios.
21	Significant Subsidiaries
23.1	Consent of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP — Houston.
23.2	Consent of Miller and Lents, Ltd.
23.3	Consent of AJM Deloitte
23.4	Consent of Cawley, Gillespie & Associates, Inc.
23.5	Consent of Miller and Lents, Ltd. — NFR Energy LLC
31.1	Rule 13a-14(a)/15d-14(a) Certification of Anthony G. Petrello, Deputy Chairman, President and Chief Executive Officer
31.2	Rule 13a-14(a)/15d-14(a) Certification of R. Clark Wood, Principal Accounting and Financial Officer
32.1	Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Anthony G. Petrello, Deputy Chairman, President and Chief Executive Officer and R. Clark Wood, Principal Accounting and Financial Officer (furnished herewith).
99.1	Report of Miller and Lents, Ltd.
99.2	Report of AJM Deloitte
99.3	Report of Cawley, Gillespie & Associates, Inc.
99.4	Report of Miller and Lents, Ltd. — NFR Energy LLC
99.5	Financial Statements and Notes for NFR Energy LLC
99.6	Letter from AJM Deloitte
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document
101.DEF	XBRL Definition Linkbase Document

158

EX-12

EXHIBIT 12

NABORS INDUSTRIES LTD. AND SUBSIDIARIES

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(In thousands, except ratio amounts)

			Years Ended December 31,
			2011			2010			2009
Income (loss) from continuing operations before income taxes			$	486,724		$	293,485		$	69,126
Less earnings (add losses) from affiliates, net of dividends				(140,477	)		(24,268	)		170,564
Less subsidiary preferred stock dividends				(3,000	)		(750	)		—
Add amortization of capitalized interest				7,626			6,089			5,312
Add fixed charges as adjusted				265,079			277,468			269,870
Earnings	(1	)	$	615,982		$	552,024		$	514,872
Fixed charges:
Interest expense:
Interest on indebtedness			$	224,438		$	196,563		$	173,111
Capitalized				23,350			12,448			28,813
Amortization of debt related costs (a)				32,195			76,149			92,936
Subsidiary preferred stock dividends				3,000			750			—
Interest portion of rental expense				5,446			4,006			3,823
Fixed charges before adjustments	(2	)		288,429			289,916			298,683
Less capitalized interest				(23,350	)		(12,448	)		(28,813	)
Fixed charges as adjusted			$	265,079		$	27,468		$	269,870
Ratio (earnings divided by fixed charges before adjustments)	(1	)/(2)		2.14			1.90			1.72

(a) Includes deferred financing, discount and premium amortization.

EX-21

Exhibit 21

Nabors Industries Ltd. and Subsidiaries

Significant Subsidiaries

Subsidiary

Nabors Drilling International Ltd.

Nabors Drilling International II Ltd.

Nabors International Management Ltd.

Nabors Red Lion Limited

Nabors Blue Shield Ltd.

Nabors Global Holdings II Ltd.

Nabors Global Holdings Ltd.

Nabors International Finance Inc.

Nabors Industries Inc.

Yellow Deer Investments Corp.

Nabors Holding Company

Nabors Diamond Holdings, Inc.

Nabors Drilling USA, LP

Nabors Lux Finance 1 S.a.r.l.

Nabors Lux Finance 2 S.a.r.l.

Superior Well Services, Inc.

Nabors Holdings Ltd.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Registration Numbers 333-11313-99, 333-87069-99, 333-121908, 333-155291 and 333-166598) and on Form S-3 (Registration Number 333-159601) of Nabors Industries Ltd. and on Form S-3 (Registration Number 333-169013-01) of Nabors Industries Ltd. and Nabors Industries, Inc. of our report dated February 29, 2012 relating to the consolidated financial statements, financial statement schedule and the effectiveness of internal control over financial reporting of Nabors Industries Ltd., and of our report dated February 23, 2012 relating to the consolidated financial statements of NFR Energy LLC, which appear in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 29, 2012

EX-23.2

Exhibit 23.2

CONSENT OF MILLER AND LENTS, LTD.

INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum engineers, we hereby consent to the incorporation by reference in its Registration Statements on Form S-8 (Registration Numbers 333-11313-99, 333-87069-99, 333-121908, 333-155291 and 333-166598) and on Form S-3 (Registration Number 333-159601) of Nabors Industries Ltd. and on Form S-3 (Registration Number 333-169013-01) of Nabors Industries Ltd. and Nabors Industries, Inc. relating to the use and inclusion of our letter report dated January 18, 2012, with respect to the proved oil, gas, condensate and natural gas liquids reserves and projected future net revenues associated with these reserves as of December 31, 2011 attributable to the Ramshorn Investments, Inc. net interests in properties specified by Ramshorn Investments, Inc. and to all references to our firm which are to be included in Form 10-K for the year ended December 31, 2011 to be filed by Nabors Industries Ltd. with the Securities and Exchange Commission.

The Form 10-K contains references to certain reports prepared by Miller and Lents, Ltd. for the use of Ramshorn Investments, Inc. The analysis, conclusions, and methods contained in the reports are based upon information that was made available to us at the time the reports were prepared and Miller and Lents, Ltd. has not updated and undertakes no duty to update any results contained in the reports based on the aforementioned information. While the reports may be used as a descriptive resource, investors are advised that Miller and Lents, Ltd. has not verified information provided by others except as specifically noted in the reports, and Miller and Lents, Ltd. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such reports are based on assumptions that Miller and Lents, Ltd. believed were reasonable at the time of the preparation of the Reports and that are described in the Reports in reasonable detail. However, there is a wide range of uncertainties and risks subsequent to the preparation of the Reports that are outside our control that may impact these assumptions, including but not limited to, unforeseen market changes, economic changes, natural events, actions of governments or individuals, and changes in or the interpretation of laws and regulations.

Houston, Texas

February 29, 2012

MILLER AND LENTS, LTD. Texas Registered Engineering Firm No. F-1442
By:
	Carl D. Richard, P. E.
	Senior Vice President

TWO HOUSTON CENTER • 909 FANNIN STREET, SUITE 1300 • HOUSTON, TEXAS 77010

TELEPHONE 713-651-9455 • TELEFAX 713-654-9914 • e-mail: mail@millerandlents.com

EX-23.3

Exhibit 23.3

	Deloitte & Touche LLP Fifth Avenue Place East Tower Suite 600, 425 – 1st Street SW Calgary, AB T2P 3L8 Canada
	Tel: 403-648-3200 Fax: 403-265-0862 www.deloitte.ca

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

As Independent petroleum engineers, we hereby consent to the incorporation by reference in its Registration Statements on Form S-8 (Registration Numbers 333-11313-99, 333-87069-99, 333-121908, 333-155291 and 333-166598) and on Form S-3 (Registration Number 333-159601) of Nabors Industries Ltd. and on Form S-3 (Registration umber 333-169013-01) of Nabors Industries, Ltd. and Nabors Industries, Inc. relating to the use and inclusion of our letter report dated January 26, 2012 with respect to the proved oil, gas, condensate and natural gas liquids reserves and projected future net revenue associated with these reserves as of December 31, 2011 attributable to the Ramshorn Canada Investments Limited net interests in properties specified by Ramshorn Canada Investments Limited and to all references to our firm which are to be included in Form 10-K for the year ended December 31, 2011 to be filed by Nabors Industries Ltd. with the Securities and Exchange Commission.

AJM Deloitte
By:	“Original signed by R.G. Bertram”
	Robin G. Bertram, P.Eng.

February 29, 2012

EX-23.4

Exhibit 23.4

Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS

1000 LOUISIANA STREET, SUITE 625	306 WEST SEVENTH STREET, SUITE 302	9601 AMBERGLEN BLVD., SUITE 117
HOUSTON, TEXAS 77002-5008	FORT WORTH, TEXAS 76102-4987	AUSTIN, TEXAS 78729-1106
713-651-9944	817-336-2461	512-249-7000
FAX 713-651-9980	FAX 817-877-3728	FAX 512-233-2618

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Form 10-K of Nabors Industries Ltd. for the year ended December 31, 2011. We hereby further consent to the use of information contained in our report setting forth the estimates of revenues from Nabors Industries Ltd.’s oil and gas reserves as of December 31, 2011 and to the inclusion of our reports dated January 27, 2012 as an exhibit to the Form 10 of Nabors Industries Ltd. for the year ended December 31, 2011. We further consent to the incorporation by reference thereof into Nabors Industries Ltd.’s Registration Statements on Form S-8 (Registration Numbers 333-11313-99, 333-87069-99, 333-121908, 333-155291 and 333-166598) and Form S-3 (Registration No. 333-159601) of Nabors Industries Ltd. and Form S-3 (Registration No. 333-169013-01) of Nabors Industries Ltd. and Nabors Industries, Inc.

Sincerely,

Cawley, Gillespie & Associates, Inc.

Texas Registered Engineering Firm F-693

February 29, 2012

EX-23.5

Exhibit 23.5

CONSENT OF MILLER AND LENTS, LTD.

INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum engineers, we hereby consent to the incorporation by reference in its Registration Statements on Form S-8 (Registration Numbers 333-11313-99, 333-87069-99, 333-121908, 333-155291 and 333-166598) and on Form S-3 (Registration Number 333-159601) of Nabors Industries Ltd. and on Form S-3 (Registration Number 333-169013-01) of Nabors Industries Ltd. and Nabors Industries, Inc. relating to the use and inclusion of our letter report dated January 18, 2012, with respect to the proved oil, gas, condensate and natural gas liquids reserves and projected future net revenues associated with these reserves as of December 31, 2011 attributable to the NFR Energy LLC net interests in properties specified by NFR Energy LLC and to all references to our firm which are to be included in Form 10-K for the year ended December 31, 2011 to be filed by Nabors Industries Ltd. with the Securities and Exchange Commission.

The Form 10-K contains references to certain reports prepared by Miller and Lents, Ltd. for the use of Nabors Industries Ltd. The analysis, conclusions, and methods contained in the reports are based upon information that was made available to us at the time the reports were prepared and Miller and Lents, Ltd. has not updated and undertakes no duty to update any results contained in the reports based on the aforementioned information. While the reports may be used as a descriptive resource, investors are advised that Miller and Lents, Ltd. has not verified information provided by others except as specifically noted in the reports, and Miller and Lents, Ltd. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such reports are based on assumptions that Miller and Lents, Ltd. believed were reasonable at the time of the preparation of the reports and that are described in the reports in reasonable detail. However, there is a wide range of uncertainties and risks subsequent to the preparation of the reports that are outside our control that may impact these assumptions, including but not limited to, unforeseen market changes, economic changes, natural events, actions of governments or individuals, and changes in or the interpretation of laws and regulations.

Houston, Texas

February 29, 2012

MILLER AND LENTS, LTD. Texas Registered Engineering Firm No. F-1442
By:	/s/ Carl D. Richard, P. E.
	Carl D. Richard, P. E.
	Senior Vice President

TWO HOUSTON CENTER • 909 FANNIN STREET, SUITE 1300 • HOUSTON, TEXAS 77010

TELEPHONE 713-651-9455 • TELEFAX 713-654-9914 • e-mail: mail@millerandlents.com

EX-31.1

EXHIBIT 31.1

Certification of Chief Executive Officer

Pursuant to Exchange Act Rule 13a-14(a) or 15d-14(a)

I, Anthony G. Petrello, certify that:

1. I have reviewed this annual report on Form 10-K of Nabors Industries Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2012	/s/ Anthony G. Petrello
	Anthony G. Petrello
	Deputy Chairman, President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

Certification of Chief Financial Officer

Pursuant to Exchange Act Rule 13a-14(a) or 15d-14(a)

I, R. Clark Wood, certify that:

1. I have reviewed this annual report on Form 10-K of Nabors Industries Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2012	/s/ R. Clark Wood
	R. Clark Wood
	Principal Accounting and Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Nabors Industries Ltd. (the “Company”) for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Anthony G. Petrello, Deputy Chairman, President and Chief Executive Officer of the Company, and I, R. Clark Wood , Principal Accounting and Financial Officer of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Anthony G. Petrello

Anthony G. Petrello

Deputy Chairman, President and

Chief Executive Officer

Date:

/s/ R. Clark Wood

R. Clark Wood

Principal Accounting and

Financial Officer

Date: February 29, 2012

EX-99.1

Exhibit 99.1

January 18, 2012

Mr. Shawn McWilliams

Business Unit Controller

Ramshorn Investments, Inc.

515 W. Greens Road, Suite 1000

Houston, Texas 77067-4525

Re: Ramshorn Investments, Inc.

Proved Reserves and

Future Net Revenues

As of December 31, 2011

SEC Price Case

Dear Mr. McWilliams:

As requested, Miller and Lents, Ltd. (MLL) estimated the proved reserves and projected the future net revenues attributable to the interests of Ramshorn Investments, Inc. (Ramshorn) as of December 31, 2011. This report was prepared for Ramshorn’s use for reserves and financial planning and completed on January 18, 2012. The estimates were made in accordance with the definitions contained in Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a) as shown in the Appendix. The aggregate results are shown in the following table.

Reserves and Future Net Revenues as of December 31, 2011

Reserves Category	Net Reserves						Future Net Revenues
	Oil, MBbls.		Gas, MMcf		NGL, MBbls.		Undiscounted, M$		Discounted at 10% Per  Year, M$
Proved Producing		209.8		8,835.9		79.3		28,361.9		17,331.9
Proved Nonproducing		39.2		2,082.0		0.0		12,174.2		5,892.9
Total Proved Developed		249.0		10,917.9		79.3		40,536.1		23,224.8
Proved Undeveloped		18.4		1,120.4		0.0		2,495.7		799.8
Total Proved		267.4		12,038.3		79.3		43,031.8		24,024.6

Future net revenues as used herein are defined as the total revenues attributable to the evaluated interest less royalty, production taxes, operating expenses, and future capital expenditures. Future net revenues were discounted at 10 percent and do not include deductions for federal income tax. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

The evaluated wells are in numerous domestic fields and areas located in the states of Arkansas, Louisiana, Mississippi, Montana, North Dakota, Oklahoma, Texas, Utah, and Wyoming. Ramshorn’s

TWO HOUSTON CENTER • 909 FANNIN STREET, SUITE 1300 • HOUSTON, TEXAS 77010

TELEPHONE 713-651-9455 • TELEFAX 713-654-9914 • e-mail: mail@millerandlents.com

Mr. Shawn McWilliams	January 18, 2012
Ramshorn Investments, Inc.	Page 2

interest in the properties consists of nonoperated working interests, overriding royalty interests, or mineral interests. Ramshorn has little information on the properties other than financial statements from the operators showing allocated revenues and costs. For our evaluations, MLL used monthly summary data since October 2007 that have been accumulated by Ramshorn from these financial statements, supplemented by information from public records and commercial data services.

The nonproducing and undeveloped wells included in MLL’s evaluation were limited to properties with adequate technical data and development plans to evaluate such opportunities. Some of the Ramshorn properties may have additional behind pipe and/or undeveloped reserves but were not included herein due to lack of readily available information. Ramshorn reportedly has interests in some additional wells that were not included herein because MLL found no production records for them either from revenue statements or public sources. Some of these wells may be recently drilled or not yet on production; others may be wells that are not commercially productive. It is possible that some of the wells are actually producing now, but data were not yet available at the time of MLL’s evaluation.

Production Data

Wherever possible, MLL used the complete monthly history of production available from commercial services for our evaluation of each property. For those properties on which we found little or no production data, MLL used recent monthly production data provided by Ramshorn. On the properties that showed “plant products” production from the information provided by Ramshorn, MLL estimated natural gas liquids recovery ratios and gas shrinkage factors. Generally, MLL projected the major phase (oil or gas) based on the decline curve trend for each property or based on analogy with wells in the same field or area. Condensate yields, gas-oil ratios, NGL yields, and gas shrinkage factors were estimated and projected from the available data to forecast the secondary products.

Prices

The prices used for the 2011 reserves projections herein are in accordance with SEC standards. The oil price of $96.19 per barrel and gas price of $4.118 per MMBtu represent the 12-month average of the first-day-of-the-month price for each month within the 12-month period prior to December 31, 2011 as shown in Table 1. MLL assumed an NGL price equal to 60 percent of the oil price. Price differentials for each property were determined by comparing the actual average monthly oil, gas, and NGL price based on monthly production and revenue data provided by Ramshorn to the monthly benchmark prices of these products. The computed differentials were then used as multiplier ratios for each product to adjusted benchmark prices. For properties on which available data were insufficient to calculate price differentials, MLL used the average price multiplier that we had calculated for Ramshorn properties in the same field or state. The actual average product prices for proved reserves in this report, after appropriate adjustments, were $92.17 per barrel for oil, $52.58 per barrel for NGLs, and $4.47 per Mcf for gas.

Operating Costs

Mr. Shawn McWilliams	January 18, 2012
Ramshorn Investments, Inc.	Page 3

For working interest properties, MLL estimated current average operating costs per well per month for each property based on the historical information provided by Ramshorn. For mineral interests, overriding royalty interests, and wells for which cost data were not available, MLL estimated monthly operating costs per well per month based on analogy or experience for properties in nearby areas. Although no operating costs were incurred for overriding royalty or mineral interests, an estimate of operating cost was needed to determine the economic producing limit. MLL held operating costs constant for all future years.

Ownership Interests

Ramshorn provided a list of the net working interest and net revenue interest that it carried for each property. For some wells, the working interest or net revenue interest was unknown. For properties on the list with working interests shown but where Ramshorn’s net revenue interest was unknown, MLL estimated net revenue interests based on a 0.75 ratio of net revenue interest to working interest. The 0.75 ratio was selected because it best represented the actual average ratio for many of Ramshorn’s working interest properties. For properties on the list with no working interest and modest net revenue interests, MLL assumed Ramshorn holds an overriding royalty or mineral interest only. Some of the properties have ceased to produce or are producing at rates below the estimated economic limit. They are included herein, but remaining reserves and future net revenues for these properties were reported as zero. Properties on which MLL had interest data but for which we could not find production data were excluded from this report.

Interest reversions were scheduled based on payout criteria and balances provided by Ramshorn. MLL assumed no production balancing provisions exist for the Ramshorn properties as no relevant information was available.

Reserves Projections

Forecasts of future production were made for each property based on historical trend or analogy. Reserves were determined as the sum of the forecast production for all months after December 31, 2011 until the economic producing limit was reached for each property. For properties with short or erratic production histories, there is greater uncertainty in the projection of future production than for properties with long histories of production on a consistent decline trend. Gas reserves are reported at the appropriate pressure and temperature base for each state; therefore, the consolidated total is at a mixed pressure base.

Attachments

Table 1 shows the first-day-of-the-month price for each month within the 12- month period prior to December 31, 2011 used to calculate the SEC 12- month average prices used in the MLL’s projections. Figure 1 is a pie chart showing reserves and discounted future net revenues by state. In preparing this chart, MLL used an equivalence factor of six Mcf of gas per barrel of hydrocarbon liquid (oil or NGLs).

Mr. Shawn McWilliams	January 18, 2012
Ramshorn Investments, Inc.	Page 4

Exhibits 1 through 16 are cash flows and one-line summaries grouped as requested by Ramshorn. Exhibit 1 shows the total cash flow summary for total proved reserves. Exhibits 2, 3, and 4 show cash flow summaries by reserves category. Exhibits 5 through 13 show cash flow summaries sorted by state. Exhibits 14, 15, and 16 are one-line summaries of individual wells sorted by state, alphabetic order, and descending future net revenues, respectively.

As an aid to property identification, the numerical well code assigned by Ramshorn to its properties is shown on the exhibits in addition to the entity name.

Other Considerations

As instructed by Ramshorn, MLL used an abandonment cost of $40,000 per well, which was applied when each well reached its economic limit. In some cases, application of this abandonment cost causes the undiscounted future net revenues to be negative. These wells were included in our summary with their negative values.

Future costs of abandoning facilities and any future costs of restoration of producing fields to satisfy environmental standards were not deducted from total revenues, as such estimates are beyond the scope of this assignment.

In conducting this evaluation, MLL relied upon production, revenue, cost, and ownership data supplied by Ramshorn and upon nonconfidential data from public records or commercial data services. These data were accepted as represented and considered appropriate for the purpose served by the report.

MLL applied all methods, procedures, and assumptions it considered necessary and appropriate under the circumstances in using the data provided to prepare this report.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of hydrocarbons to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, MLL is not aware of any regulations that would affect Ramshorn’s ability to recover the estimated reserves and resources.

Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in Ramshorn or any affiliated company. MLL’s compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Production of this report was supervised by Carl D. Richard, an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Mr. Shawn McWilliams	January 18, 2012
Ramshorn Investments, Inc.	Page 5

Very truly yours,
MILLER AND LENTS, LTD. Texas Registered Engineering Firm No. F-1442
By	/s/ Carl D. Richard, P.E.
	Carl D. Richard, P.E.
	Senior Vice President

CDR/psh

EX-99.2

Exhibit 99.2

	Fifth Avenue Place
	600, 425 – 1 Street SW
	Calgary AB T2P 3L8
	Canada
	Tel: 403-648-3200
	Fax: 403-265-0862
	www.deloitte.ca

January 26, 2012

Ramshorn Canada Investments Limited

2800, 500 – 4^th Avenue SW

Calgary, Alberta

T2P 2V6

Attention: Mr. Mike Read

RE: Ramshorn Canada Investments Limited
Reserve estimation and economic evaluation

At your request and authorization, Deloitte & Touche LLP (“AJM Deloitte”) has prepared an independent evaluation of certain oil and gas assets of Ramshorn Canada Investments Limited (“Ramshorn”) in the Coles Lake area of British Columbia effective December 31, 2011.

This report has been prepared for the exclusive use of Ramshorn Canada Investments Limited and no part thereof shall be reproduced, distributed or made available to any other person, company, regulatory body or organization without the complete content of the report and the knowledge and consent of AJM Deloitte.

The evaluation includes an estimate of proved developed producing, total proved and proved plus probable reserves with an associated forecast of the pre-tax present value of future production income from the property using AJM Deloitte 2011 12 31 Forecast Pricing. All values are in Canadian dollars unless specified. This report documents the results of the evaluation with the following tables summarizing the total corporate reserves and value:

• Table 1 – summary of total corporate reserves and value using forecast prices and costs, and

• Table 2- reserves reconciliation.

The oil and gas reserves calculations and income projections, upon which this report is based, were estimated in accordance with the Canadian Oil and Gas Evaluation Handbook (COGEH). The Evaluation Procedure section included in this report details the reserves definitions, price and market demand forecasts and general procedure used by AJM Deloitte in its determination of this evaluation. The extent and character of ownership and all factual data supplied by Ramshorn Canada Investments Limited were accepted as presented (see Representation Letter attached within).

This report contains forward looking statements including expectations of future production and capital expenditures. Information concerning reserves may also be deemed to be forward looking as estimates imply that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil and gas industry (i.e. operational risks in development, exploration and production; potential delays or

Ramshorn Canada Investments Limited

Reserve estimation and economic evaluation

Page 2

changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimates; the uncertainty of estimates and projections relating to production, costs and expenses, political and environmental factors), and commodity price and exchange rate fluctuation. Present values for various discount rates documented in this report may not necessarily represent fair market value of the reserves.

This report also includes a price sensitivity run with the AJM Deloitte SEC 12 month average December 1, 2011 price forecast.

A Boe conversion ratio of 6 Mcf: 1 barrel has been used within this report. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

No value has been assigned in this evaluation for non-reserve lands.

It has been a pleasure to perform this evaluation for you, and we trust it is sufficient to meet your current requirements. Should you have any questions, please contact our office.

Yours truly,

Original signed by: “Robin G. Bertram”

Robin G. Bertram, P. Eng.

Associate Partner

/ct

TABLE 1

Ramshorn Canada Investments Limited

DETAILED ECONOMIC SUMMARY

AJM Deloitte December 31, 2011 Forecast Pricing (CAD)

Effective December 31, 2011						Canada
		PDP		PDNP		PUD		TP		PB		P+P		Possible		P+P+P
Sales Gas	MMcf
Ultimate Remaining			7,495.9		2,163.4		27,126.0		36,785.3		54,000.0		90,785.3		68,587.3		159,372.6
WI Before Royalty			7,495.9		2,163.4		27,126.0		36,785.3		54,000.0		90,785.3		68,587.3		159,372.6
WI After Royalty			6,556.9		1,663.3		21,787.4		30,007.6		41,209.3		71,216.9		50,846.6		122,063.5
Royalty Interest			0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0
Total Net			6,556.9		1,663.3		21,787.4		30,007.6		41,209.3		71,216.9		50,846.6		122,063.5
MBOE	Mboe
Ultimate Remaining			1,249.3		360.6		4,521.0		6,130.9		9,000.0		15,130.9		11,431.2		26,562.1
WI Before Royalty			1,249.3		360.6		4,521.0		6,130.9		9,000.0		15,130.9		11,431.2		26,562.1
WI After Royalty			1,092.8		277.2		3,631.2		5,001.3		6,868.2		11,869.5		8,474.4		20,343.9
Royalty Interest			0.0		0.0		0.0		0.0		0.0		0.0		0.0		0.0
Total Net			1,092.8		277.2		3,631.2		5,001.3		6,868.2		11,869.5		8,474.4		20,343.9
Net Present Values—BTAX	M$
Undiscounted			16,600.5		4,510.5		15,014.0		36,125.1		136,033.9		172,158.9		257,591.0		429,750.0
Discounted at 5%			14,351.9		3,466.6		-1,034.5		16,783.9		78,147.8		94,931.7		138,366.7		233,298.4
Discounted at 10%			12,609.3		2,736.8		-10,136.8		5,209.2		46,292.4		51,501.6		82,553.9		134,055.5
Discounted at 15%			11,242.5		2,207.4		-15,327.9		-1,877.9		27,579.8		25,701.9		53,053.1		78,755.0
Discounted at 20%			10,152.2		1,810.9		-18,231.2		-6,268.2		16,011.5		9,743.3		35,946.7		45,690.0

Light & Medium Oil includes Shale Oil. Heavy Oil Includes Ultra Heavy in Alberta and Bitumen. Sales Gas includes Solution gas, Associated and Non- Associated gas, Coalbed Methane, Shale gas and Hydrates.

© Deloitte & Touche LLP and affiliated entities.

Independent petroleum consultants consent

The undersigned firm of Independent Qualified Reserves Evaluators and Auditors of Calgary, Alberta, Canada has prepared an independent evaluation of reserves and future net revenues derived therefrom, of the Petroleum and Natural Gas assets of the interests of Ramshorn Canada Investments Limited according to the Canadian Oil and Gas Evaluation Handbook. If required, these reserves and future net revenues were estimated using forecast prices and costs (before and after income taxes) according to the requirements of National Instrument 51-101 (NI 51-101). The effective date of this evaluation is December 31, 2011.

In the course of the evaluation, Ramshorn Canada Investments Limited provided AJM Deloitte personnel with basic information which included land, well and accounting (product prices and operating costs) information; reservoir and geological studies, estimates of on-stream dates for certain properties, contract information, budget forecasts and financial data. Other engineering, geological or economic data required to conduct the evaluation and upon which this report is based, were obtained from public records, other operators and from AJM Deloitte non confidential files. The extent and character of ownership and accuracy of all factual data supplied for the independent evaluation, from all sources, has been accepted.

A “Representation Letter” dated January 24, 2012 and signed by the President was received from Ramshorn Canada Investments Limited prior to the finalization of this report. This letter specifically addressed the accuracy, completeness and materiality of all the data and information that was supplied to us during the course of our evaluation of Ramshorn Canada Investments Limited’s reserves and net present values. This letter is included within.

A field inspection and environmental/safety assessment of the properties was beyond the scope of the engagement of AJM Deloitte and none was carried out. The “Representation Letter” received from Ramshorn Canada Investments Limited provided assurance that no additional information necessary for the completion of our assignment would have been obtained by a field inspection.

The accuracy of any reserve and production estimates is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates presented herein are considered reasonable, and adhere to the COGE Handbook and NI 51-101 (as applicable), the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward.

Revenue projections presented in this report are based in part on forecasts of market prices, current exchange rates, inflation, market demand and government policy which are subject to uncertainties and may in future differ materially from the forecasts herein. Present values of future net revenues documented in this report do not necessarily represent the fair market value of the reserves evaluated herein.

PERMIT TO PRACTICE

Deloitte & Touche LLP

Permit Number: P-11444

The Association of Professional Engineers,

Geologists and Geophysicists of Alberta

Certificate of qualification

I, R. G. Bertram, a Professional Engineer, of the 6^th Floor, 425 – 1^st Street S.W., Calgary, Alberta, Canada hereby certify that:

1. I am an associate partner of Deloitte & Touche LLP (“AJM Deloitte”), which did prepare an evaluation of certain oil and gas assets of the interests of Ramshorn Canada Investments Limited. The effective date of this evaluation is December 31, 2011.

2. I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of Ramshorn Canada Investments Limited.

3. I attended the University of Alberta and graduated with a Bachelor of Science Degree in Petroleum Engineering in 1985; that I am a Registered Professional Engineer in the Province of Alberta; and I have in excess of twenty six years of engineering experience.

4. I am a Qualified Reserves Auditor as defined in the Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 3.2.

5. A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities.

Original signed by: “R. G. Bertram”
	R. G. Bertram, P. Eng.
	January 24, 2012
	Date

Certificate of qualification

I, I. J. Olsen, a Professional Engineer, of the 6^th Floor, 425 – 1^st Street Avenue S.W., Calgary, Alberta, Canada hereby certify that:

1. I am an employee of Deloitte & Touche LLP (“AJM Deloitte”), which did prepare an evaluation of certain oil and gas assets of the interests of Ramshorn Canada Investments Limited. The effective date of this evaluation is December 31, 2011.

2. I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of Ramshorn Canada Investments Limited.

3. I attended the University of Alberta and graduated with a Bachelor of Science Degree in Chemical Engineering in 2007; that I am a Registered Professional Engineer in the Province of Alberta; and I have in excess of four years of engineering experience.

4. A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities.

Original signed by: “I. J. Olsen”
	I. J. Olsen, P. Eng.
	January 24, 2012
	Date

Certificate of qualification

I, L. D. Boyd, a Registered Professional Geologist, of the 6^th Floor, 425 – 1^st Street S.W., Calgary, Alberta, Canada hereby certify that:

1. I am an employee of Deloitte & Touche LLP (“AJM Deloitte”), which did prepare an evaluation of certain oil and gas assets of the interests of Ramshorn Canada Investments Limited. The effective date of this evaluation is December 31, 2011.

2. I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of Ramshorn Canada Investments Limited.

3. I attended the University of Calgary and graduated with a Bachelor of Science Degree in Geology in 1976; that I am a Registered Professional Geologist in the Province of Alberta; and I have in excess of thirty five years of geological experience.

4. A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities.

Original signed by: “L. D. Boyd”
	L. D. Boyd, P. Geol.
	January 24, 2012
	Date

EX-99.3

Exhibit 99.3

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS 78729-1106 512-249-7000 306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817- 336-246 www.cgaus.com 1000 LOUISIANA STREET, SUITE 625 HOUSTON, TEXAS 77002-5008 713-651-9944

January 27, 2012

Mr. Shawn McWilliams

Oil and Gas Business Unit Controller

Ramshorn Investments Inc.

515 West Greens Road, Suite 600

Houston, Texas 77067

Re:	Evaluation Summary – SEC Price Case
	Ramshorn Investments Inc. Interests
	Total Proved Reserves Certain Properties in Texas As of January 1, 2012

Dear Mr. McWilliams:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the Ramshorn Investments Inc. interests in certain oil and gas properties located in various states within the United States. This report, completed January 27, 2012 covers 100% of the proved reserves for Ramshorn Investments Inc. The results of this evaluation are presented below:

		Proved Developed Producing		Proved Developed Non-Producing		Proved Undeveloped		Total Proved
Net Reserves
Oil	—   Mbbl		172.9		320.6		838.1		1,331.7
Gas	—  MMcf		2,242.4		426.4		2,161.7		4,830.6
NGL	—   Mbbl		38.7		44.1		60.0		142.8
Revenue
Oil	—  M$		15,546.5		28,661.6		75,212.1		119,420.2
Gas	—  M$		7,085.3		1,501.5		7,032.4		15,619.2
NGL	—  M$		2,024.0		2,314.9		3,130.7		7,469.6
Severance Taxes	—  M$		1,050.1		1,591.0		3,859.0		6,500.1
Ad Valorem Taxes	—  M$		639.0		784.1		2,037.5		3,460.6
Operating Expenses	—  M$		7,351.4		4,292.0		10,581.4		22,224.7
Investments	—  M$		0.0		6,133.1		34,034.5		40,167.6
Net Operating Income	—  M$		15,615.1		19,677.7		34,862.9		70,155.8
Discounted @ 10%	—  M$		11,012.6		11,123.7		11,140.8		33,277.1

The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc. (“CG&A”)

Ramshorn Investments Inc.

January 27, 2012

Page 2

Hydrocarbon Pricing

As requested for the SEC Price scenario, oil and gas prices were adjusted to the following index prices.

Year	WTI Oil Price $/BBL	HH Gas Price $/MMBTU
2012	96.06	4.11

In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2011. Prices were not escalated in the SEC scenario. Adjustments to oil and gas prices were made based upon data provided by your office. These adjustments include treating cost, transportation charges and/or crude quality and gravity corrections.

Expenses and Taxes

Lease operating expenses and investments were forecast as furnished by your office and were not escalated. Severance tax values were determined by applying normal state severance tax rates. Ad valorem tax rates were forecast as provided by your office.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 17 proved undeveloped locations in Texas. Each of these drilling locations proposed as part of Ramshorn’s development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Ramshorn has indicated they have every intent to complete this development plan within the next five years. Furthermore, Ramshorn has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Ramshorn properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Ramshorn Investments Inc.

January 27, 2012

Page 3

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by Robert D. Ravnaas, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or Ramshorn Investments Inc. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

	Yours very truly,
	Robert D. Ravnaas, P.E. President Cawley, Gillespie & Associates Texas Registered Engineering Firm F-693

APPENDIX

Explanatory Comments for Summary Tables

HEADINGS

Table I

Description of Table Information

Identity of Interest Evaluated

Property Description – Location

Reserve Classification and Development Status

Effective Date of Evaluation

FORECAST

(Columns)

(1) (11)(21)	Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)	Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)	Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)	Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)	Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)	Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)	Revenue derived from oil sales -- column (5) times column (8).
(13)	Revenue derived from gas sales -- column (6) times column (9).
(14)	Revenue derived from NGL sales -- column (7) times column (10).
(15)	Revenue derived from hedge positions.
(16)	Total Revenue – sum of column (12) through column (15).
(17)	Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(18)	Revenue after taxes – column (16) less column (17).
(19)	Ad Valorem taxes.
(20)	$/MCFE6 – is the total of column (22), column (25), column (26), and column (27) divided by MCF Gas Equivalent (“MCFE”). MCFE is net gas production column (6) plus net oil production column (5) converted to gas at one bbl oil per six Mcf gas plus net NGL production column (7) converted to gas at one bbl NGL per 3.9 Mcf gas.
(22)	Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)	Average gross wells.
(24)	Average net wells are gross wells times working interest.
(25)	Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)	3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(27)	Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
(28)	Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29)(30)	Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)	Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

DCF Profile	•    The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.
Life	•    The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes	•    Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck	•    A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

	Appendix
Cawley, Gillespie & Associates, Inc.	Page 1

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

	Appendix
Cawley, Gillespie & Associates, Inc.	Page 2

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22) Proved oil and gas reserves. 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, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

	Appendix
Cawley, Gillespie & Associates, Inc.	Page 3

“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

	Appendix
Cawley, Gillespie & Associates, Inc.	Page 4

EX-99.4

Exhibit 99.4

January 18, 2012

NFR Energy LLC

1415 Louisiana Street, Suite 1600

Houston, Texas 77002

Attention: Mr. Todd Levesque

Re: Proved Reserves and

Future Net Revenues

As of December 31, 2011

SEC Case

Gentlemen:

As requested, Miller and Lents, Ltd. (MLL) estimated the reserves and projected the future net revenues attributable to the interests of NFR Energy LLC (NFR) in certain oil and gas properties located primarily in East Texas, Montana, and Utah as of December 31, 2011. The report was prepared for NFR’s use in reserves and financial reporting and planning and was completed on January 16, 2011. The aggregate results of our evaluations, using constant product prices determined under Securities and Exchange Commission (SEC) guidelines for year-end 2011 are summarized below.

Reserves and Future Net Revenues as of December 31, 2011

Reserves Category	Net Reserves						Future Net Revenues
	Oil, MBbls.		NGL, MBbls.		Gas, MMcf		Undiscounted, M$		Discounted at 10% Per Year, M$
Proved Producing		1,812.5		8,719.3		398,424.9		1,435,795.4		710,037.8
Proved Nonproducing		585.4		1,625.5		116,533.5		320,049.8		130,438.9
Proved Undeveloped		3,477.2		15,684.5		655,058.2		1,620,845.3		328,793.2
Total Proved		5,875.1		26,029.3		1,170,016.6		3,376,690.5		1,169,269.9

Definitions

The reserves reported herein are in accordance with the definitions contained in SEC Regulation S-X, Rule 4-10(a) as shown in Appendix 1. Prices used herein and that are shown in Table 1 represent the 12-month average of the first-day-of-the-month price for each month within the 12-month period prior to December 31, 2011 as required by SEC guidelines.

Future net revenues, as used herein, are defined as the total gross revenues less royalty, production taxes, operating costs, and capital expenditures. Future net revenues do not include

TWO HOUSTON CENTER • 909 FANNIN STREET, SUITE 1300 • HOUSTON, TEXAS 77010

TELEPHONE 713-651-9455 • TELEFAX 713-654-9914 • e-mail: mail@millerandlents.com

NFR Energy LLC	January 18, 2012
Attention: Mr. Todd Levesque	Page 2

deductions for federal income tax. The future net revenues were discounted at 10 percent per year (referenced later herein as “discounted future net revenues”) in accordance with SEC guidelines and to illustrate the time value of future cash flows. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

Reserves Considerations

NFR has advised us that MLL’s estimates herein represent 100 percent of its proved booked reserves for year-end 2011. All reserves are in the United States and are grouped into two geographic divisions. The properties in NFR’s East Texas Division evaluated herein are located primarily in East Texas, but one lease is in western Louisiana. The properties in NFR’s Rockies Division include several fields in north-central Montana and one field in Utah. Reserves projected for the East Texas area are generally from reservoirs at depths below 7,000 feet that produce gas with modest condensate yields. Reserves projected for the Montana properties are generally from reservoirs shallower than 3,000 feet and produce dry gas. Reserves projected for the Utah properties are from reservoirs at depths below 8,000 feet and typically produce gas with low condensate yields. Discussion of the properties in NFR’s two divisions follows.

East Texas Division

In the East Texas area, numerous reservoirs are productive. The zones are primarily gas-bearing, have very low average permeabilities, and range in depth from approximately 7,000 feet to more than 14,000 feet. Reservoirs include (from shallowest to deepest) Pettit, Travis Peak, Upper Cotton Valley, Lower Cotton Valley, Bossier, Haynesville, and Cotton Valley Lime. Recent development in these reservoirs has been with horizontal wells with large multi-stage hydraulic fracture treatments.

NFR is planning horizontal wells for essentially all future Haynesville shale development and undeveloped Cotton Valley areas. Typically, future NFR planned horizontal wells are projected to have lateral lengths of 3,500 feet or more (unless restricted by lease geometry) and oriented perpendicular to the main fracture plan in the reservoir. Hydraulic fracture stages spaced about 250 feet apart along the laterals are planned. Current spacing between horizontal laterals is expected to be 600 feet.

Reserves for existing wells were based on extrapolation of production performance generally using hyperbolic decline curves to a minimum exponential decline rate of five percent per year.

Future Haynesville horizontal well reserves and production profiles are based on average performance trends from NFR wells, adjusted for the expected lateral length, net pay thickness, and well density currently planned for the subject leases. NFR operates approximately 40 horizontal Haynesville wells in their leased areas. Information such as lateral length, pay thickness, number of fracture stimulation stages, fracture proppant concentrations and initial producing rate, were combined and correlated against the estimated ultimate recovery (EUR) for these wells. These correlations were

NFR Energy LLC	January 18, 2012
Attention: Mr. Todd Levesque	Page 3

segmented by area and used to estimate the initial producing rates and reserves for undeveloped Haynesville wells in those areas. All future NFR Haynesville development will be horizontal drilling with lateral wells spaced 600 feet apart. MLL did not consider any interference effects for this spacing due to the simultaneous fracture stimulation techniques being employed by NFR going forward.

Future Cotton Valley horizontal (CV HRZ) well reserves and production profiles were based on models built to compare the actual performance and future extrapolation of horizontal wells (adjusted for lateral length and number of fracture stages) with actual performance and future extrapolation of adjacent Cotton Valley vertical (CV VERT) wells. For reserves for CV HRZ wells drilled in areas where drainage from producing CV VERT wells is likely to occur, a well drainage area was calculated and applied as an interference factor to arrive at a depletion-adjusted EUR.

Condensate yields were projected based on actual yields reported for NFR wells. Generally, shallower zones are richer in condensate than deeper zones. For wells connected to gas processing plants and undrilled locations on leases with wells connected to plants, NGLs are projected based on NGL yields obtained from processing plant reports or sales records provided by NFR. Where NGLs are projected, net residue gas sales are reported herein as gas reserves. Where no NGLs are projected, wellhead gas volumes are reported herein as gas reserves. For the table on the first page of this report, MLL consolidated oil and condensate into oil reserves and reported NGL reserves separately.

Some identified development locations are uneconomic based on MLL estimates and SEC-compliant prices and are not included herein. For purposes of this report, projections with positive future net revenues were considered economic even if discounted future net revenues were negative. Many of NFR’s projected Haynesville development wells have positive undiscounted future net revenues but negative discounted future net revenues due to current SEC-compliant gas prices.

Rockies Division

The NFR properties from the Klabzuba acquisition are located in the Bearpaw Arch in north-central Montana. Production is primarily dry gas from shallow clastic reservoir targets including Judith River, Eagle Sandstone, Medicine Hat, Niobrara, and Sawtooth at depths less than 3,000 feet. Current production and future development is based primarily on 160-acre spacing although some reservoirs are being developed on 80-acre spacing.

The NFR properties from the Gasco acquisition are located in the Riverbend Field of Utah. Production is primarily gas with modest condensate yields. From one to six reservoirs are productive at various locations across the field.

Reserves for existing wells were based on extrapolation of production performance, generally using hyperbolic decline curves to a minimum exponential decline rate of six percent per year. Reserves for undeveloped locations are based on analogy, considering the performance of existing wells in the subject area and reservoir.

NFR Energy LLC	January 18, 2012
Attention: Mr. Todd Levesque	Page 4

Economic Considerations

Future prices and costs were projected based on information provided by NFR. No future escalation of prices or costs was assumed. Operating costs, price differentials from selected benchmarks, and Btu and shrinkage adjustments were included for each well or lease, based on recent actual averages. Operating expenses included both a component cost per well month and a component cost per Mcf produced. Ad valorem and severance taxes were projected based on recent averages, legislated rates, or adjustments used for high cost gas wells in Texas. Capital costs for drilling and completion of future wells and recompletion of existing wells were based on NFR’s recent actual experience and estimates.

Product prices were projected using selected spot price benchmarks (West Texas Intermediate crude oil sold at Cushing, Oklahoma and gas sold at the Henry Hub) with appropriate differentials applied for each well, lease, or area. The SEC prices applicable for year-end 2011 reserves disclosures are calculated for each product as the average of the prices existent on the first day of each month in 2011. For our cash flow projections, constant prices were used throughout the life of production in accordance with SEC guidelines. The SEC-compliant benchmark prices used herein were $96.19 per barrel for oil and $4.118 per million Btu for gas. MLL assumed an NGL price equal to 60 percent of the benchmark oil price. The actual average prices used in this report for proved reserves, after appropriate adjustments, were $90.14 per barrel for oil, $51.79 per barrel for NGLs, and $4.14 per Mcf for gas.

Attachments

Attached Exhibits 1 through 4 are summary totals by reserves category showing annual projections of reserves and cash flows. Exhibit 5 is a one-line summary showing reserves and future cash flows for each of our evaluation cases, grouped by reserves category and sorted alphabetically by entity name within each category. Exhibit 6 is a one-line summary grouped by acquisition (designated by NFR) then sorted by reserves category and entity name. Exhibit 7 is a one-line summary sorted alphabetically by entity name, without reserves category or acquisition groupings. Exhibit 8 is a one-line summary ranking of entities (from highest to lowest discounted future net revenues) within each reserves category. On all the one-line summaries, the East Texas Division properties and the Rockies Division properties are grouped separately.

An index is provided at the beginning of the Exhibits section.

Other Considerations

The timing of production start from development drilling and from recompletions was based on estimates or schedules provided by NFR. Capital costs for development well drilling were generally incorporated into our cash flows from one to five months before production start, based on recent experience with new wells in various areas and reservoirs. Costs for recompletion workovers were

NFR Energy LLC	January 18, 2012
Attention: Mr. Todd Levesque	Page 5

generally incorporated one month before production start, and completion costs for all wells were generally incorporated just before production start.

Future costs of abandoning facilities and wells and any future costs of restoration of producing fields to satisfy environmental standards were not deducted from total revenues as such estimates are considered separately from our reserves report in NFR’s financial accounting.

Gas volumes are reported at the standard pressure base used for each state. Therefore, some aggregates shown herein are at a mixed pressure base.

Well counts, as reported in the various economic output tables, actually represent completions and recompletions. Thus, a single well bore may be counted more than once in the total well count.

In conducting this evaluation, MLL relied upon production histories; accounting and cost data; ownership; geological, geophysical, and engineering data; development plans supplied by NFR; and upon non-confidential data from public records or commercial data services. These data were accepted as represented and are considered appropriate for the purpose served by the report. MLL used all methods, procedures, and assumptions as it considered necessary and appropriate under the circumstances in using the data provided to prepare the report.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of hydrocarbons to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, MLL is not aware of any regulations that would affect NFR’s ability to recover the estimated reserves and resources.

Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in NFR Energy LLC, or any affiliate. Our compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Production of this report was supervised by Carl D. Richard, an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Very truly yours,

MILLER AND LENTS, LTD.

Texas Registered Engineering Firm No. F-1442

NFR Energy LLC	January 18, 2012
Attention: Mr. Todd Levesque	Page 6

By	/s/ Leslie A. Fallon, P.E.
	Leslie A. Fallon, P.E.
	Vice President
By	/s/ Carl D. Richard, P.E.
	Carl D. Richard, P.E.
	Senior Vice President

CDR/psh

EX-99.5

Exhibit 99.5

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	2
Audited Consolidated Financial Statements
Consolidated Balance Sheets	3
Consolidated Statement of Operations	4
Consolidated Statement of Member’s Capital	5
Consolidated Statement of Cash Flows	6
Notes to Consolidated Financial Statements	7-28
Supplemental Oil and Gas Disclosures (Unaudited)	29-33

Report of Independent Registered Public Accounting Firm

The Member of NFR Energy LLC

In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations, of member’s capital, and of cash flows present fairly, in all material respects, the financial position of NFR Energy LLC and its subsidiaries (the “Company” and “Member”) at December 31, 2011 and December 31, 2010 and the results of their operations and their cash flows for each of the three years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, at December 31, 2009, the Company changed the manner in which its oil and natural gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and natural gas costs.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 23, 2012

2

Consolidated Financial Statements

NFR Energy LLC

Consolidated Balance Sheets

As of December 31, 2011 and 2010

	December  31, 2011			December  31, 2010
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	4,306		$	4,437
Accounts receivable, net		24,872			16,016
Prepaid expenses and other current assets		5,649			11,010
Derivative instruments		90,838			40,749
Total current assets		125,665			72,212
Property, plant and equipment:
Oil and gas properties (full cost method)
Proved		2,292,875			1,506,565
Unproved		208,230			218,172
Gas gathering and processing equipment		39,763			40,195
Office furniture and fixtures		8,963			6,325
		2,549,831			1,771,257
Accumulated depletion, depreciation and amortization		(1,041,969	)		(934,682	)
Total property, plant and equipment, net		1,507,862			836,575
Other assets:
Derivative instruments		36,920			68,272
Deferred financing costs		14,669			13,024
Total other assets		51,589			81,296
Total assets	$	1,685,116		$	990,083
Liabilities and member’s capital
Current liabilities:
Accounts payable—trade	$	5,221		$	4,160
Accounts payable—related party		12,126			16,058
Royalties payable		8,820			4,904
Accrued interest payable		13,908			13,078
Accrued exploration and development		39,772			48,112
Accrued operating expenses and other		26,647			17,776
Derivative instruments		56			—
Total current liabilities		106,550			104,088
Long term liabilities:
Revolving credit facility		418,000			94,000
Senior notes		346,782			346,153
Asset retirement obligation		15,348			9,213
Derivative instruments		17,409			—
Other long term obligations		854			891
Total long term liabilities		798,393			450,257
Commitments and contingencies
Member’s capital:
Member’s capital		1,267,698			1,065,183
Amounts receivable from member		(41	)		(150	)
Accumulated deficit		(620,585	)		(738,052	)
Accumulated other comprehensive income		130,837			105,722
Total controlling interests member’s capital		777,909			432,703
Noncontrolling interests		2,264			3,035
Total member’s capital		780,173			435,738
Total liabilities and member’s capital	$	1,685,116		$	990,083

The accompanying notes are an integral part of these consolidated financial statements.

3

Consolidated Financial Statements

NFR Energy LLC

Consolidated Statements of Operations

For the Years Ended December 31, 2011, 2010 and 2009

	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Revenues
Oil, natural gas and natural gas liquids sales	$	204,989		$	132,062		$	81,937
Gain on derivative instruments		72,517			51,104			60,686
Other revenue		131			1,390			957
Total revenues		277,637			184,556			143,580
Operating expenses
Lease operating expenses		27,113			18,637			18,253
Workover expenses		2,903			848			482
Marketing, gathering, transportation and other		19,717			13,730			6,031
Production and ad valorem taxes		7,775			5,483			4,228
General and administrative expenses		23,543			20,605			17,662
Depletion, depreciation and amortization		82,178			52,490			44,813
Gain on bargain purchase		(99,548	)		(372	)		—
Accretion expense		628			493			407
Bad debt expense		3			18			93
Impairments		29,921			1,711			407,294
Total operating expenses		94,233			113,643			499,263
Other income (expenses)
Interest expense		(39,632	)		(33,468	)		(9,392	)
Gain (loss) on derivative instruments		(25,799	)		2,547			3,793
Other loss		(389	)		(963	)		(8,478	)
Total other expenses		(65,820	)		(31,884	)		(14,077	)
Net income (loss) including noncontrolling interests		117,584			39,029			(369,760	)
Less: Net income applicable to noncontrolling interests		(117	)		(260	)		(516	)
Net income (loss) applicable to controlling interests	$	117,467		$	38,769		$	(370,276	)

The accompanying notes are an integral part of these consolidated financial statements.

4

Consolidated Financial Statements

NFR Energy LLC

Consolidated Statement of Member’s Capital

For the Years ended December 31, 2011, 2010 and 2009

(in thousands)

	Comprehensive			Member’s Capital					Amounts Receivable from			Accumulated			Accumulated Other Comprehensive		Noncontrolling			Total Member’s
	Income			Units		Value			Member			Deficit			Income		Interests			Capital
Balance as of December 31, 2008					855	$	854,144		$	(272	)	$	(406,545	)	$	40,919	$	2,734		$	490,980
Member’s contributions					152		151,838			—			—			—		—			151,838
Amounts receivable from members					—		—			(86	)		—			—		—			(86	)
Distributions—noncontrolling interests					—		—			—			—			—		(475	)		(475	)
Distributions to members for state tax withholding					—		(375	)		—			—			—		—			(375	)
Comprehensive loss
Net loss applicable to controlling interests	$	(370,276	)		—		—			—			(370,276	)		—		—			(370,276	)
Unrealized gain on derivative instruments		14,480			—		—			—			—			14,480		—			14,480
Comprehensive loss applicable to controlling interests		(355,796	)
Net income applicable to noncontrolling interests		516			—		—			—			—			—		516			516
Comprehensive loss including noncontrolling interests	$	(355,280	)
Balance as of December 31, 2009					1,007	$	1,005,607		$	(358	)	$	(776,821	)	$	55,399	$	2,775		$	286,602
Member’s contributions					60		60,000			—			—			—		—			60,000
Amounts receivable from member					—		—			208			—			—		—			208
Distributions to member for state tax withholding					—		(424	)		—			—			—		—			(424	)
Comprehensive income
Net income applicable to controlling interests	$	38,769			—		—			—			38,769			—		—			38,769
Unrealized gain on derivative instruments		50,323			—		—			—			—			50,323		—			50,323
Comprehensive income applicable to controlling interests		89,092
Net income applicable to noncontrolling interests		260			—		—			—			—			—		260			260
Comprehensive income including noncontrolling interests	$	89,352
Balance as of December 31, 2010					1,067	$	1,065,183		$	(150	)	$	(738,052	)	$	105,722	$	3,035		$	435,738
Member’s contributions					203		203,000			—			—			—		—			203,000
Amounts receivable from member					—		—			109			—			—		—			109
Distributions—noncontrolling interests					—		—			—			—			—		(888	)		(888	)
Distributions to member for state tax withholding					—		(485	)		—			—			—		—			(485	)
Comprehensive income
Net income applicable to controlling interests	$	117,467			—		—			—			117,467			—		—			117,467
Unrealized gain on derivative instruments		25,115			—		—			—			—			25,115		—			25,115
Comprehensive income applicable to controlling interests		142,582
Net income applicable to noncontrolling interests		117			—		—			—			—			—		117			117
Comprehensive income including noncontrolling interests	$	142,699
Balance as of December 31, 2011					1,270	$	1,267,698		$	(41	)	$	(620,585	)	$	130,837	$	2,264		$	780,173

The accompanying notes are an integral part of these consolidated financial statements.

5

Consolidated Financial Statements

NFR Energy LLC

Consolidated Statement of Cash Flows

For the Years ended December 31, 2011, 2010 and 2009

	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	117,584		$	39,029		$	(369,760	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		82,178			52,490			44,813
Impairments		29,921			1,711			407,294
Loss on sale of asset		600			1,138			8,569
Bad debt expense		3			18			93
Accretion expense		628			493			407
Accrued interest expense		1,458			11,953			(142	)
Rent expense and amortization of deferred rent		(38	)		(321	)		120
Amortization of deferred financing costs		2,817			4,325			1,083
(Gain) loss on derivative instruments		23,844			(1,672	)		(3,793	)
Amortization of option premium		—			3,239			3,918
Amortization of prepaid expenses		2,482			1,762			2,374
Gain on bargain purchase		(99,548	)		(372	)		—
Non cash distributions to member		(485	)		(424	)		(375	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		(8,858	)		3,610			275
Increase in other assets		(6,713	)		(5,393	)		(10,895	)
(Decrease) increase in accounts and royalties payable and accrued liabilities		13,159			(5,871	)		(1,277	)
Net cash provided by operating activities		159,032			105,715			82,704
Cash flows from investing activities:
Oil and gas property additions		(292,648	)		(270,548	)		(311,689	)
Oil and gas property acquisitions		(385,218	)		(64,525	)		—
Cash received from insurance proceeds		—			2,343			—
Gas processing equipment additions		(3,810	)		(246	)		(366	)
Other asset additions		(2,952	)		(425	)		(1,511	)
Cash received from sale of assets		3,706			8,012			5,584
Net cash used in investing activities		(680,922	)		(325,389	)		(307,982	)
Cash flows from financing activities:
Borrowings from revolving credit facility		584,500			176,500			243,500
Proceeds from issuance of senior notes		—			345,597			—
Debt repayments		(260,500	)		(347,000	)		(167,500	)
Deferred financing costs		(4,462	)		(13,683	)		(3,633	)
Capital contributions		203,109			60,208			151,752
Distribution—noncontrolling interests		(888	)		—			(475	)
Net cash provided by financing activities		521,759			221,622			223,644
Net increase (decrease) in cash and cash equivalents		(131	)		1,948			(1,634	)
Cash and cash equivalents, beginning of period		4,437			2,489			4,123
Cash and cash equivalents, end of period	$	4,306		$	4,437		$	2,489

The accompanying notes are an integral part of these consolidated financial statements.

6

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

1. Organization

NFR Energy LLC (NFR or the Company) was established as a Delaware limited liability company in July 2006. Ramshorn Investments, Inc. (Ramshorn), a wholly owned subsidiary of Nabors Industries Ltd. (Nabors), and First Reserve Corporation (First Reserve) have formed NFR as a joint venture to invest in oil and natural gas exploration opportunities within the onshore U.S. market. Ramshorn and First Reserve each committed $500 million in equity. Operations of the Company commenced in 2007. Nabors is one of the largest land drilling contractors in the world, conducting drilling operations and providing well and other services in the U.S. and internationally. First Reserve was founded in 1983 and is the oldest and largest private equity firm specializing in the energy industry. Additional equity commitments were made by certain members of NFR management and the Company’s board of representatives (the Members).

On November 5, 2010, the Company formed NFR Holdings LLC as a Delaware limited liability company (NFR Holdings), at which time NFR Holdings formed NFR Holdings II, LLC as a Delaware limited liability company (NFR Holdings II), and NFR Holdings II formed NFR Merger Sub LLC, as a Delaware limited liability company (Merger Sub). Effective November 5, 2010, Merger Sub merged into the Company, with the Company being the surviving entity (the Merge”) and all of the membership interests of the Company were converted into membership interests in NFR Holdings. In addition to membership interests, all incentive units are maintained and held by NFR Holdings. As a consequence of the Merger, NFR Holdings II LLC is now the single member owner of NFR Energy LLC. The change in legal structure had no direct impact on the financial statements of the Company.

The Company is operating in one segment and is pursuing development and exploration projects in a variety of forms including operated and non-operated working interests, joint ventures, farm-outs, and acquisitions, including conventional and unconventional resources. NFR is a holding company within which it conducts its operations through, and its operating assets are owned by its subsidiaries.

2. Significant Accounting Policies

Basis of Presentation

The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (GAAP). The accompanying consolidated financial statements include NFR and its subsidiaries. All significant intercompany transactions have been eliminated.

Certain other reclassifications have been made to prior periods to conform to the current presentation.

Change in Accounting Method

In January 2010 the Financial Accounting Standard Board (FASB) issued Accounting Standards Update 2010-03 (ASU 2010-03), “Extractive Industries – Oil and Gas”, which conforms the authoritative guidance to the requirements of the new Securities Exchange Commission (SEC) rules released in December 2008 “Modernization of Oil and Gas Reporting” and are effective December 31, 2009. The principle revisions under the new FASB and SEC authoritative guidance include changing the manner in which 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. These changes will result in future amounts of depreciation, depletion and amortization (DD&A) being different from what would have been recorded if the new rules had not been mandated. This change in accounting has been treated in these financial statements as a change in accounting principle that is inseparable from a change in accounting estimate. As noted below, reserves and discounted cash flows prepared using the new rules were used in the calculation of DD&A for the fourth quarter of 2009 and the ceiling test at December 31, 2011, 2010 and 2009.

7

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

Cash and Cash Equivalents

All highly liquid investments purchased with an initial maturity of three months or less are considered to be cash equivalents.

Concentration of Credit Risk

The Company’s receivables are comprised of oil and natural gas revenue receivables. The amounts are due from a limited number of entities; therefore, the collectability is dependent upon the general economic conditions of a few purchasers. The Company regularly reviews collectability and establishes the allowance for doubtful accounts as necessary using the specific identification method. The receivables are not collateralized.

Inventory

Inventory, which is included in prepaid expenses and other, consists principally of tubular goods, spare parts, and equipment, that is used in our drilling operations. The inventory balance, net of impairments, was $4.1 million and $9.3 million as of December 31, 2011 and 2010, respectively. Inventory is stated at the lower of weighted-average cost or market. In 2009, the Company revamped its drilling program and moved to a horizontal program due to improved economics versus a vertical program, leaving it with inventory not properly designed for its horizontal drilling activities, in effect, rendering it obsolete. The total impairments relating to obsolete inventory was $1.4 million, $1.7 million and $21.3 million in 2011, 2010 and 2009, respectively, included in “Impairments” in the consolidated statements of operations.

Oil and Natural Gas Properties and Equipment

The Company uses the fullcost method of accounting for its investment in oil and natural gas properties. Under this method, the Company capitalizes all acquisition, exploration, and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits, and other internal costs directly attributable to these activities. The Company capitalized $3.5 million, $3.5 million and $3.3 million of internal costs in 2011, 2010 and 2009, respectively. Costs associated with production and general corporate activities, however, are expensed in the period incurred. The Company also includes the present value of its dismantlement, restoration, and abandonment costs within the capitalized oil and natural gas property balance (see “Asset Retirement Obligation” below). Unless a significant portion of the Company’s proved reserve quantities is sold (greater than 25%), proceeds from the sale of oil and natural gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. The properties are reviewed on a quarterly basis for impairment, and if impaired, are reclassified to proved property and included in the ceiling test and depletion calculations.

Under the full cost method of accounting, a ceiling test is performed on a quarterly basis. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A, may not exceed the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheets, using the unweighted average first day of the month pricesfor the prior twelve month period for 2011 and 2010 (adjusted for quality and basis differentials) and prices in effect at the end of the period for periods ended before December 31, 2009, held flat for the life of production, discounted at 10%, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as “Accumulated depletion, depreciation and amortization”.

8

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

In December 2008, the SEC adopted major revisions to its rules governing oil and natural gas Company reporting requirements. The new rules include provisions that permit the use of new technologies to determine proved reserves, and allow companies to disclose their probable and possible reserves to investors in SEC documents outside of the financial statements. The previous rules limited disclosure to only proved reserves. The new rules also require companies that have an audit performed on their reserves to report the independence and qualifications of the reserve auditor, and file the reserve engineer’s reports when a third party reserve engineer is relied upon to prepare reserve estimates. The new rules also require that oil and natural gas reserves be reported and the full cost ceiling value be calculated using an average price based upon the beginning of the month for the prior twelve-month period. The new reporting requirements are effective for reporting periods ending on or after December 31, 2009. The FASB has issued ASU 2010-03 “Extractive Industries – Oil and Gas” to align its rules for oil and natural gas reserves estimation and disclosure requirements with the SEC’s final rule. The impact of these new rules is reflected below in the Supplemental Oil and Gas Disclosure section.

For the quarter ended December 31, 2011, the Company recognized an impairment of $25.7 million for the carrying value of proved oil and gas properties in excess of the ceiling limitation in 2011 as a result of the decline of natural gas prices. The Company did not recognize any impairment charges relating to oil and natural gas properties in 2010. In first quarter of 2009, the Company recognized an impairment of $155.9 million due to a decrease in the period end price reserve estimates, as required under the former SEC rules. In the fourth quarter of 2009, the Company recognized an impairment of $230.1 million, as a result of the change in the reserve estimates defined under the new SEC rules as noted above.

A decline in natural gas and oil prices subsequent to December 31, 2011, could result in the recognition of additional impairment of the carrying value of proved oil and gas properties in 2012. The average of the historical unweighted first-day-of-the-month prices for the prior twelve month periods ended December 31, 2011 and February 29, 2012 was $4.12 and $3.86 for natural gas, respectively. If, the average of the historical unweighted first-day-of-the-month natural gas prices for the prior twelve month periods remains at current levels or decline further through the end of the first quarter of 2012 due to further price decline, we estimate we would have a further reduction in our asset carrying value for oil and gas properties.

Gathering assets and related facilities, certain other property and equipment, and furniture and fixtures are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from 3 to 30 years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.

The Company’s DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities.

During 2010, the Company received insurance proceeds of $2.3 million which were netted with the replacement costs recognized in oil and gas properties.

Capitalized Interest

The Company capitalizes interest costs to oil and natural gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. The Company capitalized $5.9 million of interest during each of the years ended December 31, 2011 and 2010.

Leases

The Company accounts for leases with escalation clauses and rent holidays on a straight-line basis in accordance with Accounting Standards Codification (ASC) 840, “Leases”. The deferred rent expense liability associated with future lease commitments was reported under the caption “Other long term obligations” on our consolidated balance sheet.

9

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

Derivative Instruments and Hedging Activities

The Company uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Such derivative instruments, which are placed with major financial institutions who are participants in the Company’s first lien credit facility (the Credit Agreement) (see Note 5) that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps, options, or basis swaps.

At December 31, 2011, with the exception of basis swaps, substantially all of our oil and natural gas derivative contracts are settled based upon reported New York Mercantile Exchange (NYMEX) prices. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables from separate hedging arrangements with that counterparty. The oil and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a generally high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. Our fixed-price swap, and collar agreements are used to fix the sales price for our anticipated future oil and natural gas production. Upon settlement, the Company receives a fixed price for the hedged commodity and receives or pays our counterparty a floating market price, as defined in each instrument. The instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, the Company pays our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to the Company. The Company has designated these swap and collar agreements as cash flow hedges.

The Company’s non-designated positions at December 31, 2011 included natural gas basis swaps and both oil and natural gas options. The basis swaps are used to minimize exposure to fluctuating differentials on certain pricing indices against other pricing indices. These instruments are settled monthly. Upon settlement, the Company will pay a floating price on a specified index, and the counterparty will pay a floating price on a different specified index, either of which may include a specified differential. When the Company’s specified index price is less than the counterparties, the counterparty will pay the Company. When the Company’s specified index price is greater than the counterparties specified index price, the Company will pay the counterparty. Additionally, the Company has sold natural gas calls, oil calls, and oil puts. For the oil and natural gas calls, the counterparty has the option to purchase a set volume of the contracted commodity at a contracted price on a contracted date in the future. For the oil puts, the counterparty has the option to sell a contracted volume of the commodity at a contracted price on a contracted date in future.

The Company accounts for these activities pursuant to ASC 815, “Derivatives and Hedging” which requires that derivative instruments other than those that meet the normal purchases and sales exception, be recorded on the balance sheets as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties). ASC 815 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in accumulated other comprehensive income. Realized gains and losses from the Company’s oil and natural gas cash flow hedges are generally recognized in gain (loss) on derivative instruments located in operating income in the consolidated statement of operations when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current-period earnings as a gain (loss) on derivative instruments located in other income in the consolidated statement of operations. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting under ASC 815 will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in accumulated other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in accumulated other comprehensive income until such time as the forecasted transaction impacts earnings. If

10

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative instruments and the hedged item over time, and any ineffectiveness is immediately reported as unrealized gain or loss on derivative instruments in the consolidated statement of operations.

Deferred Financing Costs

Deferred financing costs of approximately $4.5 million and $13.6 million were incurred during 2011 and 2010, respectively. Deferred financing costs in 2011 include costs associated with the amendment of the Company’s senior secured revolving Credit Facility (the Credit Facility). Deferred financing costs in 2010 include costs to amend the Credit Facility and the issuance of our 2017 Notes (see Note 5). Deferred financing costs are being amortized over the life of the respective obligations.

Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s Credit Facility is reported at carrying value which approximates fair value based on current rates applicable to similar instruments. Since considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the purchase or refinancing of such instruments. The Company’s derivative instruments are reported at fair value based on Level 2 fair value methodologies and the 2017 Notes are reported at carrying value but further compared to fair value based on Level 2 fair value methodologies (see Note 9).

Asset Retirement Obligation

The Company follows ASC 410, “Asset Retirement and Environmental Obligations”. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheets and capitalize the present value of the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. The capitalized costs associated with an ARO are included in the amortization base for purposes of calculating the ceiling test.

The information below reconciles the value of the asset retirement obligation:

	For the year ended December 31,
	2011			2010
	(in thousands)
Beginning Balance	$	9,213		$	8,155
Liabilities incurred		5,693			595
Liabilities settled		(186	)		(30	)
Accretion expense		628			493
Ending Balance	$	15,348		$	9,213

11

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

Revenue Recognition

The Company records revenues from the sales of natural gas and crude oil when the production is produced and sold, and also when collectability is ensured. The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of natural gas actually sold by the Company. The Company also reduces revenue for other owners’ natural gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and natural gas reserves. The Company had no material gas imbalances at December 31, 2011 and did not have gas imbalances at December 31, 2010.

Use of Estimates

The preparation of the consolidated financial statements for the Company in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas reserve quantities that are the basis for the calculation of DD&A and impairment of oil and natural gas properties, and timing and costs associated with its retirement obligations.

Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of the Company being passed through to the member. As such, no recognition of federal or state income taxes for the Company or its subsidiaries that are organized as limited liability companies have been provided for in the accompanying consolidated financial statements. Any uncertain tax position taken by the member is not an uncertain position of the Company.

In accordance with the operating agreement of NFR, to the extent possible without impairing the Company’s ability to continue to conduct its business and activities, and in order to permit its member to pay taxes on the taxable income of the Company, NFR would be required to make distributions to the member in the amount equal to the estimated tax liability of the member computed as if the member paid income tax at the highest marginal federal and state rate applicable to an individual resident of New York, New York, in the event that taxable income is generated for the member. There was no taxable income and therefore no distributions in 2011, 2010 or 2009.

Recent Accounting Pronouncements

In June 2011, the FASB issued Accounting Standards Update 2011-5, “Presentation of Comprehensive Income” (ASU 2011-5). The FASB has issued new guidance for how companies must present other comprehensive income (OCI) and its components in their financial statements. The guidance applies to all companies that report items of OCI but perhaps is most relevant for companies that have historically presented components of OCI as part of their statement of changes in stockholders’ equity which is no longer an option available under this guidance. ASU 2011-5 is intended to increase the prominence of items that are recorded in OCI and improve comparability and transparency in financial statements and allow for a more prominent evaluation of the effect of OCI on a company’s overall performance. The new guidance described in ASU 2011-05 will supersede the presentation options in Topic 220 (previously known as Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income). The guidance, however, affects only the presentation of OCI, not the components that must be reported in OCI. ASU 2011-5 is effective for private companies for annual periods beginning after Dec. 15, 2012, and interim and annual periods thereafter. Early adoption is permitted.

12

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures About Offsetting Assets and Liabilities” (ASU 2011-11). ASU 2011-11 amends the disclosure requirements on offsetting assets and liabilities by requiring improved information about financial instruments and derivative instruments that have a right of offset or are subject to an enforceable master netting arrangement or similar agreement. This information will enable users of a company’s financial statements to evaluate the effect or potential effect of netting arrangements on a company’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. The Company is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Companyshould provide the disclosures required by those amendments retrospectively for all comparative periods presented.

In December 2010, the FASB issued Accounting Standards Update 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (ASU 2010-29). ASU 2010-29 clarifies that when presenting comparative pro forma financial statements in conjunction with business combination disclosures, revenue and earnings of the combined entity should be presented as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period. In addition, the update requires adescription of the nature and amount of material, nonrecurring pro forma adjustments included in pro forma revenue and earnings that are directly attributable to the business combination. This update is effective prospectively for business combinations that occur on or after the beginning of the first annual reporting period after December 15, 2010. As ASU 2010-29 relates to disclosure requirements, there will be no impact on the Company’s financial condition or results of operations.

In December 2010, the FASB issued Accounting Standards Update 2010-28, “Intangibles — Goodwill and Other: When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts” (ASU 2010-28). ASU 2010-28 requires step two of the goodwill impairment test to be performed when the carrying value of a reporting unit is zero or negative, if it is more likely than not that a goodwill impairment exists. The requirements of this update are effective for fiscal years beginning after December 15, 2010. The Company does not currently have goodwill.

In February 2010, the FASB issued Accounting Standards Update 2010-09, “Amendments to Certain Recognition and Disclosure Requirements” (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filers, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. The Company adopted the provisions of ASU 2010-09 in the period ended March 31, 2010.

In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures” (ASU 2010-03), which aligns the FASB’s oil and gas reserve estimation and disclosure requirements with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and became effective for the year ended December 31, 2009. We adopted the final rule and ASU 2010-03 effective December 31, 2009, as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new rules for periods before the adoption of ASU 2010-03 and the final rule are not required.

In December 2008, the SEC issued a final rule, “Modernization of Oil and Gas Reporting”, which is effective January 1, 2010 for reporting 2009 oil and gas reserve information. We adopted the guidance as of December 31, 2009. In January 2010, the FASB issued ASU 2010-03 “Extractive Industries – Oil and Gas” to align its rules for oil and natural gas reserves estimation and disclosure requirements with the SEC’s final rule.

13

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

2. Significant Accounting Policies (continued)

In January 2010, the FASB issued additional disclosure requirements related to fair value measurements. The guidance requires disclosure of transfers of assets and liabilities between Level 1 and Level 2 in the fair value measurement hierarchy, including the reasons for the transfers and disclosure of major purchases, sales, issuances, and settlements on a gross basis in the reconciliation of the assets and liabilities measured under Level 3 of the fair value measurement hierarchy. The guidance is effective in interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures which are effective for interim and annual periods beginning after December 15, 2010. We adopted the provisions for the quarter ending March 31, 2010, except for the Level 3 reconciliation disclosures included in Note 9, which we adopted in the quarter ending March 31, 2011. Adopting the disclosure requirements for the quarter ending March 31, 2010 did not have an impact on our financial position or results of operations. We do not expect adoption of the Level 3 reconciliation disclosures in 2011 to have any impact on our financial position or results of operations.

3. Significant Customers

During the year ended December 31, 2011, purchases by three companies exceeded 10% of the total oil and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP, Texla Energy Management LLC and PVR Midstream LLC accounted for approximately 18%, 15% and 13% of oil and natural gas sales, respectively. During the year ended December 31, 2010, purchases by two companies exceeded 10% of the total oil and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP and PVR Midstream LLC accounted for approximately 22% and 23% of oil and natural gas sales, respectively. During the year ended December 31, 2009, purchases by one company exceeded 10% of the total oil and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP accounted for approximately 28% of total oil and natural gas sales. The Company believes that the loss of any of the purchasers above would not result in a material adverse effect on its ability to market future oil and natural gas production.

4. Property Acquisitions

Total costs incurred for property acquisitions for 2011 and 2010 were approximately $396.4 million and $129.0 million respectively (excluding related asset retirement costs), of which approximately $31.3 million and $68.8 million related to unproved properties and $365.1 million and $60.2 million related to proved property acquisitions.

On September 26, 2011, the Company signed a Purchase and Sale Agreement for the acquisition of certain oil and gas properties in East Texas which closed on November 14, 2011for $222.0 million, net of purchase price adjustments. This acquisition qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $235.1 million for proved property and $5.3 million for unproved acreage, which resulted in a bargain purchase gain of $18.4 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for the proved developed and undeveloped reserves and unproved acreage.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		000,000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	235.1
Unproved leasehold properties		5.3
Bargain purchase gain		(18.4	)
Cash, net of accrued purchase price adjustments	$	222.0

14

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)

The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on our results of operations for the years ended December 31, 2011 and 2010 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.

	Year Ended				Year Ended
	December 31, 2011				December 31, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited )
Total revenues	$	277,637	$	317,254	$	184,556	$	243,220
Total operating expenses (1)	$	193,781	$	222,918	$	113,643	$	154,260
Net income applicable to controlling interests (1)	$	217,015	$	227,495	$	38,769	$	56,816

(1) Bargain purchase gain of $99.5 million and $18.4 million, recognized in actual and pro forma operating expenses, respectively, has been excluded from actual and pro forma results above.

On July 5, 2011, NFR entered into an agreement to purchase oil and gas properties in East Texas which closed on August 18, 2011 for $102.6 million, net of purchase price adjustments. This acquisition qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $142.3 million for proved property and $14.8 million for unproved acreage, which resulted in a bargain purchase gain of $54.5 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for the proved developed and undeveloped reserves and unproved acreage, as well as an upward shift in the forward price curve at the time of closing.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		00,000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved properties	$	142.3
Unproved properties		14.8
Bargain purchase gain		(54.5	)
Cash, net of accrued purchase price adjustments	$	102.6

15

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)

The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on our results of operations for the years ended December 31, 2011 and 2010 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.

	Year Ended				Year Ended
	December 31, 2011				December 31, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited )
Total revenues	$	277,637	$	292,128	$	184,556	$	210,549
Total operating expenses (1)	$	193,781	$	202,478	$	113,643	$	131,252
Net income applicable to controlling interests (1)	$	217,015	$	222,809	$	38,769	$	47,153

(1) Bargain purchase gain of $99.5 million and $54.5 million, recognized in actual and pro forma operating expenses, respectively, has been excluded from actual and pro forma results above.

On January 31, 2011 and February 8, 2011, NFR entered into agreements to purchase working interests in developed and undeveloped acreage in East Texas for $60.7 million and $11.2 million, respectively, for a total adjusted purchase price of $71.8 million,which qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $87.4 million for developed acreage, which resulted in a bargain purchase gain of $26.7 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included proved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for both proved developed and undeveloped reserves and unproved acreage, as well as a result of an upward shift in the forward price curve at the time of closing and receipt of updated production data for the recent producing wells that improved the well economics.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		000000
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	87.4
Unproved leasehold properties		11.2
Asset retirement obligation		(0.1	)
Bargain purchase gain		(26.7	)
Cash, net of accrued purchase price adjustments	$	71.8

16

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)

The unaudited pro forma results presented below have been prepared to give the effect of the acquisitions discussed above on our results of operations for the years ended December 31, 2011 and 2010 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if these acquisitions had been completed on such date or to project our results of operations for any future date or period.

	Year Ended				Year Ended
	December 31, 2011				December 31, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited )
Total revenues	$	277,637	$	280,519	$	184,556	$	215,385
Total operating expenses (1)	$	193,781	$	194,412	$	113,643	$	132,848
Net income applicable to controlling interests (1)	$	217,015	$	219,266	$	38,769	$	50,393

(1) Bargain purchase gain of $99.5 million and $26.7 million, recognized in actual and pro forma operating expenses, respectively, has been excluded from actual and pro forma results above.

On October 7, 2010, NFR entered into an agreement to purchase working interests in developed and undeveloped acreage for an adjusted purchase price of $64.5 million, which qualified as a business combination pursuant to ASC 805. NFR recorded a fair value of $64.9 million, which resulted in a bargain purchase gain of $0.4 million that was recorded in the current period’s earnings.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

		000000
Proved developed and undeveloped properties	$	48.8
Unproved leasehold properties		16.4
Asset retirement obligation		(0.3	)
Bargain purchase gain		(0.4	)
Cash, net of accrued purchase price adjustments	$	64.5

The unaudited pro forma results presented below have been prepared to give effect to the acquisition discussed above on our results of operations as if it had been consummated at the beginning of the comparable period for the year ended December 31, 2009. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if this acquisition had been completed on such date or to project our results of operations for any future date or period.

	Year Ended				Year Ended
	December 31, 2010				December 31, 2009
	Actual		Pro Forma		Actual			Pro Forma
	(in thousands)
Pro Forma (unaudited )
Total revenues	$	184,556	$	193,240	$	143,580		$	155,952
Total operating expenses	$	113,643	$	118,627	$	499,263		$	498,390
Net income (loss) applicable to controlling interests	$	38,769	$	42,469	$	(370,276	)	$	(357,031	)

17

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

4. Property Acquisitions (continued)

In May 2010, NFR entered into an agreement to purchase working interests in 16,339 net undeveloped acres that are prospective for the Haynesville Shale formation in Harrison, Panola and Rusk Counties, Texas, for $42.6 million. None of the acreage was developed or proved at the time of acquisition.

In June 2009, NFR entered into an agreement to acquire the deep rights (Haynesville Shale) with approximately 23,000 net acres in East Texas for a cash purchase price of approximately $60 million as adjusted in accordance with the purchase and sale agreement. The acquisition closed on June 22, 2009. None of the acreage was developed or proved at the time of acquisition.

Additionally, during 2009 NFR acquired leases for acreage in the same areas as the acquisitions listed above for $6.3 million.

Acquired properties that are considered to be business combinations are recorded at their fair value. In determining the fair value of the proved and unproved properties, the Company prepares estimates of oil and natural gas reserves. The Company estimates future prices to apply to the estimatedreserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing unproved reserves, probable and possible reserves are reduced by additional risk-weighting factors.

The results of each of the acquisitions are included in the accompanying consolidated statement of operations since the respective date of purchase.

The Company incurred $274.6 million and $238.8 million in development costs, for 2011 and 2010 respectively. All development related costs were included in proved properties. The Company incurred exploration costs of $0.5 million and $0.2 million in 2011 and 2010, respectively.

The unproved costs associated with the Company’s drilling projects will be transferred to proved properties as the wells are drilled or impaired.

5. Long-Term Debt

Senior Notes

On February 12, 2010, we and our subsidiary NFR Energy Finance Corporation co-issued $200 million in 9.75% senior unsecured notes due 2017 (the 2017 Notes) in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933 and to persons outside the United States in compliance with Regulation S of the Securities Act of 1933. The 2017 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 each year commencing August 15, 2010. The 2017 Notes were issued at 98.73% of par. In conjunction with the issuance of the 2017 Notes, the Company recorded a discount of $2.53 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $1.85 million and $2.21 million at December 31, 2011 and 2010, respectively. The 2017 Notes were issued under and are governed by an indenture dated February 12, 2010 between the Company, NFR Energy Finance Corporation, the Bank of New York Mellon Trust Company, N.A. as trustee, and the Company’s subsidiaries named therein as guarantors.

18

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

5. Long-Term Debt (continued)

All of our domestic restricted subsidiaries that guarantee our Credit Facility (other than NFR Energy Finance Corporation) have guaranteed the 2017 Notes on a senior unsecured basis. We utilized the net proceeds from the sale to repay in full our second lien term loan facility, including the associated prepayment premium, which had an outstanding balance of $50.0 million, and to repay approximately $138.0 million in outstanding borrowings under our Credit Facility. The second lien term loan was paid in full and extinguished on February 12, 2010. The Company paid $3.1 million in early termination fees associated with the repayment of the second lien term loan facility. Additionally, the Company expensed $1.8 million of accumulated deferred financing costs associated with the second lien. Both the early termination fee and the amortization of deferred financing costs are included in interest expense on the statement of operations.

On April 14, 2010, we and NFR Energy Finance Corporation issued an additional $150 million in senior notes at 9.75% due 2017. The additional notes were issued at 98.75% of par and bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 of each year commencing August 15, 2010. The additional notes were issued under the same indenture as the 2017 Notes issued on February 12, 2010. The Company recorded a discount of $1.87 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $1.37 million and $1.63 million at December 31, 2011 and 2010, respectively. Proceeds were used to repay the entire outstanding balance under our Credit Facility, to purchase assets in East Texas, and to provide working capital for general corporate purposes in 2010.

We may redeem the 2017 Notes, in whole or in part, at any time on or after February 15, 2014, at a redemption price (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:

Year	Percentage
2014		104.875
2015		102.438
2016		100.000

At any time before February 15, 2013, we may redeem up to 35% of the aggregate principal amount of the 2017 Notes issued under the indenture with the net cash proceeds of one or more equity offerings at a redemption price equal to 109.750% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the date of such redemption, provided that: at least 50% of the aggregate principal amount of the notes remains outstanding immediately after the occurrence of such redemption, and such redemption occurs within 180 days of the date of the closing of any such equity offering.

In addition, we may redeem some or all of the 2017 Notes prior to February 15, 2014 at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest to the date of such redemption, plus a “make-whole” premium equal to the greater of (1) 1% of the principal amount of such note or (2) the excess of (a) the present value at such time of (i) the redemption price of such note at February 15, 2014, plus (ii) all required interest payments due on the 2017 Notes through February 15, 2014, computed using a discount rate equal to the yield of United States Treasury securities with a constant maturity most nearly equal to the period from the redemption date to February 15, 2014 plus 50 basis points, over (b) the principal amount of such note. Each holder of the notes will also be entitled to require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of such repurchase upon a change of control.

19

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

5. Long-Term Debt (continued)

The indenture governing the 2017 Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness unless the ratio of our adjusted consolidated EBITDA to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0 (subject to exceptions for borrowings within certain limits under our Credit Facility); pay dividends or repurchase or redeem equity interests; limit dividends or other payments by restricted subsidiaries that are not guarantors to us or our other subsidiaries; make certain investments; incur liens; enter into certain types of transactions with our affiliates; and sell assets or consolidate or merge with or into other companies. However, if and for as long as the 2017 Notes have an investment grade rating from Standard & Poor’s Ratings Group, Inc. and Moody’s Investors Service, Inc., and no default or event of default exists under the indenture, we will not be subject to certain of the foregoing covenants.

First Lien Revolving Credit Facility

On November 30, 2007, the Company entered into a first lien revolving Credit Facility with a syndicate of banks. BNP Paribas is the Credit Facility’s administration agent. Subsequently, through a series of redeterminations, the Company has amended and restated the Credit Facility. The most recent redetermination on November 14, 2011, increased the borrowing base from $500 million to $625 million. The next redetermination will be in March 2012.

As of December 31, 2011, commitments under the facility are $750 million, the borrowing base is $625 million, and the Credit Facility’s maturity date is April 7, 2016.

Borrowings made under the Credit Facility are guaranteed by first priority perfected liens and security interests on substantially all assets of NFR and its wholly-owned domestic subsidiaries and a pledge of 100% of NFR’s ownership of equity units of all non-wholly owned domestic subsidiaries.

Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (ABR). The Eurodollar rate is calculated as London Interbank Offered Rate (LIBOR) plus an applicable margin that varies from 1.75% (for periods in which NFR has utilized less than 30% of the borrowing base) to 2.75% (for periods in which NFR has utilized equal to or greater than 90% of the borrowing base). The ABR is calculated as the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) Eurodollar rate on such day (or if such day is not a business day, the immediately preceding business day) plus 1.5%. The Company elects the basis of the interest rate at the time of each borrowing. In addition, NFR pays a commitment fee of 0.50% under the Credit Facility (quarterly in arrears) for the amount that the aggregate commitments exceed borrowings under the Credit Facility.

Under the Credit Facility, the Company may request letters of credit, provided that the borrowing base is not exceeded or will not be exceeded as a result of issuance of the letter of credit. There were no outstanding letters of credit on December 31, 2011 or December 31, 2010.

The Credit Facility requires the Company to comply with certain financial covenants to maintain (a) a current ratio, defined as a ratio of consolidated current assets (including the unused amount of the total commitments under the Credit Facility, but excluding noncash assets under ASC 815, Derivatives and Hedging (formerly Statements of Financial Accounting Standards (SFAS) 133), to consolidated current liabilities (excluding noncash obligations under ASC 815 and the current maturities under the Credit Facility, determined at the end of each quarter), of not less than 1.0 to 1.0; (b) an interest coverage ratio at the end of each quarter defined as a ratio of EBITDA (as such terms are defined in the Credit Facility) for the period of four fiscal quarters then ending to interest expense for such period of not less than 2.5 to 1.0.

In addition, the Credit Facility contains covenants that restrict, among other things, the Company’s ability to incur other indebtedness, create liens, or sell itsassets; merge with other entities; pay dividends; and make certain investments.

20

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

5. Long-Term Debt (continued)

At December 31, 2011 and December 31, 2010, NFR was in compliance with its financial debt covenants under the Credit Facility. At December 31, 2011, the outstanding balance under our Credit Facility was $418 million and we were able to incur approximately $207 million of secured indebtedness under our Credit Facility, which amount represents the available portion of our adjusted borrowing base of $625 million. At December 31, 2010, we had available to us $206 million remaining on our borrowing base of $300 million.

Subsequent to the period ended December 31, 2011 through the date of the report on February 23, 2012, the Company has drawn an additional $39 million and has repaid $15 million under our Credit Facility.

In addition to the Credit Agreement, NFR entered into a second lien term loan facility for $50 million on April 28, 2009 which was paid in full and extinguished on February 12, 2010. The average annual interest rate for our term loan borrowings for the twelve months ended December 31, 2009 was 4%, plus an applicable margin of 1,000 basis points, or 14%.

6. Member’s Capital

The Company is authorized to issue one class of units to be designated as “Common Units”. The Units are not represented by certificates. All Common Units are issued at a price equal to $1,000 per unit.

7. Statement of Cash Flows

During the year ended December 31, 2011, the Company’s noncash investing and financing activities consisted of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $5.7 million.

• Recognition of bargain purchase gains of $99.5 million related to the recognition of the fair market value in excess of the consideration paid for proved developed and undeveloped reserves and undeveloped acreage.

• Changes to oil and natural gas properties of $47.3 million, included in accrued exploration and development.

During the year ended December 31, 2010, the Company’s noncash investing and financing activities consisted of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $0.6 million.

• Recognition of bargain purchase gains of $0.4 million related to the recognition of the fair market value in excess of the consideration paid for proved developed and undeveloped reserves and undeveloped acreage.

• Changes to oil and natural gas properties of $23.4 million, included in accrued exploration and development.

During the year ended December 31, 2009, the Company’s noncash investing and financing activities consisted of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $1.1 million.

• Changes to oil and natural gas properties of $36.6 million, included in accrued exploration and development.

NFR paid $41.1 million, $20.9 million and $11.8 million for interest during 2011, 2010 and 2009, respectively.

21

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments

The Company is exposed to risks associated with unfavorable changes in the market price of natural gas as a result of the forecasted sale of its production and uses derivative instruments to hedge or reduce its exposure to certain of these risks. During 2011, a portion of commodity derivative instruments were designated as cash flow hedges and were subject to cash flow hedge accounting under ASC 815. For the remaining derivative instruments, the Company either did not elect hedge accounting for accounting purposes or did not qualify for hedge accounting treatment and, accordingly, recorded the net change in the mark-to-market valuation of these derivative instruments in the consolidated statement of operations.

During February 2011, the Company restructured its hedge portfolio through the execution of new financial commodity derivative contracts, the restructuring of certain existing derivative contracts and the liquidation of certain derivative contract positions as follows:

• The Company liquidated and settled all existing hedge contracts covering volumes for the years 2014 and 2015.

• The Company “re-couponed” all volumes covered by the existing 2013 swap contracts from $7.40/MMBTU to $6.0/MMBTU.

• The Company added new swap contracts of 9.6BCF at an average price of $6.17/MMBTU and 16.4BCF at an average price of $5.67/MMBTU in 2011 and 2012, respectively. Proceeds from the liquidation and re-couponing actions taken in the bullets above were used to execute the new swap contracts that were added for 2011 and 2012.

The net impact of the restructure on the fair market value of derivative instruments was $2.9 million, recognized in other expenses as a loss on derivative instruments.

During June 2011, the Company added oil contracts to its hedge portfolio. These contracts were executed in order to hedge future oil production against volatility in commodity prices through December 31, 2012.

During December 2011, the Company executed the sale of oil and natural gas options for which a premium was received that will be amortized as the contracts settle each month. The Company used the premium received to execute natural gas swap contracts above market.

22

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments (continued)

The following swaps, basis swaps and costless collars were outstanding with associated notional volumes and contracted swap, floor, and ceiling prices that represent hedge weighted average prices for the index specified as of December 31, 2011:

	Future production designated for hedge accounting
	2012		2013
Swaps—Natural Gas
Volume (MMBTU)		24,787,101		32,238,731
Price	$	6.19	$	5.23
Collars—Natural Gas
Volume (MMBTU)		7,233,210		—
Price (Floor/Ceiling)	$	6.00 / $8.65		—
Collars—Oil
Volume (Bbls) (1)		128,100		—
Price (Floor/Ceiling) (1)	$	85.00 / $110.10		—

	Future production not designated for hedge accounting
	2012		2013		2014		2015
Puts—Oil (Sell)
Volume (Bbls) (1)		128,100		—		—		—
Price (1)	$	70.00		—		—		—
Calls—Oil (Sell)
Volume (Bbls)		—		127,750		127,750		127,750
Price		—	$	110.00	$	110.00	$	110.00
Calls—Natural Gas (Sell)
Volume (MMBTU)		—		—		21,900,000		21,900,000
Price		—		—	$	5.25	$	5.25
Basis Swap, NYMEX—East Texas (Houston Ship Channel)
Volume (MMBTU)		4,002,250		1,277,500		—		—
Contract differential (2)	$	0.10 - $0.15	$	0.11 - $0.15		—		—
Basis Swap, NYMEX—TEXOK (NGLP)
Volume (MMBTU)		12,006,750		3,869,000		—		—
Contract differential (2)	$	0.16 - $0.29	$	0.21 - $0.25		—		—

(1) The Company sold options on a like amount of oil volume as the standard collar noted above. The addition of the put contract establishes a derivative contract structure which will require the Company to make payment to the counterparty if the settlement price for any settlement period is below the put price. The Company will be entitled to a net payment equal to the difference between the floor price of the standard collar ($85) and the additional put price of ($70), should the settlement price be equal to or less than the additional put price. If the settlement price is greater than the additional put price, the result is the same as it would have been with a standard collar contract.

(2) Basis swaps settle based on NYMEX pricing minus a differential, which is then compared to Inside Federal Energy Regulatory Commission (FERC) for the index on which volumes are being hedged.

For our energy commodity derivative instruments that were designated as cash flow hedges, the portion of the change in the value of derivative instruments that is effective in offsetting changes in expected cash flows (the effective portion) is reported as a component of accumulated other comprehensive income, but only to the extent that they can later offset the undesired changes in expected cash flows during the period in which the hedged cash flows affect earnings. To the contrary, the portion of the change in the value of derivative instruments that is not effective in offsetting undesired changes in expected cash flows (the ineffective portion), as well as any component excluded from the assessment of the effectiveness of the derivative instruments, is required to be recognized currently in earnings. The Company excludes time value associated with costless collars from the assessment of effectiveness.

The Company recorded a short term and a longterm derivative asset of $90.8 million and $36.9 million, respectively, and recorded a short term and a long term derivative liability of $0.1 million and $17.4 million, respectively, related to the fair value of the derivatives instrument’s prices on remaining volumes as of December 31, 2011 after application of ASC 820, “Fair Value Measurements”.

23

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments (continued)

The table below provides data about the carrying values of derivatives instruments as of December 31, 2011.

	Assets Derivatives
Derivatives designated as hedging instruments			December 31, 2011			December 31, 2010
			(in thousands)
			Fair Value
Current		Derivative Instruments	$	92,760		$	41,805
Long term		Derivative Instruments		41,007			69,309
Total derivatives designated as hedging instruments			$	133,767		$	111,114
	Assets Derivatives
Derivatives not designated as hedging instruments			December 31, 2011			December 31, 2010
			(in thousands)
			Fair Value
Current		Derivative Instruments	$	—		$	—
Long term		Derivative Instruments		6			5
Total derivatives not designated as hedging instruments			$	6		$	5
	Liabilities Derivatives
Derivatives not designated as hedging instruments			December 31, 2011			December 31, 2010
			(in thousands)
			Fair Value
Current		Derivative Instruments	$	(1,978	)	$	(1,056	)
Long term		Derivative Instruments		(21,502	)		(1,042	)
Total derivatives not designated as hedging instruments			$	(23,480	)	$	(2,098	)

The following table summarizes the cash flow hedge gains and losses and their locations on the Consolidated Balance Sheets as of December 31, 2011 and 2010 and Consolidated Statement of Operations for the year ended December 31, 2011 and 2010:

Derivatives in Cash Flow Hedging Relationships	Amount of Gain Recognized in Other Comprehensive Income (OCI)		Location of Gain Reclassified from Accumulated OCI into Operating Income	Amount of Gain Reclassified from Accumulated OCI into Operating Income		Location of Gain (loss) in Other Income Ineffective Hedges	Amount of Gain (loss) Recognized in Income (Ineffective portion and Amount Excluded from Effectiveness Testing)
	(in thousands)
For the Year Ended December 31, 2011
Derivative			Gain on			Gain on
Instruments	$	97,632	derivative instruments	$	72,517	derivative instruments	$	409
Total	$	97,632		$	72,517		$	409
For the Year Ended December 31, 2010
Derivative			Gain on			Loss on
Instruments	$	105,629	derivative instruments	$	55,305	derivative instruments	$	(533	)
Total	$	105,629		$	55,305		$	(533	)

24

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

8. Derivative Financial Instruments (continued)

The following table summarizes the location in the Consolidated Statement of Operations and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting for the year ended December 31, 2011 and December 31, 2010:

Derivatives Not Designated as Hedging Instruments	Location of Loss Recognized in Other Income	Recognized in Other Income on Derivatives for the Years Ended
		December 31, 2011		December 31, 2010
		(in thousands)
	Loss on
Derivative Instruments	Derivative Instruments	$	(26,208)	$	(1,121)

The consolidated accumulated other comprehensive income balance was $130.8 million as of December 31, 2011, and $105.7 million as of December 31, 2010. Approximately $74.7 million of this total accumulated gain associated with commodity price risk management activities as of December 31, 2011, is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur.)

9. Fair Value Measurements

In September 2006, the FASB issued ASC 820, “Fair Value Measurements”, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of ASC 820 are effective January 1, 2008. The FASB has also issued ASC 820-10-55, which delayed the effective date of ASC 820 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company adopted ASC 820 as discussed above and elected to defer the application thereof to nonfinancial assets and liabilities in accordance with ASC 820-10-55 until January 1, 2009.

As discussed in Note 8, the Company utilizes derivative instruments to hedge against the variability in cash flows associated with the forecasted sale of its anticipated future natural gas production. The Company generally hedges a substantial, but varying, portion of anticipated natural gas production for the next 12 to 60 months. These derivatives are carried at fair value on the consolidated balance sheets.

As defined in ASC 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes 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. The Company classifies fair value balances based on the observability of those inputs. ASC 820 establishes afair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

25

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

9. Fair Value Measurements (continued)

The three levels of the fair value hierarchy defined by ASC 820 are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, basis swaps, options, and collars.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table sets forth, by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2011 and 2010. As required by ASC 820, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

		$00000000		$00000000			$00000000		$00000000
	Recurring Fair Value Measures
	(in millions)
	Level 1		Level 2			Level 3		Total
As of December 31, 2011
Derivative Assets	$	—	$	127.8		$	—	$	127.8
Derivative Liabilities		—		(17.5	)		—		(17.5	)
Total	$	—	$	110.3		$	—	$	110.3
	Level 1		Level 2			Level 3		Total
As of December 31, 2010
Derivative Assets	$	—	$	109.0		$	—	$	109.0
Total	$	—	$	109.0		$	—	$	109.0

Derivatives listed above include commodity swaps, basis swaps, put and call options and collars that are carried at fair value. The fair value amounts on the consolidated balance sheets associated with the Company’s derivatives resulted from Level 2 fair value methodologies, that is, the Company is able to value the assets and liabilities based on observable market data for similar instruments. The amounts above include the impact of netting assets and liabilities with counterparties with which the right of offset exists.

This observable data includes the forward curve for commodity prices and interest rates based on quoted markets prices and prospective volatility factors related to changes in commodity prices, as well as the impact of our non-performance risk of the counterparties which is derived using credit default swap values.

26

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

9. Fair Value Measurements (continued)

The Company measures fair value of its long term debt based on quoted market prices with consideration given to the effect of the Company’s credit risk. The carrying value of the Company’s Credit Facility approximates fair value based on current rates applicable to similar instruments. The following table outlines the fair value of our 2017 Notes as of December 31, 2011 and 2010:

	December 31, 2011		December 31, 2010
	(in thousands)
2017 Senior Notes
Carrying Value	$	346,782	$	346,153
Fair Value	$	323,456	$	322,207

10. Related-Party Transactions

NFR paid $87.7 million, $58.7 million and $42.2 million during 2011, 2010 and 2009, respectively, to Nabors and its subsidiaries for drilling and other oilfield services and the Company has recognized a liability on our consolidated balance sheets as of December 31, 2011 and 2010 of $12.1 million and $16.0 million, respectively, for these services.

NFR paid $0.8 million during 2010 and 2009, to Smith International, Inc. (Smith), an oil and natural gas services company, for services provided. A member of the Company’s board of representatives was the Chief Executive Officer, President, and Chief Operating Officer of Smith through August of 2010.

11. Commitments

The Company leases approximately 55,000 square feet of office space in downtown Houston, Texas, under a lease, which terminates on May 13, 2013. The average rent for this space over the life of the lease is approximately $0.6 million per year. The Company has an option to extend its lease term for an additional 60 months. As of December 31, 2011, total future commitments are $1.2 million.

The Company leases approximately 14,100 square feet of office space in downtown Denver, Colorado, under two leases. One lease terminates on August 31, 2014 and the Company has the option to extend its lease term for an additional 60 months. This lease, which is approximately 11,000 square feet, is sub leased out with proceeds to offset the rent commitments. The average rent for this space over the life of the lease is approximately $0.2 million per year. As of December 31, 2011 total future commitments are $0.6 million. The second lease continues with a month to month lease term.

The Company leases various office and production equipment. As of December 31, 2011, total future commitments are $0.8 million. The majority of our operating leases continue with a month to month lease term after initial contractual obligations have expired.

As part of our ongoing operations, we have contracted with affiliates of Nabors to secure drilling rigs for drilling the oil and natural gas well activity we expect to undertake. As of December 31, 2011 total future commitments are $37.1 million.

As of December 31, 2011, future minimum lease payments were as follows (in millions):

	Estimated Payments
	(in millions)
Year Ending December 31,
2012	$	24.9
2013		14.5
2014		0.2
Thereafter		—
	$	39.6

27

CONSOLIDATED FINANCIAL STATEMENTS

NFR ENERGY LLC

Notes to Consolidated Financial Statements

11. Commitments (continued)

Rent expense was approximately $1.6 million for the year ended December 31, 2011, $1.2 million for the year ended December 31, 2010 and $1.1 million for the year ended December 31, 2009.

As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not pay such commitments, the acreage positions or wells may be lost.

The Company is at risk of lawsuits arising in the ordinary course of our business. In Management’s opinion, the Company is not currently involved in any legal proceedings which, individually or in aggregate, could have a material effect on the financial condition, operations or cashflows of the Company.

12. Employee Benefit Plans

The Company co-sponsors a 401(k) tax deferred savings plan (the Plan) and makes it available to employees. The Plan is a defined contribution plan, and the Company may make discretionary matching contributions of up to 6% of each participating employee’s compensation to the Plan. The contributions made by the Company totaled approximately $845,000 during the year ended December 31, 2011, $643,000 during the year ended December 31, 2010, and $502,000 for the period ended December 31, 2009.

13. Subsequent Events

Management has evaluated subsequent events through February 23, 2012, which represents the date the consolidated financial statements were issued, and have no reportable events.

28

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following supplemental information regarding our natural gas and oil producing activities is presented in accordance with the requirements of Section 932-235-50 of the ASC.

Costs Incurred

The costs incurred in oil and natural gas acquisitions, exploration and development activities were as follows:

	For the Year Ended December 31,
	2011		2010		2009
	(in thousands)
Property acquisition costs, proved (1)	$	466,874	$	60,252	$	6,297
Property acquisition costs, unproved (1)		28,663		68,758		62,725
Exploration and extension well costs		507		218		2,263
Development costs		274,631		238,850		252,838
Asset retirement costs		5,693		595		1,100
Total Costs	$	776,368	$	368,673	$	325,223

(1) Property acquisition costs for the year ended December 31, 2011include bargain purchase gains of $79.4 million allocated to proved property acquisition costs and $20.1 million allocated to unproved property acquisition costs.

Capitalized Costs

The capitalized costs in oil and natural gas properties were as follows:

	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Proved properties	$	2,292,875		$	1,506,565		$	1,177,439
Unproved properties		208,230			218,172			178,625
		2,501,105			1,724,737			1,356,064
Accumulated depletion, depreciation and amortization		(1,029,535	)		(925,874	)		(877,190	)
Net capitalized costs	$	1,471,570		$	798,863		$	478,874

29

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Results of Operations

Results of operations for oil and natural gas producing activities, which exclude processing and other activities, corporate general and administrative expenses, and straight-line depreciation expense on non-oil and gas assets, were as follows:

	For the Year Ended December 31,
	2011		2010		2009
	(in thousands)
Revenues	$	204,989	$	132,062	$	81,937
Gain on derivative instruments		72,517		51,104		60,686
Operating costs:
Lease operating expenses		27,113		18,637		18,253
Workover expenses		2,903		848		482
Marketing, gathering, transportation and other		19,717		13,730		6,031
Production and ad valorem taxes		7,775		5,483		4,228
Depletion, depreciation and amortization		77,932		48,685		41,137
Impairments		29,921		1,711		407,295
Results of operations	$	112,145	$	94,072	$	(334,803	)

Oil and Natural Gas Reserves and Related Financial Data

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following tables set forth our total proved reserves and the changes in our total proved reserves. These reserve estimates are based in part on reports prepared by Miller and Lents, Ltd. (Miller and Lents), independent petroleum engineers, utilizing data compiled by us. In preparing its reports, Miller and Lents evaluated properties representing all of our proved reserves at December 31, 2011, 2010 and 2009. Our proved reserves are located onshore in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved reserves are the estimated quantities of natural gas, natural gas liquids and oil that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in future years from known oil and natural gas reservoirs under existing economic conditions, operating methods and government regulations at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

30

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Proved reserves as of December 31, 2011 and 2010 were estimated using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve months as required under new SEC rules. The average of the historical unweighted first-day-of-the-month prices for the prior twelve month periods ended December 31, 2011 and 2010 were $4.12 and $4.38, respectively. The average of the historical unweighted first-day-of-the-month prices for the prior twelve months ended February 29, 2012 is $3.86 and the future prices actually received may materially differ from current prices or the prices used in making the reserve estimates impacting the amount of proved developed and proved undeveloped reserves as of December 31, 2011. With respect to future development costs and operating expenses, the Company derived estimates using the current cost environment at year end, which is consistent with both the current and former SEC rules. The new SEC rules, which were adopted for the year ended December 31, 2009, also contain new reserve definitions and permit the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The new SEC rules further state that any proved undeveloped reserves (“PUD”) associated with undeveloped acreage must be part of a development drilling program and be drilled within five years of such reserves being originally booked in order to maintain their proved reserve status. Any PUDs not meeting these criteria will be reclassified as unproved reserves. As reflected in the table below, approximately 472.4 Bcfe of the increase in our total estimated proved reserves from December 31, 2008 to December 31, 2009 relates to the application of the new SEC rules discussed herein.

	Natural									Natural Gas
	Gas			NGLS			Oil			Equivalents
Estimated Proved Reserves	(Bcf)			(BBLS)			(BBLS)			(Bcfe)
December 31, 2008		375.8			5.3			2.7			423.8
Revisions—Performance		14.1			0.3			0.2			17.0
Revisions—Pricing		(86.2	)		(1.3	)		(0.5	)		(96.9	)
Extensions, Additions and Discoveries (Old SEC Rules)		192.7			0.6			1.7			207.1
Extensions, Additions and Discoveries (New SEC Rules) (1)		460.9			1.3			0.6			472.4
Production		(18.9	)		(0.3	)		(0.1	)		(21.4	)
Purchases in Place		—			—			—			—
Sales in Place		—			—			—			—
December 31, 2009		938.4			5.9			4.6			1,002.0
Revisions—Performance		(127.1	)		4.4			(0.9	)		(106.0	)
Revisions—SEC Rule Revision (2)		(121.1	)		(0.5	)		—			(124.3	)
Revisions—Pricing		8.8			0.1			—			9.4
Extensions, Additions and Discoveries		218.1			0.8			0.5			226.2
Production		(24.8	)		(0.4	)		(0.1	)		(28.2	)
Purchases in Place (3)		220.8			0.9			0.8			230.3
Sales in Place		(2.1	)		—			(0.1	)		(2.7	)
December 31, 2010		1,111.0			11.2			4.8			1,206.7
Revisions—Performance		(101.2	)		(5.0	)		0.5			(128.2	)
Revisions—SEC Rule Revision (2)		(590.2	)		(0.2	)		(3.6	)		(613.0	)
Revisions—Pricing		(28.8	)		(0.4	)		0.3			(29.4	)
Extensions, Additions and Discoveries		207.1			5.1			1.3			245.7
Production		(39.0	)		(0.2	)		(0.7	)		(44.3	)
Purchases in Place (3)		611.1			15.5			3.3			723.9
Sales in Place		—			—			—			—
December 31, 2011		1,170.0			26.0			5.9			1,361.4
Estimated Proved Developed Reserves
December 31, 2009		214.5			2.3			1.3			236.0
December 31, 2010		295.6			4.6			1.5			332.6
December 31, 2011		515.0			10.3			2.4			591.2

(1) Primarily due to the application of revised definitions contained in the SEC’s new rules, particularly the definition of proved oil and natural gas reserves, which now permits the addition of undrilled locations beyond immediate offsets of producing wells that are supported by a determination, with reasonable certainty, of reservoir continuity.

(2) In 2010 and 2011, we had negative revisions of 124.3 Bcfe and 613.0 Bcfe, respectively, which was primarily the result of proved undeveloped reserves being reclassified to non-proved status for adherence with the SEC five year guidance for recording proved reserves.

(3) Attributable to the purchase of oil and gas properties in East Texas as described in Note 4 in the “Notes to Consolidated Financial Statements”.

31

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information was developed utilizing procedures prescribed byASC 932, Disclosures about Oil and Gas Producing Activities. The information is based on estimates prepared by our petroleum engineering staff. The “standardized measure of discounted future net cash flows” should not be viewed as representative of the current value of our proved oil and natural gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

In reviewing the information that follows, we believe that the following factors should be taken into account:

• future costs and sales prices will probably differ from those required to be used in these calculations;

• actual production rates for future periods may vary significantly from the rates assumed in the calculations;

• a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and natural gas revenues.

Under the standardized measure, future cash inflows were estimated by using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve month periods ended December 31,2011, 2010 and 2009. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future developmentand production costs based on year end costs in order to arrive at net cash flows before tax. Use of a 10% discount rate and year-end prices and costs are required by ASC 932.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.

The standardized measure of discounted future net cash flows from our estimated proved oil and natural gas reserves follows:

	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Future cash inflows	$	6,724,283		$	5,807,655		$	3,915,847
Less related future:
Production costs		(2,020,736	)		(1,513,149	)		(1,257,905	)
Development costs		(1,326,857	)		(1,708,651	)		(1,307,147	)
Future net cash inflows		3,376,690			2,585,855			1,350,795
10% annual discount for estimated timing of cash flows (1)		(2,207,421	)		(2,000,181	)		(1,244,380	)
Standardized measure of discounted future net cash flows	$	1,169,269		$	585,674		$	106,415

(1) The negative present value factor is due to the addition of proved undeveloped properties that require a large amount of development costs. Additionally, these costs are weighted heavily in the first five years.

32

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas and crude oil reserves follows:

	For the Year Ended December 31,
	2011			2010			2009
	(in thousands)
Beginning Balance	$	585,674		$	106,415		$	280,427
Revisions of previous estimates
Changes in prices and costs		(41,896	)		296,445			(147,028	)
Changes in quantities		40,535			154,218			1,803
Additions to proved reserves (1)		168,123			40,663			(52,953	)
Purchases of reserves		527,760			10,960			—
Sales of reserves		—			(2,907	)		—
Accretion of discount		58,567			10,642			28,043
Sales of oil and gas, net		(147,481	)		(93,364	)		(52,943	)
Change in estimated future development costs		(102,647	)		(113,582	)		27,954
Previously estimated development costs incurred		88,980			139,109			12,279
Changes in rate of production and other, net		(8,346	)		37,075			8,833
Net change		583,595			479,259			(174,012	)
Ending Balance	$	1,169,269		$	585,674		$	106,415

(1) The negative value of additions in 2009 is attributable to a large number of wells that were proved as a result of the new SEC rules. Consistent with the new SEC rules, the Company only adds proved undeveloped reserves that will be developed within a five year time horizon. As a result, a large amount of future development costs are included in the present value calculation. Additionally, these costs are not discounted as heavily as costs in the later years, thus causing the total present value to be negative.

33

EX-99.6

Exhibit 99.6

	Deloitte & Touche LLP
	Fifth Avenue Place East Tower
	Suite 600, 425 – 1st Street SW
	Calgary, AB T2P 3L8
	Canada
	Tel: 403-648-3200
	Fax: 403-265-0862
	www.deloitte.ca

February 28, 2012

Ramshorn Canada Investments Limited

2800, 500 – 4th Avenue S.W.

Calgary, Alberta

T2P 2V6

Attention: Mr. Mike Reid

Dear Sir:

Re: Ramshorn Canada Investments Limited (RCI)

This is to confirm our Reserve and Resource Estimation and Economic Evaluation effective December 31, 2011 for Ramshorn Canada Investments Limited (RCI) dated January 26, 2012 prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC.

The proved and proved plus probable reserve estimates provided conform to the reserve definitions as set forth in the SEC’s Regulation S-X Part 210.4-10(a) and as clarified in subsequent Commission Staff Accounting Bulletins. We believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the reports.

In accordance with SEC requirements all prices and costs (capital and operating) were held constant. The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in AJM’s individual property evaluations. An oil equivalent conversion factor of 6.0 Mcf per 1.0 barrel oil was used for sales gas.

Yours very truly,

Signed by “Robin G. Bertram

Robin G. Bertram, P.Eng

Financial Advisory

Deloitte & Touche LLP

/sd

XML

Cash and Cash Equivalents and Short-term Investments (Tables)

12 Months Ended

Dec. 31, 2011

Cash and Cash Equivalents and Short term Investments [Abstract]

Cash and cash equivalents and, short-term investments

	December 31,		December 31,
	2011		2010
	(In thousands)
Cash and cash equivalents	$	398,575	$	641,702
Short-term investments:
Trading equity securities		11,600		19,630
Available-for-sale equity securities		71,433		79,698
Available-for-sale debt securities		57,881		60,160
Total short-term investments	$	140,914	$	159,488

Cash and cash equivalents and short-term investments

	December 31,
	2011							2010
	Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses
	(In thousands)
Cash and cash equivalents	$	398,575	$	—	$	—		$	641,702	$	—	$	—
Short-term investments:
Trading equity securities		11,600		5,876		—			19,630		13,906		—
Available-for-sale equity securities		71,433		33,075		—			79,698		38,176		(2,274	)
Available-for-sale debt securities:
Commercial paper and CDs		1,230		—		—			1,275		—		—
Corporate debt securities		51,300		22,494		(2,095	)		52,022		15,274		(18	)
Mortgage-backed debt securities		309		10		—			372		16		—
Mortgage-CMO debt securities		2,547		13		(15	)		3,015		21		(6	)
Asset-backed debt securities		2,495		—		(238	)		3,476		—		(268	)
Total available-for-sale debt securities		57,881		22,517		(2,348	)		60,160		15,311		(292	)
Total available-for-sale securities		129,314		55,592		(2,348	)		139,858		53,487		(2,566	)
Total short-term investments		140,914		61,468		(2,348	)		159,488		67,393		(2,566	)
Total cash, cash equivalents and short-term investments	$	539,489	$	61,468	$	(2,348	)	$	801,190	$	67,393	$	(2,566	)

Gross unrealized losses of cash and cash equivalents and short-term investments

	As of December 31, 2011
	Less Than 12 Months				More Than 12 Months
	Fair Value		Gross Unrealized Loss		Fair Value		Gross Unrealized Loss
	(In thousands)
Available-for-sale equity securities	$	—	$	—	$	—	$	—
Available-for-sale debt securities:(1)
Corporate debt securities		17,700		2,095		—		—
Mortgage-CMO debt securities		2,217		7		83		8
Asset-backed debt securities		—		—		2,494		238
Total available-for-sale debt securities		19,917		2,102		2,577		246
Total	$	19,917	$	2,102	$	2,577	$	246

(1) Our unrealized losses on available-for-sale debt securities held for more than one year are comprised of various types of securities. Each of these securities have a rating ranging from “A” to “AAA” from Standard & Poor’s and ranging from “A2” to “Aaa” from Moody’s Investors Service and is considered of high credit quality. In each case, we do not intend to sell these investments, and it is less likely than not that we will be required to sell them to satisfy our own cash flow and working capital requirements. We believe that we will be able to collect all amounts due according to the contractual terms of each investment and, therefore, do not consider the decline in value of these investments to be other-than-temporary at December 31, 2011.

Estimated fair values of corporate, mortgage-backed, mortgage-CMO and asset-backed debt securities

	Estimated Fair Value
	December 31, 2011
	(In thousands)
Debt securities:
Due in one year or less	$	1,230
Due after one year through five years		—
Due in more than five years		56,651
Total debt securities	$	57,881

Debt and equity securities

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Available-for-sale:
Proceeds from sales and maturities	$	12,672	$	13,062	$	23,411
Realized gains (losses), net		3,036		1,692		(54,311	)(1)

(1) Includes other-than-temporary impairments of $18.7 million related to an equity security and a $35.6 million credit-related impairment to a corporate debt security.

XML

Supplemental Balance Sheet Income Statement and Cash Flow Information (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net
Losses (gains) on sales, retirements and involuntary conversions of long-lived assets	$ (11,155)	$ 6,430	$ 5,927
Acquisition-related costs	151	7,021
Litigation expenses	11,301	6,356	11,474
Foreign currency transaction losses (gains)	5,499	18,100	7,993
Losses (gains) on derivative instruments	(2,159)	119	(1,399)
Losses (gains) on debt retirement, net	58	7,042	(11,197)
Other losses (gains)	819	2,170	(816)
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net	$ 4,514	$ 47,238	$ 11,982

XML

Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2011 States Rigs	Dec. 31, 2010
Nature of Operations (Textual) [Abstract]
Number of actively marketed land drilling rigs	499
Number of states in which oil, gas and geothermal land drilling operations are conducted	48
Minimum company's ownership interest in joint venture		49.00%
Maximum company's ownership interest in oil and gas joint venture		50.00%
Number of rigs actively markets joint venture in Saudi Arabia	9
U.S. [Member]
Nature of Operations [Line Items]
Number of rigs marketing for land well-servicing and workover work	581
Number of platform rigs actively marketed	39
Number of jack-up rigs actively marketed	12
Number of barge rigs actively marketed	4
Number of hydraulic horsepower pressure pumping services in key basins throughout United States and Canada	730,000
Canada [Member]
Nature of Operations [Line Items]
Number of rigs marketing for land well-servicing and workover work	174
Joint Venture in Saudi Arabia [Member]
Nature of Operations [Line Items]
Company's ownership interest in joint venture with Saudi Arabia	51.00%

XML

Earnings (Losses) Per Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings (Losses) Per Share [Abstract]

Earnings (losses) per share computations

	Year Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Net income (loss) (numerator):
Income (loss) from continuing operations, net of tax	$	342,164		$	255,870		$	132,721
Less: net (income) loss attributable to noncontrolling interest		(1,045	)		(85	)		342
Net income (loss) from continuing operations — basic		341,119			255,785			133,063
Add interest expense on assumed conversion of our 0.94% senior exchangeable notes, net of tax(1)		—			—			—
Adjusted net income (loss) attributable to Nabors — diluted	$	341,119		$	255,785		$	133,063
Earnings (losses) per share:
Basic from continuing operations	$	1.19		$	.90		$	.47
Diluted from continuing operations	$	1.17		$	.88		$	.46
Income from discontinued operations, net of tax	$	(97,440	)	$	(161,090	)	$	(218,609	)
Earnings (losses) per share, discontinued operations:
Basic from discontinued operations	$	(.34	)	$	(.57	)	$	(.77	)
Diluted from discontinued operations	$	(.34	)	$	(.55	)	$	(.76	)
Shares (denominator):
Weighted-average number of shares outstanding — basic(2)		287,118			285,145			283,326
Net effect of dilutive stock options, warrants and restricted stock awards based on the if-converted method		5,366			4,851			3,176
Assumed conversion of our 0.94% senior exchangeable notes(1)		—			—			—
Weighted-average number of shares outstanding — diluted		292,484			289,996			286,502

(1) At maturity in May 2011, we redeemed the remaining aggregate principal amount of $1.4 billion of our 0.94% senior exchangeable notes. Prior to maturity, we had purchased $1.4 billion par value of these notes in the open market for cash of $1.2 billion. Diluted earnings (losses) per share for the years ended December 31, 2010 and 2009 exclude any incremental shares that would have been issuable upon exchange of these notes based on a calculation using our stock price. Our stock price did not exceed the threshold during any period for the years ended December 31, 2010 and 2009.

(2) On July 31, 2009, the exchangeable shares of Nabors Exchangeco were exchanged for Nabors’ common shares on a one-for-one basis. Basic shares outstanding includes the following weighted-average number of common shares and restricted stock of Nabors and weighted-average number of exchangeable shares of Nabors Exchangeco, respectively: 287.1 million shares for the year ended December 31, 2011; 285.1 million shares for the year ended December 31, 2010; and 283.3 million shares for the year ended December 31, 2009.

XML

Condensed Consolidating Financial Information (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Condensed Consolidating Statements Of Cash Flows
Net cash provided by operating activities	$ 1,456,487,000	$ 1,106,984,000	$ 1,616,972,000
Cash flows from investing activities:
Purchases of investments	(11,746,000)	(34,147,000)	(32,674,000)
Sales and maturities of investments	39,063,000	34,613,000	57,033,000
Cash paid for acquisition of businesses, net	(55,459,000)	(733,630,000)
Investment in unconsolidated affiliates	(112,262,000)	(40,936,000)	(125,076,000)
Distribution of proceeds from asset sales of unconsolidated affiliates	142,984,000
Capital expenditures	(2,042,617,000)	(930,277,000)	(1,093,435,000)
Proceeds from sales of assets and insurance claims	180,558,000	31,072,000	31,375,000
Net cash used for investing activities	(1,859,479,000)	(1,673,305,000)	(1,162,777,000)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts	6,375,000	(6,298,000)	(18,157,000)
Proceeds from long-term debt	697,578,000	696,948,000	1,124,978,000
Debt issuance costs	(7,141,000)	(8,934,000)	(8,832,000)
Payments for (proceeds from) hedge transactions		(5,667,000)
Proceeds from revolving credit facilities	1,560,000,000	600,000,000
Proceeds from issuance of common shares	11,605,000	8,201,000	11,249,000
Reduction in long-term debt	(1,404,281,000)	(398,514,000)	(1,081,801,000)
Reduction in revolving credit facilities	(700,000,000)	(600,000,000)
Repurchase of equity component of convertible debt	(12,000)	(4,712,000)	(6,586,000)
Settlement of call options and warrants, net	0	1,134,000
Purchase of restricted stock	(2,626,000)	(1,935,000)	(1,515,000)
Tax benefit related to share-based awards	1,747,000	31,000	37,000
Net cash provided by (used for) financing activities	163,245,000	280,254,000	19,373,000
Effect of exchange rate changes on cash and cash equivalents	(3,380,000)	(46,000)	12,160,000
Net increase (decrease) in cash and cash equivalents	(243,127,000)	(286,113,000)	485,728,000
Cash and cash equivalents, beginning of period	641,702,000	927,815,000	442,087,000
Cash and cash equivalents, end of period	398,575,000	641,702,000	927,815,000
Nabors (Parent/Guarantor) [Member]
Condensed Consolidating Statements Of Cash Flows
Net cash provided by operating activities	6,614,000	115,179,000	40,589,000
Cash flows from investing activities:
Cash paid for investments in consolidated affiliates	(26,235,000)	(122,300,000)	(46,912,000)
Net cash used for investing activities	(26,235,000)	(122,300,000)	(46,912,000)
Cash flows from financing activities:
Proceeds from issuance of common shares	11,605,000	8,201,000	11,249,000
Purchase of restricted stock	(2,626,000)	(1,935,000)	(1,515,000)
Net cash provided by (used for) financing activities	8,979,000	6,266,000	9,734,000
Effect of exchange rate changes on cash and cash equivalents	0
Net increase (decrease) in cash and cash equivalents	(10,644,000)	(855,000)	3,411,000
Cash and cash equivalents, beginning of period	10,847,000	11,702,000	8,291,000
Cash and cash equivalents, end of period	203,000	10,847,000	11,702,000
Nabors Delaware (Issuer/Guarantor) [Member]
Condensed Consolidating Statements Of Cash Flows
Net cash provided by operating activities	(31,178,000)	757,345,000	646,645,000
Cash flows from investing activities:
Cash paid for investments in consolidated affiliates	(65,000,000)	(1,027,134,000)	(900,000,000)
Net cash used for investing activities	(65,000,000)	(1,027,134,000)	(900,000,000)
Cash flows from financing activities:
Proceeds from long-term debt	697,578,000	696,948,000	1,124,978,000
Debt issuance costs	(7,141,000)	(8,934,000)	(8,832,000)
Payments for (proceeds from) hedge transactions		(5,667,000)
Proceeds from revolving credit facilities	1,510,000,000	600,000,000
Reduction in long-term debt	(1,404,246,000)	(274,095,000)	(856,203,000)
Reduction in revolving credit facilities	(700,000,000)	(600,000,000)
Repurchase of equity component of convertible debt	(12,000)	(4,712,000)	(6,586,000)
Settlement of call options and warrants, net		1,134,000
Cash dividends paid		(135,000,000)
Net cash provided by (used for) financing activities	96,179,000	269,674,000	253,394,000
Effect of exchange rate changes on cash and cash equivalents	0
Net increase (decrease) in cash and cash equivalents	1,000	(115,000)	39,000
Cash and cash equivalents, beginning of period	20,000	135,000	96,000
Cash and cash equivalents, end of period	21,000	20,000	135,000
Nabors Holdings (Issuer) [Member]
Condensed Consolidating Statements Of Cash Flows
Net cash provided by operating activities	0	0	608,000
Cash flows from investing activities:
Proceeds from sale of consolidated affiliates			239,421,000
Net cash used for investing activities	0	0	239,421,000
Cash flows from financing activities:
Intercompany debt			143,859,000
Reduction in long-term debt		0	(225,191,000)
Cash dividends paid		0	(159,956,000)
Net cash provided by (used for) financing activities	0	0	(241,288,000)
Net increase (decrease) in cash and cash equivalents	0	0	(1,259,000)
Cash and cash equivalents, beginning of period	0	0	1,259,000
Cash and cash equivalents, end of period	0	0	0
Other Subsidiaries (Non-Guarantors) [Member]
Condensed Consolidating Statements Of Cash Flows
Net cash provided by operating activities	1,479,357,000	504,460,000	1,089,086,000
Cash flows from investing activities:
Purchases of investments	(11,746,000)	(34,147,000)	(32,674,000)
Sales and maturities of investments	39,063,000	34,613,000	57,033,000
Cash paid for acquisition of businesses, net	(55,459,000)	(733,630,000)
Investment in unconsolidated affiliates	(112,262,000)	(40,936,000)	(125,076,000)
Distribution of proceeds from asset sales of unconsolidated affiliates	142,984,000
Capital expenditures	(2,039,921,000)	(930,277,000)	(1,093,435,000)
Proceeds from sales of assets and insurance claims	179,558,000	31,072,000	31,375,000
Proceeds from sale of consolidated affiliates			(239,421,000)
Net cash used for investing activities	(1,857,783,000)	1,673,305,000	(1,402,198,000)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts	6,375,000	(6,298,000)	(18,157,000)
Proceeds from revolving credit facilities	50,000,000
Intercompany debt			(143,859,000)
Reduction in long-term debt	(35,000)	(124,419,000)	(407,000)
Tax benefit related to share-based awards	1,747,000	31,000
Cash dividends paid		(135,000,000)
Proceeds from parent contributions	91,235,000	1,149,434,000	946,912,000
Net cash provided by (used for) financing activities	149,322,000	883,748,000	784,489,000
Effect of exchange rate changes on cash and cash equivalents	(3,380,000)	(46,000)	12,160,000
Net increase (decrease) in cash and cash equivalents	(232,484,000)	(285,143,000)	483,537,000
Cash and cash equivalents, beginning of period	630,835,000	915,978,000	432,441,000
Cash and cash equivalents, end of period	398,351,000	630,835,000	915,978,000
Consolidating Adjustments [Member]
Condensed Consolidating Statements Of Cash Flows
Net cash provided by operating activities	0	(270,000,000)	(159,956,000)
Cash flows from investing activities:
Cash paid for investments in consolidated affiliates	91,235,000	1,149,434,000	946,912,000
Net cash used for investing activities	91,235,000	1,149,434,000	946,912,000
Cash flows from financing activities:
Cash dividends paid		270,000,000	159,956,000
Proceeds from parent contributions	(91,235,000)	(1,149,434,000)	(946,912,000)
Net cash provided by (used for) financing activities	(91,235,000)	(879,434,000)	(786,956,000)
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$ 0	$ 0	$ 0

XML

Cash and Cash Equivalents and Short-term Investments (Details Textual) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Available-for-sale Securities [Line Items]
Other-than-temporary impairment on equity security	$ 198,072	$ 61,292	$ 118,543
Cash and Cash Equivalents and Investments (Textual) [Abstract]
Credit related impairment on debt securities			35,649
Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Other-than-temporary impairment on equity security	$ 18,700

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Consolidated Subsidiary [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved	$ 688,787	$ 599,978
Property acquisition costs, unproved	218,128	227,584
Total acquisition costs	906,915	827,562
Accumulated depreciation and depletion	(568,959)	(474,456)
Net capitalized costs for consolidated subsidiaries	337,956	353,106
Equity Companies [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved	1,141,393	926,368
Property acquisition costs, unproved	103,657	138,308
Total acquisition costs	1,245,050	1,064,676
Accumulated depreciation and depletion	(512,503)	(564,785)
Net capitalized costs for consolidated subsidiaries	732,547	499,891
U.S. [Member] | Consolidated Subsidiary [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved	587,385	480,618
Property acquisition costs, unproved	101,611	136,625
Total acquisition costs	688,996	617,243
Accumulated depreciation and depletion	(539,380)	(463,330)
Net capitalized costs for consolidated subsidiaries	149,616	153,913
U.S. [Member] | Equity Companies [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved	1,141,393	749,515
Property acquisition costs, unproved	103,657	108,541
Total acquisition costs	1,245,050	858,056
Accumulated depreciation and depletion	(512,503)	(460,622)
Net capitalized costs for consolidated subsidiaries	732,547	397,434
Canada [Member] | Consolidated Subsidiary [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved	101,402	62,109
Property acquisition costs, unproved	92,750	89,785
Total acquisition costs	194,152	151,894
Accumulated depreciation and depletion	(28,838)	(7,344)
Net capitalized costs for consolidated subsidiaries	165,314	144,550
Canada [Member] | Equity Companies [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved	0	78,224
Property acquisition costs, unproved	0	28,884
Total acquisition costs	0	107,108
Accumulated depreciation and depletion	0	(72,338)
Net capitalized costs for consolidated subsidiaries	0	34,770
Colombia [Member] | Consolidated Subsidiary [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved		57,251
Property acquisition costs, unproved	23,767	1,174
Total acquisition costs	23,767	58,425
Accumulated depreciation and depletion	(741)	(3,782)
Net capitalized costs for consolidated subsidiaries	23,026	54,643
Colombia [Member] | Equity Companies [Member]
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Property acquisition costs, proved	0	98,629
Property acquisition costs, unproved	0	883
Total acquisition costs	0	99,512
Accumulated depreciation and depletion	0	(31,825)
Net capitalized costs for consolidated subsidiaries	$ 0	$ 67,687

XML

Summary of Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Inventory
Raw materials	$ 133,480	$ 81,308
Work-in-progress	50,951	23,629
Finished goods	88,421	53,899
Total	$ 272,852	$ 158,836

XML

Share Based Compensation (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011 Y	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation expense	$ 21,200,000	$ 13,700,000	$ 106,700,000
Previously Unrecognized Compensation Expense Related to Restricted Stock and Stock Option Granted	21,244,000	13,746,000	106,725,000
Option to purchase common stock available for grant	15,500,000	17,300,000
Total Future Compensation expected to vest, Unvested Options	4,000,000
Weighted Average Period for Cost recognition	2
Share Based Compensation (Textual) [Abstract]
Tax benefit realized from share based awards	200,000	100,000	300,000
Options outstanding exercisable at weighted average	24,939,000	24,900,000	27,200,000
Weighted average exercise prices of options outstanding	$ 19.83	$ 20.19	$ 21.04
Granted, Shares	931,000	32,115	10,015,883
Aggregate value of restricted stock awards at date of grant	30,000,000	11,900,000
Total intrinsic value of stock option exercised	18,300,000	6,900,000	19,700,000
Total fair value of option vested during the period	5,200,000	5,600,000	10,800,000
Stock option plan expiration period	More than 10 years
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares	3 to 5 years
Restricted Stock Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation expense	13,400,000	10,500,000	88,900,000
Fair value of Restricted Stock Awarded to Employees and Directors that vested	21,400,000	26,700,000	23,900,000
Option to purchase common stock available for grant	15,500,000
Total Future Compensation expected to vest, Unvested Options	28,900,000
Vesting period of shares	3 to 5 Years
Previously Unrecognized [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Previously Unrecognized Compensation Expense Related to Restricted Stock and Stock Option Granted			$ 72,100,000
Restricted stock awards granted to directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of shares	Up to 4 years
Employees and Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock Awarded to Employees and Directors	1,096,379	538,496
Unvested Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Period for Cost recognition	2

XML

Commitments and Contingencies (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Minimum pipeline commitments under transportation
2012	$ 54,287
2013	68,056
2014	66,373
2015	64,845
2016	48,330
Thereafter	86,808
Total	$ 388,699

XML

Pension Postretirement and Postemployment Benefits (Tables)

12 Months Ended

Dec. 31, 2011

Pension, Postretirement and Postemployment Benefits [Abstract]

Pool pension plan

	Pension Benefits
	2011			2010
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	20,628		$	18,865
Remeasurement		1,517			—
Interest cost		1,198			1,116
Actuarial loss (gain)		3,975			1,289
Benefit payments		(659	)		(642	)
Benefit obligation at end of year(1)	$	26,659		$	20,628
Change in plan assets:
Fair value of plan assets at beginning of year	$	15,219		$	14,058
Actual (loss) return on plan assets		480			1,364
Employer contribution		1,312			439
Benefit payments		(659	)		(642	)
Fair value of plan assets at end of year	$	16,352		$	15,219
Funded status:
Underfunded status at end of year	$	(10,307	)	$	(5,409	)
Amounts recognized in consolidated balance sheets:
Other long-term liabilities	$	(10,307	)	$	(5,409	)

	Year Ended December 31,
	2011			2010			2009
Components of net periodic benefit cost (recognized in our consolidated statements of income):
Interest cost	$	1,198		$	1,116		$	1,093
Expected return on plan assets		(1,008	)		(909	)		(794	)
Recognized net actuarial loss		628			457			545
Net periodic benefit cost	$	818		$	664		$	844
Weighted-average assumptions:
Weighted-average discount rate		4.25	%		5.50	%		6.00	%
Expected long-term rate of return on plan assets		6.50	%		6.50	%		6.50	%

(1) As of December 31, 2011 and 2010, the accumulated benefit obligation was the same as the projected benefit obligation.

Investments within the fair value of Pool Pension Plan

	Fair Value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:(1)
Cash	$	—	$	396	$	—	$	396
Short-term investments:
Available-for-sale equity securities(2)		—		9,166		—		9,166
Available-for-sale debt securities(3)		—		6,790		—		6,790
Total investments		—		15,956		—		15,956
Total	$	—	$	16,352	$	—	$	16,352

(1) Includes investments in collective trust funds that are valued based on the fair value of the underlying investments using quoted prices in active markets or other significant inputs that are deemed observable.

(2) Includes funds that invest primarily in U.S. common stocks and foreign equity securities.

(3) Includes funds that invest primarily in investment grade debt.

Weighted-average asset allocations of Pool Pension Plan

	Pension Benefits
	2011			2010
Cash		2	%		2	%
Equity securities		56	%		56	%
Debt securities		42	%		42	%
Total		100	%		100	%

Benefits paid for five years thereafter

	(In thousands)
2012	$	791
2013		890
2014		1,004
2015		1,117
2016		1,193
2017 — 2021		7,428

XML

Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts [Abstract]

VALUATION AND QUALIFYING ACCOUNTS

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2011, 2010 and 2009

	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
	(In thousands)
2011
Allowance for doubtful accounts	$	22,507	$	5,352		$	(29	)	$	13,873		$	41,703
Inventory reserve		6,784		(1,185	)		1,889			(504	)		6,984
Valuation allowance on deferred tax assets		1,514,153		—			—			(28,613	)		1,485,540
2010
Allowance for doubtful accounts	$	23,681	$	1,545		$	167		$	(2,886	)	$	22,507
Inventory reserve		4,824		(182	)		1,695			447			6,784
Valuation allowance on deferred tax assets		1,570,890		—			—			(56,737	)		1,514,153
2009
Allowance for doubtful accounts	$	23,224	$	5,793		$	239		$	(5,575	)	$	23,681
Inventory reserve		4,483		1,429			—			(1,088	)		4,824
Valuation allowance on deferred tax assets		132,262		1,438,628			—			—			1,570,890

XML

Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Property, Plant and Equipment, Net [Abstract]
Land	$ 22,120	$ 12,087
Buildings	132,753	122,635
Drilling, workover and well-servicing rigs, and related equipment	11,150,927	10,632,968
Marine transportation and supply vessels	14,023	13,663
Oilfield hauling and mobile equipment	1,171,930	551,892
Other machinery and equipment	248,938	143,976
Oil and gas properties	42,033	664,289
Construction in process	815,987	349,455
Property, plant and equipment, gross	13,598,711	12,490,965
Less: accumulated depreciation and amortization	(4,928,781)	(4,182,122)
Less: accumulated depletion on oil and gas properties	(39,984)	(493,424)
Property, plant and equipment, net	$ 8,629,946	$ 7,815,419	$ 7,646,050

XML

Segment Information (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011 Segment	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Equity in (earnings) losses of unconsolidated affiliates, net of dividends	$ 132,388,000	$ 13,630,000	$ (229,813,000)
Investments in unconsolidated affiliates accounted for using equity method	371,000,000	265,800,000
Segment Information (Textual) [Abstract]
Investments in unconsolidated affiliates accounted for using cost method		1,900,000	900,000
Number of operating segments	10
Number of reportable segments	6
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Equity in (earnings) losses of unconsolidated affiliates, net of dividends	59,700,000	18,700,000	(182,600,000)
Proportionate share, net from oil and gas	(15,600,000)		(189,300,000)
Investments in unconsolidated affiliates accounted for using equity method	294,100,000	146,500,000	190,100,000
Subtotal Contract Drilling [Member]
Segment Reporting Information [Line Items]
Equity in (earnings) losses of unconsolidated affiliates, net of dividends	(1,200,000)	6,900,000	9,700,000
Investments in unconsolidated affiliates accounted for using equity method	51,500,000	54,800,000	49,800,000
Other Operating Segments [Member]
Segment Reporting Information [Line Items]
Equity in (earnings) losses of unconsolidated affiliates, net of dividends	(1,900,000)	7,700,000	17,500,000
Investments in unconsolidated affiliates accounted for using equity method	$ 25,400,000	$ 64,500,000	$ 65,800,000

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details 4) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Standardized Measure of Discounted Future Cash Flows
Discounted future net cash flows	$ 650,376	$ 623,570
Consolidated Subsidiary [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	246,047	1,642,300
Future production costs	(72,209)	(570,643)
Future development costs	(47,112)	(168,885)
Future income tax expense	0	(268,774)
Future net cash inflows	126,726	633,998
Effect of discounting net cash flows at 10%	(58,413)	(365,534)
Discounted future net cash flows	68,313	268,464
Equity Companies [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	3,347,348	3,045,431
Future production costs	(1,005,922)	(816,092)
Future development costs	(660,509)	(863,352)
Future income tax expense	0
Future net cash inflows	1,680,917	1,365,987
Effect of discounting net cash flows at 10%	(1,098,854)	(1,010,881)
Discounted future net cash flows	582,063	355,106
U.S. [Member]
Standardized Measure of Discounted Future Cash Flows
Discounted future net cash flows	639,365	504,514
U.S. [Member] | Consolidated Subsidiary [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	225,141	1,468,944
Future production costs	(66,448)	(481,487)
Future development costs	(45,045)	(152,309)
Future income tax expense	0	(268,774)
Future net cash inflows	113,188	566,374
Effect of discounting net cash flows at 10%	(55,886)	(353,232)
Discounted future net cash flows	57,302	213,142
U.S. [Member] | Equity Companies [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	3,347,348	2,889,308
Future production costs	(1,005,922)	(752,792)
Future development costs	(660,509)	(850,053)
Future income tax expense	0
Future net cash inflows	1,680,917	1,286,463
Effect of discounting net cash flows at 10%	(1,098,854)	(995,091)
Discounted future net cash flows	582,063	291,372
Canada [Member]
Standardized Measure of Discounted Future Cash Flows
Discounted future net cash flows	11,011	14,210
Canada [Member] | Consolidated Subsidiary [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	20,906	16,435
Future production costs	(5,761)	(5,600)
Future development costs	(1,607)	(360)
Future net cash inflows	13,538	10,475
Effect of discounting net cash flows at 10%	(2,527)	(2,046)
Discounted future net cash flows	11,011	8,429
Canada [Member] | Equity Companies [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	0	14,713
Future production costs	0	(6,463)
Future development costs	0	(992)
Future income tax expense	0
Future net cash inflows	0	7,258
Effect of discounting net cash flows at 10%	0	(1,477)
Discounted future net cash flows	0	5,781
Colombia [Member]
Standardized Measure of Discounted Future Cash Flows
Discounted future net cash flows	0	104,846
Colombia [Member] | Consolidated Subsidiary [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	0	156,921
Future production costs	0	(83,556)
Future development costs	0	(16,216)
Future net cash inflows	0	57,149
Effect of discounting net cash flows at 10%	0	(10,256)
Discounted future net cash flows	0	46,893
Colombia [Member] | Equity Companies [Member]
Standardized Measure of Discounted Future Cash Flows
Future cash flows from sales of oil and gas	0	141,410
Future production costs	0	(56,837)
Future development costs	0	(12,307)
Future income tax expense	0
Future net cash inflows	0	72,266
Effect of discounting net cash flows at 10%	0	(14,313)
Discounted future net cash flows	$ 0	$ 57,953

XML

Fair Value Measurements (Details Textual) (USD $)	Dec. 31, 2011	Dec. 31, 2010
Fair Value Measurement (Textual) [Abstract]
Unamortized loss on interest rate swap	$ 300,000	$ 700,000
Securities available-for-sale	129,314,000	139,858,000
Trading equity securities, fair value	11,600,000	19,630,000
Fair Value of long-term equity method investments	$ 5,900,000	$ 7,400,000
5.375% Senior Notes Due August 2012 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due	5.375%
6.15% Senior Notes Due February 2018 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due	6.15%
9.25% Senior Notes Due January 2019 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due	9.25%
5.00% senior notes due September 2020 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due	5.00%
4.625% senior notes due September 2021 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due	4.625%

XML

Income Taxes (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
United States and Other Jurisdictions:
United States	$ 178,270	$ (82,723)	$ (505,264)
Other jurisdictions	309,499	376,293	574,048
Income (loss) from continuing operations before income tax	$ 487,769	$ 293,570	$ 68,784

XML

Summary of Significant Accounting Policies (Details Textual) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of Significant Accounting Policies (Textual) [Abstract]
Investments in unconsolidated affiliates accounted for using equity method	$ 371.0	$ 265.8
Investments in unconsolidated affiliates accounted for using cost method		1.9	0.9
Assets held for sale include investments in unconsolidated affiliates accounted for using the equity method	13.7	79.5
Fair Value of Equity Security investment	5.9	7.4
Impairment charges of oil and gas related assets		192.2
Capitalized cost discounted of unproved properties	10.00%
Impairment charges for unconsolidated oil and gas joint ventures	15.6		237.1
Equity Interest acquired	50.00%
Percentage in excess of fair value over carrying value	20.00%
Goodwill for the consolidated company, expected to be deductible for tax purposes	$ 12.9
Deferral of disclosure requirements provided by FASB regarding change to definition of oil and gas activities	1
Other Rigs [Member]
Property, Plant and Equipment [Line Items]
Operating rig asset depreciable life, operating days	4,900
Non-operating rig asset depreciable life	20
Jack Up Rigs [Member]
Property, Plant and Equipment [Line Items]
Operating rig asset depreciable life, operating days	8,030
Non-operating rig asset depreciable life	30
Building [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life, Minimum	10
Estimated useful life, Maximum	30
Well Servicing Rigs [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life, Minimum	3
Estimated useful life, Maximum	15
Marine transportation and supply vessels [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life, Minimum	10
Estimated useful life, Maximum	25
Oilfield Hauling and Mobile Equipment and Other Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life, Minimum	3
Estimated useful life, Maximum	10

XML

Earnings (Losses) Per Share (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings (Losses) Per Share (Textual) [Abstract]
0.94% senior exchangeable notes due 2011, par value outstanding	$ 275,326,000	$ 1,379,018,000
Average number of options and warrants excluded from diluted earnings (losses) per share	9,241,543	14,004,749	34,113,887
Mode of exchange of exchangeable shares of Nabors Exchangeco for Nabors common shares	one-for-one basis
Weighted-average number of common shares and restricted stock of Nabors included in Weighted-average number of shares outstanding basic	287,100,000	285,100,000	283,300,000
0.94% Senior Exchangeable Notes Due May 2011 [Member]
Earnings (Losses) Per Share (Textual) [Abstract]
Principal redeemed senior exchangeable notes	1,400,000,000
Interest rate on senior notes due	0.94%
Purchase amount of 0.94% senior exchangeable notes due 2011	1,200,000,000
0.94% senior exchangeable notes due 2011, par value outstanding	$ 1,400,000,000

XML

Share Based Compensation (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Unvested stock options
Options outstanding, Beginning Balance, Shares	28,932,000
Granted, Outstanding	931,000	32,115	10,015,883
Granted, Weighted-Average Grant-Date Fair Value	$ 6.24	$ 6.62	$ 0.0285
Forfeited, Shares	(459,000)
Options outstanding, Ending Balance, Shares	27,870,000	28,932,000
Unvested Stock Options [Member]
Unvested stock options
Options outstanding, Beginning Balance, Shares	3,941,000
Unvested Options, Weighted-Average Grant-Date Fair Value, Beginning Balance	$ 3.88	$ 2.81
Granted, Outstanding	931,000
Granted, Weighted-Average Grant-Date Fair Value	$ 6.24
Vested, Outstanding	(1,800,000)
Vested, Weighted-Average Grant-Date Fair Value	$ 2.87
Forfeited, Shares	(172,000)
Forfeited, Weighted-Average Grant-Date Fair Value	$ 2.73
Options outstanding, Ending Balance, Shares	2,900,000	3,941,000
Unvested Options, Weighted-Average Grant-Date Fair Value, Ending Balance	$ 3.88	$ 2.81

XML

Debt (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Short-Term Borrowings
Credit available	$ 215,901	$ 270,263
Letters of credit outstanding, inclusive of financial and performance guarantees	(80,408)	(70,605)
Remaining availability	$ 135,493	$ 199,658

XML

Investments in Unconsolidated Affiliates (Deatils) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investments in Unconsolidated Affiliates
Current assets	$ 311,972				$ 322,086				$ 311,972	$ 322,086
Long-term assets	1,728,399				1,332,212				1,728,399	1,332,212
Current liabilities	275,171				345,279				275,171	345,279
Long-term liabilities	800,444				460,198				800,444	460,198
Gross revenues									832,774	901,742	960,823
Gross margin									278,019	241,831	223,005
Net income (loss)									270,161	48,426	(462,613)
Nabors' earnings (losses) from our U.S. oil and gas joint venture	$ (2,700)	$ 33,700	$ 9,300	$ 16,300	$ 4,900	$ 11,800	$ 8,900	$ 7,700	$ 56,647	$ 33,267	$ (155,432)

XML

Debt (Details Textual) (USD $)	12 Months Ended								12 Months Ended								12 Months Ended						12 Months Ended					12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2011 CreditFacility	Dec. 31, 2010	Dec. 31, 2009	Aug. 23, 2011	Jul. 22, 2008	Dec. 31, 2011 Nabors Delaware (Issuer/Guarantor) [Member]	Dec. 31, 2010 Nabors Delaware (Issuer/Guarantor) [Member]	Dec. 31, 2011 Consolidated Subsidiary [Member]	Dec. 31, 2011 0.94% Senior Exchangeable Notes Due May 2011 [Member]	Dec. 31, 2010 0.94% Senior Exchangeable Notes Due May 2011 [Member]	Dec. 31, 2009 0.94% Senior Exchangeable Notes Due May 2011 [Member]	Dec. 31, 2011 6.15% Senior Notes Due February 2018 [Member]	Dec. 31, 2010 6.15% Senior Notes Due February 2018 [Member]	Aug. 20, 2008 6.15% Senior Notes Due February 2018 [Member]	Jul. 22, 2008 6.15% Senior Notes Due February 2018 [Member]	Feb. 20, 2008 6.15% Senior Notes Due February 2018 [Member]	Dec. 31, 2011 9.25% Senior Notes Due January 2019 [Member]	Dec. 31, 2010 9.25% Senior Notes Due January 2019 [Member]	Jan. 12, 2009 9.25% Senior Notes Due January 2019 [Member]	Dec. 31, 2011 5.375% Senior Notes Due August 2012 [Member]	Dec. 31, 2010 5.375% Senior Notes Due August 2012 [Member]	Aug. 22, 2002 5.375% Senior Notes Due August 2012 [Member]	Dec. 31, 2010 5.00% senior notes due September 2020 [Member]	Dec. 31, 2011 5.00% senior notes due September 2020 [Member]	Sep. 14, 2010 5.00% senior notes due September 2020 [Member]	Dec. 31, 2011 4.625% senior notes due September 2021 [Member]	Dec. 31, 2010 4.625% senior notes due September 2021 [Member]	Dec. 31, 2011 Revolving Credit Facilities [Member]	Dec. 31, 2010 Revolving Credit Facilities [Member]	Aug. 31, 2009 4.875% senior notes due August 2009 [Member]	Dec. 31, 2011 4.875% senior notes due August 2009 [Member]	Dec. 31, 2011 Federal Rate [Member]	Dec. 31, 2011 Libor Rate [Member]
Debt Instrument [Line Items]
Interest rate on senior note due									0.94%			6.15%					9.25%			5.375%				5.00%		4.625%					4.875%
Current portion of long-term debt	$ 275,326,000	$ 1,379,018,000				$ 274,604,000	$ 1,378,178,000		$ 1,400,000,000											$ 274,600,000
Aggregate amount of senior notes					400,000,000										975,000,000	575,000,000			1,125,000,000			275,000,000			700,000,000						225,000,000
Issuance of notes																															56,600,000
Description of Senior notes redemption price																	purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture
Total notional amount of treasury rate lock derivative to hedge the risk of changes in interest payments																							500,000,000
Cash paid upon settlement of cash flow hedge due to change in fair value of derivatives																							5,700,000
Gains on debt retirement, net	(58,000)	(7,042,000)	11,197,000						(100,000)	(7,000,000)	11,500,000
Aggregate principal amount of private placement				700,000,000								967,490,000	966,276,000				1,125,000,000	1,125,000,000		274,604,000	273,977,000		697,037,000	697,343,000		697,667,000	0
Aggregate principal amount of senior notes									1,400,000,000					975,000,000
Borrowings under revolving credit facilities																												1,200,000,000
Weighted average interest rate on revolving credit facilities																												1.80%
Increase in aggregate principal amount of commitments																												200,000,000
Unsecured revolving credit facility	215,901,000	270,263,000																										1,400,000,000
Unsecured revolving credit facility borrowing capacity	135,493,000	199,658,000																										540,000,000
Revolving Credit facility Interest Rate Description	Borrowings under the senior unsecured revolving credit facilities bear interest, at Nabor’s option, for 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.
Revolving Credit facility Base Rate Description	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 the administrative agent, as established from time to time and (iii) LIBOR for an interest period of one month beginning on such day plus 1%
Letters of credit outstanding, inclusive of financial and performance guarantees	(80,408,000)	(70,605,000)				1,350,000,000		50,000,000																				860,000,000	0
Debt instrument basis spread on variable																																0.50%	1.00%
Payments for repurchase of notes																														$ 168,400,000	$ 56,800,000
Debt (Textual) [Abstract]
Maturity period of revolving credit facility	September, 2014
Purchase price of notes	equal to 101% of their principal amount,plus accrued and unpaid interest, if any
Frequency of interest payments	semi-annually
Number of letter of credit facilities	6

XML

Share Based Compensation (Details 3) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2010
Unvested restricted stock
Restricted Stock Granted, Outstanding	1,096
Restricted Stock Granted, Weighted-Average Grant-Date Fair Value	$ 27.32
Restricted Stock Vested, Outstanding	(1,400)
Restricted Stock Vested Weighted-Average Grant-Date Fair Value	$ 17.43
Restricted Forfeited, Outstanding	(85)
Restricted stock, Forfeited, Weighted-Average Grant-Date Fair Value	$ 28.11
Restricted Stock Unvested, Outstanding, Beginning Balance	1,945	1,556
Restricted Stock Unvested, Weighted-Average Grant-Date Fair Value, Ending Balance	$ 26.07		$ 19.23

XML

Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2008
Available for sale debt securities:
Trading securities - energy industry	$ 11,600	$ 19,630
Total short-term investments			46,000
Recurring [Member]
Short term investments:
Available-for-sale equity securities - energy industry	71,433
Available for sale debt securities:
Commercial paper and CDs	1,230
Corporate debt securities	51,300
Mortgage-backed debt securities	309
Mortgage-CMO debt securities	2,547
Asset-backed debt securities	2,495
Trading securities - energy industry	11,600
Total short-term investments	140,914
Liabilities:
Derivative contract	1,281
Recurring [Member] | Level 1 [Member]
Short term investments:
Available-for-sale equity securities - energy industry	60,923
Available for sale debt securities:
Commercial paper and CDs	1,230
Corporate debt securities	0
Mortgage-backed debt securities	0
Mortgage-CMO debt securities	0
Asset-backed debt securities	2,495
Trading securities - energy industry	11,600
Total short-term investments	76,248
Liabilities:
Derivative contract	0
Recurring [Member] | Level 2 [Member]
Short term investments:
Available-for-sale equity securities - energy industry	10,510
Available for sale debt securities:
Commercial paper and CDs	0
Corporate debt securities	51,300
Mortgage-backed debt securities	309
Mortgage-CMO debt securities	2,547
Asset-backed debt securities	0
Trading securities - energy industry	0
Total short-term investments	64,666
Liabilities:
Derivative contract	1,281
Recurring [Member] | Level 3 [Member]
Short term investments:
Available-for-sale equity securities - energy industry	0
Available for sale debt securities:
Commercial paper and CDs	0
Corporate debt securities	0
Mortgage-backed debt securities	0
Mortgage-CMO debt securities	0
Asset-backed debt securities	0
Trading securities - energy industry	0
Total short-term investments	0
Liabilities:
Derivative contract	$ 0

XML

Related- Party Transactions

12 Months Ended

Dec. 31, 2011

Related-Party Transactions [Abstract]

Related-Party Transactions

Note 17    Related-Party Transactions

The Company and Nabors Delaware entered into an agreement with Eugene M. Isenberg, the Chairman of our Board of Directors, on February 2, 2012 but effective December 31, 2011, pursuant to which:

• Mr. Isenberg voluntarily terminated both his employment with the Company and his Employment Agreement, and forwent any right to payment in connection with such termination, including a possible payment of $100 million in connection with the Company’s appointment of a new chief executive officer on October 28, 2011, which Mr. Isenberg could have treated as a constructive termination under his employment agreement;

• Mr. Isenberg will continue as Chairman of the Board, but will not stand for reelection as a director when his term expires in June 2012; at that time, he will be appointed Chairman Emeritus for a three-year term, which will be extended for additional one-year terms unless terminated by him or by the Company, and receive cash compensation equal to other nonemployee directors;

• Nabors Delaware will pay $6,600,000 into an escrow account, which will bear interest at the guaranteed rate of 6% per annum compounded daily and will be distributed either to Mr. Isenberg’s estate or to the trustees of his revocable trust;

• Mr. Isenberg ceases participation in the Company’s benefit plans and forfeits any benefits available to him thereunder (including forfeiture of the balance in his deferred bonus account), except as stated below or otherwise required by law:

• he and his spouse continue to participate in medical, dental and life insurance coverage until either receives equivalent coverage and benefits under the plans and programs of a subsequent employer or their death;

• he remains entitled to distribution of vested account balances in the Company’s 401(k) plan and its Deferred Compensation Plan;

• he retains certain benefits under the split-dollar life insurance agreements in effect between him and Nabors Delaware

• all of Mr. Isenberg’s stock option and restricted stock awards were already fully vested and remain subject to the applicable plans and agreements governing them; and

• Mr. Isenberg waives all claims or other liabilities related to his Employment Agreement or his termination of employment, and the Company waives certain claims against Mr. Isenberg.

Nabors and certain key employees, including Messrs. Isenberg and Petrello, entered into split-dollar life insurance agreements, pursuant to which we pay a portion of the premiums under life insurance policies with respect to these individuals and, in some instances, members of their families. These agreements provide that we are reimbursed for the premium payments upon the occurrence of specified events, including the death of an insured individual. We will not be reimbursed for the premium payments paid on behalf of Mr. Isenberg as provided by the agreement entered into on February 2, 2012. 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 $6.3 million related to these policies. The cash surrender value of these policies of approximately $5.8 million and $9.5 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2011 and 2010, respectively.

Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors under the agreements with Messrs. Isenberg and Petrello 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 $218.4 million, $271.6 million and $327.3 million for the years ended December 31, 2011, 2010 and 2009, respectively. Expenses from business transactions with these affiliated entities totaled $.9 million, $3.4 million and $9.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. Additionally, we had accounts receivable from these affiliated entities of $110.7 million and $97.8 million as of December 31, 2011 and 2010, respectively. We had accounts payable to these affiliated entities of $46.1 million and $12.7 million as of December 31, 2011 and 2010, respectively, and long-term payables with these affiliated entities of $.8 million as of each of December 31, 2011 and 2010, which are 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 2011 and 2010, we recognized $2.0 million and $1.4 million, respectively, 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 first quarter of 2010, we purchased shares of Shona’s preferred stock and warrants to purchase additional common shares for $.9 million, which we had accounted for under the cost method of accounting. During 2011, Shona became a public company in Canada, with voting common shares listed on the TSX Venture Exchange. As of December 31, 2011, we held a minority interest of approximately 7.55% of the issued and outstanding common shares of Shona. The fair value of this equity security investment is $10.5 million.

XML

Unaudited Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Unaudited Quarterly Financial Information [Abstract]

Unaudited Quarterly Financial Information

	Year Ended December 31, 2011
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(1)	$	1,389,842		$	1,352,950		$	1,642,227		$	1,731,979
Income (loss) from continuing operations, net of tax	$	94,552		$	70,887		$	87,190		$	89,535
Income from discontinued operations, net of tax		(12,396	)		121,167			(12,226	)		(193,985	)
Less: Net (income) loss attributable to noncontrolling interest		669			394			(708	)		(1,400	)
Net income (loss) attributable to Nabors	$	82,825		$	192,448		$	74,256		$	(105,850	)
Earnings (loss) per share:(2)
Basic from continuing operations	$	.33		$	.25		$	.30		$	.31
Basic from discontinued operations		(.04	)		.42			(.04	)		(.68	)
Total Basic	$	.29		$	.67		$	.26		$	(.37	)
Diluted from continuing operations	$	.33		$	.24		$	.30		$	.30
Diluted from discontinued operations		(.05	)		.41			(.05	)		(.66	)
Total Diluted	$	.28		$	.65		$	.25		$	(.36	)
	Year Ended December 31, 2010
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(3)	$	890,469		$	898,169		$	1,068,870		$	1,310,242
Income (loss) from continuing operations, net of tax	$	46,477		$	44,949		$	12,347		$	152,097
Income from discontinued operations, net of tax		(7,379	)		(1,887	)		(51,501	)		(100,323	)
Less: Net (income) loss attributable to noncontrolling interest		1,102			559			(453	)		(1,293	)
Net income (loss) attributable to Nabors	$	40,200		$	43,621		$	(39,607	)	$	50,481
Earnings per share:(2)
Basic from continuing operations	$	.17		$	.16		$	.04		$	.53
Basic from discontinued operations		(.03	)		(.01	)		(.18	)		(.35	)
Total Basic	$	.14		$	.15		$	(.14	)	$	.18
Diluted from continuing operations	$	.16		$	.16		$	.04		$	.52
Diluted from discontinued operations		(.02	)		(.01	)		(.18	)		(.35	)
Total Diluted	$	.14		$	.15		$	(.14	)	$	.17

(1) Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $16.3 million, $9.3 million, $33.7 million and $(2.7) million, respectively.

(2) Earnings per share is computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the total computed for the year.

(3) Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $7.7 million, $8.9 million, $11.8 million and $4.9 million, respectively.

XML

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment [Abstract]

Major Components of Property, Plant and Equipment

	December 31,
	2011			2010
	(In thousands)
Land	$	22,120		$	12,087
Buildings		132,753			122,635
Drilling, workover and well-servicing rigs, and related equipment		11,150,927			10,632,968
Marine transportation and supply vessels		14,023			13,663
Oilfield hauling and mobile equipment		1,171,930			551,892
Other machinery and equipment		248,938			143,976
Oil and gas properties(1)		42,033			664,289
Construction in process(2)		815,987			349,455
		13,598,711			12,490,965
Less: accumulated depreciation and amortization		(4,928,781	)		(4,182,122	)
accumulated depletion on oil and gas properties		(39,984	)		(493,424	)
	$	8,629,946		$	7,815,419

(1) A significant portion of our oil and gas properties have been reclassified to assets held for sale at December 31, 2011. Information relating to suspended wells that have capitalized costs for more than one year on this date is located at Note 4 — Discontinued Operations.

(2) Relates to amounts capitalized for new or substantially new drilling, workover and well-servicing rigs that were under construction and had not yet been placed in service as of December 31, 2011 or 2010.

XML

Share Based Compensation (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2011 Y	Dec. 31, 2010 Y	Dec. 31, 2009 Y
Fair value of stock options
Weighted-average fair value of options granted:	$ 6.24	$ 6.62	$ 0.0285
Weighted-average risk free interest rate:	0.65%	1.49%	1.75%
Dividend yield:	0.00%	0.00%	0.00%
Volatility:(1)	51.09%	41.44%	34.78%
Expected life:	4.0	4.0	4.0

XML

Pension, Postretirement and Postemployment Benefits (Details) (Pension Benefits [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	$ 20,628	$ 18,865
Remeasurement	1,517
Interest cost	1,198	1,116	1,093
Actuarial loss (gain)	3,975	1,289
Benefit payments	(659)	(642)
Benefit obligation at end of year	26,659	20,628	18,865
Change in plan assets:
Fair value of plan assets at beginning of year	15,219	14,058
Actual (loss) return on plan assets	480	1,364
Employer contribution	1,312	439
Benefit payments	(659)	(642)
Fair value of plan assets at end of year	16,352	15,219	14,058
Funded status:
Underfunded status at end of year	(1,030)	(5,409)
Amounts recognized in consolidated balance sheets:
Other long-term liabilities	(10,307)	(5,409)
Components of net periodic benefit cost (recognized in our consolidated statements of income):
Interest cost	1,198	1,116	1,093
Expected return on plan assets	(1,008)	(909)	(794)
Recognized net actuarial loss	628	457	545
Net periodic benefit cost	$ 818	$ 664	$ 844
Weighted-average assumptions:
Weighted-average discount rate	4.25%	5.50%	6.00%
Expected long-term rate of return on plan assets	6.50%	6.50%	6.50%

XML

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2011

Oil and Gas [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Condensed Statements of Income

	Year Ended December 31,
Condensed Statements of Income — Oil and Gas Operating segment	2011			2010			2009
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates
Oil and Gas	$	125,654	(1)	$	37,615		$	(57,864	)(2)
Income (loss) from discontinued operations
Income (loss) from discontinued operations	$	18.660		$	(26,139	)	$	(81,678	)
Impairment on wholly owned assets		(255,046	)(3)		(192,179	)(4)		(205,897	)(5)
Gain (loss) on disposal of assets		46,811			—			—
Less: income tax expense (benefit)		(98,181	)		(62,028	)		(85,431	)
Income (loss) from discontinued operations, net of tax	$	(91,394	)	$	(156,290	)	$	(202,144	)

(1) Includes approximately $83 million of equity in earnings during 2011 for our proportionate share of Remora’s net income, inclusive of the gains recognized for asset sales during 2011.

(2) Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million during 2009.

(3) Includes impairments of $255.0 million to write down the carrying value of our wholly owned oil and gas-centered assets, including $27.2 million related to an oil and gas financing receivable that was deemed uncollectible.

(4) Includes impairments of $192.2 million related to our wholly owned oil and gas assets. Of this total, $137.8 million represented writedowns to the carrying value of some acreage in the United States, which we currently do not have future plans to develop due to sustained low natural gas prices, and certain exploratory wells in Colombia, which we determined were uneconomical to develop in the foreseeable future. The remaining $54.3 million related to impairment of an oil and gas financing receivable was determined using discounted cash flow models, a Level 3 measurement, and involved assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices.

(5) Includes impairments totaling $205.9 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 lasting 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. Annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $56.8 million to write down the carrying value of some acreage that we do not have future plans to develop.

Other Operating Segments [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Condensed Statements of Income

	Year Ended December 31,
Condensed Statements of Income — Other Operating Segments	2011			2010			2009
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates
Other Operating Segments	$	29,713		$	29,739		$	28,751
Income (loss) from discontinued operations
Income (loss) from discontinued operations	$	(210	)	$	1,059		$	(1,636	)
Goodwill impairment		—			—			(14,689	)(6)
Impairment of long-lived assets		(7,853	)		(7,460	)(7)		—
Gain (loss) on disposal of assets		—			—			—
Less: income tax expense (benefit)		(2,017	)		(1,601	)		140
Income (loss) from discontinued operations, net of tax	$	(6,046	)	$	(4,800	)	$	(16,465	)

(6) Includes $14.7 million to impair the remaining goodwill balance of Nabors Blue Sky Ltd. as a result of our annual goodwill impairment tests. We determined the impairment charge was 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.

(7) Includes $7.5 million of impairment to our aircraft and some drilling equipment during the year ended December 31, 2010. These impairment charges resulted from annual impairment tests on long-lived assets.

XML

Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Balance Sheets

	December 31, 2011
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)		Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments			Consolidated Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	203	$	21	$	—	$	398,351	$	—		$	398,575
Short-term investments		—		—		—		140,914		—			140,914
Assets held for sale		—		—		—		401,500		—			401,500
Accounts receivable, net		—		—		—		1,576,555		—			1,576,555
Inventory		—		—		—		272,852		—			272,852
Deferred income taxes		—		—		—		127,874		—			127,874
Other current assets		50		671		—		169,323		—			170,044
Total current assets		253		692		—		3,087,369		—			3,088,314
Long-term investments and other receivables		—		—		—		11,124		—			11,124
Property, plant and equipment, net		—		40,792		—		8,589,154		—			8,629,946
Goodwill		—		—		—		501,258		—			501,258
Intercompany receivables		164,760		—		—		537,881		(702,641	)		—
Investment in unconsolidated affiliates		5,429,029		6,084,868		—		1,843,654		(12,986,530	)		371,021
Other long-term assets		—		32,037		—		278,440		—			310,477
Total assets	$	5,594,042	$	6,158,389	$	—	$	14,848,880	$	(13,689,171	)	$	12,912,140
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	274,604	$	—	$	722	$	—		$	275,326
Trade accounts payable		42		23		—		782,688		—			782,753
Accrued liabilities		6,185		100,101		—		556,200		—			662,486
Asset held for sale		—		—		—		54,287		—			54,287
Income taxes payable		—				—		27,710		—			27,710
Total current liabilities		6,227		374,728		—		1,421,607		—			1,802,562
Long-term debt		—		4,297,500		—		50,990		—			4,348,490
Asset held for sale		—		—		—		71,375		—			71,375
Other long-term liabilities		—		32,303		—		189,079		—			221,382
Deferred income taxes		—		11,221		—		786,705		—			797,926
Intercompany payable		—		379,400		—		323,241		(702,641	)		—
Total liabilities		6,227		5,095,152		—		2,842,997		(702,641	)		7,241,735
Subsidiary preferred stock		—		—		—		69,188		—			69,188
Shareholders’ equity		5,587,815		1,063,237		—		11,923,293		(12,986,530	)		5,587,815
Noncontrolling interest		—		—		—		13,402		—			13,402
Total equity		5,587,815		1,063,237		—		11,936,695		(12,986,530	)		5,601,217
Total liabilities and equity	$	5,594,042	$	6,158,389	$	—	$	14,848,880	$	(13,689,171	)	$	12,912,140

	December 31, 2010
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)		Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments			Consolidated Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,847	$	20	$	—	$	630,835	$	—		$	641,702
Short-term investments		—		—		—		159,488		—			159,488
Assets held for sale		—		—		—		352,048		—			352,048
Accounts receivable, net		—		—		—		1,116,510		—			1,116,510
Inventory		—		—		—		158,836		—			158,836
Deferred income taxes		—		—		—		31,510		—			31,510
Other current assets		50		16,366		—		136,420		—			152,836
Total current assets		10,897		16,386		—		2,585,647		—			2,612,930
Long-term investments and other receivables		—		—		—		40,300		—			40,300
Property, plant and equipment, net		—		44,270		—		7,771,149		—			7,815,419
Goodwill		—		—		—		494,372		—			494,372
Intercompany receivables		160,250		—		—		322,697		(482,947	)		—
Investment in unconsolidated affiliates		5,160,800		5,814,219		—		1,665,459		(12,372,755	)		267,723
Other long-term assets		—		36,538		—		379,287		—			415,825
Total assets	$	5,331,947	$	5,911,413	$	—	$	13,258,911	$	(12,855,702	)	$	11,646,569
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	1,378,178	$	—	$	840	$	—		$	1,379,018
Trade accounts payable		—		—		—		355,282		—			355,282
Accrued liabilities		3,785		89,480		—		301,027		—			394,292
Income taxes payable		—		6,859		—		18,929		—			25,788
Total current liabilities		3,785		1,474,517		—		676,078		—			2,154,380
Long-term debt		—		3,062,291		—		1,835		—			3,064,126
Other long-term liabilities		—		12,787		—		232,978		—			245,765
Deferred income taxes		—		71,815		—		698,432		—			770,247
Intercompany payable		—		301,451		—		181,496		(482,947	)		—
Total liabilities		3,785		4,922,861		—		1,790,819		(482,947	)		6,234,518
Subsidiary preferred stock		—		—		—		69,188		—			69,188
Shareholders’ equity		5,328,162		988,552		—		11,384,203		(12,372,755	)		5,328,162
Noncontrolling interest		—		—		—		14,701		—			14,701
Total equity		5,328,162		988,552		—		11,398,904		(12,372,755	)		5,342,863
Total liabilities and equity	$	5,331,947	$	5,911,413	$	—	$	13,258,911	$	(12,855,702	)	$	11,646,569

Condensed Consolidating Statements of Income (Loss)

	Year Ended December 31, 2011
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—	$	—		$	—	$	6,060,351		$	—		$	6,060,351
Earnings (losses) from unconsolidated affiliates		—		—			—		56,647			—			56,647
Earnings (losses) from consolidated affiliates		256,245		214,308			—		107,536			(578,089	)		—
Investment income (loss)		4		68			—		19,868			—			19,940
Intercompany interest income		—		69,437			—		—			(69,437	)		—
Total revenues and other income		256,249		283,813			—		6,244,402			(647,526	)		6,136,938
Costs and other deductions:
Direct costs		—		—			—		3,775,964			—			3,775,964
General and administrative expenses		11,970		348			—		478,174			(600	)		489,892
Depreciation and amortization		—		3,532			—		920,562			—			924,094
Interest expense		—		278,657			—		(22,024	)		—			256,633
Intercompany interest expense		—		—			—		69,437			(69,437	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		600		(1,904	)		—		5,218			600			4,514
Impairments and other charges		—		—			—		198,072			—			198,072
Total costs and other deductions		12,570		280,633			—		5,425,403			(69,437	)		5,649,169
Income (loss) from continuing operations before income taxes		243,679		3,180			—		818,999			(578,089	)		487,769
Income tax expense (benefit)		—		(78,118	)		—		220,723			—			142,605
Subsidiary preferred stock dividend		—		—			—		3,000			—			3,000
Income (loss) from continuing operations, net of tax		243,679		81,298			—		595,276			(578,089	)		342,164
Income (loss) from discontinued operations, net of tax		—		—			—		(97,440	)		—			(97,440	)
Net income (loss)		243,679		81,298			—		497,836			(578,089	)		244,724
Less: Net (income) loss attributable to noncontrolling interest		—		—			—		(1,045	)		—			(1,045	)
Net income (loss) attributable to Nabors	$	243,679	$	81,298		$	—	$	496,791		$	(578,089	)	$	243,679

	Year Ended December 31, 2010
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—		$	—		$	—	$	4,134,483		$	—		$	4,134,483
Earnings (losses) from unconsolidated affiliates		—			—			—		33,267			—			33,267
Earnings (losses) from consolidated affiliates		68,749			(183,242	)		—		(316,657	)		431,150			—
Investment income (loss)		15			—			—		7,248			—			7,263
Intercompany interest income		—			72,435			—		—			(72,435	)		—
Total revenues and other income		68,764			(110,807	)		—		3,858,341			358,715			4,175,013
Costs and other deductions:
Direct costs		—			—			—		2,400,519			—			2,400,519
General and administrative expenses		9,165			445			—		330,067			(957	)		338,720
Depreciation and amortization		—			3,303			—		757,659			—			760,962
Interest expense		—			283,396			—		(10,684	)		—			272,712
Intercompany interest expense		—			—			—		72,435			(72,435	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		(35,096	)		42,504			—		38,873			957			47,238
Impairments and other charges		—			—			—		61,292			—			61,292
Total costs and other deductions		(25,931	)		329,648			—		3,650,161			(72,435	)		3,881,443
Income (loss) from continuing operations before income taxes		94,695			(440,455	)		—		208,180			431,150			293,570
Income tax expense (benefit)		—			(95,168	)		—		132,118			—			36,950
Subsidiary preferred stock dividend		—			—			—		750			—			750
Income (loss) from continuing operations, net of tax		94,695			(345,287	)		—		75,312			431,150			255,870
Income (loss) from discontinued operations, net of tax		—			—			—		(161,090	)		—			(161,090	)
Net income (loss)		94,695			(345,287	)		—		(85,778	)		431,150			94,780
Less: Net (income) loss attributable to noncontrolling interest		—			—			—		(85	)		—			(85	)
Net income (loss) attributable to Nabors	$	94,695		$	(345,287	)	$	—	$	(85,863	)	$	431,150		$	94,695

	Year Ended December 31, 2009
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—		$	—		$	—		$	3,662,220		$	—		$	3,662,220
Earnings (losses) from unconsolidated affiliates		—			—			—			(155,432	)		—			(155,432	)
Earnings (losses) from consolidated affiliates		(74,204	)		(316,443	)		(86,751	)		(441,133	)		918,531			—
Investment income (loss)		58			2,357			101			23,006			—			25,522
Intercompany interest income		—			66,150			5,558			—			(71,708	)		—
Total revenues and other income		(74,146	)		(247,936	)		(81,092	)		3,088,661			846,823			3,532,310
Costs and other deductions:
Direct costs		—			—			—			1,981,504			—			1,981,504
General and administrative expenses		28,350			336			1			393,375			(570	)		421,492
Depreciation and amortization		—			3,594			—			660,364			—			663,958
Interest expense		—			288,715			5,634			(28,302	)		—			266,047
Intercompany interest expense		—			—			—			71,708			(71,708	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		(16,950	)		4,145			5,069			37,395			(17,677	)		11,982
Impairments and other charges		—			—			—			118,543			—			118,543
Total costs and other deductions		11,400			296,790			10,704			3,234,587			(89,955	)		3,463,526
Income (loss) from continuing operations before income taxes		(85,546	)		(544,726	)		(91,796	)		(145,926	)		936,778			68,784
Income tax expense (benefit)		—			(84,465	)		15,744			4,784			—			(63,937	)
Income (loss) from continuing operations, net of tax		(85,546	)		(460,261	)		(107,540	)		(150,710	)		936,778			132,721
Income (loss) from discontinued operations, net of tax		—			—			—			(218,609	)		—			(218,609	)
Net income (loss)		(85,546	)		(460,261	)		(107,540	)		(369,319	)		936,778			(85,888	)
Less: Net (income) loss attributable to noncontrolling interest		—			—			—			342			—			342
Net income (loss) attributable to Nabors	$	(85,546	)	$	(460,261	)	$	(107,540	)	$	(368,977	)	$	936,778		$	(85,546	)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2011
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	6,612		$	(31,178	)	$	—	$	1,481,053		$			$	1,456,487
Cash flows from investing activities:
Purchases of investments		—			—			—		(11,746	)		—			(11,746	)
Sales and maturities of investments		—			—			—		39,063			—			39,063
Cash paid for acquisition of businesses, net		—			—			—		(55,459	)		—			(55,459	)
Investment in unconsolidated affiliates		—			—			—		(112,262	)		—			(112,262	)
Distribution of proceeds from asset sales of unconsolidated affiliates		—			—			—		142,984			—			142,984
Capital expenditures		—			—			—		(2,042,617	)		—			(2,042,617	)
Proceeds from sales of assets and insurance claims		—			—			—		180,558			—			180,558
Cash paid for investments in consolidated affiliates		(26,235	)		(65,000	)		—		—			91,235			—
Net cash provided by (used for) investing activities		(26,235	)		(65,000	)		—		(1,859,479	)		91,235			(1,859,479	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—		6,375			—			6,375
Proceeds from long-term debt		—			697,578			—		—			—			697,578
Debt issuance costs		—			(7,141	)		—		—			—			(7,141	)
Proceeds from revolving credit facilities		—			1,510,000			—		50,000			—			1,560,000
Proceeds from issuance of common shares		11,605			—			—		—			—			11,605
Reduction in long-term debt		—			(1,404,246	)		—		(35	)		—			(1,404,281	)
Reduction in revolving credit facilities		—			(700,000	)		—		—			—			(700,000	)
Repurchase of equity component of convertible debt		—			(12	)		—		—			—			(12	)
Purchase of restricted stock		(2,626	)		—			—		—			—			(2,626	)
Tax benefit related to share-based awards		—			—			—		1,747			—			1,747
Proceeds from parent contributions		—			—			—		91,235			(91,235	)		—
Net cash (used for) provided by financing activities		8,979			96,179			—		149,322			(91,235	)		163,245
Effect of exchange rate changes on cash and cash equivalents		—			—			—		(3,380	)		—			(3,380	)
Net (decrease) increase in cash and cash equivalents		(10,644	)		1			—		(232,484	)		—			(243,127	)
Cash and cash equivalents, beginning of period		10,847			20			—		630,835			—			641,702
Cash and cash equivalents, end of period	$	203		$	21		$	—	$	398,351		$	—		$	398,575

	Year Ended December 31, 2010
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	115,179		$	757,345		$	—	$	504,460		$	(270,000	)	$	1,106,984
Cash flows from investing activities:
Purchases of investments		—			—			—		(34,147	)		—			(34,147	)
Sales and maturities of investments		—			—			—		34,613			—			34,613
Cash paid for acquisition of businesses, net		—			—			—		(733,630	)		—			(733,630	)
Investment in unconsolidated affiliates		—			—			—		(40,936	)		—			(40,936	)
Capital expenditures		—			—			—		(930,277	)		—			(930,277	)
Proceeds from sales of assets and insurance claims		—			—			—		31,072			—			31,072
Cash paid for investments in consolidated affiliates		(122,300	)		(1,027,134	)		—		—			1,149,434			—
Net cash provided by (used for) investing activities		(122,300	)		(1,027,134	)		—		(1,673,305	)		1,149,434			(1,673,305	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—		(6,298	)		—			(6,298	)
Proceeds from long-term debt		—			696,948			—		—			—			696,948
Debt issuance costs		—			(8,934	)		—		—			—			(8,934	)
Payments for hedge transactions		—			(5,667	)		—		—			—			(5,667	)
Proceeds from revolving credit facilities		—			600,000			—		—			—			600,000
Proceeds from issuance of common shares		8,201			—			—		—			—			8,201
Reduction in long-term debt		—			(274,095	)		—		(124,419	)		—			(398,514	)
Reduction in revolving credit facilities		—			(600,000	)		—		—			—			(600,000	)
Repurchase of equity component of convertible debt		—			(4,712	)		—		—			—			(4,712	)
Settlement of call options and warrants, net		—			1,134			—		—			—			1,134
Purchase of restricted stock		(1,935	)		—			—		—			—			(1,935	)
Tax benefit related to share-based awards		—			—			—		31			—			31
Cash dividends paid		—			(135,000	)		—		(135,000	)		270,000			—
Proceeds from parent contributions		—			—			—		1,149,434			(1,149,434	)		—
Net cash (used for) provided by financing activities		6,266			269,674			—		883,748			(879,434	)		280,254
Effect of exchange rate changes on cash and cash equivalents		—			—			—		(46	)		—			(46	)
Net (decrease) increase in cash and cash equivalents		(855	)		(115	)		—		(285,143	)		—			(286,113	)
Cash and cash equivalents, beginning of period		11,702			135			—		915,978			—			927,815
Cash and cash equivalents, end of period	$	10,847		$	20		$	—	$	630,835		$	—		$	641,702

	Year Ended December 31, 2009
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	40,589		$	646,645		$	608		$	1,089,086		$	(159,956	)	$	1,616,972
Cash flows from investing activities:
Purchases of investments		—			—			—			(32,674	)		—			(32,674	)
Sales and maturities of investments		—			—			—			57,033			—			57,033
Investment in unconsolidated affiliates		—			—			—			(125,076	)		—			(125,076	)
Capital expenditures		—			—			—			(1,093,435	)		—			(1,093,435	)
Proceeds from sales of assets and insurance claims		—			—			—			31,375			—			31,375
Proceeds from sale of consolidated affiliates		—			—			239,421			(239,421	)		—			—
Cash paid for investments in consolidated affiliates		(46,912	)		(900,000	)		—			—			946,912			—
Net cash provided by (used for) investing activities		(46,912	)		(900,000	)		239,421			(1,402,198	)		946,912			(1,162,777	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—			(18,157	)		—			(18,157	)
Proceeds from long-term debt		—			1,124,978			—			—			—			1,124,978
Debt issuance costs		—			(8,832	)		—			—			—			(8,832	)
Intercompany debt		—			—			143,859			(143,859	)		—			—
Proceeds from issuance of common shares		11,249			—			—			—			—			11,249
Reduction in long-term debt		—			(856,203	)		(225,191	)		(407	)		—			(1,081,801	)
Repurchase of equity component of convertible debt		—			(6,586	)		—			—			—			(6,586	)
Purchase of restricted stock		(1,515	)		—			—			—			—			(1,515	)
Tax benefit related to share-based awards		—			37			—			—			—			37
Cash dividends paid		—			—			(159,956	)		—			159,956			—
Proceeds from parent contributions		—			—			—			946,912			(946,912	)		—
Net cash (used for) provided by financing activities		9,734			253,394			(241,288	)		784,489			(786,956	)		19,373
Effect of exchange rate changes on cash and cash equivalents		—			—			—			12,160			—			12,160
Net (decrease) increase in cash and cash equivalents		3,411			39			(1,259	)		483,537			—			485,728
Cash and cash equivalents, beginning of period		8,291			96			1,259			432,441			—			442,087
Cash and cash equivalents, end of period	$	11,702		$	135		$	—		$	915,978		$	—		$	927,815

XML

Cash and Cash Equivalents and Short-term Investments (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Gross unrealized losses of cash and cash equivalents and short-term investments
Available-for-sale securities, less than 12 months	$ 19,917
Available-for-sale securities, gross unrealized loss, less than 12 months	2,102
Available-for-sale securities, more than 12 months	2,577
Available-for-sale securities, gross unrealized loss, more than 12 months	246
Debt Securities [Member]
Gross unrealized losses of cash and cash equivalents and short-term investments
Available-for-sale securities, less than 12 months	19,917
Available-for-sale securities, gross unrealized loss, less than 12 months	2,102
Available-for-sale securities, more than 12 months	2,577
Available-for-sale securities, gross unrealized loss, more than 12 months	246
Equity Securities [Member]
Gross unrealized losses of cash and cash equivalents and short-term investments
Available-for-sale securities, less than 12 months	0
Available-for-sale securities, gross unrealized loss, less than 12 months	0
Available-for-sale securities, more than 12 months	0
Available-for-sale securities, gross unrealized loss, more than 12 months	0
Corporate debt securities [Member]
Gross unrealized losses of cash and cash equivalents and short-term investments
Available-for-sale securities, less than 12 months	17,700
Available-for-sale securities, gross unrealized loss, less than 12 months	2,095
Available-for-sale securities, more than 12 months	0
Available-for-sale securities, gross unrealized loss, more than 12 months	0
Mortgage-CMO debt securities [Member]
Gross unrealized losses of cash and cash equivalents and short-term investments
Available-for-sale securities, less than 12 months	2,217
Available-for-sale securities, gross unrealized loss, less than 12 months	7
Available-for-sale securities, more than 12 months	83
Available-for-sale securities, gross unrealized loss, more than 12 months	8
Asset-backed debt securities [Member]
Gross unrealized losses of cash and cash equivalents and short-term investments
Available-for-sale securities, less than 12 months	0
Available-for-sale securities, gross unrealized loss, less than 12 months	0
Available-for-sale securities, more than 12 months	2,494
Available-for-sale securities, gross unrealized loss, more than 12 months	$ 238

XML

Supplemental Balance Sheet Income Statement and Cash Flow Information (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investment income (loss)
Interest and dividend income	$ 9,930	$ 7,457	$ 15,700
Gains (losses) on investments, net	10,010	(192)	9,822
Investment income (loss)	$ 19,940	$ 7,263	$ 25,522

XML

Discontinued Operations (Details Textual) (USD $)	3 Months Ended								12 Months Ended			1 Months Ended	12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Cat Canyon And West Cat Canyon [Member]	Dec. 31, 2011 Nabors Blue Sky Limited [Member]	Dec. 31, 2010 U.S. [Member]	Dec. 31, 2009 North Central Texas [Member]	Dec. 31, 2011 Remora Energy International L P [Member]	Dec. 31, 2010 Remora Energy International L P [Member]	Dec. 31, 2010 Stone Mountain Ventures Partnership [Member]
Schedule of Equity Method Investments [Line Items]
Company's ownership interest for investments																	49.70%	50.00%
Cash proceeds from affiliate, from sale of oil and gas assets									$ 89,200,000			$ 71,600,000				$ 333,100,000
Earnings (losses) from unconsolidated affiliates	(2,700,000)	33,700,000	9,300,000	16,300,000	4,900,000	11,800,000	8,900,000	7,700,000	56,647,000	33,267,000	(155,432,000)					83,000,000
Impairment of oil and gas-related assets										192,200,000					205,900,000
Percentage of working capital interest sold												25.00%
Impairment of acreage oil and gas property														137,800,000	56,800,000
Impairment of oil and gas properties financing receivable	27,200,000								27,200,000					54,300,000	149,100,000
Gain on disposal of assets									39,600,000			7,200,000
Impairment of long-lived assets										27,372,000			7,900,000
Discontinued Operations (Textual) [Abstract]
Cash distribution from the sale of oil and gas assets									142,984,000
Impairment on wholly owned assets									(255,046,000,000)	(192,179,000)	(205,897,000)
Proportionate share of full cost ceiling test write downs											47,800,000
Goodwill impairment											14,700,000
Impairment of long-lived assets									(7,853,000)	7,500,000
Current liability of discontinued operations	54,287,000				0				54,287,000	0
Noncurrent liability of discontinued operations	71,400,000								71,400,000
Total capitalized cost of suspended wells					42,800,000					42,800,000
Capitalized cost of well in process of drilling	$ 12,100,000								$ 12,100,000

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Minimum rental commitments under non cancellable operating leases

	(In thousands)
2012	$	25,288
2013		20,060
2014		14,363
2015		7,273
2016		4,020
Thereafter		9,857
	$	80,861

Minimum pipeline commitments under transportation

	(In thousands)
2012	$	54,287
2013		68,056
2014		66,373
2015		64,845
2016		48,330
Thereafter(1)		86,808
	$	388,699

(1) Final commitment period is for the period ending October 2029.

Minimum salary and bonus obligations under employment contract

	(In thousands)
2012	$	9,752
2013		3,905
2014		501
2015		—
2016		—
Thereafter		—
	$	14,158

Summary of total maximum amount of financial guarantees issued

	Maximum Amount
	2012		2013		2014		Thereafter		Total
	(In thousands)
Financial standby letters of credit and other financial surety instruments	$	105,055	$	38	$	—	$	—	$	105,093

XML

Nature of Operations

12 Months Ended

Dec. 31, 2011

Nature of Operations [Abstract]

Nature of Operations

Note 1    Nature of Operations

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 499 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Middle East, the Far East, the South Pacific, Russia and Africa.

• We actively market approximately 581 rigs for land well-servicing and workover work in the United States and approximately 174 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 39 platform, 12 jackup and four barge rigs in the United States, including the Gulf of Mexico, and multiple international markets.

In addition to the foregoing services:

• We provide hydraulic fracturing, cementing, nitrogen and acid pressure pumping services with over 730,000 hydraulic horsepower in key basins throughout the United States and Canada.

• We offer a wide range of ancillary well-site services, including engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select U.S. 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 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 have invested in oil and gas exploration, development and production activities through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests.

The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, well-servicing, fluid logistics and workover operations, on land and offshore. Our hydraulic fracturing and downhole surveying services are included in our Pressure Pumping operating segment. Our oil and gas exploration, development and production operations are included in our Oil and Gas operating segment, or in discontinued operations in some cases. Our operating segments engaged in drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction operations are aggregated in our Other Operating Segments.

The consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications have been made to prior periods to conform to the current period presentation, with no effect on our consolidated financial position, results of operations or cash flows.

XML

Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)	$ 1,731,979	$ 1,642,227	$ 1,352,950	$ 1,389,842	$ 1,310,242	$ 1,068,870	$ 898,169	$ 890,469	$ 6,116,998	$ 4,167,750	$ 3,506,788
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									924,094	760,962	663,958
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									927,048	667,549	439,834
Interest expense									(256,633)	(272,712)	(266,047)
Investment income (loss)									19,940	7,263	25,522
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net									(4,514)	(47,238)	(11,982)
Impairments and other charges									(198,072)	(61,292)	(118,543)
Income (loss) from continuing operations before income tax									487,769	293,570	68,784
Income tax expense (benefit)									142,605	36,950	(63,937)
Subsidiary preferred stock dividend									3,000	750
Income (loss) from continuing operations, net of tax	89,535	87,190	70,887	94,552	152,097	12,347	44,949	46,477	342,164	255,870	132,721
Gain (loss) on acquisitions/dispositions	(193,985)	(12,226)	121,167	(12,396)	(100,323)	(51,501)	(1,887)	(7,379)	(97,440)	(161,090)	(218,609)
Net income (loss)									244,724	94,780	(85,888)
Less: Net (income) loss attributable to noncontrolling interest	(1,400)	(708)	394	669	(1,293)	(453)	559	1,102	(1,045)	(85)	342
Net income (loss) attributable to Nabors	(105,850)	74,256	192,448	82,825	50,481	(39,607)	43,621	40,200	243,679	94,695	(85,546)
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									2,247,735	1,878,063	990,287
ASSETS
Total assets	12,912,140				11,646,569				12,912,140	11,646,569	10,644,690
U.S. Lower 48 Land Drilling [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									1,698,620	1,294,853	1,082,531
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									288,373	241,258	226,875
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									414,317	274,215	294,679
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									650,342	294,239	327,269
ASSETS
Total assets	3,216,803				2,762,362				3,216,803	2,762,362	2,609,101
U.S. Land Well-servicing [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									701,223	444,665	412,243
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									78,314	65,561	69,557
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									74,725	31,597	28,950
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									165,953	84,657	16,671
ASSETS
Total assets	812,049				630,518				812,049	630,518	594,456
U.S. Offshore [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									170,727	123,761	157,305
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									37,242	37,059	37,204
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									843	9,245	30,508
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									63,817	23,625	48,694
ASSETS
Total assets	402,506				379,292				402,506	379,292	440,556
Alaska [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									129,894	179,218	204,407
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									34,989	37,195	29,946
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									27,671	51,896	62,742
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									5,582	891	55,426
ASSETS
Total assets	288,253				313,123				288,253	313,123	373,146
Canada [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									574,754	389,229	298,653
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									75,919	74,735	65,883
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									94,637	22,970	(7,019)
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									95,001	53,834	29,214
ASSETS
Total assets	962,239				1,065,268				962,239	1,065,268	984,740
International [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									1,104,461	1,093,608	1,265,097
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									273,315	247,134	208,949
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									123,813	254,744	365,566
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									653,759	365,597	328,252
ASSETS
Total assets	3,702,611				3,279,763				3,702,611	3,279,763	3,151,513
Subtotal Contract Drilling [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									4,379,679	3,525,334	3,420,236
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									788,152	702,942	638,414
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									736,006	644,667	775,426
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									1,634,454	822,843	805,526
ASSETS
Total assets	9,384,461				8,430,326				9,384,461	8,430,326	8,153,512
Pressure Pumping [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									1,237,306	321,295
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									102,009	32,204
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									229,125	66,651
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									285,304	924,693
ASSETS
Total assets	1,503,298				1,163,236				1,503,298	1,163,236	0
Oil and Gas [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									59,685	18,657	(182,654)
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									0	0	0
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									59,685	18,657	(182,654)
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									208,995	113,361	184,185
ASSETS
Total assets	796,327				805,410				796,327	805,410	835,465
Other Operating Segments [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									674,206	427,154	417,531
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									34,162	28,452	27,441
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									55,617	42,401	35,319
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									136,515	28,799	20,446
ASSETS
Total assets	720,775				539,373				720,775	539,373	502,501
Other reconciling items [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									(233,878)	(124,690)	(148,325)
Depreciation and amortization, and depletion:
Depreciation and amortization, and depletion									(229)	(2,636)	(1,897)
Adjusted income (loss) derived from operating activities from continuing operations:
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)									(153,385)	(104,827)	(188,257)
Capital expenditures and acquisitions of businesses
Capital expenditures and acquisitions									(17,533)	(11,633)	(19,870)
ASSETS
Total assets	$ 507,279				$ 708,224				$ 507,279	$ 708,224	$ 1,153,212

XML

Acquisitions (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Assets:
Cash and cash equivalents	$ 1,045
Accounts receivable	143,842
Inventory	33,963
Other current assets	7,612
Property, plant and equipment	415,000
Intangible assets	131,811
Goodwill	334,992
Other long-term assets	14,726
Total assets	1,082,991
Liabilities:
Current liabilities	78,277
Deferred income taxes	119,201
Long-term debt	124,792
Other long-term liabilities	10,258
Total liabilities	332,528
Preferred stock	69,188
Net assets acquired	$ 681,275

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details 5) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Sales of reserves	$ 0
Consolidated Subsidiary [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	268,464	56,613
Value of reserves added during the year due to extensions, discoveries and net purchase less related costs	32,838	53,109
Sales of oil and gas produced, net of production costs	(28,769)	(22,682)
Development costs incurred during the year	360	8,359
Net change in prices and production costs	(14,053)	94,153
Net change in future development costs	775	4,248
Revisions of previous reserves estimates	16,152	(28,966)
Purchases of reserves	4,557	196,613
Sales of reserves	(330,526)
Accretion of discount	30,864	5,088
Other	946	(11,008)
Net change in income taxes	87,064	(87,063)
Total change in the standardized measure for consolidated subsidiaries	(200,151)	211,851
Discounted future net cash flows, Ending balance	68,312	268,464
Equity Companies [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	355,106	76,216
Value of reserves added during the year due to extensions, discoveries and net purchase less related costs	83,692	60,894
Sales of oil and gas produced, net of production costs	(84,030)	(54,280)
Development costs incurred during the year	(44,294)	69,207
Net change in prices and production costs	(20,856)	88,801
Net change in future development costs	(51,098)	(1,221)
Revisions of previous reserves estimates	20,178	92,935
Purchases of reserves	262,719	5,453
Sales of reserves	(50,847)	(6,864)
Accretion of discount	29,155	6,617
Other	(6,250)	17,348
Net change in income taxes	0
Total change in the standardized measure for consolidated subsidiaries	226,957	278,890
Discounted future net cash flows, Ending balance	582,063	355,106
U.S. [Member] | Consolidated Subsidiary [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	213,142	38,345
Value of reserves added during the year due to extensions, discoveries and net purchase less related costs	32,838	8,037
Sales of oil and gas produced, net of production costs	(14,247)	(10,670)
Development costs incurred during the year	360	8,359
Net change in prices and production costs	(15,274)	96,662
Net change in future development costs	775	4,155
Revisions of previous reserves estimates	(4,925)	(27,501)
Purchases of reserves	0	196,613
Sales of reserves	(272,448)
Accretion of discount	30,021	3,562
Other	356	(17,357)
Net change in income taxes	87,064	(87,063)
Total change in the standardized measure for consolidated subsidiaries	(155,840)	174,797
Discounted future net cash flows, Ending balance	57,302	213,142
U.S. [Member] | Equity Companies [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	291,372	52,941
Value of reserves added during the year due to extensions, discoveries and net purchase less related costs	83,692	20,230
Sales of oil and gas produced, net of production costs	(71,143)	(46,276)
Development costs incurred during the year	(44,294)	69,207
Net change in prices and production costs	(20,856)	90,974
Net change in future development costs	(51,098)
Revisions of previous reserves estimates	20,178	76,723
Purchases of reserves	262,719	5,453
Sales of reserves	0	(1,446)
Accretion of discount	29,155	5,294
Other	(6,250)	18,272
Net change in income taxes	0
Total change in the standardized measure for consolidated subsidiaries	290,691	238,431
Discounted future net cash flows, Ending balance	582,063	291,372
Canada [Member] | Consolidated Subsidiary [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	8,429	6,527
Sales of oil and gas produced, net of production costs	(5,848)	(3,311)
Net change in prices and production costs	1,221	46
Net change in future development costs	0	(192)
Revisions of previous reserves estimates	1,218	5,628
Purchases of reserves	4,557
Accretion of discount	843	496
Other	590	(765)
Total change in the standardized measure for consolidated subsidiaries	2,582	1,902
Discounted future net cash flows, Ending balance	11,010	8,429
Canada [Member] | Equity Companies [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	5,781	9,569
Sales of oil and gas produced, net of production costs	3,245	2,998
Net change in prices and production costs	0	(5,205)
Net change in future development costs	0	(374)
Revisions of previous reserves estimates	0	(1,077)
Sales of reserves	(9,026)
Accretion of discount	0	794
Other	0	(924)
Net change in income taxes	0
Total change in the standardized measure for consolidated subsidiaries	(5,781)	(3,788)
Discounted future net cash flows, Ending balance	0	5,781
Colombia [Member] | Consolidated Subsidiary [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	46,893	11,741
Value of reserves added during the year due to extensions, discoveries and net purchase less related costs	0	45,072
Sales of oil and gas produced, net of production costs	(8,674)	(8,701)
Net change in prices and production costs	0	(2,555)
Net change in future development costs	0	285
Revisions of previous reserves estimates	19,859	(7,093)
Sales of reserves	(58,078)
Accretion of discount	0	1,030
Other	0	7,114
Total change in the standardized measure for consolidated subsidiaries	(46,893)	35,152
Discounted future net cash flows, Ending balance	0	46,893
Colombia [Member] | Equity Companies [Member]
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Discounted future net cash flows, Beginning balance	57,953	13,706
Value of reserves added during the year due to extensions, discoveries and net purchase less related costs	0	40,664
Sales of oil and gas produced, net of production costs	(16,132)	(11,002)
Net change in prices and production costs	0	3,032
Net change in future development costs	0	(847)
Revisions of previous reserves estimates	0	17,289
Sales of reserves	(41,821)	(5,418)
Accretion of discount	0	529
Net change in income taxes	0
Total change in the standardized measure for consolidated subsidiaries	(57,953)	44,247
Discounted future net cash flows, Ending balance	$ 0	$ 57,953

XML

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2011

Investments in Unconsolidated Affiliates [Abstract]

Investments in Unconsolidated Affiliates

	December 31,
	2011		2010
	(In thousands)
Current assets	$	311,972	$	322,086
Long-term assets		1,728,399		1,332,212
Current liabilities		275,171		345,279
Long-term liabilities		800,444		460,198

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Gross revenues	$	832,774	$	901,742	$	960,823
Gross margin		278,019		241,831		223,005
Net income (loss)		270,161		48,426		(462,613	)
Nabors’ earnings (losses) from unconsolidated affiliates(1)		56,647		33,267		(155,432	)

(1) Nabors’ earnings (losses) from unconsolidated affiliates included in discontinued operations, net of tax was $76.5 million, $(10.6) million, and $(59.2) million, respectively, for the years ended December 31, 2011, 2010 and 2009.

XML

Unaudited Quarterly Financial Information

12 Months Ended

Dec. 31, 2011

Unaudited Quarterly Financial Information [Abstract]

Unaudited Quarterly Financial Information

Note 21    Unaudited Quarterly Financial Information

	Year Ended December 31, 2011
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(1)	$	1,389,842		$	1,352,950		$	1,642,227		$	1,731,979
Income (loss) from continuing operations, net of tax	$	94,552		$	70,887		$	87,190		$	89,535
Income from discontinued operations, net of tax		(12,396	)		121,167			(12,226	)		(193,985	)
Less: Net (income) loss attributable to noncontrolling interest		669			394			(708	)		(1,400	)
Net income (loss) attributable to Nabors	$	82,825		$	192,448		$	74,256		$	(105,850	)
Earnings (loss) per share:(2)
Basic from continuing operations	$	.33		$	.25		$	.30		$	.31
Basic from discontinued operations		(.04	)		.42			(.04	)		(.68	)
Total Basic	$	.29		$	.67		$	.26		$	(.37	)
Diluted from continuing operations	$	.33		$	.24		$	.30		$	.30
Diluted from discontinued operations		(.05	)		.41			(.05	)		(.66	)
Total Diluted	$	.28		$	.65		$	.25		$	(.36	)
	Year Ended December 31, 2010
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(3)	$	890,469		$	898,169		$	1,068,870		$	1,310,242
Income (loss) from continuing operations, net of tax	$	46,477		$	44,949		$	12,347		$	152,097
Income from discontinued operations, net of tax		(7,379	)		(1,887	)		(51,501	)		(100,323	)
Less: Net (income) loss attributable to noncontrolling interest		1,102			559			(453	)		(1,293	)
Net income (loss) attributable to Nabors	$	40,200		$	43,621		$	(39,607	)	$	50,481
Earnings per share:(2)
Basic from continuing operations	$	.17		$	.16		$	.04		$	.53
Basic from discontinued operations		(.03	)		(.01	)		(.18	)		(.35	)
Total Basic	$	.14		$	.15		$	(.14	)	$	.18
Diluted from continuing operations	$	.16		$	.16		$	.04		$	.52
Diluted from discontinued operations		(.02	)		(.01	)		(.18	)		(.35	)
Total Diluted	$	.14		$	.15		$	(.14	)	$	.17

(1) Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $16.3 million, $9.3 million, $33.7 million and $(2.7) million, respectively.

(2) Earnings per share is computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the total computed for the year.

(3) Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $7.7 million, $8.9 million, $11.8 million and $4.9 million, respectively.

XML

Supplemental Balance Sheet, Income Statement and Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Balance Sheet, Income Statement and Cash Flow Information [Abstract]

Supplemental Balance Sheet, Income Statement and Cash Flow Information

Note 20    Supplemental Balance Sheet, Income Statement and Cash Flow Information

At December 31, 2010, other long-term assets included a deposit of $40 million of restricted funds held at a financial institution to assure future credit availability for an unconsolidated affiliate.

Accrued liabilities include the following:

	December 31, 2011		December 31, 2010
	(In thousands)
Accrued compensation	$	173,732	$	116,680
Deferred revenue		172,578		88,389
Other taxes payable		44,652		25,227
Workers’ compensation liabilities		22,645		31,944
Interest payable		99,869		89,276
Due to joint venture partners		6,041		6,030
Warranty accrual		5,237		3,376
Litigation reserves		23,687		12,301
Provision for termination payment(1)		100,000		—
Current liability to discontinued operations		54,287		—
Professional fees		6,413		3,222
Current deferred tax liability		269		1,027
Other accrued liabilities		7,363		16,820
	$	716,773	$	394,292

(1) Represents a $100 million provision for a termination payment. See Note 3 — Impairments and Other Charges for additional discussion.

Investment income (loss) includes the following:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Interest and dividend income	$	9,930		$	7,457		$	15,700
Gains (losses) on investments, net		10,010	(1)		(194	)(2)		9,822	(3)
	$	19,940		$	7,263		$	25,522

(1) Reflects gain (loss) on sale of debt securities and gains (losses) from our long-term investments of $18.0 million, partially offset by net unrealized losses of $8.0 million from our trading securities.

(2) Includes net unrealized losses of $4.4 million from our trading securities, partially offset by gains on the sale of debt securities and gains from our long-term investments of $4.2 million.

(3) Reflects net unrealized gains of $9.8 million from our trading securities.

Losses (gains) on sales and retirements of long-lived assets and other expense (income), net includes the following:

	Year Ended December 31,
	2011			2010		2009
	(In thousands)
Losses (gains) on sales, retirements and involuntary conversions of long-lived assets	$	(11,155	)(1)	$	6,430	$	5,927
Acquisition-related costs		151			7,021		—
Litigation expenses		11,301			6,356		11,474
Foreign currency transaction losses (gains)		5,499			18,100		7,993
Losses (gains) on derivative instruments		(2,159	)		119		(1,399	)
Losses (gains) on debt extinguishment(2)		58			7,042		(11,197	)
Other losses (gains)		819			2,170		(816	)
	$	4,514		$	47,238	$	11,982

(1) Includes a $13.1 million pre-tax gain from our acquisition of Peak during the year ended December 31, 2011 representing the excess of the estimated fair value of the assets and liabilities over the net carrying value of our previously held equity interest. See Note 5 — Acquisitions for additional discussion.

(2) Includes $.1 million, $(7.0) million and $11.5 million pre-tax (losses) gains on our purchases of our 0.94% senior exchangeable notes in the open market during 2011, 2010 and 2009, respectively.

Supplemental cash flow information for the years ended December 31, 2011, 2010 and 2009 is as follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Cash paid for income taxes	$	53,759		$	58,574		$	107,994
Cash paid for interest, net of capitalized interest		208,212			180,731			126,796
Acquisitions of businesses:
Fair value of assets acquired		80,585			796,399			—
Goodwill		8,000			339,992			—
Liabilities assumed		(10,471	)		(332,528	)		—
Common stock of acquired company previously owned		—			—			—
Subsidiary preferred stock obligation		—			(69,188	)		—
Gain on acquisition		(13,114	)		—			—
Cash paid for acquisitions of businesses		65,000			734,675			—
Cash acquired in acquisitions of businesses		(9,541	)		(1,045	)		—
Cash paid for acquisitions of businesses, net	$	55,459		$	733,630		$	—

XML

Pension, Postretirement and Postemployment Benefits (Details 3) (Pension Benefits [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Pension Benefits [Member]
Benefits paid for five years thereafter
2012	$ 791
2013	890
2014	1,004
2015	1,117
2016	1,193
2017-2021	$ 7,428

XML

Summary of Significant Accounting Policies (Details1) (USD $) In Thousands, unless otherwise specified	12 Months Ended					12 Months Ended										12 Months Ended				12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 U.S. Lower 48 Land Drilling [Member]	Dec. 31, 2010 U.S. Lower 48 Land Drilling [Member]	Dec. 31, 2009 U.S. Lower 48 Land Drilling [Member]	Dec. 31, 2011 U.S. Land Well-servicing [Member]	Dec. 31, 2010 U.S. Land Well-servicing [Member]	Dec. 31, 2010 U.S. Offshore [Member]	Dec. 31, 2011 U.S. Offshore [Member]	Dec. 31, 2011 Alaska [Member]	Dec. 31, 2010 Alaska [Member]	Dec. 31, 2009 Alaska [Member]	Dec. 31, 2011 International [Member]	Dec. 31, 2010 International [Member]	Dec. 31, 2009 International [Member]	Dec. 31, 2011 Subtotal Contract Drilling [Member]	Dec. 31, 2010 Subtotal Contract Drilling [Member]	Dec. 31, 2010 Pressure Pumping [Member]	Dec. 31, 2011 Pressure Pumping [Member]	Dec. 31, 2011 Other Operating Segments [Member]	Dec. 31, 2010 Other Operating Segments [Member]
Change in the carrying amount of goodwill for various Contract Drilling segments and other Operating Segments
Beginning Balance	$ 494,372	$ 164,265	$ 30,154	$ 30,154	$ 30,154	$ 55,839	$ 50,839	$ 18,003	$ 7,296	$ 19,995	$ 19,995	$ 19,995	$ 18,983	$ 18,983	$ 18,983	$ 132,267	$ 137,974	$ 0	$ 334,992	$ 27,113	$ 26,291
Acquisitions and purchase price adjustment	7,233	339,992				(767)	5,000									(767)	5,000	334,992		8,000
Goodwill impairments		(10,707)						(10,707)									(10,707)
Cumulative Translation Adjustment	(347)	822																		(347)	822
Ending Balance	$ 501,258	$ 494,372	$ 30,154	$ 30,154	$ 30,154	$ 55,072	$ 55,839	$ 7,296	$ 7,296	$ 19,995	$ 19,995	$ 19,995	$ 18,983	$ 18,983	$ 18,983	$ 131,500	$ 132,267	$ 334,992	$ 334,992	$ 34,766	$ 27,113

XML

Debt (Tables)

12 Months Ended

Dec. 31, 2011

Debt [Abstract]

Long-term debt

	December 31, 2011		December 31, 2010
	(In thousands)
5.375% senior notes due August 2012	$	274,604	$	273,977
6.15% senior notes due February 2018		967,490		966,276
9.25% senior notes due January 2019		1,125,000		1,125,000
5.00% senior notes due September 2020		697,343		697,037
4.625% senior notes due September 2021		697,667		—
0.94% senior exchangeable notes due May 2011		—		1,378,178
Revolving credit facilities		860,000		—
Other		1,712		2,676
		4,623,816		4,443,144
Less: current portion		275,326		1,379,018
	$	4,348,490	$	3,064,126

Maturity of primary debt

	Paid at Maturity
	(In thousands)
2012	$	275,000	(1)
2013		—
2014		860,000	(2)
2015		—
2016		—
Thereafter		3,500,000	(3)
	$	4,635,000

(1) Represents our 5.375% senior notes due August 2012.

(2) Represents amounts drawn on revolving credit facilities, which expire September 2014.

(3) Represents our 6.15% senior notes due February 2018, 9.25% senior notes due January 2019, 5.0% senior notes due September 2020 and 4.625% senior notes due September 2021.

Short-Term Borrowings

	December 31,
	2011			2010
	(In thousands)
Credit available	$	215,901		$	270,263
Letters of credit outstanding, inclusive of financial and performance guarantees		(80,408	)		(70,605	)
Remaining availability	$	135,493		$	199,658

XML

Segment Information

12 Months Ended

Dec. 31, 2011

Segment Information [Abstract]

Segment Information

Note 22    Segment Information

As of December 31, 2011, we operated our business out of 10 operating segments. Our six Contract Drilling operating segments are engaged in drilling, workover and well-servicing operations, on land and offshore, and represent reportable segments. These operating segments consist of our Alaska, U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, U.S. Offshore, Canada and International business units. Our hydraulic fracturing and downhole surveying services are included in our Pressure Pumping operating segment. Our oil and gas operating segment includes our unconsolidated U.S. oil and gas joint venture. This segment is engaged in the exploration for, and the development of and production of oil and natural gas. Our Other Operating Segments, consisting of Canrig Drilling Technology Ltd. and Ryan Directional Services, Inc., are engaged in the manufacturing of top drives, manufacturing of drilling instrumentation systems, construction services, trucking and logistics services, manufacturing and marketing of directional drilling and rig instrumentation systems, directional drilling, and rig instrumentation and data collection services. These Other Operating Segments do not meet the criteria for disclosure, individually or in the aggregate, as reportable segments.

The accounting policies of the segments are the same as those described in Note 2 — Summary of Significant Accounting Policies. Inter-segment sales are recorded at cost or cost plus a profit margin. We evaluate the performance of our segments based on several criteria, including adjusted income (loss) derived from operating activities.

The following table sets forth financial information with respect to our reportable segments:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Operating revenues and earnings (losses) from unconsolidated affiliates from continuing operations:(1)
Contract Drilling:(2)
U.S. Lower 48 Land Drilling	$	1,698,620		$	1,294,853		$	1,082,531
U.S. Land Well-servicing		701,223			444,665			412,243
U.S. Offshore		170,727			123,761			157,305
Alaska		129,894			179,218			204,407
Canada		574,754			389,229			298,653
International		1,104,461			1,093,608			1,265,097
Subtotal Contract Drilling(3)		4,379,679			3,525,334			3,420,236
Pressure Pumping(4)		1,237,306			321,295			—
Oil and Gas(5)(6)		59,685			18,657			(182,654	)
Other Operating Segments(7)(8)		674,206			427,154			417,531
Other reconciling items(9)		(233,878	)		(124,690	)		(148,325	)
Total	$	6,116,998		$	4,167,750		$	3,506,788
Depreciation and amortization, and depletion:(1)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	288,373		$	241,258		$	226,875
U.S. Land Well-servicing		78,314			65,561			69,557
U.S. Offshore		37,242			37,059			37,204
Alaska		34,989			37,195			29,946
Canada		75,919			74,735			65,883
International		273,315			247,134			208,949
Subtotal Contract Drilling		788,152			702,942			638,414
Pressure Pumping(4)		102,009			32,204			—
Oil and Gas		—			—			—
Other Operating Segments		34,162			28,452			27,441
Other reconciling items(9)		(229	)		(2,636	)		(1,897	)
Total depreciation and amortization, and depletion	$	924,094		$	760,962		$	663,958
Adjusted income (loss) derived from operating activities from continuing operations:(1)(10)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	414,317		$	274,215		$	294,679
U.S. Land Well-servicing		74,725			31,597			28,950
U.S. Offshore		843			9,245			30,508
Alaska		27,671			51,896			62,742
Canada		94,637			22,970			(7,019	)
International		123,813			254,744			365,566
Subtotal Contract Drilling(3)		736,006			644,667			775,426
Pressure Pumping(4)		229,125			66,651			—
Oil and Gas(5)(6)		59,685			18,657			(182,654	)
Other Operating Segments(7)(8)		55,617			42,401			35,319
Other reconciling items(11)		(153,385	)		(104,827	)		(188,257	)
Total adjusted income derived from operating activities	$	927,048		$	667,549		$	439,834
Interest expense		(256,633	)		(272,712	)		(266,047	)
Investment income (loss)		19,940			7,263			25,522
Gains (losses) on sales and retirements of long-lived assets and other (income) expense, net		(4,514	)		(47,238	)		(11,982	)
Impairments and other charges(12)		(198,072	)		(61,292	)		(118,543	)
Income (loss) from continuing operations before income taxes		487,769			293,570			68,784
Income tax expense (benefit)		142,605			36,950			(63,937	)
Subsidiary preferred stock dividend		3,000			750			—
Income (loss) from continuing operations, net of tax		342,164			255,870			132,721
Income (loss) from discontinued operations, net of tax		(97,440	)		(161,090	)		(218,609	)
Net income (loss)		244,724			94,780			(85,888	)
Less: Net income (loss) attributable to noncontrolling interest		(1,045	)		(85	)		342
Net income (loss) attributable to Nabors	$	243,679		$	94,695		$	(85,546	)

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Capital expenditures and acquisitions of businesses:(13)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	650,342		$	294,239		$	327,269
U.S. Land Well-servicing		165,953			84,657			16,671
U.S. Offshore		63,817			23,625			48,694
Alaska		5,582			891			55,426
Canada		95,001			53,834			29,214
International		653,759			365,597			328,252
Subtotal Contract Drilling		1,634,454			822,843			805,526
Pressure Pumping(4)		285,304			924,693			—
Oil and Gas		208,995			113,361			184,185
Other Operating Segments		136,515			28,799			20,446
Other reconciling items(11)(17)		(17,533	)		(11,633	)		(19,870	)
Total capital expenditures and acquisitions of businesses	$	2,247,735		$	1,878,063		$	990,287

	December 31,
	2011		2010		2009
	(In thousands)
Total assets:
Contract Drilling:(14)
U.S. Lower 48 Land Drilling	$	3,216,803	$	2,762,362	$	2,609,101
U.S. Land Well-servicing		812,049		630,518		594,456
U.S. Offshore		402,506		379,292		440,556
Alaska		288,253		313,123		373,146
Canada		962,239		1,065,268		984,740
International		3,702,611		3,279,763		3,151,513
Subtotal Contract Drilling		9,384,461		8,430,326		8,153,512
Pressure Pumping(4)		1,503,298		1,163,236		—
Oil and Gas(15)		796,327		805,410		835,465
Other Operating Segments(16)		720,775		539,373		502,501
Other reconciling items(11)(17)		507,279		708,224		1,153,212
Total assets	$	12,912,140	$	11,646,569	$	10,644,690

(1) All periods present the operating activities of our wholly owned oil and gas assets in the United States, Canada and Colombia, including equity interests in Canada and Colombia, as well as the Nabors Blue Sky Ltd. business as discontinued operations.

(2) These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore.

(3) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.2) million, $6.9 million and $9.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.

(4) Includes operating results of the Superior acquisition beginning September 10, 2010.

(5) Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(15.6) million and $(189.3) million for the years ended December 31, 2011 and 2009, respectively.

(6) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $59.7 million, $18.7 million and $(182.6) million for the years ended December 31, 2011, 2010 and 2009, respectively. Additional information is provided in Note 24 — Supplemental Information on Oil and Gas Exploration and Production Activities.

(7) Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction operations.

(8) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.9) million, $7.7 million and $17.5 million for the years ended December 31, 2011, 2010 and 2009, 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 in accordance with 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 accurately reflect 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 in the above table.

(11) Represents the elimination of inter-segment transactions and unallocated corporate expenses, assets and capital expenditures.

(12) Represents impairments and other charges recorded during the years ended December 31, 2011, 2010 and 2009, respectively.

(13) Includes the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.

(14) Includes $51.5 million, $54.8 million and $49.8 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(15) Includes $294.1 million, $146.5 million and $190.1 million investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(16) Includes $25.4 million, $64.5 million and $65.8 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(17) Includes $1.9 million and $.9 million of investments in unconsolidated affiliates accounted for using the cost method as of December 31, 2010 and 2009, respectively.

The following table sets forth financial information with respect to Nabors’ operations by geographic area:

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Operating revenues and earnings (losses) from unconsolidated affiliates from continuing operations:
U.S.	$	4,329,079	$	2,612,954	$	1,817,374
Outside the U.S.		1,787,919		1,554,796		1,689,414
	$	6,116,998	$	4,167,750	$	3,506,788
Property, plant and equipment, net:
U.S.	$	4,974,239	$	4,447,388	$	4,107,250
Outside the U.S.		3,655,707		3,368,031		3,538,800
	$	8,629,946	$	7,815,419	$	7,646,050
Goodwill:
U.S.	$	466,794	$	459,560	$	130,275
Outside the U.S.		34,464		34,812		33,990
	$	501,258	$	494,372	$	164,265

XML

Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2011

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

Note 23    Condensed Consolidating Financial Information

Nabors has fully and unconditionally guaranteed all of the issued public debt securities of Nabors Delaware, and Nabors and Nabors Delaware fully and unconditionally guaranteed the 4.875% senior notes due August 2009 issued by Nabors Holdings 1, ULC, an unlimited liability company formed under the Companies Act of Nova Scotia, Canada and a subsidiary of Nabors (“Nabors Holdings”). During 2009, we paid the balance of Nabors Holdings 1, ULC’s 4.875% senior notes. Effective September 30, 2009, Nabors Holdings 1, ULC was amalgamated with Nabors Drilling Canada ULC, the successor company.

The following condensed consolidating financial information is included so that separate financial statements of Nabors Delaware and Nabors Holdings are not required to be filed with the SEC. The condensed consolidating financial statements present investments in both consolidated and unconsolidated affiliates using the equity method of accounting.

The following condensed consolidating financial information presents condensed consolidating balance sheets as of December 31, 2011 and 2010, statements of income (loss) for the years ended December 31, 2011, 2010 and 2009 and the consolidating statements of cash flows for the years ended December 31, 2011, 2010 and 2009 of (a) Nabors, parent/guarantor, (b) Nabors Delaware, issuer of public debt securities guaranteed by Nabors and guarantor of the 4.875% senior notes issued by Nabors Holdings, (c) Nabors Holdings, issuer of the 4.875% senior notes, (d) the non-guarantor subsidiaries, (e) consolidating adjustments necessary to consolidate Nabors and its subsidiaries and (f) Nabors on a consolidated basis.

Condensed Consolidating Balance Sheets

	December 31, 2011
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)		Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments			Consolidated Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	203	$	21	$	—	$	398,351	$	—		$	398,575
Short-term investments		—		—		—		140,914		—			140,914
Assets held for sale		—		—		—		401,500		—			401,500
Accounts receivable, net		—		—		—		1,576,555		—			1,576,555
Inventory		—		—		—		272,852		—			272,852
Deferred income taxes		—		—		—		127,874		—			127,874
Other current assets		50		671		—		169,323		—			170,044
Total current assets		253		692		—		3,087,369		—			3,088,314
Long-term investments and other receivables		—		—		—		11,124		—			11,124
Property, plant and equipment, net		—		40,792		—		8,589,154		—			8,629,946
Goodwill		—		—		—		501,258		—			501,258
Intercompany receivables		164,760		—		—		537,881		(702,641	)		—
Investment in unconsolidated affiliates		5,429,029		6,084,868		—		1,843,654		(12,986,530	)		371,021
Other long-term assets		—		32,037		—		278,440		—			310,477
Total assets	$	5,594,042	$	6,158,389	$	—	$	14,848,880	$	(13,689,171	)	$	12,912,140
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	274,604	$	—	$	722	$	—		$	275,326
Trade accounts payable		42		23		—		782,688		—			782,753
Accrued liabilities		6,185		100,101		—		556,200		—			662,486
Asset held for sale		—		—		—		54,287		—			54,287
Income taxes payable		—				—		27,710		—			27,710
Total current liabilities		6,227		374,728		—		1,421,607		—			1,802,562
Long-term debt		—		4,297,500		—		50,990		—			4,348,490
Asset held for sale		—		—		—		71,375		—			71,375
Other long-term liabilities		—		32,303		—		189,079		—			221,382
Deferred income taxes		—		11,221		—		786,705		—			797,926
Intercompany payable		—		379,400		—		323,241		(702,641	)		—
Total liabilities		6,227		5,095,152		—		2,842,997		(702,641	)		7,241,735
Subsidiary preferred stock		—		—		—		69,188		—			69,188
Shareholders’ equity		5,587,815		1,063,237		—		11,923,293		(12,986,530	)		5,587,815
Noncontrolling interest		—		—		—		13,402		—			13,402
Total equity		5,587,815		1,063,237		—		11,936,695		(12,986,530	)		5,601,217
Total liabilities and equity	$	5,594,042	$	6,158,389	$	—	$	14,848,880	$	(13,689,171	)	$	12,912,140

	December 31, 2010
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)		Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments			Consolidated Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,847	$	20	$	—	$	630,835	$	—		$	641,702
Short-term investments		—		—		—		159,488		—			159,488
Assets held for sale		—		—		—		352,048		—			352,048
Accounts receivable, net		—		—		—		1,116,510		—			1,116,510
Inventory		—		—		—		158,836		—			158,836
Deferred income taxes		—		—		—		31,510		—			31,510
Other current assets		50		16,366		—		136,420		—			152,836
Total current assets		10,897		16,386		—		2,585,647		—			2,612,930
Long-term investments and other receivables		—		—		—		40,300		—			40,300
Property, plant and equipment, net		—		44,270		—		7,771,149		—			7,815,419
Goodwill		—		—		—		494,372		—			494,372
Intercompany receivables		160,250		—		—		322,697		(482,947	)		—
Investment in unconsolidated affiliates		5,160,800		5,814,219		—		1,665,459		(12,372,755	)		267,723
Other long-term assets		—		36,538		—		379,287		—			415,825
Total assets	$	5,331,947	$	5,911,413	$	—	$	13,258,911	$	(12,855,702	)	$	11,646,569
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	1,378,178	$	—	$	840	$	—		$	1,379,018
Trade accounts payable		—		—		—		355,282		—			355,282
Accrued liabilities		3,785		89,480		—		301,027		—			394,292
Income taxes payable		—		6,859		—		18,929		—			25,788
Total current liabilities		3,785		1,474,517		—		676,078		—			2,154,380
Long-term debt		—		3,062,291		—		1,835		—			3,064,126
Other long-term liabilities		—		12,787		—		232,978		—			245,765
Deferred income taxes		—		71,815		—		698,432		—			770,247
Intercompany payable		—		301,451		—		181,496		(482,947	)		—
Total liabilities		3,785		4,922,861		—		1,790,819		(482,947	)		6,234,518
Subsidiary preferred stock		—		—		—		69,188		—			69,188
Shareholders’ equity		5,328,162		988,552		—		11,384,203		(12,372,755	)		5,328,162
Noncontrolling interest		—		—		—		14,701		—			14,701
Total equity		5,328,162		988,552		—		11,398,904		(12,372,755	)		5,342,863
Total liabilities and equity	$	5,331,947	$	5,911,413	$	—	$	13,258,911	$	(12,855,702	)	$	11,646,569

Condensed Consolidating Statements of Income (Loss)

	Year Ended December 31, 2011
	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—	$	—		$	—	$	6,060,351		$	—		$	6,060,351
Earnings (losses) from unconsolidated affiliates		—		—			—		56,647			—			56,647
Earnings (losses) from consolidated affiliates		256,245		214,308			—		107,536			(578,089	)		—
Investment income (loss)		4		68			—		19,868			—			19,940
Intercompany interest income		—		69,437			—		—			(69,437	)		—
Total revenues and other income		256,249		283,813			—		6,244,402			(647,526	)		6,136,938
Costs and other deductions:
Direct costs		—		—			—		3,775,964			—			3,775,964
General and administrative expenses		11,970		348			—		478,174			(600	)		489,892
Depreciation and amortization		—		3,532			—		920,562			—			924,094
Interest expense		—		278,657			—		(22,024	)		—			256,633
Intercompany interest expense		—		—			—		69,437			(69,437	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		600		(1,904	)		—		5,218			600			4,514
Impairments and other charges		—		—			—		198,072			—			198,072
Total costs and other deductions		12,570		280,633			—		5,425,403			(69,437	)		5,649,169
Income (loss) from continuing operations before income taxes		243,679		3,180			—		818,999			(578,089	)		487,769
Income tax expense (benefit)		—		(78,118	)		—		220,723			—			142,605
Subsidiary preferred stock dividend		—		—			—		3,000			—			3,000
Income (loss) from continuing operations, net of tax		243,679		81,298			—		595,276			(578,089	)		342,164
Income (loss) from discontinued operations, net of tax		—		—			—		(97,440	)		—			(97,440	)
Net income (loss)		243,679		81,298			—		497,836			(578,089	)		244,724
Less: Net (income) loss attributable to noncontrolling interest		—		—			—		(1,045	)		—			(1,045	)
Net income (loss) attributable to Nabors	$	243,679	$	81,298		$	—	$	496,791		$	(578,089	)	$	243,679

	Year Ended December 31, 2010
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—		$	—		$	—	$	4,134,483		$	—		$	4,134,483
Earnings (losses) from unconsolidated affiliates		—			—			—		33,267			—			33,267
Earnings (losses) from consolidated affiliates		68,749			(183,242	)		—		(316,657	)		431,150			—
Investment income (loss)		15			—			—		7,248			—			7,263
Intercompany interest income		—			72,435			—		—			(72,435	)		—
Total revenues and other income		68,764			(110,807	)		—		3,858,341			358,715			4,175,013
Costs and other deductions:
Direct costs		—			—			—		2,400,519			—			2,400,519
General and administrative expenses		9,165			445			—		330,067			(957	)		338,720
Depreciation and amortization		—			3,303			—		757,659			—			760,962
Interest expense		—			283,396			—		(10,684	)		—			272,712
Intercompany interest expense		—			—			—		72,435			(72,435	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		(35,096	)		42,504			—		38,873			957			47,238
Impairments and other charges		—			—			—		61,292			—			61,292
Total costs and other deductions		(25,931	)		329,648			—		3,650,161			(72,435	)		3,881,443
Income (loss) from continuing operations before income taxes		94,695			(440,455	)		—		208,180			431,150			293,570
Income tax expense (benefit)		—			(95,168	)		—		132,118			—			36,950
Subsidiary preferred stock dividend		—			—			—		750			—			750
Income (loss) from continuing operations, net of tax		94,695			(345,287	)		—		75,312			431,150			255,870
Income (loss) from discontinued operations, net of tax		—			—			—		(161,090	)		—			(161,090	)
Net income (loss)		94,695			(345,287	)		—		(85,778	)		431,150			94,780
Less: Net (income) loss attributable to noncontrolling interest		—			—			—		(85	)		—			(85	)
Net income (loss) attributable to Nabors	$	94,695		$	(345,287	)	$	—	$	(85,863	)	$	431,150		$	94,695

	Year Ended December 31, 2009
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—		$	—		$	—		$	3,662,220		$	—		$	3,662,220
Earnings (losses) from unconsolidated affiliates		—			—			—			(155,432	)		—			(155,432	)
Earnings (losses) from consolidated affiliates		(74,204	)		(316,443	)		(86,751	)		(441,133	)		918,531			—
Investment income (loss)		58			2,357			101			23,006			—			25,522
Intercompany interest income		—			66,150			5,558			—			(71,708	)		—
Total revenues and other income		(74,146	)		(247,936	)		(81,092	)		3,088,661			846,823			3,532,310
Costs and other deductions:
Direct costs		—			—			—			1,981,504			—			1,981,504
General and administrative expenses		28,350			336			1			393,375			(570	)		421,492
Depreciation and amortization		—			3,594			—			660,364			—			663,958
Interest expense		—			288,715			5,634			(28,302	)		—			266,047
Intercompany interest expense		—			—			—			71,708			(71,708	)		—
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net		(16,950	)		4,145			5,069			37,395			(17,677	)		11,982
Impairments and other charges		—			—			—			118,543			—			118,543
Total costs and other deductions		11,400			296,790			10,704			3,234,587			(89,955	)		3,463,526
Income (loss) from continuing operations before income taxes		(85,546	)		(544,726	)		(91,796	)		(145,926	)		936,778			68,784
Income tax expense (benefit)		—			(84,465	)		15,744			4,784			—			(63,937	)
Income (loss) from continuing operations, net of tax		(85,546	)		(460,261	)		(107,540	)		(150,710	)		936,778			132,721
Income (loss) from discontinued operations, net of tax		—			—			—			(218,609	)		—			(218,609	)
Net income (loss)		(85,546	)		(460,261	)		(107,540	)		(369,319	)		936,778			(85,888	)
Less: Net (income) loss attributable to noncontrolling interest		—			—			—			342			—			342
Net income (loss) attributable to Nabors	$	(85,546	)	$	(460,261	)	$	(107,540	)	$	(368,977	)	$	936,778		$	(85,546	)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2011
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	6,612		$	(31,178	)	$	—	$	1,481,053		$			$	1,456,487
Cash flows from investing activities:
Purchases of investments		—			—			—		(11,746	)		—			(11,746	)
Sales and maturities of investments		—			—			—		39,063			—			39,063
Cash paid for acquisition of businesses, net		—			—			—		(55,459	)		—			(55,459	)
Investment in unconsolidated affiliates		—			—			—		(112,262	)		—			(112,262	)
Distribution of proceeds from asset sales of unconsolidated affiliates		—			—			—		142,984			—			142,984
Capital expenditures		—			—			—		(2,042,617	)		—			(2,042,617	)
Proceeds from sales of assets and insurance claims		—			—			—		180,558			—			180,558
Cash paid for investments in consolidated affiliates		(26,235	)		(65,000	)		—		—			91,235			—
Net cash provided by (used for) investing activities		(26,235	)		(65,000	)		—		(1,859,479	)		91,235			(1,859,479	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—		6,375			—			6,375
Proceeds from long-term debt		—			697,578			—		—			—			697,578
Debt issuance costs		—			(7,141	)		—		—			—			(7,141	)
Proceeds from revolving credit facilities		—			1,510,000			—		50,000			—			1,560,000
Proceeds from issuance of common shares		11,605			—			—		—			—			11,605
Reduction in long-term debt		—			(1,404,246	)		—		(35	)		—			(1,404,281	)
Reduction in revolving credit facilities		—			(700,000	)		—		—			—			(700,000	)
Repurchase of equity component of convertible debt		—			(12	)		—		—			—			(12	)
Purchase of restricted stock		(2,626	)		—			—		—			—			(2,626	)
Tax benefit related to share-based awards		—			—			—		1,747			—			1,747
Proceeds from parent contributions		—			—			—		91,235			(91,235	)		—
Net cash (used for) provided by financing activities		8,979			96,179			—		149,322			(91,235	)		163,245
Effect of exchange rate changes on cash and cash equivalents		—			—			—		(3,380	)		—			(3,380	)
Net (decrease) increase in cash and cash equivalents		(10,644	)		1			—		(232,484	)		—			(243,127	)
Cash and cash equivalents, beginning of period		10,847			20			—		630,835			—			641,702
Cash and cash equivalents, end of period	$	203		$	21		$	—	$	398,351		$	—		$	398,575

	Year Ended December 31, 2010
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)		Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	115,179		$	757,345		$	—	$	504,460		$	(270,000	)	$	1,106,984
Cash flows from investing activities:
Purchases of investments		—			—			—		(34,147	)		—			(34,147	)
Sales and maturities of investments		—			—			—		34,613			—			34,613
Cash paid for acquisition of businesses, net		—			—			—		(733,630	)		—			(733,630	)
Investment in unconsolidated affiliates		—			—			—		(40,936	)		—			(40,936	)
Capital expenditures		—			—			—		(930,277	)		—			(930,277	)
Proceeds from sales of assets and insurance claims		—			—			—		31,072			—			31,072
Cash paid for investments in consolidated affiliates		(122,300	)		(1,027,134	)		—		—			1,149,434			—
Net cash provided by (used for) investing activities		(122,300	)		(1,027,134	)		—		(1,673,305	)		1,149,434			(1,673,305	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—		(6,298	)		—			(6,298	)
Proceeds from long-term debt		—			696,948			—		—			—			696,948
Debt issuance costs		—			(8,934	)		—		—			—			(8,934	)
Payments for hedge transactions		—			(5,667	)		—		—			—			(5,667	)
Proceeds from revolving credit facilities		—			600,000			—		—			—			600,000
Proceeds from issuance of common shares		8,201			—			—		—			—			8,201
Reduction in long-term debt		—			(274,095	)		—		(124,419	)		—			(398,514	)
Reduction in revolving credit facilities		—			(600,000	)		—		—			—			(600,000	)
Repurchase of equity component of convertible debt		—			(4,712	)		—		—			—			(4,712	)
Settlement of call options and warrants, net		—			1,134			—		—			—			1,134
Purchase of restricted stock		(1,935	)		—			—		—			—			(1,935	)
Tax benefit related to share-based awards		—			—			—		31			—			31
Cash dividends paid		—			(135,000	)		—		(135,000	)		270,000			—
Proceeds from parent contributions		—			—			—		1,149,434			(1,149,434	)		—
Net cash (used for) provided by financing activities		6,266			269,674			—		883,748			(879,434	)		280,254
Effect of exchange rate changes on cash and cash equivalents		—			—			—		(46	)		—			(46	)
Net (decrease) increase in cash and cash equivalents		(855	)		(115	)		—		(285,143	)		—			(286,113	)
Cash and cash equivalents, beginning of period		11,702			135			—		915,978			—			927,815
Cash and cash equivalents, end of period	$	10,847		$	20		$	—	$	630,835		$	—		$	641,702

	Year Ended December 31, 2009
	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Nabors Holdings (Issuer)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
	(In thousands)
Net cash provided by (used for) operating activities	$	40,589		$	646,645		$	608		$	1,089,086		$	(159,956	)	$	1,616,972
Cash flows from investing activities:
Purchases of investments		—			—			—			(32,674	)		—			(32,674	)
Sales and maturities of investments		—			—			—			57,033			—			57,033
Investment in unconsolidated affiliates		—			—			—			(125,076	)		—			(125,076	)
Capital expenditures		—			—			—			(1,093,435	)		—			(1,093,435	)
Proceeds from sales of assets and insurance claims		—			—			—			31,375			—			31,375
Proceeds from sale of consolidated affiliates		—			—			239,421			(239,421	)		—			—
Cash paid for investments in consolidated affiliates		(46,912	)		(900,000	)		—			—			946,912			—
Net cash provided by (used for) investing activities		(46,912	)		(900,000	)		239,421			(1,402,198	)		946,912			(1,162,777	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			—			(18,157	)		—			(18,157	)
Proceeds from long-term debt		—			1,124,978			—			—			—			1,124,978
Debt issuance costs		—			(8,832	)		—			—			—			(8,832	)
Intercompany debt		—			—			143,859			(143,859	)		—			—
Proceeds from issuance of common shares		11,249			—			—			—			—			11,249
Reduction in long-term debt		—			(856,203	)		(225,191	)		(407	)		—			(1,081,801	)
Repurchase of equity component of convertible debt		—			(6,586	)		—			—			—			(6,586	)
Purchase of restricted stock		(1,515	)		—			—			—			—			(1,515	)
Tax benefit related to share-based awards		—			37			—			—			—			37
Cash dividends paid		—			—			(159,956	)		—			159,956			—
Proceeds from parent contributions		—			—			—			946,912			(946,912	)		—
Net cash (used for) provided by financing activities		9,734			253,394			(241,288	)		784,489			(786,956	)		19,373
Effect of exchange rate changes on cash and cash equivalents		—			—			—			12,160			—			12,160
Net (decrease) increase in cash and cash equivalents		3,411			39			(1,259	)		483,537			—			485,728
Cash and cash equivalents, beginning of period		8,291			96			1,259			432,441			—			442,087
Cash and cash equivalents, end of period	$	11,702		$	135		$	—		$	915,978		$	—		$	927,815

XML

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Tax effects on unrealized gains/(losses) on marketable securities	$ 86	$ 7,435	$ 839
Tax effect on unrealized gains/(losses) on adjusted basis for marketable debt security			1,199
Tax effects on reclassification adjustment for (gains)/losses included in net income (loss)	0	693	4,921
Tax effect on pension liability amortization	319	259	325
Tax effect on Pension liability adjustment	2,421	405	89
Tax effect on amortization of (gains)/losses on cash flow hedges	239	2,119	18
Accumulated Other Comprehensive Income
Tax effects on unrealized gains/(losses) on marketable securities	86	7,435	839
Tax effect on unrealized gains/(losses) on adjusted basis for marketable debt security			1,199
Tax effects on reclassification adjustment for (gains)/losses included in net income (loss)	0	693	4,921
Tax effect on pension liability amortization	319	259	325
Tax effect on Pension liability adjustment			89
Tax effect on amortization of (gains)/losses on cash flow hedges	$ 239	$ 2,119	$ 18

XML

Supplemental Information On Oil and Gas Exploration and Production Activities (unaudited)

12 Months Ended

Dec. 31, 2011

Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited) [Abstract]

Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited)

Note 24    Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited)

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 Canadian 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 at December 31, 2009. Accordingly after the one-year deferral, we are presenting the information with regard to our oil and gas producing activities for the years ended December 31, 2011 and 2010.

The estimates of net proved oil and gas reserves as of December 31, 2011 were based on reserve reports prepared by independent petroleum engineers. AJM Deloitte 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. Cawley, Gillespie & Associates, Inc. prepared reports of estimated proved oil reserves for wholly owned assets located in the Eagle Ford Shale and Giddings field in Grimes County, Texas.

The estimates of net proved natural gas and oil reserves as of December 31, 2010 were based on reserve reports prepared by the following 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 properties located in the Cat Canyon and West Cat Canyon Fields in Santa Barbara County, California. Lonquist & Co., LLC prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Colombia.

The following supplementary information includes our results of operations for oil and gas production activities; capitalized costs related to oil and gas producing activities; and costs incurred in oil and gas property acquisition, exploration and development. Supplemental information is also provided for the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

Results of Operations

Results of operations consist of all activities within our Oil and Gas operating segment, or in discontinued operations in some cases. Net revenues from production include only the revenues from the production and sale of natural gas, oil, and natural gas liquids. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization (“DD&A”) allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

	United States			Canada			Colombia			Total
	(in thousands)
Results of Operations
For the year ended December 31, 2011:
Consolidated Subsidiaries
Revenue	$	25,684		$	7,046		$	12,378		$	45,108
Production costs		12,682			27,432	(3)		3,704			43,818
Exploration expenses		23,768			3,324			122			27,214
Depreciation and depletion		22,350			104			949			23,403
Impairment of oil and gas properties		71,392			183,654						255,046
Loss (gain) on dispositions		(6,642	)		—			(39,599	)		(46,241	)
Related income tax expense (benefit)		(38,707	)		(54,979	)		15,577			(78,109	)
Results of producing activities for consolidated subsidiaries	$	(59,159	)	$	(152,489	)	$	31,625		$	(180,023	)
Equity Companies(1)
Revenue	$	98,933		$	1,335		$	26,730		$	126,998
Production costs		27,790			4,600			10,598			42,988
Depreciation and depletion		39,564			1,032			9,806			50,402
Impairment of oil and gas properties		15,624			—			—			15,624
Realized loss (gain) on derivative instruments		(33,969	)		(84	)		—			(34,053	)
Loss (gain) on acquisitions/dispositions		(49,484	)		—			(95,301	)		(144,785	)
Related income tax expense (benefit)(2)		—			—			6,055			6,055
Results of producing activities for equity companies	$	99,408		$	(4,213	)	$	95,572		$	190,767
Total results of operations	$	40,249		$	(156,702	)	$	127,197		$	10,744
For the year ended December 31, 2010:
Consolidated Subsidiaries
Revenue	$	19,180		$	11,276		$	16,619		$	47,075
Production costs		8,510			7,965			7,918			24,393
Exploration expenses		—			—			39,047			39,047
Depreciation and depletion		20,092			5,424			3,737			29,253
Impairment of oil and gas properties		110,165			—			—			110,165
Related income tax expense (benefit)		(15,856	)		(3,078	)		610			(18,324	)
Results of producing activities for consolidated subsidiaries	$	(103,731	)	$	965		$	(34,693	)	$	(137,459	)
Equity Companies(1)
Revenue	$	64,736		$	6,038		$	20,176		$	90,950
Production costs		18,460			9,036			9,174			36,670
Depreciation and depletion		24,221			6,033			7,058			37,312
Impairment of oil and gas properties		851			—			—			851
Realized gain on derivative instruments		(25,424	)		(2,543	)		—			(27,967	)
Related income tax expense (benefit)(2)		—			—			—			—
Results of producing activities for equity companies	$	46,628		$	(6,488	)	$	3,944		$	44,084
Total results of operations	$	(57,103	)	$	(5,523	)	$	(30,749	)	$	(93,375	)

(1) Represents our proportionate share of interests in our equity companies.

(2) Equity companies are pass-through entities for tax purposes.

(3) Includes $24.2 million of transportation costs from pipeline commitments.

Capitalized Cost

Capitalized costs include the cost of properties, equipment and facilities for oil and gas-producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or for active completion, and costs of exploratory wells suspended or waiting for completion.

	United States			Canada			Colombia			Total
	(in thousands)
Capitalized Costs
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	587,385		$	101,402		$	—		$	688,787
Property acquisition costs, unproved		101,611			92,750			23,767			218,128
Total acquisition costs		688,996			194,152			23,767			906,915
Accumulated depreciation and depletion		(539,380	)		(28,838	)		(741	)		(568,959	)
Net capitalized costs for consolidated subsidiaries	$	149,616		$	165,314		$	23,026		$	337,956
Equity Companies(1)
Property acquisition costs, proved	$	1,141,393		$	—		$	—		$	1,141,393
Property acquisition costs, unproved		103,657			—			—			103,657
Total acquisition costs		1,245,050			—			—			1,245,050
Accumulated depreciation and depletion		(512,503	)		—			—			(512,503	)
Net capitalized costs for equity companies	$	732,547		$	—		$	—		$	732,547
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	480,618		$	62,109		$	57,251		$	599,978
Property acquisition costs, unproved		136,625			89,785			1,174			227,584
Total acquisition costs		617,243			151,894			58,425			827,562
Accumulated depreciation and depletion		(463,330	)		(7,344	)		(3,782	)		(474,456	)
Net capitalized costs for consolidated subsidiaries	$	153,913		$	144,550		$	54,643		$	353,106
Equity Companies(1)
Property acquisition costs, proved	$	749,515		$	78,224		$	98,629		$	926,368
Property acquisition costs, unproved		108,541			28,884			883			138,308
Total acquisition costs		858,056			107,108			99,512			1,064,676
Accumulated depreciation and depletion		(460,622	)		(72,338	)		(31,825	)		(564,785	)
Net capitalized costs for equity companies	$	397,434		$	34,770		$	67,687		$	499,891

(1) Represents our proportionate share of interests in our equity companies.

Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense during 2011 and 2010, respectively, for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs include the costs of drilling and equipping successful exploration wells, as well as dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

	United States		Canada		Colombia			Total
	(in thousands)
Costs incurred in property acquisitions, exploration and development activities
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	23,051	$	7,748	$	—		$	30,799
Property acquisition costs, unproved		37,272		26,099		—			63,371
Exploration costs		49,156		—		122			49,278
Development costs		43,780		184		19,605			63,569
Asset retirement costs		496		750		254			1,500
Total costs incurred for consolidated subsidiaries	$	153,755	$	34,781	$	19,981		$	208,517
Equity Companies(1)
Property acquisition costs, proved	$	232,410	$	—	$	—		$	232,410
Property acquisition costs, unproved		14,268		—		4,395			18,663
Exploration costs		252		—		—			252
Development costs		136,711		—		—			136,711
Asset retirement costs		2,834		—		—			2,834
Total costs incurred for equity companies	$	386,475	$	—	$	4,395		$	390,870
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	25,080	$	—	$	—		$	25,080
Property acquisition costs, unproved		25,202		—		1,000			26,202
Exploration costs		8,199		—		33,599			41,798
Development costs		19,118		3,876		—			22,994
Asset retirement costs		—		—		770			770
Total costs incurred for consolidated subsidiaries	$	77,599	$	3,876	$	35,369		$	116,844
Equity Companies(1)
Property acquisition costs, proved	$	29,975	$	—	$	—		$	29,975
Property acquisition costs, unproved		34,207		—		—			34,207
Exploration costs		108		—		29,927			30,035
Development costs		118,828		1,056		11,805			131,689
Asset retirement costs		296		—		(104	)		192
Total costs incurred for equity companies	$	183,414	$	1,056	$	41,628		$	226,098

(1) Represents our proportionate share of interests in equity companies.

Oil and Gas Reserves

The reserve disclosures that follow reflect estimates of proved reserves for our consolidated subsidiaries and equity companies of natural gas, oil, and natural gas liquids owned at December 31, 2011 and 2010 and changes in proved reserves during 2011 and 2010. Our year-end reserve volumes in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserve quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Estimates of volumes of proved reserves of natural gas at year end are expressed in billions of cubic feet of natural gas (“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 and the properties of our unconsolidated U.S. joint venture, the prices used in our reserve reports were $4.12 per mcf for the 12-month average of natural gas, $57.71 per barrel for natural gas liquids and $96.19 per barrel for oil at December 31, 2011. For our wholly owned properties in Canada, the price used in our reserve reports was $3.85 per mcf for the 12-month average of natural gas at December 31, 2011.

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 liquid natural gas and $61.12 per barrel for oil at December 31, 2010. The prices used in our 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 liquid natural gas 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.

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, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in average prices and year-end costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.

Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and our ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others.

In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, we do not view equity company reserves any differently than those of our consolidated subsidiaries.

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

	United States						Canada					Colombia					Total
Reserves	Liquids (MMBbls)			Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)			Liquids (MMBbls)			Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)
Net proved reserves of consolidated subsidiaries
January 1, 2011		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Revisions		0.1			(3.9	)		—		0.9			—			—		0.1			(3.0	)
Extensions, additions and discoveries		1.6			4.0			—		—			—			—		1.6			4.0
Production		(0.2	)		(3.0	)		—		(2.1	)		(0.1	)		—		(0.3	)		(5.1	)
Purchases in place		—			—			—		3.9			—			—		—			3.9
Sales in place		(20.9	)(2)		—			—		—			(1.9	)		—		(22.8	)		—
December 31, 2011		1.8			16.9			—		8.2			—			—		1.8			25.1
January 1, 2010		0.4			29.6			—		5.0			0.9			—		1.3			34.6
Revisions		0.1			(11.7	)		—		3.6			(0.7	)		—		(0.6	)		(8.1	)
Extensions, additions and discoveries		—			5.0			—		—			2.0			—		2.0			5.0
Production		(0.1	)		(3.1	)		—		(3.1	)		(0.2	)		—		(0.3	)		(6.2	)
Purchases in place		20.8	(2)		—			—		—			—			—		20.8			—
Sales in place		—			—			—		—			—			—		—			—
December 31, 2010		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Proportional interest in proved reserves of equity companies
January 1, 2011		7.9			552.8			—		5.2			1.9			—		9.8			558.0
Revisions		(4.2	)		(359.0	)		—		—			—			—		(4.2	)		(359.0	)
Extensions, additions and discoveries		3.2			103.1			—		—			—			—		3.2			103.1
Production		(0.4	)		(18.6	)		—		(0.4	)		(0.3	)		—		(0.7	)		(19.0	)
Purchases in place		9.4			304.2	(3)		—		—			—			—		9.4			304.2
Sales in place		—			—			—		(4.8	)(4)		(1.6	)(5)		—		(1.6	)		(4.8	)
December 31, 2011		15.9			582.5			—		—			—			—		15.9			582.5
January 1, 2010		5.2			466.9			—		7.5			0.6			—		5.8			474.4
Revisions		1.5			(119.1	)		—		(0.8	)		0.5			—		2.0			(119.9	)
Extensions, additions and discoveries		0.6			108.5			—		—			1.3			—		1.9			108.5
Production		(0.2	)		(12.3	)		—		(1.5	)		(0.3	)		—		(0.5	)		(13.8	)
Purchases in place		0.8			109.8			—		—			—			—		0.8			109.8
Sales in place		—			(1.0	)		—		—			(0.2	)		—		(0.2	)		(1.0	)
December 31, 2010		7.9			552.8			—		5.2			1.9			—		9.8			558.0
Total proved reserves at December 31, 2009		5.6			496.5			—		12.5			1.5			—		7.1			509.0
Total proved reserves at December 31, 2010		29.1			572.6			—		10.7			3.9			—		33.0			583.3
Total proved reserves at December 31, 2011		17.7			599.4			—		8.2			—			—		17.7			607.6
Proved Developed Reserves at January 1, 2010
Consolidated subsidiaries		0.2			18.4			—		5.0			0.6			—		0.8			23.4
Equity companies(1)		1.8			106.6			—		7.5			0.5			—		2.3			114.1
Proved Developed Reserves at December 31, 2010
Consolidated subsidiaries		2.7			17.1			—		5.5			1.6			—		4.3			22.6
Equity companies(1)		3.0			147.1			—		5.2			0.5			—		3.5			152.3
Proved Developed Reserves at December 31, 2011
Consolidated subsidiaries		0.9			13.6			—		8.2			—			—		0.9			21.8
Equity companies(1)		6.3			256.4			—		—			—			—		6.3			256.4
Proved Undeveloped Reserves at January 1, 2010
Consolidated subsidiaries		0.2			11.2			—		—			0.3			—		0.5			11.2
Equity companies(1)		3.4			360.3			—		—			0.1			—		3.5			360.3
Proved Undeveloped Reserves at December 31, 2010
Consolidated subsidiaries		18.5			2.7			—		—			0.4			—		18.9			2.7
Equity companies(1)		4.9			405.7			—		—			1.4			—		6.3			405.7
Proved Undeveloped Reserves at December 31, 2011
Consolidated subsidiaries		0.9			3.3			—		—			—			—		0.9			3.3
Equity companies(1)		9.6			326.1			—		—			—			—		9.6			326.1

(1) Represents our proportionate share of interests in equity companies.

(2) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(3) Relates to acquisitions of properties with 360.4 Bcfe and drilling of non-proved properties of 122.2 Bcfe. In addition, negative revisions of 384 Bcfe were noted primarily resulting from proved undeveloped reserves being reclassified to non-proved status in accordance with the SEC five-year guidance for recording proved reserves.

(4) Relates to SMVP that was dissolved in June 2011, and of proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

(5) Relates to the sale of Remora’s assets which resulted in a decrease in proved reserves of 9.5 Bcfe.

Standardized Measure of Discounted Future Cash Flows

For the years ended December 31, 2011 and 2010, the standardized measure of discounted future net cash flow was computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and global, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The 10-percent discount factor is prescribed by GAAP.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our consolidated subsidiaries and equity companies’ proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Significant changes in estimated reserve volumes or commodity prices could have a material effect on our consolidated financial statements.

	United States			Canada			Colombia			Total
	(in thousands)
Standardized Measure of Discounted Future Cash Flows
For the year ended December 31, 2011:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	225,141		$	20,906		$	—		$	246,047
Future production costs		(66,448	)		(5,761	)		—			(72,209	)
Future development costs		(45,505	)		(1,607	)		—			(47,112	)
Future income tax expense(2)		—			—			—			—
Future net cash inflows		113,188			13,538			—			126,726
Effect of discounting net cash flows at 10%		(55,886	)		(2,527	)		—			(58,413	)
Discounted future net cash flows	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Future cash flows from sales of oil and gas	$	3,347,348		$	—		$	—		$	3,347,348
Future production costs		(1,005,922	)		—			—			(1,005,922	)
Future development costs		(660,509	)		—			—			(660,509	)
Future income tax expense(3)		—			—			—			—
Future net cash inflows		1,680,917			—			—			1,680,917
Effect of discounting net cash flows at 10%		(1,098,854	)		—			—			(1,098,854	)
Discounted future net cash flows	$	582,063		$	—		$	—		$	582,063
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	639,365		$	11,011		$	—		$	650,376
For the year ended December 31, 2010:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	1,468,944		$	16,435		$	156,921		$	1,642,300
Future production costs		(481,487	)		(5,600	)		(83,556	)		(570,643	)
Future development costs		(152,309	)		(360	)		(16,216	)		(168,885	)
Future income tax expense(2)		(268,774	)		—			—			(268,774	)
Future net cash inflows		566,374			10,475			57,149			633,998
Effect of discounting net cash flows at 10%		(353,232	)		(2,046	)		(10,256	)		(365,534	)
Discounted future net cash flows	$	213,142		$	8,429		$	46,893		$	268,464
Equity Companies(1)
Future cash flows from sales of oil and gas	$	2,889,308		$	14,713		$	141,410		$	3,045,431
Future production costs		(752,792	)		(6,463	)		(56,837	)		(816,092	)
Future development costs		(850,053	)		(992	)		(12,307	)		(863,352	)
Future income tax expense (3)		—			—			—			—
Future net cash inflows		1,286,463			7,258			72,266			1,365,987
Effect of discounting net cash flows at 10%		(995,091	)		(1,477	)		(14,313	)		(1,010,881	)
Discounted future net cash flows	$	291,372		$	5,781		$	57,953		$	355,106
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	504,514		$	14,210		$	104,846		$	623,570

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table reflects the estimate of changes in the standardized measure of discounted future net cash flows from proved reserves:

	United States			Canada			Colombia			Total
	(in thousands)
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries
Discounted future net cash flows as of December 31, 2009	$	38,345		$	6,527		$	11,741		$	56,613
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		8,037			—			45,072			53,109
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(10,670	)		(3,311	)		(8,701	)		(22,682	)
Development costs incurred during the year		8,359			—			—			8,359
Net change in prices and production costs		96,662			46			(2,555	)		94,153
Net change in future development costs		4,155			(192	)		285			4,248
Revisions of previous reserves estimates		(27,501	)		5,628			(7,093	)		(28,966	)
Purchases of reserves		196,613	(4)		—			—			196,613
Accretion of discount		3,562			496			1,030			5,088
Other		(17,357	)		(765	)		7,114			(11,008	)
Net change in income taxes(2)		(87,063	)		—			—			(87,063	)
Total change in the standardized measure for consolidated subsidiaries	$	174,797		$	1,902		$	35,152		$	211,851
Discounted future net cash flows as of December 31, 2010	$	213,142		$	8,429		$	46,893		$	268,464
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		32,838			—			—			32,838
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(14,247	)		(5,848	)		(8,674	)		(28,769	)
Development costs incurred during the year		360			—			—			360
Net change in prices and production costs		(15,274	)		1,221			—			(14,053	)
Net change in future development costs		775			—			—			775
Revisions of previous reserves estimates		(5,285	)		1,219			19,859			15,793
Purchases of reserves					4,557						4,557
Divestiture of reserves		(272,448	)(4)					(58,078	)(5)		(330,526	)
Accretion of discount		30,021			843						30,864
Other		356			590						946
Net change in income taxes(2)		87,064									87,064
Total change in the standardized measure for consolidated subsidiaries	$	(155,840	)	$	2,582		$	(46,893	)	$	(200,151	)
Discounted future net cash flows as of December 31, 2011	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Discounted future net cash flows as of December 31, 2009	$	52,941		$	9,569		$	13,706		$	76,216
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		20,230			—			40,664			60,894
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(46,276	)		2,998			(11,002	)		(54,280	)
Development costs incurred during the year		69,207			—			—			69,207
Net change in prices and production costs		90,974			(5,205	)		3,032			88,801
Net change in future development costs		—			(374	)		(847	)		(1,221	)
Revisions of previous reserves estimates		76,723			(1,077	)		17,289			92,935
Purchases of reserves		5,453			—			—			5,453
Sales of reserves		(1,446	)		—			(5,418	)		(6,864	)
Accretion of discount		5,294			794			529			6,617
Other		18,272			(924	)		—			17,348
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	238,431		$	(3,788	)	$	44,247		$	278,890
Discounted future net cash flows as of December 31, 2010	$	291,372		$	5,781		$	57,953		$	355,106
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		83,692			—			—			83,692
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(71,143	)		3,245			(16,132	)		(84,030	)
Development costs incurred during the year		44,294			—			—			44,294
Net change in prices and production costs		(20,856	)		—			—			(20,856	)
Net change in future development costs		(51,098	)		—			—			(51,098	)
Revisions of previous reserves estimates		20,178			—			—			20,178
Purchases of reserves		262,719			—			—			262,719
Divestiture of reserves		—			(9,026	)(6)		(41,821	)(5)		(50,847	)
Sales of reserves		—			—			—			—
Accretion of discount		29,155			—			—			29,155
Other		(6,250	)		—			—			(6,250	)
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	290,691		$	(5,781	)	$	(57,953	)	$	226,957
Discounted future net cash flows as of December 31, 2011	$	582,063		$	—		$	—		$	582,063

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

(4) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(5) In April 2011, some of our wholly owned oil and gas assets in Colombia were sold. Remora completed sales of its oil and gas assets in Colombia, resulting in a decrease of proved reserves of 9.5 Bcfe, in the second quarter of 2011.

(6) In June 2011, SMVP that was dissolved in June 2011, resulting in a decrease in proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

XML

Financial Instruments and Risk Concentration (Details) (USD $)	1 Months Ended	12 Months Ended
	Jun. 30, 2004	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2005	Oct. 21, 2002
Financial Instrument and Risk Concentration (Textual) [Abstract]
Fair value of 5.375% senior notes		$ 5,187,676,000	$ 4,879,402,000			$ 200,000,000
Range-cap-and-floor derivative instrument Unwound	100,000,000
Loss during unwound of interest rate swap					2,700,000
Interest savings from swap agreement					2,700,000
Derivative liability of range-cap-and-floor transaction		1,300,000	3,400,000
Gain loss related to range-cap-and-floor		2,200,000	(100,000)	1,400,000
6.15% Senior Notes Due February 2018 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due		6.15%
Financial Instrument and Risk Concentration (Textual) [Abstract]
Fair value of 5.375% senior notes		1,113,986,000	1,041,008,000
9.25% Senior Notes Due January 2019 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due		9.25%
Financial Instrument and Risk Concentration (Textual) [Abstract]
Fair value of 5.375% senior notes		1,419,514,000	1,393,943,000
5.375% Senior Notes Due August 2012 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due		5.375%
Financial Instrument and Risk Concentration (Textual) [Abstract]
Fair value of 5.375% senior notes		281,188,000	291,500,000
5.00% senior notes due September 2020 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due		5.00%
Financial Instrument and Risk Concentration (Textual) [Abstract]
Fair value of 5.375% senior notes		734,475,000	678,335,000
4.625% senior notes due September 2021 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate on senior note due		4.625%
Financial Instrument and Risk Concentration (Textual) [Abstract]
Fair value of 5.375% senior notes		$ 708,176,000	$ 0

XML

Supplemental Balance Sheet Income Statement and Cash Flow Information (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Extinguishment of Debt [Line Items]
Pre-tax (losses) gains on purchases of senior exchangeable notes	$ (58,000)	$ (7,042,000)	$ 11,197,000
Supplemental Balance Sheet Income Statement and Cash Flow Information (Textual) [Abstract]
Provision for termination payment	100,000,000	0
Gain on sale of debt securities and long term investments	18,000,000	4,200,000
Net unrealized gains (losses) from trading securities	8,000,000	4,400,000	9,800,000
Peak [Member]
Extinguishment of Debt [Line Items]
Gain on acquisition of equity method investment	13,100,000
0.94% senior exchangeable notes [Member]
Extinguishment of Debt [Line Items]
Pre-tax (losses) gains on purchases of senior exchangeable notes	$ 100,000	$ (7,000,000)	$ 11,500,000
Interest rate on senior note due	0.94%

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Recurring Fair Value Measurements

	Fair Value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Short-term investments:
Available-for-sale equity securities — energy industry	$	60,923	$	10,510	$	—	$	71,433
Available-for-sale debt securities
Commercial paper and CDs		1,230		—		—		1,230
Corporate debt securities		—		51,300		—		51,300
Mortgage-backed debt securities		—		309		—		309
Mortgage-CMO debt securities		—		2,547		—		2,547
Asset-backed debt securities		2,495		—		—		2,495
Trading securities — energy industry		11,600		—		—		11,600
Total short-term investments	$	76,248	$	64,666	$	—	$	140,914
Liabilities:
Derivative contract	$	—	$	1,281	$	—	$	1,281

Fair Value of Financial Instruments

	December 31,
	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
5.375% senior notes due August 2012(1)	$	274,604	$	281,188	$	273,977	$	291,500
6.15% senior notes due February 2018		967,490		1,113,986		966,276		1,041,008
9.25% senior notes due January 2019		1,125,000		1,419,514		1,125,000		1,393,943
5.00% senior notes due September 2020		697,343		734,475		697,037		678,335
4.625% senior notes due September 2021		697,667		708,176		—		—
0.94% senior exchangeable notes due May 2011		—		—		1,378,178		1,403,315
Subsidiary preferred stock		69,188		68,625		69,188		68,625
Revolving credit facilities		860,000		860,000		—		—
Other		1,712		1,712		2,676		2,676
	$	4,693,004	$	5,187,676	$	4,512,332	$	4,879,402

(1) Includes $.3 million and $.7 million as of December 31, 2011 and 2010, respectively, related to the unamortized loss on the interest rate swap that was unwound during the fourth quarter of 2005.

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited) [Abstract]

Results of operations exclude general office overhead and interest expense attributable to oil and gas activities

	United States			Canada			Colombia			Total
	(in thousands)
Results of Operations
For the year ended December 31, 2011:
Consolidated Subsidiaries
Revenue	$	25,684		$	7,046		$	12,378		$	45,108
Production costs		12,682			27,432	(3)		3,704			43,818
Exploration expenses		23,768			3,324			122			27,214
Depreciation and depletion		22,350			104			949			23,403
Impairment of oil and gas properties		71,392			183,654						255,046
Loss (gain) on dispositions		(6,642	)		—			(39,599	)		(46,241	)
Related income tax expense (benefit)		(38,707	)		(54,979	)		15,577			(78,109	)
Results of producing activities for consolidated subsidiaries	$	(59,159	)	$	(152,489	)	$	31,625		$	(180,023	)
Equity Companies(1)
Revenue	$	98,933		$	1,335		$	26,730		$	126,998
Production costs		27,790			4,600			10,598			42,988
Depreciation and depletion		39,564			1,032			9,806			50,402
Impairment of oil and gas properties		15,624			—			—			15,624
Realized loss (gain) on derivative instruments		(33,969	)		(84	)		—			(34,053	)
Loss (gain) on acquisitions/dispositions		(49,484	)		—			(95,301	)		(144,785	)
Related income tax expense (benefit)(2)		—			—			6,055			6,055
Results of producing activities for equity companies	$	99,408		$	(4,213	)	$	95,572		$	190,767
Total results of operations	$	40,249		$	(156,702	)	$	127,197		$	10,744
For the year ended December 31, 2010:
Consolidated Subsidiaries
Revenue	$	19,180		$	11,276		$	16,619		$	47,075
Production costs		8,510			7,965			7,918			24,393
Exploration expenses		—			—			39,047			39,047
Depreciation and depletion		20,092			5,424			3,737			29,253
Impairment of oil and gas properties		110,165			—			—			110,165
Related income tax expense (benefit)		(15,856	)		(3,078	)		610			(18,324	)
Results of producing activities for consolidated subsidiaries	$	(103,731	)	$	965		$	(34,693	)	$	(137,459	)
Equity Companies(1)
Revenue	$	64,736		$	6,038		$	20,176		$	90,950
Production costs		18,460			9,036			9,174			36,670
Depreciation and depletion		24,221			6,033			7,058			37,312
Impairment of oil and gas properties		851			—			—			851
Realized gain on derivative instruments		(25,424	)		(2,543	)		—			(27,967	)
Related income tax expense (benefit)(2)		—			—			—			—
Results of producing activities for equity companies	$	46,628		$	(6,488	)	$	3,944		$	44,084
Total results of operations	$	(57,103	)	$	(5,523	)	$	(30,749	)	$	(93,375	)

(1) Represents our proportionate share of interests in our equity companies.

(2) Equity companies are pass-through entities for tax purposes.

(3) Includes $24.2 million of transportation costs from pipeline commitments.

Capitalized costs

	United States			Canada			Colombia			Total
	(in thousands)
Capitalized Costs
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	587,385		$	101,402		$	—		$	688,787
Property acquisition costs, unproved		101,611			92,750			23,767			218,128
Total acquisition costs		688,996			194,152			23,767			906,915
Accumulated depreciation and depletion		(539,380	)		(28,838	)		(741	)		(568,959	)
Net capitalized costs for consolidated subsidiaries	$	149,616		$	165,314		$	23,026		$	337,956
Equity Companies(1)
Property acquisition costs, proved	$	1,141,393		$	—		$	—		$	1,141,393
Property acquisition costs, unproved		103,657			—			—			103,657
Total acquisition costs		1,245,050			—			—			1,245,050
Accumulated depreciation and depletion		(512,503	)		—			—			(512,503	)
Net capitalized costs for equity companies	$	732,547		$	—		$	—		$	732,547
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	480,618		$	62,109		$	57,251		$	599,978
Property acquisition costs, unproved		136,625			89,785			1,174			227,584
Total acquisition costs		617,243			151,894			58,425			827,562
Accumulated depreciation and depletion		(463,330	)		(7,344	)		(3,782	)		(474,456	)
Net capitalized costs for consolidated subsidiaries	$	153,913		$	144,550		$	54,643		$	353,106
Equity Companies(1)
Property acquisition costs, proved	$	749,515		$	78,224		$	98,629		$	926,368
Property acquisition costs, unproved		108,541			28,884			883			138,308
Total acquisition costs		858,056			107,108			99,512			1,064,676
Accumulated depreciation and depletion		(460,622	)		(72,338	)		(31,825	)		(564,785	)
Net capitalized costs for equity companies	$	397,434		$	34,770		$	67,687		$	499,891

(1) Represents our proportionate share of interests in our equity companies.

Costs incurred in property acquisitions, exploration development activities

	United States		Canada		Colombia			Total
	(in thousands)
Costs incurred in property acquisitions, exploration and development activities
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	23,051	$	7,748	$	—		$	30,799
Property acquisition costs, unproved		37,272		26,099		—			63,371
Exploration costs		49,156		—		122			49,278
Development costs		43,780		184		19,605			63,569
Asset retirement costs		496		750		254			1,500
Total costs incurred for consolidated subsidiaries	$	153,755	$	34,781	$	19,981		$	208,517
Equity Companies(1)
Property acquisition costs, proved	$	232,410	$	—	$	—		$	232,410
Property acquisition costs, unproved		14,268		—		4,395			18,663
Exploration costs		252		—		—			252
Development costs		136,711		—		—			136,711
Asset retirement costs		2,834		—		—			2,834
Total costs incurred for equity companies	$	386,475	$	—	$	4,395		$	390,870
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	25,080	$	—	$	—		$	25,080
Property acquisition costs, unproved		25,202		—		1,000			26,202
Exploration costs		8,199		—		33,599			41,798
Development costs		19,118		3,876		—			22,994
Asset retirement costs		—		—		770			770
Total costs incurred for consolidated subsidiaries	$	77,599	$	3,876	$	35,369		$	116,844
Equity Companies(1)
Property acquisition costs, proved	$	29,975	$	—	$	—		$	29,975
Property acquisition costs, unproved		34,207		—		—			34,207
Exploration costs		108		—		29,927			30,035
Development costs		118,828		1,056		11,805			131,689
Asset retirement costs		296		—		(104	)		192
Total costs incurred for equity companies	$	183,414	$	1,056	$	41,628		$	226,098

(1) Represents our proportionate share of interests in equity companies.

Net Proved Reserves

	United States						Canada					Colombia					Total
Reserves	Liquids (MMBbls)			Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)			Liquids (MMBbls)			Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)
Net proved reserves of consolidated subsidiaries
January 1, 2011		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Revisions		0.1			(3.9	)		—		0.9			—			—		0.1			(3.0	)
Extensions, additions and discoveries		1.6			4.0			—		—			—			—		1.6			4.0
Production		(0.2	)		(3.0	)		—		(2.1	)		(0.1	)		—		(0.3	)		(5.1	)
Purchases in place		—			—			—		3.9			—			—		—			3.9
Sales in place		(20.9	)(2)		—			—		—			(1.9	)		—		(22.8	)		—
December 31, 2011		1.8			16.9			—		8.2			—			—		1.8			25.1
January 1, 2010		0.4			29.6			—		5.0			0.9			—		1.3			34.6
Revisions		0.1			(11.7	)		—		3.6			(0.7	)		—		(0.6	)		(8.1	)
Extensions, additions and discoveries		—			5.0			—		—			2.0			—		2.0			5.0
Production		(0.1	)		(3.1	)		—		(3.1	)		(0.2	)		—		(0.3	)		(6.2	)
Purchases in place		20.8	(2)		—			—		—			—			—		20.8			—
Sales in place		—			—			—		—			—			—		—			—
December 31, 2010		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Proportional interest in proved reserves of equity companies
January 1, 2011		7.9			552.8			—		5.2			1.9			—		9.8			558.0
Revisions		(4.2	)		(359.0	)		—		—			—			—		(4.2	)		(359.0	)
Extensions, additions and discoveries		3.2			103.1			—		—			—			—		3.2			103.1
Production		(0.4	)		(18.6	)		—		(0.4	)		(0.3	)		—		(0.7	)		(19.0	)
Purchases in place		9.4			304.2	(3)		—		—			—			—		9.4			304.2
Sales in place		—			—			—		(4.8	)(4)		(1.6	)(5)		—		(1.6	)		(4.8	)
December 31, 2011		15.9			582.5			—		—			—			—		15.9			582.5
January 1, 2010		5.2			466.9			—		7.5			0.6			—		5.8			474.4
Revisions		1.5			(119.1	)		—		(0.8	)		0.5			—		2.0			(119.9	)
Extensions, additions and discoveries		0.6			108.5			—		—			1.3			—		1.9			108.5
Production		(0.2	)		(12.3	)		—		(1.5	)		(0.3	)		—		(0.5	)		(13.8	)
Purchases in place		0.8			109.8			—		—			—			—		0.8			109.8
Sales in place		—			(1.0	)		—		—			(0.2	)		—		(0.2	)		(1.0	)
December 31, 2010		7.9			552.8			—		5.2			1.9			—		9.8			558.0
Total proved reserves at December 31, 2009		5.6			496.5			—		12.5			1.5			—		7.1			509.0
Total proved reserves at December 31, 2010		29.1			572.6			—		10.7			3.9			—		33.0			583.3
Total proved reserves at December 31, 2011		17.7			599.4			—		8.2			—			—		17.7			607.6
Proved Developed Reserves at January 1, 2010
Consolidated subsidiaries		0.2			18.4			—		5.0			0.6			—		0.8			23.4
Equity companies(1)		1.8			106.6			—		7.5			0.5			—		2.3			114.1
Proved Developed Reserves at December 31, 2010
Consolidated subsidiaries		2.7			17.1			—		5.5			1.6			—		4.3			22.6
Equity companies(1)		3.0			147.1			—		5.2			0.5			—		3.5			152.3
Proved Developed Reserves at December 31, 2011
Consolidated subsidiaries		0.9			13.6			—		8.2			—			—		0.9			21.8
Equity companies(1)		6.3			256.4			—		—			—			—		6.3			256.4
Proved Undeveloped Reserves at January 1, 2010
Consolidated subsidiaries		0.2			11.2			—		—			0.3			—		0.5			11.2
Equity companies(1)		3.4			360.3			—		—			0.1			—		3.5			360.3
Proved Undeveloped Reserves at December 31, 2010
Consolidated subsidiaries		18.5			2.7			—		—			0.4			—		18.9			2.7
Equity companies(1)		4.9			405.7			—		—			1.4			—		6.3			405.7
Proved Undeveloped Reserves at December 31, 2011
Consolidated subsidiaries		0.9			3.3			—		—			—			—		0.9			3.3
Equity companies(1)		9.6			326.1			—		—			—			—		9.6			326.1

(1) Represents our proportionate share of interests in equity companies.

(2) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(3) Relates to acquisitions of properties with 360.4 Bcfe and drilling of non-proved properties of 122.2 Bcfe. In addition, negative revisions of 384 Bcfe were noted primarily resulting from proved undeveloped reserves being reclassified to non-proved status in accordance with the SEC five-year guidance for recording proved reserves.

(4) Relates to SMVP that was dissolved in June 2011, and of proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

(5) Relates to the sale of Remora’s assets which resulted in a decrease in proved reserves of 9.5 Bcfe.

Standardized Measure of Discounted Future Cash Flows

	United States			Canada			Colombia			Total
	(in thousands)
Standardized Measure of Discounted Future Cash Flows
For the year ended December 31, 2011:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	225,141		$	20,906		$	—		$	246,047
Future production costs		(66,448	)		(5,761	)		—			(72,209	)
Future development costs		(45,505	)		(1,607	)		—			(47,112	)
Future income tax expense(2)		—			—			—			—
Future net cash inflows		113,188			13,538			—			126,726
Effect of discounting net cash flows at 10%		(55,886	)		(2,527	)		—			(58,413	)
Discounted future net cash flows	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Future cash flows from sales of oil and gas	$	3,347,348		$	—		$	—		$	3,347,348
Future production costs		(1,005,922	)		—			—			(1,005,922	)
Future development costs		(660,509	)		—			—			(660,509	)
Future income tax expense(3)		—			—			—			—
Future net cash inflows		1,680,917			—			—			1,680,917
Effect of discounting net cash flows at 10%		(1,098,854	)		—			—			(1,098,854	)
Discounted future net cash flows	$	582,063		$	—		$	—		$	582,063
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	639,365		$	11,011		$	—		$	650,376
For the year ended December 31, 2010:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	1,468,944		$	16,435		$	156,921		$	1,642,300
Future production costs		(481,487	)		(5,600	)		(83,556	)		(570,643	)
Future development costs		(152,309	)		(360	)		(16,216	)		(168,885	)
Future income tax expense(2)		(268,774	)		—			—			(268,774	)
Future net cash inflows		566,374			10,475			57,149			633,998
Effect of discounting net cash flows at 10%		(353,232	)		(2,046	)		(10,256	)		(365,534	)
Discounted future net cash flows	$	213,142		$	8,429		$	46,893		$	268,464
Equity Companies(1)
Future cash flows from sales of oil and gas	$	2,889,308		$	14,713		$	141,410		$	3,045,431
Future production costs		(752,792	)		(6,463	)		(56,837	)		(816,092	)
Future development costs		(850,053	)		(992	)		(12,307	)		(863,352	)
Future income tax expense (3)		—			—			—			—
Future net cash inflows		1,286,463			7,258			72,266			1,365,987
Effect of discounting net cash flows at 10%		(995,091	)		(1,477	)		(14,313	)		(1,010,881	)
Discounted future net cash flows	$	291,372		$	5,781		$	57,953		$	355,106
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	504,514		$	14,210		$	104,846		$	623,570

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves

	United States			Canada			Colombia			Total
	(in thousands)
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries
Discounted future net cash flows as of December 31, 2009	$	38,345		$	6,527		$	11,741		$	56,613
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		8,037			—			45,072			53,109
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(10,670	)		(3,311	)		(8,701	)		(22,682	)
Development costs incurred during the year		8,359			—			—			8,359
Net change in prices and production costs		96,662			46			(2,555	)		94,153
Net change in future development costs		4,155			(192	)		285			4,248
Revisions of previous reserves estimates		(27,501	)		5,628			(7,093	)		(28,966	)
Purchases of reserves		196,613	(4)		—			—			196,613
Accretion of discount		3,562			496			1,030			5,088
Other		(17,357	)		(765	)		7,114			(11,008	)
Net change in income taxes(2)		(87,063	)		—			—			(87,063	)
Total change in the standardized measure for consolidated subsidiaries	$	174,797		$	1,902		$	35,152		$	211,851
Discounted future net cash flows as of December 31, 2010	$	213,142		$	8,429		$	46,893		$	268,464
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		32,838			—			—			32,838
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(14,247	)		(5,848	)		(8,674	)		(28,769	)
Development costs incurred during the year		360			—			—			360
Net change in prices and production costs		(15,274	)		1,221			—			(14,053	)
Net change in future development costs		775			—			—			775
Revisions of previous reserves estimates		(5,285	)		1,219			19,859			15,793
Purchases of reserves					4,557						4,557
Divestiture of reserves		(272,448	)(4)					(58,078	)(5)		(330,526	)
Accretion of discount		30,021			843						30,864
Other		356			590						946
Net change in income taxes(2)		87,064									87,064
Total change in the standardized measure for consolidated subsidiaries	$	(155,840	)	$	2,582		$	(46,893	)	$	(200,151	)
Discounted future net cash flows as of December 31, 2011	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Discounted future net cash flows as of December 31, 2009	$	52,941		$	9,569		$	13,706		$	76,216
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		20,230			—			40,664			60,894
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(46,276	)		2,998			(11,002	)		(54,280	)
Development costs incurred during the year		69,207			—			—			69,207
Net change in prices and production costs		90,974			(5,205	)		3,032			88,801
Net change in future development costs		—			(374	)		(847	)		(1,221	)
Revisions of previous reserves estimates		76,723			(1,077	)		17,289			92,935
Purchases of reserves		5,453			—			—			5,453
Sales of reserves		(1,446	)		—			(5,418	)		(6,864	)
Accretion of discount		5,294			794			529			6,617
Other		18,272			(924	)		—			17,348
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	238,431		$	(3,788	)	$	44,247		$	278,890
Discounted future net cash flows as of December 31, 2010	$	291,372		$	5,781		$	57,953		$	355,106
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		83,692			—			—			83,692
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(71,143	)		3,245			(16,132	)		(84,030	)
Development costs incurred during the year		44,294			—			—			44,294
Net change in prices and production costs		(20,856	)		—			—			(20,856	)
Net change in future development costs		(51,098	)		—			—			(51,098	)
Revisions of previous reserves estimates		20,178			—			—			20,178
Purchases of reserves		262,719			—			—			262,719
Divestiture of reserves		—			(9,026	)(6)		(41,821	)(5)		(50,847	)
Sales of reserves		—			—			—			—
Accretion of discount		29,155			—			—			29,155
Other		(6,250	)		—			—			(6,250	)
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	290,691		$	(5,781	)	$	(57,953	)	$	226,957
Discounted future net cash flows as of December 31, 2011	$	582,063		$	—		$	—		$	582,063

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

(4) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(5) In April 2011, some of our wholly owned oil and gas assets in Colombia were sold. Remora completed sales of its oil and gas assets in Colombia, resulting in a decrease of proved reserves of 9.5 Bcfe, in the second quarter of 2011.

(6) In June 2011, SMVP that was dissolved in June 2011, resulting in a decrease in proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

XML

Fair Value Measurements (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Oct. 21, 2002
Fair Value of Financial Instruments
Carrying Value	$ 4,693,004	$ 4,512,332
Fair Value	5,187,676	4,879,402	200,000
5.375% Senior Notes Due August 2012 [Member]
Fair Value of Financial Instruments
Carrying Value	274,604	273,977
Fair Value	281,188	291,500
6.15% Senior Notes Due February 2018 [Member]
Fair Value of Financial Instruments
Carrying Value	967,490	966,276
Fair Value	1,113,986	1,041,008
9.25% Senior Notes Due January 2019 [Member]
Fair Value of Financial Instruments
Carrying Value	1,125,000	1,125,000
Fair Value	1,419,514	1,393,943
5.00% senior notes due September 2020 [Member]
Fair Value of Financial Instruments
Carrying Value	697,343	697,037
Fair Value	734,475	678,335
4.625% senior notes due September 2021 [Member]
Fair Value of Financial Instruments
Carrying Value	697,667	0
Fair Value	708,176	0
0.94% Senior Exchangeable Notes Due May 2011 [Member]
Fair Value of Financial Instruments
Carrying Value	0	1,378,178
Fair Value	0	1,403,315
Subsidiary preferred stock [Member]
Fair Value of Financial Instruments
Carrying Value	69,188	69,188
Fair Value	68,625	68,625
Revolving Credit Facilities [Member]
Fair Value of Financial Instruments
Carrying Value	860,000	0
Fair Value	860,000	0
Other [Member]
Fair Value of Financial Instruments
Carrying Value	1,712	2,676
Fair Value	$ 1,712	$ 2,676

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 398,575	$ 641,702
Short-term investments	140,914	159,488
Assets held for sale	401,500	352,048
Accounts receivable, net	1,576,555	1,116,510
Inventory	272,852	158,836
Deferred income taxes	127,874	31,510
Other current assets	170,044	152,836
Total current assets	3,088,314	2,612,930
Long-term investments and other receivables	11,124	40,300
Property, plant and equipment, net	8,629,946	7,815,419
Goodwill	501,258	494,372
Investment in unconsolidated affiliates	371,021	267,723
Other long-term assets	310,477	415,825
Total assets	12,912,140	11,646,569
Current liabilities:
Current portion of long-term debt	275,326	1,379,018
Trade accounts payable	782,753	355,282
Accrued liabilities	716,773	394,292
Income taxes payable	27,710	25,788
Total current liabilities	1,802,562	2,154,380
Long-term debt	4,348,490	3,064,126
Other long-term liabilities	292,758	245,765
Deferred income taxes	797,925	770,247
Total liabilities	7,241,735	6,234,518
Commitments and contingencies (Note 18)
Subsidiary preferred stock (Notes 5 and 15)	69,188	69,188
Shareholders' equity:
Common shares, par value $.001 per share: Authorized common shares 800,000; issued 317,042 and 315,034, respectively	317	315
Capital in excess of par value	2,287,743	2,255,787
Accumulated other comprehensive income	321,264	342,052
Retained earnings	3,956,364	3,707,881
Less: treasury shares, at cost, 29,414 common shares	(977,873)	(977,873)
Total shareholders' equity	5,587,815	5,328,162
Noncontrolling interest	13,402	14,701
Total equity	5,601,217	5,342,863
Total liabilities and equity	$ 12,912,140	$ 11,646,569

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Change in unrecognized tax benefits

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Balance as of January 1,	$	81,174		$	69,048		$	51,819
Additions based on tax positions related to the current year(1)		1,850			1,026			4,787
Additions for tax positions of prior years(1)		11,748			17,060			12,889
Reductions for tax positions of prior years		(11,082	)		(4,709	)		(447	)
Settlements(2)		(14,842	)		(1,251	)		—
Balance as of December 31,	$	68,848		$	81,174		$	69,048

(1) Includes an unrecognized tax benefit of $10.8 million related to an Algeria audit assessment.

(2) Includes $8.6 million related to a settlement of the 1995 to 1997 income tax audits with the Canada Revenue Agency.

Income (loss) from continuing operations before income taxes

	Year Ended December 31,
	2011		2010			2009
	(In thousands)
United States and Other Jurisdictions:
United States	$	178,270	$	(82,723	)	$	(505,264	)
Other jurisdictions		309,499		376,293			574,048
Income (loss) before income taxes from continuing operations	$	487,769	$	293,570		$	68,784

Income tax expense (benefit) from continuing operations

	2011			2010			2009
	(In thousands)
Current:
U.S. federal	$	27,649		$	(137,847	)	$	(15,434	)
Outside the U.S.		43,732			54,779			84,221
State		38,321			5,859			2,671
		109,702			(77,209	)		71,458
Deferred:
U.S. federal		41,540			97,114			(80,353	)
Outside the U.S.		4,413			13,607			(46,603	)
State		(13,050	)		3,438			(8,439	)
		32,903			114,159			(135,395	)
Income tax expense (benefit)	$	142,605		$	36,950		$	(63,937	)

Reconciliation of the differences between taxes on income (loss) before income taxes

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Income tax provision at statutory rate (Bermuda rate of 0%)	$	—		$	—		$	—
Taxes on U.S. and other international earnings (losses) at greater than the Bermuda rate		112,094			18,686			(60,741	)
Increase (decrease) in valuation allowance		(6,450	)		2,407			6,062
Effect of change in tax rate		(258	)		40			(9,248	)
Tax reserves and interest		11,948			8,808			14,652
State income taxes		25,271			7,009			(14,662	)
Income tax expense (benefit)	$	142,605		$	36,950		$	(63,937	)
Effective tax rate		29.2	%		12.6	%		(93.0	)%

Deferred tax assets and liabilities

	December 31,
	2011			2010
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	2,009,318		$	1,848,956
Equity compensation		25,937			19,262
Deferred revenue		32,200			13,428
Tax credit and other attribute carryforwards		90,297			89,141
Insurance loss reserve		24,598			28,537
Other		114,043			62,324
Subtotal		2,296,393			2,061,648
Valuation allowance		(1,485,540	)		(1,514,153	)
Deferred tax assets	$	810,853		$	547,495
Deferred tax liabilities:
Depreciation, amortization and depletion for tax in excess of book expense	$	1,317,256		$	1,123,622
Variable interest investments		116,005			75,204
Other		34,822			54,738
Deferred tax liability		1,468,083			1,253,564
Net deferred assets (liabilities)	$	(657,230	)	$	(706,069	)
Balance Sheet Summary
Net current deferred asset	$	127,874		$	31,510
Net noncurrent deferred asset(1)		13,090			33,694
Net current deferred liability(2)		(269	)		(1,027	)
Net noncurrent deferred liability		(797,925	)		(770,246	)
Net deferred asset (liability)	$	(657,230	)	$	(706,069	)

(1) This amount is included in other long-term assets.

(2) This amount is included in accrued liabilities.

NOL carryforwards by year of expiration

Year Ended December 31,	Total		U.S. Federal		Non-U.S.
	(In thousands)
2012	$	8,778	$		$	8,778
2013		30,348				30,348
2014		3,980				3,980
2015		12,824				12,824
2016		50,176		7,504		42,672
2017		26,601		5,423		21,178
2018		68,888		33,111		35,777
2019		35,986		17,722		18,264
2020		14,612				14,612
2021		7,895				7,895
2027		2,014				2,014
2028		31,237				31,237
2029		184,463		130,842		53,621
2030		533,825		485,648		48,177
2031		626,288		549,795		76,493
Subtotal: expiring NOLs		1,637,915		1,230,045		407,870
Non-expiring NOLs		5,021,678		—		5,021,678
Total	$	6,659,593	$	1,230,045	$	5,429,548

XML

Subsidiary Preferred Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Subsidiary Preferred Stock (Textual) [Abstract]
Preferred shares, shares issued	0	0
Preferred shares, par value	$ 0.001	$ 0.001
Preferred shares, shares authorized	25,000,000	25,000,000
Entitlement of Preferred Stock Voting Rights	one vote per share
Superior Subsidiary [Member]
Subsidiary Preferred Stock (Textual) [Abstract]
Preferred shares, shares issued	75,000,000
Preferred shares, par value	$ 0.01
Preferred shares, shares authorized	10,000,000
Cumulative Preferred Divided	$ 40.00
Per share liquidation preference	$ 1,000
Liquidation Preference of preferred stock	$ 75.0
101% of the Liquidation Value, plus all accrued dividends	101% of the Liquidation Value, plus all accrued dividends
Convertible rate of preferred stock	$ 22.12
Conversion price of preferred stock before acquisition	$ 25.00
Conversion rate of deemed common shares	40 deemed common shares for each share of preferred stock
Number of deemed common shares in conversion	3,000,000
Redemption value of deemed common shares	$ 66.4

XML

Supplemental Balance Sheet Income Statement and Cash Flow Information (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental cash flow information
Cash paid for income taxes	$ 53,759	$ 58,574	$ 107,994
Cash paid for interest, net of capitalized interest	208,212	180,731	126,796
Acquisitions of businesses:
Fair value of assets acquired	80,585	796,399
Goodwill	8,000	339,992
Liabilities assumed	(10,471)	(332,528)
Common stock of acquired company previously owned	0	0	0
Subsidiary preferred stock obligation	0	(69,188)	0
Gain on acquisition	(13,114)	0
Cash paid for acquisitions of businesses	65,000	734,675
Cash acquired in acquisitions of businesses	(9,541)	(1,045)
Cash paid for acquisition of business, net	$ 55,459	$ 733,630

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net income (loss) attributable to Nabors	$ 243,679	$ 94,695	$ (85,546)
Adjustments to net income (loss):
Depreciation and amortization	927,460	766,519	668,415
Depletion and other exploratory expenses	44,551	27,002	11,078
Deferred income tax expense (benefit)	(34,739)	55,964	(218,760)
Deferred financing costs amortization	5,107	5,431	6,133
Pension liability amortization and adjustments	818	664	844
Discount amortization on long-term debt	27,042	70,719	86,802
Amortization of loss on hedges	927	786	580
Impairments and other charges	460,971	260,931	339,129
Losses (gains) on long-lived assets, net	(51,945)	(1,050)	12,339
Losses (gains) on investments, net	(12,486)	191	(9,954)
Losses (gains) on debt retirement, net	58	7,042	(11,197)
Losses (gains) on derivative instruments	234	2,471	338
Gain on acquisition	(13,114)	0
Share-based compensation	21,244	13,746	106,725
Foreign currency transaction losses (gains), net	5,725	17,880	8,372
Equity in (earnings) losses of unconsolidated affiliates, net of dividends	(132,388)	(13,630)	229,813
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(459,455)	(249,725)	450,530
Inventory	(114,896)	(15,201)	52,995
Other current assets	(24,820)	6,589	205,108
Other long-term assets	71,867	7,509	(22,233)
Trade accounts payable and accrued liabilities	517,615	70,463	(146,470)
Income taxes payable	999	(19,208)	(62,535)
Other long-term liabilities	(27,967)	(2,804)	(5,534)
Net cash provided by operating activities	1,456,487	1,106,984	1,616,972
Cash flows from investing activities:
Purchases of investments	(11,746)	(34,147)	(32,674)
Sales and maturities of investments	39,063	34,613	57,033
Cash paid for acquisition of businesses, net	(55,459)	(733,630)
Investment in unconsolidated affiliates	(112,262)	(40,936)	(125,076)
Distribution of proceeds from asset sales of unconsolidated affiliates	142,984
Capital expenditures	(2,042,617)	(930,277)	(1,093,435)
Proceeds from sales of assets and insurance claims	180,558	31,072	31,375
Net cash used for investing activities	(1,859,479)	(1,673,305)	(1,162,777)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts	6,375	(6,298)	(18,157)
Proceeds from issuance of long-term debt	697,578	696,948	1,124,978
Debt issuance costs	(7,141)	(8,934)	(8,832)
Payments for (proceeds from) hedge transactions		(5,667)
Proceeds from revolving credit facilities	1,560,000	600,000
Proceeds from issuance of common shares	11,605	8,201	11,249
Reduction in long-term debt	(1,404,281)	(398,514)	(1,081,801)
Reduction in revolving credit facilities	(700,000)	(600,000)
Repurchase of equity component of convertible debt	(12)	(4,712)	(6,586)
Settlement of call options and warrants, net	0	1,134
Purchase of restricted stock	(2,626)	(1,935)	(1,515)
Tax benefit related to share-based awards	1,747	31	37
Net cash provided by financing activities	163,245	280,254	19,373
Effect of exchange rate changes on cash and cash equivalents	(3,380)	(46)	12,160
Net increase (decrease) in cash and cash equivalents	(243,127)	(286,113)	485,728
Cash and cash equivalents, beginning of period	641,702	927,815	442,087
Cash and cash equivalents, end of period	$ 398,575	$ 641,702	$ 927,815

XML

Income Taxes (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2031	Dec. 31, 2008
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 6,659,593,000			$ 76,493,000
Unrecognized tax benefit	68,848,000	81,174,000	69,048,000		51,819,000
Income Taxes (Textual) [Abstract]
Liability related to unrecognized tax benefit including accrued interest and penalties	28,200,000	42,900,000	38,500,000
Tax expense including interest and penalties	4,600,000	5,100,000	5,200,000
US Federal tax rate	35.00%
NOL carryforwards for alternative minimum tax purpose	686,000,000
Net operating loss carryforwards	2,009,318,000	1,848,956,000
Recognized valuation allowance relating to NOL carryforwards	1,450,000,000
Domestic Country [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	1,230,045,000
Expiration date of NOL carry forwards	2016 to 2031
Foreign Country [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	5,429,548,000
Expiration date of NOL carry forwards	2012 to 2031
NOL carryforward expiring other jurisdiction	408,000,000
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	649,000,000
Expiration date of NOL carry forwards	2012 to 2031
Algeria Audit Assessment [Member]
Operating Loss Carryforwards [Line Items]
Unrecognized tax benefit	13,500,000
Addition to unrecognized tax benefits	10,800,000
Canada Revenue Agency [Member]
Operating Loss Carryforwards [Line Items]
Tax audit settlements	16,800,000
Income tax audit settlement period	1995 to 1997
Reduction to unrecognized tax benefits	$ 8,600,000

XML

Impairments and Other Charges (Deatils Textual) (USD $)	12 Months Ended
	Dec. 31, 2011 Rigs	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Schedule of Trading Securities and Other Trading Assets [Line Items]
Other-than-temporary impairment on equity security			$ 54,300,000
Impaired Long-Lived Assets Held and Used [Line Items]
Provision for retirement of long-lived assets	98,072,000	23,213,000	64,229,000
Impairment of long-lived assets		27,372,000
Goodwill impairments		10,707,000
Impairments and Other Charges (Textual) [Abstract]
Number of Jackup rigs decommissioned and retired	1
Contribution for employee benefit in Nabors	1,000,000
Number of land rigs decommissioned and retired	116
Credit related impairment on debt securities			35,649,000
Carrying value of equity investment				46,000,000
U.S. Lower 48 Land Drilling [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Provision for retirement of long-lived assets	63,200,000
International [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Provision for retirement of long-lived assets	26,100,000
U.S. Land Well-servicing [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Provision for retirement of long-lived assets	8,900,000
U.S. Offshore [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		27,300,000
Goodwill impairments		10,707,000
Equity Securities [Member]
Schedule of Trading Securities and Other Trading Assets [Line Items]
Other-than-temporary impairment on equity security			$ 18,700,000

XML

Pension, Postretirement and Postemployment Benefits (Details 2) (Pension Benefits [Member])	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits [Member]
Weighted-average asset allocations of Pool Pension Plan
Cash	2.00%	2.00%
Equity securities	56.00%	56.00%
Debt securities	42.00%	42.00%
Total	100.00%	100.00%

XML

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Inventory

	December 31, 2011		December 31, 2010
	(In thousands)
Raw materials	$	133,480	$	81,308
Work-in-progress		50,951		23,629
Finished goods		88,421		53,899
	$	272,852	$	158,836

Change in the carrying amount of goodwill for various Contract Drilling segments and other Operating Segments

	Balance as of December 31, 2009		Acquisitions and Purchase Price Adjustments			Impairments			Cumulative Translation Adjustment		Balance as of December 31, 2010
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—		$	—	$	30,154
U.S. Land Well-servicing		50,839		5,000	(1)		—			—		55,839
U.S. Offshore		18,003		—			(10,707	)(2)		—		7,296
Alaska		19,995		—			—			—		19,995
International		18,983		—			—			—		18,983
Subtotal Contract Drilling		137,974		5,000			(10,707	)		—		132,267
Pressure Pumping		—		334,992	(3)		—			—		334,992
Other Operating Segments		26,291		—			—			822		27,113
Total	$	164,265	$	339,992		$	(10,707	)	$	822	$	494,372

	Balance as of December 31, 2010		Acquisitions and Purchase Price Adjustments			Impairments		Cumulative Translation Adjustment			Balance as of December 31, 2011
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—	$	—		$	30,154
U.S. Land Well-servicing		55,839		(767	)(1)		—		—			55,072
U.S. Offshore		7,296		—			—		—			7,296
Alaska		19,995		—			—		—			19,995
International		18,983		—			—		—			18,983
Subtotal Contract Drilling		132,267		(767	)		—		—			131,500
Pressure Pumping		334,992		—			—		—			334,992
Other Operating Segments		27,113		8,000	(4)		—		(347	)		34,766
Total	$	494,372	$	7,233		$	—	$	(347	)	$	501,258

(1) Represents the goodwill recorded in connection with our acquisition of Energy Contractors during 2010 and an adjustment to the goodwill recorded during 2011. See Note 5 — Acquisitions for additional discussion.

(2) Represents goodwill impairment associated with our U.S. Offshore operating segment. 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. See Note 3 — Impairments and Other Charges for additional information.

(3) Represents the goodwill recorded in connection with our acquisition of Superior. See Note 5 — Acquisitions for additional discussion.

(4) Represents goodwill recorded in connection with our acquisition of the remaining 50 percent equity interest of Peak. See Note 5 — Acquisitions for additional discussion.

Our Oil and Gas segment does not have any goodwill. Goodwill for the consolidated company, totaling approximately $12.9 million, is expected to be deductible for tax purposes.

XML

Cash and Cash Equivalents and Short-term Investments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Cash and cash equivalents, short-term and long-term investments and other receivables
Cash and cash equivalents	$ 398,575	$ 641,702	$ 927,815	$ 442,087
Short-term investments:
Trading equity securities	11,600	19,630
Available-for-sale equity securities	71,433	79,698
Available-for-sale debt securities	57,881	60,160
Total short-term investments	$ 140,914	$ 159,488

XML

Common Shares

12 Months Ended

Dec. 31, 2011

Common Shares [Abstract]

Common Shares

Note 14    Common Shares

Our authorized share capital consists of 800 million common shares, par value $.001 per share, and 25 million preferred shares, par value $.001 per share. Common shares issued were 317,042,324 and 315,034,436 at $.001 par value as of December 31, 2011 and 2010, respectively. No preferred shares have been issued. The preferred stock is issuable in one or more classes or series, full, limited or no voting rights, designations, preferences, special rights, qualifications, limitations and restrictions as may be determined by Nabors Industries Ltd.’s board.

From time to time, treasury shares may be reissued. When shares are reissued, we use the weighted-average-cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from our capital in excess of par value account. No shares have been purchased during the years ended December 31, 2011, 2010 and 2009.

During 2011, 2010 and 2009 our outstanding shares increased by 82,138, 110,805 and 218,835, respectively, pursuant to a share settlement of stock options exercised by Mr. Petrello. As part of these transactions, Mr. Petrello surrendered unexercised vested stock options to the Company with a value of approximately $7.6 million, $24.5 million and $5.6 million, respectively, to satisfy the option exercise price and related income taxes for 2011, 2010 and 2009. During 2010 our outstanding shares also increased by 22,385, pursuant to a similar share settlement of stock options exercised by Mr. Isenberg. As part of these transactions, Mr. Isenberg surrendered unexercised vested stock options to the Company with a value of approximately $50.1 million to satisfy the option exercise price and related income taxes for 2010.

For the years ended December 31, 2011, 2010 and 2009 the Compensation Committee of our Board of Directors granted restricted stock awards to some of our executive officers, other key employees, and independent directors. We awarded 1,096,379, 538,496 and 85,000 restricted shares at an average market price of $27.32, $22.15 and $11.55 to these individuals for 2011, 2010 and 2009, respectively. See Note 8 — Share-Based Compensation for a summary of our restricted stock and option awards as of December 31, 2011.

For the years ended December 31, 2011, 2010 and 2009 our employees exercised vested options to acquire 1.1 million, .7 million and 1.5 million of our common shares, respectively, resulting in proceeds of $11.6 million, $8.2 million and $11.2 million, respectively.

XML

Impairments and Other Charges (Tables)

12 Months Ended

Dec. 31, 2011

Impairments and Other Charges [Abstract]

Components of impairments and other charges

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Provision for termination payment	$	100,000	$	—	$	—
Provision for retirement of long-lived assets		98,072		23,213		64,229
Impairment of long-lived assets		—		27,372		—
Goodwill impairments		—		10,707		—
Other-than-temporary impairment of equity security		—		—		18,665
Other-than-temporary impairment of debt security		—		—		40,300
Less other-than-temporary impairment recognized in accumulated other comprehensive income (loss)		—		—		(4,651	)
Credit-related impairment of investment		—		—		35,649
Impairments and other charges	$	198,072	$	61,292	$	118,543

XML

Pension, Postretirement and Postemployment Benefits (Details 1) (Pension Benefits [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	$ 16,352	$ 15,219	$ 14,058
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	396
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	9,166
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	6,790
Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	15,956
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 1 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 1 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 1 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	16,352
Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	396
Level 2 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	9,166
Level 2 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	6,790
Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	15,956
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 3 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 3 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 3 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	0
Level 3 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan assets	$ 0

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Total results of operations	$ 10,744	$ (93,375)
Consolidated Subsidiary [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	45,108	47,075
Production costs	43,818	24,393
Exploration expenses	27,214	39,047
Depreciation and depletion	23,403	29,253
Impairment of oil and gas properties	255,046	110,165
Loss (gain) on acquisitions/dispositions	(46,241)
Related income tax expense (benefit)	(78,109)	(18,324)
Total results of operations	(180,023)	(137,459)
Equity Companies [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	126,998	90,950
Production costs	42,988	36,670
Depreciation and depletion	50,402	37,312
Impairment of oil and gas properties	15,624	851
Loss (gain) on acquisitions/dispositions	(49,484)
Realized gain on derivative instruments	(34,053)	(27,967)
Related income tax expense (benefit)	6,055	0
Total results of operations	190,767	44,084
U.S. [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Total results of operations	40,249	(57,103)
U.S. [Member] | Consolidated Subsidiary [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	25,684	19,180
Production costs	12,682	8,510
Exploration expenses	23,768
Depreciation and depletion	22,350	20,092
Impairment of oil and gas properties	71,392	110,165
Loss (gain) on acquisitions/dispositions	(6,642)
Related income tax expense (benefit)	(38,707)	(15,856)
Total results of operations	(59,159)	(103,731)
U.S. [Member] | Equity Companies [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	98,933	64,736
Production costs	27,790	18,460
Depreciation and depletion	39,564	24,221
Impairment of oil and gas properties	15,624	851
Loss (gain) on acquisitions/dispositions	(49,484)
Realized gain on derivative instruments	(33,969)	(25,424)
Related income tax expense (benefit)		0
Total results of operations	99,408	46,628
Canada [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Total results of operations	(156,702)	(5,523)
Canada [Member] | Consolidated Subsidiary [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	7,046	11,276
Production costs	27,432	7,965
Exploration expenses	3,324
Depreciation and depletion	104	5,424
Impairment of oil and gas properties	183,654
Related income tax expense (benefit)	(54,979)	(3,078)
Total results of operations	(152,489)	965
Canada [Member] | Equity Companies [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	1,335	6,038
Production costs	4,600	9,036
Depreciation and depletion	1,032	6,033
Realized gain on derivative instruments	(84)	(2,543)
Related income tax expense (benefit)		0
Total results of operations	(4,213)	(6,488)
Colombia [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Total results of operations	127,197	(30,749)
Colombia [Member] | Consolidated Subsidiary [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	12,378	16,619
Production costs	3,704	7,918
Exploration expenses	122	39,047
Depreciation and depletion	949	3,737
Loss (gain) on acquisitions/dispositions	(39,599)
Related income tax expense (benefit)	15,577	610
Total results of operations	31,625	(34,693)
Colombia [Member] | Equity Companies [Member]
Results of operations exclude general office overhead and interest expense attributable to oil and gas activities
Revenue	26,730	20,176
Production costs	10,598	9,174
Depreciation and depletion	9,806	7,058
Loss (gain) on acquisitions/dispositions	(95,301)
Related income tax expense (benefit)	6,055	0
Total results of operations	$ 95,572	$ 3,944

XML

Pension, Postretirement and Postemployment Benefits

12 Months Ended

Dec. 31, 2011

Pension, Postretirement and Postemployment Benefits [Abstract]

Pension, Postretirement and Postemployment Benefits

Note 16    Pension, Postretirement and Postemployment Benefits

Pension Plans

In conjunction with our acquisition of Pool Energy Services Co. (“Pool”) in November 1999, we acquired the assets and liabilities of a defined benefit pension plan, the Pool Company Retirement Income Plan (the “Pool Pension Plan”). Benefits under the Pool Pension Plan are frozen and participants were fully vested in their accrued retirement benefit on December 31, 1998.

Summarized information on the Pool Pension Plan is as follows:

	Pension Benefits
	2011			2010
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	20,628		$	18,865
Remeasurement		1,517			—
Interest cost		1,198			1,116
Actuarial loss (gain)		3,975			1,289
Benefit payments		(659	)		(642	)
Benefit obligation at end of year(1)	$	26,659		$	20,628
Change in plan assets:
Fair value of plan assets at beginning of year	$	15,219		$	14,058
Actual (loss) return on plan assets		480			1,364
Employer contribution		1,312			439
Benefit payments		(659	)		(642	)
Fair value of plan assets at end of year	$	16,352		$	15,219
Funded status:
Underfunded status at end of year	$	(10,307	)	$	(5,409	)
Amounts recognized in consolidated balance sheets:
Other long-term liabilities	$	(10,307	)	$	(5,409	)

	Year Ended December 31,
	2011			2010			2009
Components of net periodic benefit cost (recognized in our consolidated statements of income):
Interest cost	$	1,198		$	1,116		$	1,093
Expected return on plan assets		(1,008	)		(909	)		(794	)
Recognized net actuarial loss		628			457			545
Net periodic benefit cost	$	818		$	664		$	844
Weighted-average assumptions:
Weighted-average discount rate		4.25	%		5.50	%		6.00	%
Expected long-term rate of return on plan assets		6.50	%		6.50	%		6.50	%

(1) As of December 31, 2011 and 2010, the accumulated benefit obligation was the same as the projected benefit obligation.

For the years ended December 31, 2011, 2010 and 2009, the net actuarial loss amounts included in accumulated other comprehensive income (loss) in the consolidated statements of changes in equity were approximately $(12.1) million, $(6.7) million and $(6.3) million, respectively. There were no other components, such as prior service costs or transition obligations relating to pension costs recorded within accumulated other comprehensive income (loss) during 2011, 2010 and 2009.

The amount included in accumulated other comprehensive income (loss) in the consolidated statements of changes in equity that is expected to be recognized as a component of net periodic benefit cost during 2012 is approximately $1.0 million.

We analyze the historical performance of investments in equity and debt securities, together with current market factors such as inflation and interest rates to help us make assumptions necessary to estimate a long-term rate of return on plan assets. Once this estimate is made, we review the portfolio of plan assets and make adjustments thereto that we believe are necessary to reflect a diversified blend of investments in equity and debt securities that is capable of achieving the estimated long-term rate of return without assuming an unreasonable level of investment risk.

The following table sets forth, by level within the fair value hierarchy, the investments in the Pool Pension Plan as of December 31, 2011. The investments’ fair value measurement level within the fair value hierarchy is classified in its entirety based on the lowest level of input that is significant to the measurement.

	Fair Value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:(1)
Cash	$	—	$	396	$	—	$	396
Short-term investments:
Available-for-sale equity securities(2)		—		9,166		—		9,166
Available-for-sale debt securities(3)		—		6,790		—		6,790
Total investments		—		15,956		—		15,956
Total	$	—	$	16,352	$	—	$	16,352

(1) Includes investments in collective trust funds that are valued based on the fair value of the underlying investments using quoted prices in active markets or other significant inputs that are deemed observable.

(2) Includes funds that invest primarily in U.S. common stocks and foreign equity securities.

(3) Includes funds that invest primarily in investment grade debt.

The measurement date used to determine pension measurements for the plan is December 31.

Our weighted-average asset allocations as of December 31, 2011 and 2010, by asset category are as follows:

	Pension Benefits
	2011			2010
Cash		2	%		2	%
Equity securities		56	%		56	%
Debt securities		42	%		42	%
Total		100	%		100	%

We invest plan assets based on a total return on investment approach, pursuant to which the plan assets include a diversified blend of investments in equity and debt securities toward a goal of maximizing the long-term rate of return without assuming an unreasonable level of investment risk. We determine the level of risk based on an analysis of plan liabilities, the extent to which the value of the plan assets satisfies the plan liabilities and our financial condition. Our investment policy includes target allocations approximating 55% investment in equity securities and 45% investment in debt securities. The equity portion of the plan assets represents growth and value stocks of small, medium and large companies. We measure and monitor the investment risk of the plan assets both on a quarterly basis and annually when we assess plan liabilities.

We expect to contribute approximately $1.5 million to the Pool Pension Plan in 2012. This is based on the sum of (1) the minimum contribution for the 2011 plan year that will be made in 2011 and (2) the estimated minimum required quarterly contributions for the 2012 plan year. We made contributions to the Pool Pension Plan in 2011 and 2010 totaling $1.3 million and $.1 million, respectively.

As of December 31, 2011, we expect that benefits to be paid in each of the next five years after 2011 and in the aggregate for the five years thereafter will be as follows:

	(In thousands)
2012	$	791
2013		890
2014		1,004
2015		1,117
2016		1,193
2017 — 2021		7,428

Some of our employees are covered by defined contribution plans. Our contributions to the plans totaled $22.9 million and $13.6 million for the years ended December 31, 2011 and 2010, respectively. Nabors does not provide post-employment benefits to its employees, except for employees covered under the Pool Pension Plan.

Post-retirement Benefits Other Than Pensions

Prior to the date of our acquisition, Pool provided certain post-retirement healthcare and life insurance benefits to eligible retirees who had attained specific age and years of service requirements. Nabors terminated this plan at the date of acquisition (November 24, 1999). A liability of approximately $.2 million was recorded in our consolidated balance sheets as of each of December 31, 2011 and 2010, to cover the estimated costs of beneficiaries covered by the plan at the date of acquisition.

XML

Cash and Cash Equivalents and Short-term Investments (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Debt securities:
Due in one year or less	$ 1,230
Due after one year through five years	0
Due in more than five years	56,651
Total debt securities	$ 57,881

XML

Earnings (Losses) Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income (loss) (numerator):
Income (loss) from continuing operations, net of tax	$ 89,535	$ 87,190	$ 70,887	$ 94,552	$ 152,097	$ 12,347	$ 44,949	$ 46,477	$ 342,164	$ 255,870	$ 132,721
Less: Net (income) loss attributable to noncontrolling interest	(1,400)	(708)	394	669	(1,293)	(453)	559	1,102	(1,045)	(85)	342
Net income (loss) from continuing operations basic									341,119	255,785	133,063
Add interest expense on assumed conversion of our 0.94% senior exchangeable notes, net of tax
Adjusted net income (loss) attributable to Nabors - diluted									341,119	255,785	133,063
Earnings (losses) per share:
Basic from continuing operations	$ 0.31	$ 0.30	$ 0.25	$ 0.33	$ 0.53	$ 0.04	$ 0.16	$ 0.17	$ 1.19	$ 0.90	$ 0.47
Diluted from continuing operations	$ 0.30	$ 0.30	$ 0.24	$ 0.33	$ 0.52	$ 0.04	$ 0.16	$ 0.16	$ 1.17	$ 0.88	$ 0.46
Income (loss) from discontinued operations, net of tax	$ (193,985)	$ (12,226)	$ 121,167	$ (12,396)	$ (100,323)	$ (51,501)	$ (1,887)	$ (7,379)	$ (97,440)	$ (161,090)	$ (218,609)
Earnings (losses) per share, discontinued operations:
Basic from discontinued operations	$ (0.68)	$ (0.04)	$ 0.42	$ (0.04)	$ (0.35)	$ (0.18)	$ (0.01)	$ (0.03)	$ (0.34)	$ (0.57)	$ (0.77)
Diluted from discontinued operations	$ (0.66)	$ (0.05)	$ 0.41	$ (0.05)	$ (0.35)	$ (0.18)	$ (0.01)	$ (0.02)	$ (0.34)	$ (0.55)	$ (0.76)
Shares (denominator):
Weighted-average number of shares outstanding - basic									287,118	285,145	283,326
Net effect of dilutive stock options, warrants and restricted stock awards based on the if-converted method									5,366	4,851	3,176
Assumed conversion of our 0.94% senior exchangeable notes
Weighted-average number of shares outstanding - diluted		292,484							292,484	289,996	286,502

XML

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $) In Thousands, unless otherwise specified	Total	Common Shares	Capital in Excess of Par Value	Accumulated Other Comprehensive Income	Retained Earnings	Treasury Shares	Non-controlling Interest
Beginning Balances at Dec. 31, 2008	$ 4,918,424	$ 312	$ 2,129,415	$ 53,520	$ 3,698,732	$ (977,873)	$ 14,318
Beginning Balances, shares at Dec. 31, 2008		312,343
Comprehensive income (loss):
Net income (loss) attributable to Nabors	(85,546)				(85,546)
Translation adjustment attributable to Nabors	150,290			150,290
Unrealized gains/(losses) on marketable securities, net of income taxes of $86, $7,435 and $839 for 2011, 2010 and 2009, respectively	36,727			36,727
Unrealized gains/(losses) on adjusted basis for marketable debt security, net of income taxes of $1,199	1,956			1,956
Less: Reclassification adjustment for (gains)/losses included in net income (loss), net of income taxes of $0, $693 and $4,921 for 2011,2010 and 2009, respectively	49,386			49,386
Pension liability amortization, net of income taxes of $319, $259 and $325 for 2011, 2010 and 2009, respectively	519			519
Pension liability adjustment, net of income tax benefit of $2421, $405 and $89 for 2011, 2010 and 2009, respectively	130			130
Unrealized gains/(losses) and amortization of (gains)/losses on cash flow hedges, net of income taxes of $239, $2,119 and $18 for 2011,2010 and 2009, respectively	178			178
Comprehensive income (loss) attributable to Nabors	153,640
Net income (loss) attributable to noncontrolling interest	(342)						(342)
Translation adjustment attributable to noncontrolling interest	2,024						2,024
Comprehensive income (loss) attributable to noncontrolling interest	1,682
Total comprehensive income (loss)	155,322
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options	11,249	2	11,247
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options, shares	1,500	1,476
Share-based compensation	106,725		106,725
Other	(9,741)		(8,064)				(1,677)
Other, net, shares		(9)
Ending Balances at Dec. 31, 2009	5,181,979	314	2,239,323	292,706	3,613,186	(977,873)	14,323
Ending Balances, shares at Dec. 31, 2009		313,915
Comprehensive income (loss):
Net income (loss) attributable to Nabors	94,695				94,695
Translation adjustment attributable to Nabors	60,897			60,897
Unrealized gains/(losses) on marketable securities, net of income taxes of $86, $7,435 and $839 for 2011, 2010 and 2009, respectively	(7,157)			(7,157)
Less: Reclassification adjustment for (gains)/losses included in net income (loss), net of income taxes of $0, $693 and $4,921 for 2011,2010 and 2009, respectively	(1,001)			(1,001)
Pension liability amortization, net of income taxes of $319, $259 and $325 for 2011, 2010 and 2009, respectively	405			405
Pension liability adjustment, net of income tax benefit of $2421, $405 and $89 for 2011, 2010 and 2009, respectively	(635)			(635)
Unrealized gains/(losses) and amortization of (gains)/losses on cash flow hedges, net of income taxes of $239, $2,119 and $18 for 2011,2010 and 2009, respectively	(3,163)			(3,163)
Comprehensive income (loss) attributable to Nabors	144,041
Net income (loss) attributable to noncontrolling interest	85						85
Translation adjustment attributable to noncontrolling interest	723						723
Comprehensive income (loss) attributable to noncontrolling interest	808
Total comprehensive income (loss)	144,849
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options	8,201	1	8,200
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options, shares	700	714
Settlement of call options and warrants, net	1,134
Share-based compensation	13,746		13,746
Other	(5,912)		(5,482)				(430)
Other, net, shares		405
Ending Balances at Dec. 31, 2010	5,342,863	315	2,255,787	342,052	3,707,881	(977,873)	14,701
Ending Balances, shares at Dec. 31, 2010		315,034
Comprehensive income (loss):
Net income (loss) attributable to Nabors	243,679				243,679
Translation adjustment attributable to Nabors	20,257			20,257
Unrealized gains/(losses) on marketable securities, net of income taxes of $86, $7,435 and $839 for 2011, 2010 and 2009, respectively	5,270			5,270
Less: Reclassification adjustment for (gains)/losses included in net income (loss), net of income taxes of $0, $693 and $4,921 for 2011,2010 and 2009, respectively	(3,036)			(3,036)
Pension liability amortization, net of income taxes of $319, $259 and $325 for 2011, 2010 and 2009, respectively	499			499
Pension liability adjustment, net of income tax benefit of $2421, $405 and $89 for 2011, 2010 and 2009, respectively	(3,788)			(3,788)
Unrealized gains/(losses) and amortization of (gains)/losses on cash flow hedges, net of income taxes of $239, $2,119 and $18 for 2011,2010 and 2009, respectively	524			524
Comprehensive income (loss) attributable to Nabors	222,891
Net income (loss) attributable to noncontrolling interest	1,045						(1,045)
Translation adjustment attributable to noncontrolling interest	(185)						(185)
Comprehensive income (loss) attributable to noncontrolling interest	860
Total comprehensive income (loss)	223,751
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options	11,605	1	11,604
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options, shares	(1,116)	1,116
Settlement of call options and warrants, net	0
Share-based compensation	21,244		21,244
Other	1,754	1	(892)		4,804		(2,159)
Other, net, shares		892
Ending Balances at Dec. 31, 2011	$ 5,601,217	$ 317	$ 2,287,743	$ 321,264	$ 3,956,364	$ (977,873)	$ 13,402
Ending Balances, shares at Dec. 31, 2011		317,042

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
CONSOLIDATED BALANCE SHEETS [Abstract]
Common shares, par value	$ 0.001	$ 0.001
Common shares, shares authorized	800,000	800,000
Common shares, shares issued	317,042	315,034
Treasury shares, at cost	29,414	29,414

XML

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Note 9    Property, Plant and Equipment

The major components of our property, plant and equipment are as follows:

	December 31,
	2011			2010
	(In thousands)
Land	$	22,120		$	12,087
Buildings		132,753			122,635
Drilling, workover and well-servicing rigs, and related equipment		11,150,927			10,632,968
Marine transportation and supply vessels		14,023			13,663
Oilfield hauling and mobile equipment		1,171,930			551,892
Other machinery and equipment		248,938			143,976
Oil and gas properties(1)		42,033			664,289
Construction in process(2)		815,987			349,455
		13,598,711			12,490,965
Less: accumulated depreciation and amortization		(4,928,781	)		(4,182,122	)
accumulated depletion on oil and gas properties		(39,984	)		(493,424	)
	$	8,629,946		$	7,815,419

(1) A significant portion of our oil and gas properties have been reclassified to assets held for sale at December 31, 2011. Information relating to suspended wells that have capitalized costs for more than one year on this date is located at Note 4 — Discontinued Operations.

(2) Relates to amounts capitalized for new or substantially new drilling, workover and well-servicing rigs that were under construction and had not yet been placed in service as of December 31, 2011 or 2010.

Repair and maintenance expense included in direct costs in our consolidated statements of income (loss) totaled $586.4 million, $382.5 million and $277.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Interest costs of $24.0 million, $12.4 million and $29.9 million were capitalized during the years ended December 31, 2011, 2010 and 2009, respectively.

XML

Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Minimum rental commitments under non cancellable operating leases
2012	$ 25,288
2013	20,060
2014	14,363
2015	7,273
2016	4,020
Thereafter	9,857
Total	$ 80,861

XML

Income Taxes (Details 5) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2031	Dec. 31, 2030	Dec. 31, 2029	Dec. 31, 2028	Dec. 31, 2027	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
NOL carryforwards by year of expiration:
Operating Loss Carryforwards	$ 626,288	$ 533,825	$ 184,463	$ 31,237	$ 2,014	$ 7,895	$ 14,612	$ 35,986	$ 68,888	$ 26,601	$ 50,176	$ 12,824	$ 3,980	$ 30,348	$ 8,778	$ 1,637,915
Non-expiring NOLs	549,795															5,021,678
Total	76,493															6,659,593
Domestic Country [Member]
NOL carryforwards by year of expiration:
Operating Loss Carryforwards		485,648	130,842	0	0	0	0	17,722	33,111	5,423	7,504	0	0	0	0	1,230,045
Non-expiring NOLs																0
Total																1,230,045
Foreign Country [Member]
NOL carryforwards by year of expiration:
Operating Loss Carryforwards		48,177	53,621	31,237	2,014	7,895	14,612	18,264	35,777	21,178	42,672	12,824	3,980	30,348	8,778	407,870
Non-expiring NOLs																5,021,678
Total																$ 5,429,548

XML

Income Taxes (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of the differences between taxes on income (loss) before income taxes
Income tax provision at statutory rate (Bermuda rate of 0%)	$ 0	$ 0	$ 0
Taxes on U.S. and other international earnings (losses) at greater than the Bermuda rate	112,094	18,686	(60,741)
Increase (decrease) in valuation allowance	(6,450)	2,407	6,062
Effect of change in tax rate	(258)	40	(9,248)
Tax reserves and interest	11,948	8,808	14,652
State income taxes	25,271	7,009	(14,662)
Total income tax expense (benefit)	$ 142,605	$ 36,950	$ (63,937)
Effective tax rate	29.20%	12.60%	93.00%

XML

Condensed Consolidating Financial Information (Details Textual) (4.875% senior notes due August 2009 [Member])	Dec. 31, 2011
4.875% senior notes due August 2009 [Member]
Condensed Consolidating Financial Information (Textual) [Abstract]
Interest rate on senior note due	4.875%

XML

Condensed Consolidating Financial Information (Details) (USD $)	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Current assets:
Cash and cash equivalents	$ 398,575,000	$ 641,702,000	$ 927,815,000	$ 442,087,000
Short-term investments	140,914,000	159,488,000
Assets held for sale	401,500,000	352,048,000
Accounts receivable, net	1,576,555,000	1,116,510,000
Inventory	272,852,000	158,836,000
Deferred income taxes	127,874,000	31,510,000
Other current assets	170,044,000	152,836,000
Total current assets	3,088,314,000	2,612,930,000
Long-term investments and other receivables	11,124,000	40,300,000
Property, plant and equipment, net	8,629,946,000	7,815,419,000	7,646,050,000
Goodwill	501,258,000	494,372,000	164,265,000
Intercompany receivables	0	0
Investment in unconsolidated affiliates	371,021,000	267,723,000
Other long-term assets	310,477,000	415,825,000
Total assets	12,912,140,000	11,646,569,000	10,644,690,000
Current liabilities:
Current portion of long-term debt	275,326,000	1,379,018,000
Trade accounts payable	782,753,000	355,282,000
Accrued liabilities	716,773,000	394,292,000
Assets held for sale	54,287,000	0
Income taxes payable	27,710,000	25,788,000
Total current liabilities	1,802,562,000	2,154,380,000
Long-term debt	4,348,490,000	3,064,126,000
Assets held for sale	71,375,000,000
Other long-term liabilities	292,758,000	245,765,000
Deferred income taxes	797,925,000	770,247,000
Intercompany payable	0	0
Total liabilities	7,241,735,000	6,234,518,000
Subsidiary preferred stock	69,188,000	69,188,000
Total shareholders' equity	5,587,815,000	5,328,162,000
Noncontrolling interest	13,402,000	14,701,000
Total equity	5,601,217,000	5,342,863,000	5,181,979,000	4,918,424,000
Total liabilities and equity	12,912,140,000	11,646,569,000
Nabors (Parent/Guarantor) [Member]
Current assets:
Cash and cash equivalents	203,000	10,847,000	11,702,000	8,291,000
Short-term investments	0	0
Assets held for sale	0	0
Accounts receivable, net	0	0
Inventory	0	0
Deferred income taxes	0	0
Other current assets	50,000	50,000
Total current assets	253,000	10,897,000
Long-term investments and other receivables	0	0
Property, plant and equipment, net	0	0
Goodwill	0	0
Intercompany receivables	164,760,000	160,250,000
Investment in unconsolidated affiliates	5,429,029,000	5,160,800,000
Other long-term assets	0	0
Total assets	5,594,042,000	5,331,947,000
Current liabilities:
Current portion of long-term debt	0	0
Trade accounts payable	42,000	0
Accrued liabilities	6,185,000	3,785,000
Assets held for sale	0
Income taxes payable	0	0
Total current liabilities	6,227,000	3,785,000
Long-term debt	0	0
Assets held for sale	0
Other long-term liabilities	0	0
Deferred income taxes	0	0
Intercompany payable	0	0
Total liabilities	6,227,000	3,785,000
Subsidiary preferred stock	0	0
Total shareholders' equity	5,587,815,000	5,328,162,000
Noncontrolling interest	0	0
Total equity	5,587,815,000	5,328,162,000
Total liabilities and equity	5,594,042,000	5,331,947,000
Nabors Delaware (Issuer/Guarantor) [Member]
Current assets:
Cash and cash equivalents	21,000	20,000	135,000	96,000
Short-term investments	0	0
Assets held for sale	0	0
Accounts receivable, net	0	0
Inventory	0	0
Deferred income taxes	0	0
Other current assets	671,000	16,366,000
Total current assets	692,000	16,386,000
Long-term investments and other receivables	0	0
Property, plant and equipment, net	40,792,000	44,270,000
Goodwill	0	0
Intercompany receivables	0	0
Investment in unconsolidated affiliates	6,084,868,000	5,814,219,000
Other long-term assets	32,037,000	36,538,000
Total assets	6,158,389,000	5,911,413,000
Current liabilities:
Current portion of long-term debt	274,604,000	1,378,178,000
Trade accounts payable	23,000	0
Accrued liabilities	100,101,000	89,480,000
Assets held for sale	0
Income taxes payable	0	6,859,000
Total current liabilities	374,728,000	1,474,517,000
Long-term debt	4,297,500,000	3,062,291,000
Assets held for sale	0
Other long-term liabilities	32,303,000	12,787,000
Deferred income taxes	11,221,000	71,815,000
Intercompany payable	379,400,000	301,451,000
Total liabilities	5,095,152,000	4,922,861,000
Subsidiary preferred stock	0	0
Total shareholders' equity	1,063,237,000	988,552,000
Noncontrolling interest	0	0
Total equity	1,063,237,000	988,552,000
Total liabilities and equity	6,158,389,000	5,911,413,000
Nabors Holdings (Issuer) [Member]
Current assets:
Cash and cash equivalents	0	0	0	1,259,000
Short-term investments	0	0
Assets held for sale	0	0
Accounts receivable, net	0	0
Inventory	0	0
Deferred income taxes	0	0
Other current assets	0	0
Total current assets	0	0
Long-term investments and other receivables	0	0
Property, plant and equipment, net	0	0
Goodwill	0	0
Intercompany receivables	0	0
Investment in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	0	0
Current liabilities:
Current portion of long-term debt	0	0
Trade accounts payable	0	0
Accrued liabilities	0	0
Assets held for sale	0
Income taxes payable	0	0
Total current liabilities	0	0
Long-term debt	0	0
Assets held for sale	0
Other long-term liabilities	0	0
Deferred income taxes	0	0
Intercompany payable	0	0
Total liabilities	0	0
Subsidiary preferred stock	0	0
Total shareholders' equity	0	0
Noncontrolling interest	0	0
Total equity	0	0
Total liabilities and equity	0	0
Other Subsidiaries (Non-Guarantors) [Member]
Current assets:
Cash and cash equivalents	398,351,000	630,835,000	915,978,000	432,441,000
Short-term investments	140,914,000	159,488,000
Assets held for sale	401,500,000	352,048,000
Accounts receivable, net	1,576,555,000	1,116,510,000
Inventory	272,852,000	158,836,000
Deferred income taxes	127,874,000	31,510,000
Other current assets	169,323,000	136,420,000
Total current assets	3,087,369,000	2,585,647,000
Long-term investments and other receivables	11,124,000	40,300,000
Property, plant and equipment, net	8,589,154,000	7,771,149,000
Goodwill	501,258,000	494,372,000
Intercompany receivables	537,881,000	322,697,000
Investment in unconsolidated affiliates	1,843,654,000	1,665,459,000
Other long-term assets	278,440,000	379,287,000
Total assets	14,848,880,000	13,258,911,000
Current liabilities:
Current portion of long-term debt	722,000	840,000
Trade accounts payable	782,688,000	355,282,000
Accrued liabilities	556,200,000	301,027,000
Assets held for sale	54,287,000,000
Income taxes payable	27,710,000	18,929,000
Total current liabilities	1,421,607,000	676,078,000
Long-term debt	50,990,000	1,835,000
Assets held for sale	71,375,000,000
Other long-term liabilities	189,079,000	232,978,000
Deferred income taxes	786,705,000	698,432,000
Intercompany payable	323,241,000	181,496,000
Total liabilities	2,842,997,000	1,790,819,000
Subsidiary preferred stock	69,188,000	69,188,000
Total shareholders' equity	11,923,293,000	11,384,203,000
Noncontrolling interest	13,402,000	14,701,000
Total equity	11,936,695,000	11,398,904,000
Total liabilities and equity	14,848,880,000	13,258,911,000
Consolidating Adjustments [Member]
Current assets:
Cash and cash equivalents	0	0	0	0
Short-term investments	0	0
Assets held for sale	0	0
Accounts receivable, net	0	0
Inventory	0	0
Deferred income taxes	0	0
Other current assets	0	0
Total current assets	0	0
Long-term investments and other receivables	0	0
Property, plant and equipment, net	0	0
Goodwill	0	0
Intercompany receivables	(702,641,000)	(482,947,000)
Investment in unconsolidated affiliates	12,986,530,000	(12,372,755,000)
Other long-term assets	0	0
Total assets	12,689,171,000	(12,855,702,000)
Current liabilities:
Current portion of long-term debt	0	0
Trade accounts payable	0	0
Accrued liabilities	0	0
Assets held for sale	0
Income taxes payable	0	0
Total current liabilities	0	0
Long-term debt	0	0
Assets held for sale	0
Other long-term liabilities	0	0
Deferred income taxes	0	0
Intercompany payable	(702,641,000)	(482,947,000)
Total liabilities	(702,641,000)	(482,947,000)
Subsidiary preferred stock	0	0
Total shareholders' equity	(12,986,530,000)	(12,372,755,000)
Noncontrolling interest	0	0
Total equity	(12,986,530,000)	(12,372,755,000)
Total liabilities and equity	$ (13,689,171,000)	$ (12,855,702,000)

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Feb. 24, 2012	Jun. 30, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	NABORS INDUSTRIES LTD
Entity Central Index Key	0001163739
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float (actual number)			$ 6,531,806,216
Entity Common Stock, Shares Outstanding (actual number)		288,679,432

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Consolidated Subsidiary [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, proved	$ 30,799	$ 25,080
Property acquisition costs, unproved	63,371	26,202
Exploration costs	49,278	41,798
Development costs	63,569	22,994
Asset retirement costs	1,500	770
Total costs incurred for equity companies	208,517	116,844
Equity Companies [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, proved	232,410	29,975
Property acquisition costs, unproved	18,663	34,207
Exploration costs	252	30,035
Development costs	136,711	131,689
Asset retirement costs	2,834	192
Total costs incurred for equity companies	390,870	226,098
U.S. [Member] | Consolidated Subsidiary [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, proved	23,051	25,080
Property acquisition costs, unproved	37,272	25,202
Exploration costs	49,156	8,199
Development costs	43,780	19,118
Asset retirement costs	496
Total costs incurred for equity companies	153,755	77,599
U.S. [Member] | Equity Companies [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, proved	232,410	29,975
Property acquisition costs, unproved	14,268	34,207
Exploration costs	252	108
Development costs	136,711	118,828
Asset retirement costs	2,834	296
Total costs incurred for equity companies	386,475	183,414
Canada [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, proved	7,748
Canada [Member] | Consolidated Subsidiary [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, unproved	26,099
Development costs	184	3,876
Asset retirement costs	750
Total costs incurred for equity companies	34,781	3,876
Canada [Member] | Equity Companies [Member]
Costs incurred in property acquisitions, exploration and development activities
Development costs		1,056
Total costs incurred for equity companies		1,056
Colombia [Member] | Consolidated Subsidiary [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, unproved	0	1,000
Exploration costs	122	33,599
Development costs	19,605
Asset retirement costs	254	770
Total costs incurred for equity companies	19,981	35,369
Colombia [Member] | Equity Companies [Member]
Costs incurred in property acquisitions, exploration and development activities
Property acquisition costs, unproved	4,395
Exploration costs		29,927
Development costs		11,805
Asset retirement costs		(104)
Total costs incurred for equity companies	$ 4,395	$ 41,628

XML

Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2011

Investments in Unconsolidated Affiliates [Abstract]

Investments in Unconsolidated Affiliates

Note 10    Investments in Unconsolidated Affiliates

Our principal investments in unconsolidated affiliates accounted for using the equity method include drilling and workover operations located in Saudi Arabia (51% ownership) and an oil and gas exploration, development and production joint venture in the United States (49.7%). These unconsolidated affiliates are integral to our operations in those locations. See Note 17 — Related-Party Transactions for a discussion of transactions with all of these related parties.

As of December 31, 2011 and 2010, our consolidated balance sheets reflect our investments in unconsolidated affiliates accounted for using the equity method totaling $371.0 million and $265.8 million, respectively, and at December 31, 2010, our investments in unconsolidated affiliates accounted for using the cost method totaling $1.9 million. Assets held for sale include investments in unconsolidated affiliates accounted for using the equity method totaling $13.7 million and $79.5 million at December 31, 2011 and 2010, respectively.

Combined condensed financial data for investments in unconsolidated affiliates, including assets classified as held for sale, are summarized as follows:

	December 31,
	2011		2010
	(In thousands)
Current assets	$	311,972	$	322,086
Long-term assets		1,728,399		1,332,212
Current liabilities		275,171		345,279
Long-term liabilities		800,444		460,198

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Gross revenues	$	832,774	$	901,742	$	960,823
Gross margin		278,019		241,831		223,005
Net income (loss)		270,161		48,426		(462,613	)
Nabors’ earnings (losses) from unconsolidated affiliates(1)		56,647		33,267		(155,432	)

(1) Nabors’ earnings (losses) from unconsolidated affiliates included in discontinued operations, net of tax was $76.5 million, $(10.6) million, and $(59.2) million, respectively, for the years ended December 31, 2011, 2010 and 2009.

Cumulative undistributed (losses) earnings of our unconsolidated affiliates included in our retained earnings as of December 31, 2011 and 2010 totaled approximately $(404.6) million and $(373.9) million, respectively. The Earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss) for the years ended December 31, 2011 and 2009 include our proportionate share of full-cost ceiling test writedowns of $15.6 million and $189.3 million, respectively, from our unconsolidated U.S. oil and gas joint venture. This writedown is included in our Oil and Gas operating segment results. Our proportionate share of a full-cost ceiling test writedown of $47.8 million recorded for the year ended December 31, 2009 by unconsolidated oil and gas joint ventures is reflected in discontinued operations. See Note 4 — Discontinued Operations for additional information.

XML

Property, Plant and Equipment (Deatils Textual) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Property, Plant and Equipment [Line Items]
Assets held under capital leases	$ 415,000,000
Property Plant And Equipment (Textual) [Abstract]
Repair and maintenance expense	586,400,000	382,500,000	277,400,000
Interest costs capitalized	$ 24,000,000	$ 12,400,000	$ 29,900,000

XML

Income Taxes (Deatils 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current:
U.S. federal	$ 27,649	$ (137,847)	$ (15,434)
Outside the U.S.	43,732	54,779	84,221
State	38,321	5,859	2,671
Current	109,702	(77,209)	71,458
Deferred:
U.S. federal	41,540	97,114	(80,353)
Outside the U.S.	4,413	13,607	(46,603)
State	(13,050)	3,438	(8,439)
Deferred	32,903	114,159	(135,395)
Total income tax expense (benefit)	$ 142,605	$ 36,950	$ (63,937)

XML

CONSOLIDATED STATEMENTS OF INCOME (LOSS) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and other income:
Operating revenues									$ 6,060,351	$ 4,134,483	$ 3,662,220
Earnings (losses) from unconsolidated affiliates	(2,700)	33,700	9,300	16,300	4,900	11,800	8,900	7,700	56,647	33,267	(155,432)
Investment income (loss)									19,940	7,263	25,522
Total revenues and other income									6,136,938	4,175,013	3,532,310
Costs and other deductions:
Direct costs									3,775,964	2,400,519	1,981,504
General and administrative expenses									489,892	338,720	421,492
Depreciation and amortization									924,094	760,962	663,958
Interest expense									256,633	272,712	266,047
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net									4,514	47,238	11,982
Impairments and other charges									198,072	61,292	118,543
Total costs and other deductions									5,649,169	3,881,443	3,463,526
Income (loss) from continuing operations before income tax									487,769	293,570	68,784
Income tax expense (benefit):
Current									109,702	(77,209)	71,458
Deferred									32,903	114,159	(135,395)
Total income tax expense (benefit)									142,605	36,950	(63,937)
Subsidiary preferred stock dividend									3,000	750
Income (loss) from continuing operations, net of tax	89,535	87,190	70,887	94,552	152,097	12,347	44,949	46,477	342,164	255,870	132,721
Income (loss) from discontinued operations, net of tax	(193,985)	(12,226)	121,167	(12,396)	(100,323)	(51,501)	(1,887)	(7,379)	(97,440)	(161,090)	(218,609)
Net income (loss)									244,724	94,780	(85,888)
Less: Net (income) loss attributable to noncontrolling interest	(1,400)	(708)	394	669	(1,293)	(453)	559	1,102	(1,045)	(85)	342
Net income (loss) attributable to Nabors	$ (105,850)	$ 74,256	$ 192,448	$ 82,825	$ 50,481	$ (39,607)	$ 43,621	$ 40,200	$ 243,679	$ 94,695	$ (85,546)
Earnings (losses) per share:
Basic from continuing operations	$ 0.31	$ 0.30	$ 0.25	$ 0.33	$ 0.53	$ 0.04	$ 0.16	$ 0.17	$ 1.19	$ 0.90	$ 0.47
Basic from discontinued operations	$ (0.68)	$ (0.04)	$ 0.42	$ (0.04)	$ (0.35)	$ (0.18)	$ (0.01)	$ (0.03)	$ (0.34)	$ (0.57)	$ (0.77)
Total Basic	$ (0.37)	$ 0.26	$ 0.67	$ 0.29	$ 0.18	$ (0.14)	$ 0.15	$ 0.14	$ (0.85)	$ 0.33	$ (0.30)
Diluted from continuing operations	$ 0.30	$ 0.30	$ 0.24	$ 0.33	$ 0.52	$ 0.04	$ 0.16	$ 0.16	$ 1.17	$ 0.88	$ 0.46
Diluted from discontinued operations	$ (0.66)	$ (0.05)	$ 0.41	$ (0.05)	$ (0.35)	$ (0.18)	$ (0.01)	$ (0.02)	$ (0.34)	$ (0.55)	$ (0.76)
Total Diluted	$ (0.36)	$ 0.25	$ 0.65	$ 0.28	$ 0.17	$ (0.14)	$ 0.15	$ 0.14	$ 0.83	$ 0.33	$ (0.30)
Weighted-average number of common shares outstanding:
Basic									287,118	285,145	283,326
Diluted		292,484							292,484	289,996	286,502

XML

Discontinued Operations

12 Months Ended

Dec. 31, 2011

Discontinued Operations [Abstract]

Discontinued Operations

Note 4     Discontinued Operations

During 2010, we began actively marketing our oil and gas assets in Canada and Colombia, including our 49.7% and then 50.0% ownership interests in our investments of Remora and SMVP, respectively. All of these assets are included in our Oil and Gas operating segment.

In June 2011, the equity owners of SMVP dissolved the partnership and a proportionate share of the assets and liabilities were conveyed to us in exchange for our ownership interest. The exchange was not a material transaction to us and we accounted for it as a business combination. We continue to market these assets for sale, and believe that they are properly reflected in our assets held for sale balances at December 31, 2011.

In April 2011, we sold some of our wholly owned oil and gas assets in Colombia to an unrelated third party. We received proceeds of $89.2 million from this sale and recognized a gain of approximately $39.6 million. Additionally during the second quarter of 2011, Remora completed sales of its oil and gas assets in Colombia. Remora received gross proceeds of approximately $333.1 million from these sales and has made cash distributions to us in the amount of $143.0 million, with a final distribution expected upon dissolution of the joint venture.

During the fourth quarter of 2011, we announced our intention to dispose of a significant portion of our oil and gas portfolio in an expeditious and prudent manner, and accordingly, reclassified the carrying value of our wholly owned U.S. oil and gas assets to assets held for sale at December 31, 2011. During the fourth quarter of 2011, we also determined that one of our Canadian subsidiaries that provides logistic services for onshore drilling using helicopter and fixed-wing aircraft met the accounting criteria of assets held for sale. Based on quoted market prices, the carrying value of the assets was adjusted to its fair value, resulting in an impairment of $7.9 million, which is included in discontinued operations for the year ended December 31, 2011. We reclassified the adjusted carrying value of these assets to assets held for sale at December 31, 2011.

On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received proceeds of approximately $71.6 million from the sale and recognized a gain of approximately $7.2 million.

At December 31, 2011, our assets held for sale included suspended wells that have capitalized costs for more than one year. Specifically, on the north slope of Alaska, five wells, including two drilled in 2007, one drilled in 2008 and two drilled in 2010, were suspended with total capitalized costs of $42.8 million. Further drilling is needed over the area to determine if the discovery holds sufficient quantities of reserves to justify future investment of infrastructure. One well remains in the process of drilling with total capitalized costs of $12.1 million at December 31, 2011.

At December 31, 2011, our consolidated balance sheet included a current liability of discontinued operations of $54.3 million that is included in other liabilities and a noncurrent liability of discontinued operations of $71.4 million that is included in other long-term liabilities.

The operating results from the assets discussed above for all periods presented are retroactively presented and accounted for as discontinued operations in the accompanying audited consolidated statements of income (loss) and the respective accompanying notes to the consolidated financial statements. Our condensed statements of income (loss) from discontinued operations for each operating segment for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Year Ended December 31,
Condensed Statements of Income — Oil and Gas Operating segment	2011			2010			2009
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates
Oil and Gas	$	125,654	(1)	$	37,615		$	(57,864	)(2)
Income (loss) from discontinued operations
Income (loss) from discontinued operations	$	18.660		$	(26,139	)	$	(81,678	)
Impairment on wholly owned assets		(255,046	)(3)		(192,179	)(4)		(205,897	)(5)
Gain (loss) on disposal of assets		46,811			—			—
Less: income tax expense (benefit)		(98,181	)		(62,028	)		(85,431	)
Income (loss) from discontinued operations, net of tax	$	(91,394	)	$	(156,290	)	$	(202,144	)

(1) Includes approximately $83 million of equity in earnings during 2011 for our proportionate share of Remora’s net income, inclusive of the gains recognized for asset sales during 2011.

(2) Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million during 2009.

(3) Includes impairments of $255.0 million to write down the carrying value of our wholly owned oil and gas-centered assets, including $27.2 million related to an oil and gas financing receivable that was deemed uncollectible.

(4) Includes impairments of $192.2 million related to our wholly owned oil and gas assets. Of this total, $137.8 million represented writedowns to the carrying value of some acreage in the United States, which we currently do not have future plans to develop due to sustained low natural gas prices, and certain exploratory wells in Colombia, which we determined were uneconomical to develop in the foreseeable future. The remaining $54.3 million related to impairment of an oil and gas financing receivable was determined using discounted cash flow models, a Level 3 measurement, and involved assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices.

(5) Includes impairments totaling $205.9 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 lasting 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. Annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $56.8 million to write down the carrying value of some acreage that we do not have future plans to develop.

	Year Ended December 31,
Condensed Statements of Income — Other Operating Segments	2011			2010			2009
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates
Other Operating Segments	$	29,713		$	29,739		$	28,751
Income (loss) from discontinued operations
Income (loss) from discontinued operations	$	(210	)	$	1,059		$	(1,636	)
Goodwill impairment		—			—			(14,689	)(6)
Impairment of long-lived assets		(7,853	)		(7,460	)(7)		—
Gain (loss) on disposal of assets		—			—			—
Less: income tax expense (benefit)		(2,017	)		(1,601	)		140
Income (loss) from discontinued operations, net of tax	$	(6,046	)	$	(4,800	)	$	(16,465	)

(6) Includes $14.7 million to impair the remaining goodwill balance of Nabors Blue Sky Ltd. as a result of our annual goodwill impairment tests. We determined the impairment charge was 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.

(7) Includes $7.5 million of impairment to our aircraft and some drilling equipment during the year ended December 31, 2010. These impairment charges resulted from annual impairment tests on long-lived assets.

Additional discussion of our policy pertaining to the calculations of our annual impairment tests, including any impairment to goodwill, is set forth in Note 2 — Summary of Significant Accounting Policies. A further protraction of lower commodity prices or an inability to sell these assets in a timely manner could result in recognition of future impairment charges.

XML

Impairments and Other Charges

12 Months Ended

Dec. 31, 2011

Impairments and Other Charges [Abstract]

Impairments and other charges

Note 3    Impairments and Other Charges

The following table provides the components of impairments and other charges recorded during the years ended December 31, 2011, 2010 and 2009:

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Provision for termination payment	$	100,000	$	—	$	—
Provision for retirement of long-lived assets		98,072		23,213		64,229
Impairment of long-lived assets		—		27,372		—
Goodwill impairments		—		10,707		—
Other-than-temporary impairment of equity security		—		—		18,665
Other-than-temporary impairment of debt security		—		—		40,300
Less other-than-temporary impairment recognized in accumulated other comprehensive income (loss)		—		—		(4,651	)
Credit-related impairment of investment		—		—		35,649
Impairments and other charges	$	198,072	$	61,292	$	118,543

Provision for termination payment

During the fourth quarter of 2011, we recorded a provision for a contingent liability that existed on December 31, 2011 related to the change of our Chief Executive Officer that occurred in October. This charge resulted from the potential termination payment to our former Chief Executive Officer, Mr. Isenberg, under the terms of his employment contract. Subsequent to December 31, 2011, Mr. Isenberg elected to forego triggering that payment, and as a result, the Company does not owe the termination payment. In connection with that development, the Company announced plans to make charitable contributions to benefit the needs of its employees and other community-based causes. The Company contributed one million Nabors’ common shares previously held by an affiliate to the Nabors Charitable Foundation, a 501(c)(3) organization, in support of this objective. The election of Mr. Isenberg to forego triggering the potential payment, offset by the charitable contributions described above, will be recorded as a capital contribution during the first quarter of 2012.

Provision for retirement of long-lived assets

During 2011, we recorded a provision for retirement of long-lived assets totaling $98.1 million in multiple operating segments. This related to the decommissioning and retirement of one jackup rig, 116 land rigs, and a number of rigs for well-servicing and trucks. Our U.S. Lower 48 Land Drilling, International and U.S. Land Well-servicing operations recorded $63.2 million, $26.1 million and $8.9 million, respectively. These assets were deemed to be functionally or economically non-competitive for today’s market and are being dismantled for parts and scrap.

During 2010, we recorded a provision for retirement of long-lived assets totaling $23.2 million related to the abandonment of certain rig components, comprised of engines, top-drive units, building modules and other equipment that had become obsolete or inoperable in our U.S. Lower 48 Land Drilling, U.S. Well-servicing and U.S. Offshore Contract Drilling operating segments.

During 2009, we recorded a provision for retirement of long-lived assets totaling $64.2 million related to assets in our U.S. Offshore, Alaska, Canada and International Contract Drilling operating segments. The retirements included inactive workover jackup 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.

Impairments of Long-Lived Assets

We did not record any impairment of long-lived assets in 2011. During 2010, we recognized $27.3 million in impairment charges related to some jackup rigs in our U.S. Offshore operating segment. These impairment charges stemmed from annual impairment tests on long-lived assets.

The impairments and other charges, inclusive of the provisions for retirement and impairments of long-lived assets, recognized during 2011, 2010 and 2009 were determined necessary as a result of continued lower commodity prices and uncertainty in the oil and gas 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.

Goodwill Impairments

We did not record any goodwill impairment in 2011. 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 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, our customers have continued to encounter delays in obtaining government permits. It is uncertain when this will improve. 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 Note 2 — Summary of Significant Accounting Policies (included under the caption “Goodwill”) for amounts of goodwill related to each of our reporting units.

Other than Temporary Impairments of Debt and Equity Securities

We did not record any other-than-temporary impairments in 2011 or 2010. During 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 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.

XML

Subsidiary Preferred Stock

12 Months Ended

Dec. 31, 2011

Subsidiary Preferred Stock [Abstract]

Subsidiary Preferred Stock

Note 15    Subsidiary Preferred Stock

Superior had 75,000 shares of Series A Preferred Stock (“preferred stock”), $0.01 par value per share, outstanding at December 31, 2011. There are 10,000,000 shares authorized. The preferred stock is issuable in series with such voting rights, if any, designations, powers, preferences and other rights and such qualifications, limitations and restrictions as may be determined by Superior’s board; the board may also fix the number of shares constituting each series and increase or decrease the number of shares of any series.

The preferred stock is perpetual and ranks senior to Superior’s common stock with respect to payment of dividends, and amounts upon liquidation, dissolution or winding up.

We have presented the preferred stock within the mezzanine section of our consolidated balance sheets and have accounted for the preferred stock under the ASC Topic for Distinguishing Liabilities from Equity.

Dividends

Holders of the preferred stock are entitled to receive, when and if declared by Superior’s board, out of assets legally available therefor, cumulative cash dividends at the rate per annum of $40.00 per share of preferred stock. Dividends on the preferred stock are payable quarterly in arrears on December 1, March 1, June 1 and September 1 of each year (and, in the case of any undeclared and unpaid dividends, at such additional times and for such interim periods, if any, as determined by Superior’s board), at such annual rate. Dividends are cumulative from the date of the original issuance of the preferred stock, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.

As of December 31, 2011, dividends on outstanding shares of preferred stock had been declared and paid in full with respect to each quarter since its issuance.

Liquidation Preference

Holders of preferred stock are entitled to receive, in the event that Superior is liquidated, dissolved or wound up, whether voluntarily or involuntarily, $1,000 per share (the “Liquidation Value”) plus an amount per share equal to all dividends undeclared and unpaid thereon to the date of final distribution (the “Liquidation Preference”), and no more. Until the holders of preferred stock have been paid the Liquidation Preference in full, Superior may not make any payment to any holder of stock that ranks junior to the preferred stock upon liquidation, dissolution or winding up. As of December 31, 2011, the preferred stock had a total Liquidation Preference of $75.0 million.

Redemption

The preferred stock is redeemable, in whole or in part and at Superior’s option, at any time on or after November 18, 2013, for a redemption price of 101% of the Liquidation Value, plus all accrued dividends. The redemption price is payable in cash.

As a result of the Superior acquisition, each share of preferred stock is convertible, at the option of the holder thereof, into $22.12 for each share of Superior common stock into which the preferred share would have been convertible prior to the Superior acquisition (a “deemed common share”). The preferred shares had a conversion price of $25.00 per deemed common share prior to the Superior acquisition (equivalent to a conversion rate of 40 deemed common shares for each share of preferred stock), representing 3,000,000 deemed common shares. This results in a redemption value of $66.4 million at December 31, 2011, payable in cash. The right to convert shares of preferred stock that may be called for redemption will terminate at the close of business on the day preceding a redemption date.

Voting Rights

Except as otherwise required from time to time by applicable law or upon certain events of default, the holders of preferred stock have no voting rights, and their consent is not required for taking any corporate action. When and if the holders of the preferred stock are entitled to vote, each holder will be entitled to one vote per share.

XML

Financial Instruments and Risk Concentration

12 Months Ended

Dec. 31, 2011

Financial Instruments and Risk Concentration [Abstract]

Financial Instruments and Risk Concentration

Note 11    Financial Instruments and Risk Concentration

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

Foreign Currency Risk

We operate in a number of international areas and are involved in transactions denominated in currencies other than U.S. dollars, which exposes us to foreign exchange rate risk or 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.

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 that 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 our 5.375%, 6.15%, 9.25%, 5.0% and 4.625% 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. 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 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 to help mitigate and manage 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 will be 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 $1.3 million and $3.4 million as of December 31, 2011 and 2010, respectively. During 2011, 2010 and 2009, we recorded gains or (losses) of approximately $2.2 million, $(.1) million and $1.4 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).

XML

Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Aug. 23, 2011	Dec. 31, 2010
Long-term debt
Senior Notes		$ 700,000
Revolving credit facilities	(80,408)		(70,605)
Other	1,712		2,676
Long-term Debt	4,623,816		4,443,144
Current portion of long-term debt	275,326		1,379,018
Long-term debt, Noncurrent	4,348,490		3,064,126
5.375% Senior Notes Due August 2012 [Member]
Long-term debt
Senior Notes	274,604		273,977
Current portion of long-term debt	274,600
6.15% Senior Notes Due February 2018 [Member]
Long-term debt
Senior Notes	967,490		966,276
9.25% Senior Notes Due January 2019 [Member]
Long-term debt
Senior Notes	1,125,000		1,125,000
5.00% senior notes due September 2020 [Member]
Long-term debt
Senior Notes	697,343		697,037
4.625% senior notes due September 2021 [Member]
Long-term debt
Senior Notes	697,667		0
0.94% Senior Exchangeable Notes Due May 2011 [Member]
Long-term debt
0.94% senior exchangeable notes due May 2011	0		1,378,178
Current portion of long-term debt	1,400,000
Revolving Credit Facilities [Member]
Long-term debt
Revolving credit facilities	$ 860,000		$ 0

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 7    Fair Value Measurements

As defined in the ASC, fair value is the price that would be received upon sale of an asset or paid upon 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 subjective measure.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2011. Our debt securities could transfer into or out of a Level 1 or 2 measure depending on the availability of independent and current pricing at the end of each quarter. Our financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Recurring Fair Value Measurements

	Fair Value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Short-term investments:
Available-for-sale equity securities — energy industry	$	60,923	$	10,510	$	—	$	71,433
Available-for-sale debt securities
Commercial paper and CDs		1,230		—		—		1,230
Corporate debt securities		—		51,300		—		51,300
Mortgage-backed debt securities		—		309		—		309
Mortgage-CMO debt securities		—		2,547		—		2,547
Asset-backed debt securities		2,495		—		—		2,495
Trading securities — energy industry		11,600		—		—		11,600
Total short-term investments	$	76,248	$	64,666	$	—	$	140,914
Liabilities:
Derivative contract	$	—	$	1,281	$	—	$	1,281

Nonrecurring Fair Value Measurements

Fair value measurements were applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis, which would consist of measurements primarily to goodwill, oil and gas financing receivables, intangible assets and other long-lived assets, assets acquired and liabilities assumed in a business combination, and asset retirement obligations.

Fair Value of Financial Instruments

The fair value of our financial instruments has been estimated in accordance with GAAP. The fair value of our long-term debt and subsidiary preferred stock is estimated based on quoted market prices or prices quoted from third-party financial institutions. The carrying and fair values of these liabilities were as follows:

	December 31,
	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
5.375% senior notes due August 2012(1)	$	274,604	$	281,188	$	273,977	$	291,500
6.15% senior notes due February 2018		967,490		1,113,986		966,276		1,041,008
9.25% senior notes due January 2019		1,125,000		1,419,514		1,125,000		1,393,943
5.00% senior notes due September 2020		697,343		734,475		697,037		678,335
4.625% senior notes due September 2021		697,667		708,176		—		—
0.94% senior exchangeable notes due May 2011		—		—		1,378,178		1,403,315
Subsidiary preferred stock		69,188		68,625		69,188		68,625
Revolving credit facilities		860,000		860,000		—		—
Other		1,712		1,712		2,676		2,676
	$	4,693,004	$	5,187,676	$	4,512,332	$	4,879,402

(1) Includes $.3 million and $.7 million as of December 31, 2011 and 2010, 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.

As of December 31, 2011, our short-term investments were carried at fair market value and included $129.3 million and $11.6 million in securities classified as available-for-sale and trading, respectively. As of December 31, 2010, our short-term investments were carried at fair market value and included $139.9 million and $19.6 million in securities classified as available-for-sale and trading, respectively. The carrying values of our long-term investments that are accounted for using the equity method of accounting approximate fair value. The fair value of these long-term investments totaled $5.9 million and $7.4 million as of December 31, 2011 and 2010, respectively.

XML

Discontinued Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income (loss) from discontinued operations
Income (loss) from discontinued operations									$ 18,860
Impairment on wholly owned assets									(255,046,000)	(192,179)	(205,897)
Goodwill impairment											14,700
Impairment of long-lived assets									(7,853)	7,500
Gain (loss) on disposal of assets									46,811
Less: income tax expense (benefit)									(98,181)	(62,028)	(85,431)
Income (loss) from discontinued operations, net of tax	(193,985)	(12,226)	121,167	(12,396)	(100,323)	(51,501)	(1,887)	(7,379)	(97,440)	(161,090)	(218,609)
Oil and Gas [Member]
Condensed Statements of Income
Operating revenues and Earnings (losses) from unconsolidated affiliates									125,654	37,615	(57,864)
Income (loss) from discontinued operations
Income (loss) from discontinued operations										(26,139)	(81,678)
Other Operating Segments [Member]
Condensed Statements of Income
Operating revenues and Earnings (losses) from unconsolidated affiliates									29,713	29,739	28,751
Income (loss) from discontinued operations
Income (loss) from discontinued operations									(210)	1,059	(1,636)
Goodwill impairment											(14,689)
Impairment of long-lived assets										(7,460)
Less: income tax expense (benefit)									(2,017)	(1,601)	140
Income (loss) from discontinued operations, net of tax									$ (6,046)	$ (4,800)	$ (16,465)

XML

Supplemental Balance Sheet Income Statement and Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Accrued liabilities
Accrued compensation	$ 173,732	$ 116,680
Deferred revenue	172,578	88,389
Other taxes payable	44,652	25,227
Workers' compensation liabilities	22,645	31,944
Interest payable	99,869	89,276
Due to joint venture partners	6,041	6,030
Warranty accrual	5,237	3,376
Litigation reserves	23,687	12,301
Provision for termination payment	100,000	0
Current liability of discontinued operations	54,287	0
Professional fees	6,413	3,222
Current deferred tax liability	(269)	(1,027)
Other accrued liabilities	7,363	16,820
Accrued liabilities	$ 716,773	$ 394,292

XML

Acquisitions

12 Months Ended

Dec. 31, 2011

Acquisitions [Abstract]

Acquisitions

Note 5    Acquisitions

2011 Acquisitions

In July 2011, we paid $65 million in cash to acquire the remaining 50 percent equity interest of Peak, making it a wholly owned subsidiary on this date. Peak operates in Alaska, providing construction and rig moving services in icy conditions as well as light and heavy-duty moving, hauling and maintenance services. Previously, we held a 50 percent equity interest with a carrying value of $38.1 million that we had accounted for as an equity method investment. As a result of the acquisition, we consolidated the assets and liabilities of Peak during the third quarter of 2011 based on their respective fair values, in accordance with Topic 805 — Business Combinations. The excess of the estimated fair value of the assets and liabilities over the net carrying value of our previously held equity interest resulted in a gain of $13.1 million and is reflected in losses (gains) on sales and retirements of long-lived assets and other expense (income) for the year ended December 31, 2011.

In June 2011, the equity owners of SMVP dissolved the partnership and a proportionate share of the assets and liabilities were conveyed to us in exchange for our ownership interest. The assets continued to be presented as held for sale and the operating results in discontinued operations for all periods presented. See Note 4 — Discontinued Operations for additional discussion.

2010 Acquisitions

In September 2010, we acquired through a tender offer and merger all of the outstanding common stock of Superior at a price per share equal to $22.12, for a cash purchase price of approximately $681.3 million. The effects of the Superior acquisition and the operating results are included in the accompanying consolidated financial statements for the period subsequent to the effective date of the acquisition. Superior contributed revenues of $1.2 billion to our consolidated revenues for the year ended December 31, 2011.

As part of this acquisition, we recognized $7.0 million of acquisition-related transaction costs in losses (gains) on sales and retirements of long-lived assets and other expense (income) for the year ended December 31, 2010. The acquisition-related transaction costs consisted primarily of investment banking fees and legal and accounting costs. The acquisition enhanced our well-servicing, including the addition of hydraulic fracturing to our services, and workover capacity work throughout the Appalachian, Mid-Continent, Rocky Mountain, Southeast and Southwest regions of the United States.

The following table provides the allocation of the purchase price as of the acquisition date. The purchase price for Superior was allocated to the net tangible and intangible assets acquired and liabilities assumed based on fair value. The excess of the purchase price over such fair values was recorded as goodwill.

	Estimated Fair Value
	(In thousands)
Assets:
Cash and cash equivalents	$	1,045
Accounts receivable		143,842
Inventory		33,963
Other current assets		7,612
Property, plant and equipment		415,000
Intangible assets		131,811
Goodwill		334,992
Other long-term assets		14,726
Total assets		1,082,991
Liabilities:
Current liabilities	$	78,277
Deferred income taxes		119,201
Long-term debt		124,792
Other long-term liabilities		10,258
Total liabilities		332,528
Preferred stock		69,188
Net assets acquired	$	681,275

Intangible assets

We identified other intangible assets associated with fracturing and fluid logistics services, including trade name, technology, employment contracts and non-compete agreements and customer relationships. The amortization of the intangible assets is calculated on a straight-line basis, which estimates the consumption of economic benefits. The following table summarizes the intangible assets recognized at the acquisition date, the monthly amortization expense as well as their estimated useful lives:

	Estimated Fair Value		Monthly Amortization		Estimated Useful Life
	(In thousands)
Superior trade name	$	88,767	$	740		10 years
Technology		5,294		88		5 years
Employment contracts and non-compete agreements		675		33		1-3 years
Customer relationships		37,075		308		10 years
Total identifiable intangible assets	$	131,811	$	1,169

Goodwill

Goodwill of $335.0 million arising from the Superior acquisition consisted largely of the expected synergies and economies of scale from combining the operations of Nabors and Superior. We have allocated the goodwill to our Pressure Pumping operating segment. See Note 2 — Summary of Significant Account Policies for additional information.

Long-term debt

Long-term debt included a secured revolving credit facility and second lien notes at the acquisition date. As of December 31, 2010, all amounts outstanding had been repaid. See Note 12 — Debt for additional information.

On December 31, 2010, we purchased the business of Energy Contractors for a total cash purchase price of $53.4 million. The assets were comprised of vehicles and rig equipment and have been included in our U.S. Well-servicing operating segment. The purchase price was allocated to the net tangible and intangible assets acquired based on their fair value as of December 31, 2010. The excess of the purchase price over the fair values of the assets acquired was recorded as goodwill in the amount of $4.2 million.

XML

Cash and Cash Equivalents and Short-term Investments

12 Months Ended

Dec. 31, 2011

Cash and Cash Equivalents and Short term Investments [Abstract]

Cash and Cash Equivalents and Short-term Investments

Note 6    Cash and Cash Equivalents and Short-term Investments

Our cash and cash equivalents and short-term investments consisted of the following:

	December 31,		December 31,
	2011		2010
	(In thousands)
Cash and cash equivalents	$	398,575	$	641,702
Short-term investments:
Trading equity securities		11,600		19,630
Available-for-sale equity securities		71,433		79,698
Available-for-sale debt securities		57,881		60,160
Total short-term investments	$	140,914	$	159,488

Certain information related to our cash and cash equivalents and short-term investments follows:

	December 31,
	2011							2010
	Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses
	(In thousands)
Cash and cash equivalents	$	398,575	$	—	$	—		$	641,702	$	—	$	—
Short-term investments:
Trading equity securities		11,600		5,876		—			19,630		13,906		—
Available-for-sale equity securities		71,433		33,075		—			79,698		38,176		(2,274	)
Available-for-sale debt securities:
Commercial paper and CDs		1,230		—		—			1,275		—		—
Corporate debt securities		51,300		22,494		(2,095	)		52,022		15,274		(18	)
Mortgage-backed debt securities		309		10		—			372		16		—
Mortgage-CMO debt securities		2,547		13		(15	)		3,015		21		(6	)
Asset-backed debt securities		2,495		—		(238	)		3,476		—		(268	)
Total available-for-sale debt securities		57,881		22,517		(2,348	)		60,160		15,311		(292	)
Total available-for-sale securities		129,314		55,592		(2,348	)		139,858		53,487		(2,566	)
Total short-term investments		140,914		61,468		(2,348	)		159,488		67,393		(2,566	)
Total cash, cash equivalents and short-term investments	$	539,489	$	61,468	$	(2,348	)	$	801,190	$	67,393	$	(2,566	)

Certain information related to the gross unrealized losses of our cash and cash equivalents and short-term investments follows:

	As of December 31, 2011
	Less Than 12 Months				More Than 12 Months
	Fair Value		Gross Unrealized Loss		Fair Value		Gross Unrealized Loss
	(In thousands)
Available-for-sale equity securities	$	—	$	—	$	—	$	—
Available-for-sale debt securities:(1)
Corporate debt securities		17,700		2,095		—		—
Mortgage-CMO debt securities		2,217		7		83		8
Asset-backed debt securities		—		—		2,494		238
Total available-for-sale debt securities		19,917		2,102		2,577		246
Total	$	19,917	$	2,102	$	2,577	$	246

(1) Our unrealized losses on available-for-sale debt securities held for more than one year are comprised of various types of securities. Each of these securities have a rating ranging from “A” to “AAA” from Standard & Poor’s and ranging from “A2” to “Aaa” from Moody’s Investors Service and is considered of high credit quality. In each case, we do not intend to sell these investments, and it is less likely than not that we will be required to sell them to satisfy our own cash flow and working capital requirements. We believe that we will be able to collect all amounts due according to the contractual terms of each investment and, therefore, do not consider the decline in value of these investments to be other-than-temporary at December 31, 2011.

The estimated fair values of our corporate, mortgage-backed, mortgage-CMO and asset-backed debt securities at December 31, 2011, classified by time to contractual maturity, are shown below. Expected maturities differ from contractual maturities because the issuers of the securities may have the right to repay obligations without prepayment penalties and we may elect to sell the securities prior to the contractual maturity date.

	Estimated Fair Value
	December 31, 2011
	(In thousands)
Debt securities:
Due in one year or less	$	1,230
Due after one year through five years		—
Due in more than five years		56,651
Total debt securities	$	57,881

Certain information regarding our debt and equity securities is presented below:

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Available-for-sale:
Proceeds from sales and maturities	$	12,672	$	13,062	$	23,411
Realized gains (losses), net		3,036		1,692		(54,311	)(1)

(1) Includes other-than-temporary impairments of $18.7 million related to an equity security and a $35.6 million credit-related impairment to a corporate debt security.

XML

Share-Based Compensation

12 Months Ended

Dec. 31, 2011

Share-Based Compensation [Abstract]

Share-Based Compensation

Note 8    Share-Based Compensation

Total share-based compensation expense, which includes both stock options and restricted stock, totaled $21.2 million, $13.7 million and $106.7 million for the years ended December 31, 2011, 2010 and 2009, respectively. Compensation expense related to awards of restricted stock totaled $13.4 million, $10.5 million and $88.9 million for the years ended December 31, 2011, 2010 and 2009, respectively, and is included in direct costs and general and administrative expenses in our consolidated statements of income (loss). Share-based compensation expense has been allocated to our various operating segments. See Note 22 — Segment Information. Total share-based compensation expense for 2009 included the recognition of $72.1 million of compensation expense related to previously granted restricted stock and option awards held by Nabors’ Chairman and then Chief Executive Officer, Eugene M. Isenberg, and its Deputy Chairman, President and then Chief Operating Officer, Anthony G. Petrello, that was unrecognized as of April 1, 2009. The recognition of this expense resulted from provisions of their respective new employment agreements which effectively eliminated the risk of forfeiture of such awards. See Note 18 — Commitments and Contingencies for additional information.

The cash flows resulting from tax deductions in excess of the compensation cost recognized for share-based awards (excess tax benefits) are classified as financing cash flows. The actual tax benefit realized from share-based awards during the years ended December 31, 2011, 2010 and 2009 was $.2 million, $.1 million and $.3 million, respectively.

Stock Option Plans

As of December 31, 2011, we had several stock plans under which options to purchase our common shares could be granted to key officers, directors and managerial employees of Nabors and its subsidiaries. Options granted under the plans generally are at prices equal to the fair market value of the shares on the date of the grant. Options granted under the plans generally are exercisable in varying cumulative periodic installments after one year. In the case of certain key executives, options granted may vest immediately on the grant date. Options granted under the plans cannot be exercised more than ten years from the date of grant. Options to purchase 15.5 million and 17.3 million Nabors common shares remained available for grant as of December 31, 2011 and 2010, respectively. Of the common shares available for grant as of December 31, 2011, approximately 15.5 million of these shares are also available for issuance in the form of restricted shares.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model which uses assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatilities are based on implied volatilities from traded options on Nabors’ common shares, historical volatility of Nabors’ common shares, and other factors. We do not assume any dividend yield, since we do not pay dividends. We use historical data to estimate the expected term of the options and employee terminations within the option-pricing model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of the options represents the period of time that the options granted are expected to be outstanding.

We also consider an estimated forfeiture rate for these option awards, and we recognize compensation cost only for those shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of three to five years. The forfeiture rate is based on historical experience. Estimated forfeitures have been adjusted to reflect actual forfeitures during 2011.

Stock option transactions under our various stock-based employee compensation plans are presented below:

Options	Shares			Weighted-Average Exercise Price		Weighted- Average Remaining Contractual Term		Aggregate Intrinsic Value
	(In thousands, except exercise price)
Options outstanding as of December 31, 2010		28,932		$	18.73
Granted		931			15.67
Exercised		(1,116	)		12.50
Surrendered(1)		(418	)		13.53
Forfeited		(459	)		20.74
Options outstanding as of December 31, 2011		27,870		$	18.94		3.65 years	$	83,306
Options exercisable as of December 31, 2011		24,939		$	19.83		3.14 years	$	65,949

(1) Represents unexercised vested stock options that were surrendered by key officers and directors, to satisfy the option exercise price and related income taxes. See related discussion at Note 14 — Common Shares.

Of the options outstanding, 24.9 million, 24.9 million and 27.2 million were exercisable at weighted-average exercise prices of $19.83, $20.19 and $21.04, as of December 31, 2011, 2010 and 2009, respectively.

During the years ended December 31, 2011, 2010 and 2009, respectively, we awarded options vesting over periods up to four years to purchase 930,753, 32,115 and 10,015,883 of our common shares to our employees, executive officers and directors.

The fair value of stock options granted during 2011, 2010 and 2009 was calculated using the Black-Scholes option pricing model and the following weighted-average assumptions:

	Year Ended December 31,
	2011			2010			2009
Weighted average fair value of options granted:	$	6.24		$	6.62		$	2.85
Weighted average risk free interest rate:		.65	%		1.49	%		1.75	%
Dividend yield:		0	%		0	%		0	%
Volatility:(1)		51.09	%		41.44	%		34.78	%
Expected life:		4.0 years			4.0 years			4.0 years

(1) Expected volatilities are based on implied volatilities from publicly traded options to purchase Nabors’ common shares, historical volatility of Nabors’ common shares and other factors.

A summary of our unvested stock options as of December 31, 2011, and the changes during the year then ended is presented below:

Unvested Stock Options	Outstanding			Weighted-Average Grant-Date Fair Value
	(In thousands, except fair values)
Unvested as of December 31, 2010		3,941		$	2.81
Granted		931			6.24
Vested		(1,800	)		2.87
Forfeited		(172	)		2.73
Unvested as of December 31, 2011		2,900		$	3.88

The total intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was $18.3 million, $6.9 million and $19.7 million, respectively. The total fair value of options that vested during the years ended December 31, 2011, 2010 and 2009 was $5.2 million, $5.6 million and $10.8 million, respectively.

As of December 31, 2011, there was $4.0 million of total future compensation cost related to unvested options that are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately two years.

Restricted Stock and Restricted Stock Units

Our stock plans allow grants of restricted stock. Restricted stock is issued on the grant date, but cannot be sold or transferred. Restricted stock vests in varying periodic installments ranging from three to five years.

A summary of our restricted stock as of December 31, 2011, and the changes during the year then ended, is presented below:

Restricted Stock	Outstanding			Weighted-Average Grant-Date Fair Value
	(In thousands, except fair values)
Unvested as of December 31, 2010		1,945		$	19.23
Granted		1,096			27.32
Vested		(1,400	)		17.43
Forfeited		(85	)		28.11
Unvested as of December 31, 2011		1,556		$	26.07

During 2011 and 2010, we awarded 1,096,379 and 538,496 shares of restricted stock, respectively, to our employees and directors. These awards had an aggregate value at their date of grant of $30.0 million and $11.9 million, respectively, and were scheduled to vest over a period of up to four years. The fair value of restricted stock that vested during the years ended December 31, 2011, 2010 and 2009 was $21.4 million, $26.7 million and $23.9 million, respectively.

As of December 31, 2011, there was $28.9 million of total future compensation cost related to unvested restricted stock awards that are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately two years.

XML

Acquisitions (Details Textual) (USD $)	12 Months Ended				12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2010 Acquisition From Energy Contractors [Member]	Dec. 31, 2011 Peak [Member]	Jul. 31, 2011 Peak [Member]	Dec. 31, 2010 Peak [Member]
Acquisitions and Divestitures (Textual) [Abstract]
Consideration paid in cash	$ 681,300,000					$ 65,000,000
Remaining percentage of equity interest of Peak acquired							50.00%
Common stock of acquired company previously owned	0	0	0				38,100,000
Acquired price per common share	$ 22.12
Acquisition-related transaction costs	7,000,000
Long-term debt	124,792,000
Total asset purchase price				53,400,000
Goodwill	334,992,000			4,200,000
Equity Interest acquired	50.00%					50.00%
Gain on acquisition of equity method investment					13,100,000
Superior contributed revenues	$ 1,200,000,000

XML

Condensed Consolidating Financial Information (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and other income:
Operating revenues									$ 6,060,351	$ 4,134,483	$ 3,662,220
Earnings (losses) from unconsolidated affiliates	(2,700)	33,700	9,300	16,300	4,900	11,800	8,900	7,700	56,647	33,267	(155,432)
Investment income (loss)									19,940	7,263	25,522
Intercompany interest income									0	0	0
Total revenues and other income									6,136,938	4,175,013	3,532,310
Costs and other deductions:
Direct costs									3,775,964	2,400,519	1,981,504
General and administrative expenses									489,892	338,720	421,492
Depreciation and amortization									924,094	760,962	663,958
Interest expense									256,633	272,712	266,047
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net									4,514	47,238	11,982
Impairments and other charges									198,072	61,292	118,543
Total costs and other deductions									5,649,169	3,881,443	3,463,526
Income (loss) from continuing operations before income tax									487,769	293,570	68,784
Income tax expense (benefit)									142,605	36,950	(63,937)
Subsidiary preferred stock dividend									3,000	750
Income (loss) from continuing operations, net of tax	89,535	87,190	70,887	94,552	152,097	12,347	44,949	46,477	342,164	255,870	132,721
Gain (loss) on acquisitions/dispositions	(193,985)	(12,226)	121,167	(12,396)	(100,323)	(51,501)	(1,887)	(7,379)	(97,440)	(161,090)	(218,609)
Net income (loss)									244,724	94,780	(85,888)
Less: Net (income) loss attributable to noncontrolling interest	(1,400)	(708)	394	669	(1,293)	(453)	559	1,102	(1,045)	(85)	342
Net income (loss) attributable to Nabors	(105,850)	74,256	192,448	82,825	50,481	(39,607)	43,621	40,200	243,679	94,695	(85,546)
Nabors (Parent/Guarantor) [Member]
Revenues and other income:
Earnings (losses) from consolidated affiliates									256,245	68,749	(74,204)
Investment income (loss)									4	15	58
Total revenues and other income									256,249	68,764	(74,146)
Costs and other deductions:
General and administrative expenses									11,970	9,165	28,350
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net									600	(35,096)	(16,950)
Total costs and other deductions									12,570	(25,931)	11,400
Income (loss) from continuing operations before income tax									243,679	94,695	(85,546)
Income (loss) from continuing operations, net of tax									243,679		(85,546)
Net income (loss)									243,679	94,695	(85,546)
Less: Net (income) loss attributable to noncontrolling interest										0
Net income (loss) attributable to Nabors									243,679	94,695	(85,546)
Nabors Delaware (Issuer/Guarantor) [Member]
Revenues and other income:
Earnings (losses) from consolidated affiliates									214,308	(183,242)	(316,443)
Investment income (loss)									68		2,357
Intercompany interest income									69,437	72,435	66,150
Total revenues and other income									283,813	(110,807)	(247,936)
Costs and other deductions:
General and administrative expenses									348	445	336
Depreciation and amortization									3,532	3,303	3,594
Interest expense									278,657	283,396	288,715
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net									(1,904)	42,504	4,145
Total costs and other deductions									280,633	329,648	296,790
Income (loss) from continuing operations before income tax									3,180	(440,455)	(544,726)
Income tax expense (benefit)									78,118	(95,168)	(84,465)
Income (loss) from continuing operations, net of tax									81,298		(460,261)
Net income (loss)									81,298	(345,287)	(460,261)
Less: Net (income) loss attributable to noncontrolling interest										0
Net income (loss) attributable to Nabors									81,298	(345,287)	(460,261)
Nabors Holdings (Issuer) [Member]
Revenues and other income:
Operating revenues									0	0
Earnings (losses) from unconsolidated affiliates									0	0
Earnings (losses) from consolidated affiliates									0	0	(86,751)
Investment income (loss)									0	0	101
Intercompany interest income									0	0	5,558
Total revenues and other income									0	0	(81,092)
Costs and other deductions:
Direct costs									0	0
General and administrative expenses									0	0	1
Depreciation and amortization									0	0
Interest expense									0	0	5,634
Intercompany interest expense									0	0
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net									0	0	5,069
Impairments and other charges									0	0
Total costs and other deductions									0	0	10,704
Income (loss) from continuing operations before income tax									0	0	(91,796)
Income tax expense (benefit)									0	0	15,744
Subsidiary preferred stock dividend									0	0
Income (loss) from continuing operations, net of tax									0	0	(107,540)
Gain (loss) on acquisitions/dispositions									0	0
Net income (loss)									0	0	(107,540)
Less: Net (income) loss attributable to noncontrolling interest									0	0
Net income (loss) attributable to Nabors									0	0	(107,540)
Other Subsidiaries (Non-Guarantors) [Member]
Revenues and other income:
Operating revenues									6,060,351	4,134,483	3,662,200
Earnings (losses) from unconsolidated affiliates									56,647	33,267	(155,432)
Earnings (losses) from consolidated affiliates									107,536	(316,657)	(441,133)
Investment income (loss)									19,868	7,633	23,083
Intercompany interest income										0	0
Total revenues and other income									6,244,402	3,898,868	3,109,936
Costs and other deductions:
Direct costs									3,775,964	240,519	1,981,504
General and administrative expenses									478,174	338,008	400,044
Depreciation and amortization									920,562	760,950	663,506
Interest expense									(22,024)	(10,352)	(28,310)
Intercompany interest expense									69,437	72,435	71,708
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net									5,218	38,695	37,972
Impairments and other charges									198,072	61,292	330,976
Total costs and other deductions									5,425,403	3,902,212	3,486,717
Income (loss) from continuing operations before income tax									818,999	(3,344)	(145,926)
Income tax expense (benefit)									220,723	70,354	4,784
Subsidiary preferred stock dividend									3,000	750
Income (loss) from continuing operations, net of tax									595,276	(74,448)	150,710
Gain (loss) on acquisitions/dispositions									(97,440)	(161,089)	(218,609)
Net income (loss)									497,836	(85,778)	(369,319)
Less: Net (income) loss attributable to noncontrolling interest									(1,045)	(85)	342
Net income (loss) attributable to Nabors									496,791	(85,863)	(368,977)
Consolidating Adjustments [Member]
Revenues and other income:
Earnings (losses) from consolidated affiliates									(578,089)	431,150	918,531
Intercompany interest income									(69,437)	(72,435)	(17,108)
Total revenues and other income									(647,526)	358,715	846,823
Costs and other deductions:
General and administrative expenses									(600)	(957)	(570)
Intercompany interest expense									(69,437)	(72,435)	(71,708)
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net									600	957	(17,677)
Total costs and other deductions									(69,437)	(72,435)	(89,955)
Income (loss) from continuing operations before income tax									578,089	431,150	936,778
Income (loss) from continuing operations, net of tax									578,089	431,150	936,778
Net income (loss)									578,089	431,150	936,778
Net income (loss) attributable to Nabors									$ 578,089	$ 431,150	$ 936,778

XML

Debt (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Maturity of primary debt
2012	$ 275,000
2013	0
2014	860,000
2015	0
2016	0
Thereafter	3,500,000
Long-term debt total	$ 4,635,000

XML

Cash and Cash Equivalents and Short-term Investments (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Cash and cash equivalents and short-term investments
Cash and cash equivalents, fair value	$ 398,575	$ 641,702
Short-term investments:
Trading equity securities, fair value	11,600	19,630
Trading equity securities, gross unrealized holding gains	5,876	13,906
Available-for-sale debt securities:
Total available-for-sale debt securities, fair value	57,881	60,160
Total available-for-sale debt securities, gross unrealized losses	0
Available-for-sale equities securities
Available-for-sale equity securities - energy industry	129,314	139,858
Available-for-sale equity securities, gross unrealized holding gains	55,592	53,487
Available-for-sale equity securities, gross unrealized holding losses	(2,348)	(2,566)
Total short-term investments	140,914	159,488
Total cash, cash equivalents and short-term investments, fair value	539,489	801,190
Total cash, cash equivalents and short-term investments, gross unrealized gains	61,468	67,393
Total cash, cash equivalents and short-term investments, gross unrealized losses	(2,348)	(2,566)
Debt Securities [Member]
Available-for-sale debt securities:
Total available-for-sale debt securities, fair value	57,881	60,160
Total available-for-sale debt securities, gross unrealized gains	22,517	15,311
Available-for-sale equities securities
Available-for-sale equity securities, gross unrealized holding losses	(2,348)	(292)
Equity Securities [Member]
Available-for-sale equities securities
Available-for-sale equity securities - energy industry	71,433	79,698
Available-for-sale equity securities, gross unrealized holding gains	33,075	38,176
Available-for-sale equity securities, gross unrealized holding losses	0	(2,274)
Commercial paper and CDs [Member]
Available-for-sale debt securities:
Total available-for-sale debt securities, fair value	1,230	1,275
Total available-for-sale debt securities, gross unrealized gains	0
Total available-for-sale debt securities, gross unrealized losses	0
Corporate debt securities [Member]
Available-for-sale debt securities:
Total available-for-sale debt securities, fair value	51,300	52,022
Total available-for-sale debt securities, gross unrealized gains	22,494	15,274
Available-for-sale equities securities
Available-for-sale equity securities, gross unrealized holding losses	(2,095)	(18)
Mortgage-backed debt securities [Member]
Available-for-sale debt securities:
Total available-for-sale debt securities, fair value	309	372
Total available-for-sale debt securities, gross unrealized gains	10	16
Total available-for-sale debt securities, gross unrealized losses	0
Available-for-sale equities securities
Available-for-sale equity securities, gross unrealized holding losses		0
Mortgage-CMO debt securities [Member]
Available-for-sale debt securities:
Total available-for-sale debt securities, fair value	2,547	3,015
Total available-for-sale debt securities, gross unrealized gains	13	21
Available-for-sale equities securities
Available-for-sale equity securities, gross unrealized holding losses	(15)	(6)
Asset-backed debt securities [Member]
Available-for-sale debt securities:
Total available-for-sale debt securities, fair value	2,495	3,476
Total available-for-sale debt securities, gross unrealized gains	0
Available-for-sale equities securities
Available-for-sale equity securities, gross unrealized holding losses	(238)	(268)
Short-term Investments [Member]
Available-for-sale equities securities
Available-for-sale equity securities, gross unrealized holding losses	(2,348)	(2,566)
Total short-term investments	140,914	159,488
Total short-term investments, gross unrealized gains	$ 61,468	$ 67,393

XML

Related Party Transactions (Details) (USD $)	12 Months Ended				3 Months Ended			12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Apr. 30, 2011	Mar. 31, 2010 Shona [Member]	Dec. 31, 2008 Shona [Member]	Dec. 31, 2011 Shona [Member]	Dec. 31, 2011 Gene M Isenberg [Member] Nabors Delaware [Member]	Oct. 28, 2011 Gene M Isenberg [Member] Nabors Delaware [Member]
Schedule of Equity Method Investments [Line Items]
Purchase price of Shona's common stock	$ 112,262,000	$ 40,936,000	$ 125,076,000			$ 900,000
Purchase of preferred and warrants					900,000
Equity Method Investment ownership percentage							7.55%
Fair Value of Equity Security investment	5,900,000	7,400,000					10,500,000
Possible Payment in Connection with termination of employment	100,000,000	0							100,000,000
Amount to be paid into the escrow account								6,600,000
Term of appointment as chairman								3 years
Term of additional extension as chairman								1 year
Related Party Transactions (Textual) [Abstract]
Premium payments to date related to life insurance policies	6,300,000
Cash surrender value included in other long-term assets	5,800,000	9,500,000
Revenues from business transactions with unconsolidated affiliates	218,400,000	271,600,000	327,300,000
Expenses from business transactions with unconsolidated affiliates	900,000	3,400,000	9,800,000
Accounts receivable from affiliated entities	110,700,000	97,800,000
Accounts payable to affiliated entities	46,100,000	12,700,000
Long-term payables with affiliated entities	800,000	800,000
Face value of investment in senior note				20,000,000
Interest rate of investment in senior note	9.75%
Recognized Interest Income	$ 2,000,000	$ 1,400,000
Guaranteed interest rate per annum compounded daily	6.00%

XML

Acquisitions (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Intangible assets
Estimated Fair Value	$ 131,811
Monthly Amortization	1,169
Superior Trade Names [Member]
Intangible assets
Estimated Fair Value	88,767
Monthly Amortization	740
Estimated Useful Life	10 years
Technology [Member]
Intangible assets
Estimated Fair Value	5,294
Monthly Amortization	88
Estimated Useful Life	5 years
Employment Contracts and Non Compete Agreements [Member]
Intangible assets
Estimated Fair Value	675
Monthly Amortization	33
Estimated Useful Life	1-3 years
Customer Relationships [Member]
Intangible assets
Estimated Fair Value	37,075
Monthly Amortization	$ 308
Estimated Useful Life	10 years

XML

Income Taxes (Details 4) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Deferred tax assets:
Net operating loss carryforwards	$ 2,009,318	$ 1,848,956
Equity compensation	25,937	19,262
Deferred revenue	32,200	13,428
Tax credit and other attribute carryforwards	90,297	89,141
Insurance loss reserve	24,598	28,537
Other	114,043	62,324
Subtotal	2,296,393	2,061,648
Valuation allowance	(1,485,540)	(1,514,153)
Deferred tax assets	810,853	547,495
Deferred tax liabilities:
Depreciation, amortization and depletion for tax in excess of book expense	1,317,256	1,123,622
Variable interest investments	116,005	75,204
Other	34,822	54,738
Deferred tax liability	1,468,083	1,253,564
Net deferred assets (liabilities)	(657,230)	(706,069)
Balance Sheet Summary
Net current deferred asset	127,874	31,510
Net noncurrent deferred asset	13,090	33,694
Current deferred tax liability	(269)	(1,027)
Net noncurrent deferred liability	(797,925)	(770,247)
Net deferred asset (liability)	$ (657,230)	$ (706,069)

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details Textual) (USD $)	12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2011 MMBbls Bcf Wells	Dec. 31, 2010 lb Wells	Dec. 31, 2011 Cat Canyon And West Cat Canyon [Member]	Dec. 31, 2011 Cat Canyon And West Cat Canyon [Member]	Dec. 31, 2011 Equity Companies [Member]	Dec. 31, 2011 U.S. [Member] Crude Oil Per Barrel [Member] Consolidated Subsidiary [Member]	Dec. 31, 2010 U.S. [Member] Crude Oil Per Barrel [Member] Consolidated Subsidiary [Member]	Dec. 31, 2011 U.S. [Member] Crude Oil Per Barrel [Member] Equity Companies [Member]	Dec. 31, 2010 U.S. [Member] Crude Oil Per Barrel [Member] Equity Companies [Member]	Dec. 31, 2011 U.S. [Member] Liquid Natural Gas Per Barrel [Member] Consolidated Subsidiary [Member]	Dec. 31, 2010 U.S. [Member] Liquid Natural Gas Per Barrel [Member] Consolidated Subsidiary [Member]	Dec. 31, 2011 U.S. [Member] Liquid Natural Gas Per Barrel [Member] Equity Companies [Member]	Dec. 31, 2010 U.S. [Member] Liquid Natural Gas Per Barrel [Member] Equity Companies [Member]	Dec. 31, 2011 U.S. [Member] Natural Gas, Per Thousand Cubic Feet [Member] Consolidated Subsidiary [Member]	Dec. 31, 2010 U.S. [Member] Natural Gas, Per Thousand Cubic Feet [Member] Consolidated Subsidiary [Member]	Dec. 31, 2011 U.S. [Member] Natural Gas, Per Thousand Cubic Feet [Member] Equity Companies [Member]	Dec. 31, 2010 U.S. [Member] Natural Gas, Per Thousand Cubic Feet [Member] Equity Companies [Member]	Dec. 31, 2011 Canada [Member] Natural Gas, Per Thousand Cubic Feet [Member] Consolidated Subsidiary [Member]	Dec. 31, 2010 Canada [Member] Natural Gas, Per Thousand Cubic Feet [Member] Consolidated Subsidiary [Member]	Dec. 31, 2010 Canada [Member] Natural Gas, Per Thousand Cubic Feet [Member] Equity Companies [Member]	Dec. 31, 2011 Colombia [Member] Crude Oil Per Barrel [Member] Consolidated Subsidiary [Member]	Dec. 31, 2010 Colombia [Member] Crude Oil Per Barrel [Member] Consolidated Subsidiary [Member]	Dec. 31, 2010 Colombia [Member] Crude Oil Per Barrel [Member] Equity Companies [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Sales Prices						96.19	61.12	0.00	70.60	57.71	36.43	0.00	39.04	4.12	3.72	0.00	4.53	3.85	2.81	2.78	9.45	78.21	76.00
Percentage of working capital interest sold			25.00%	25.00%
Cash proceeds from affiliate, from sale of oil and gas assets	$ 89,200,000		$ 71,600,000
Percentage of purchase of working interest				25.00%
Transportation Cost From Pipeline Commitments					24,200,000
Supplemental Information On Oil And Gas Exploration And Production Activities Unaudited (Textual) [Abstract]
Acquisitions of properties	360.4
Drilling of non-proved properties	122.2
Portion of negative revisions due to proved undeveloped reserves being reclassified to non-proved	384
Proved reserves	4.8
Decrease in proved reserves	9.5
Pressure Base Per Inch for Natural Gas Volume (Pound)		14.73
Cash distribution from the sale of oil and gas assets	$ 142,984,000
Proved reserves	20.8
Productive wells		273
Number wells to be produced		22
Average production costs Per Barrel of oil equivalents BOE		65.64

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

Our consolidated financial statements include the accounts of Nabors, as well as all majority owned and non-majority owned subsidiaries required to be consolidated under GAAP. Our consolidated financial statements exclude majority owned entities for which we do not have either (1) the ability to control the operating and financial decisions and policies of that entity or (2) a controlling financial interest in a variable interest entity. All significant intercompany accounts and transactions are eliminated in consolidation.

Investments in operating entities where we have the ability to exert significant influence, but where we do not control operating and financial policies, are accounted for using the equity method. Our share of the net income (loss) of these entities is recorded as earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss), and our investment in these entities is included as a single amount in our consolidated balance sheets. Investments in unconsolidated affiliates accounted for using the equity method totaled $371.0 million and $265.8 million as of December 31, 2011 and 2010, respectively. Investments in unconsolidated affiliates accounted for using the cost method totaled $1.9 million as of December 31, 2010. At December 31, 2011 and 2010, assets held for sale included investments in unconsolidated affiliates accounted for using the equity method totaling $13.7 million and $79.5 million, respectively. See Note 4 — Discontinued Operations for additional information.

We have investments in offshore funds, which are classified as long-term investments and are accounted for using the equity method of accounting based on our ownership interest in each fund. The carrying value of these investments totaled $5.9 million and $7.4 million as of December 31, 2011 and 2010, respectively.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include demand deposits and various other short-term investments with original maturities of three months or less.

Investments

Investments

Short-term investments

Short-term investments consist of equity securities, certificates of deposit, corporate debt securities, mortgage-backed debt securities and asset-backed debt securities. Securities classified as available-for-sale or trading are stated at fair value. Unrealized holding gains and temporary losses for available-for-sale securities are excluded from earnings and, until realized, are reported net of taxes in a separate component of equity. Unrealized holding losses are included in earnings during the period for which the loss is determined to be other-than-temporary. Gains and losses from changes in the market value of securities classified as trading are reported in earnings currently.

In computing realized gains and losses on the sale of equity securities, the specific-identification method is used. In accordance with this method, the cost of the equity securities sold is determined using the specific cost of the security when originally purchased.

Long-term investments and other receivables

We have 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). These investments are non-marketable and do not have published fair values. We account for these funds under the equity method of accounting based on our percentage ownership interest and recognize gains or losses as investment income (loss), currently based on changes in the net asset value of our investment during the current period.

Our oil and gas financing receivables, previously included in long-term investments, have been reclassified to assets held for sale. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment.

Inventory

Inventory

Inventory is stated at the lower of cost or market. Cost is determined using the first-in, first-out method and includes the cost of materials, labor and manufacturing overhead. Inventory included the following:

	December 31, 2011		December 31, 2010
	(In thousands)
Raw materials	$	133,480	$	81,308
Work-in-progress		50,951		23,629
Finished goods		88,421		53,899
	$	272,852	$	158,836

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We provide for the depreciation of our drilling and workover rigs using 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 jackup 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 jackup rigs, where a 30-year depreciable life is used, after provision for salvage value.

Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings — 10 to 30 years; well-servicing rigs — 3 to 15 years; marine transportation and supply vessels — 10 to 25 years; oilfield hauling and mobile equipment and other machinery and equipment — 3 to 10 years). Amortization of capitalized leases is included in depreciation and amortization expense. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations.

We review our assets for impairment annually or 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. Impairment charges are recorded using discounted cash flows which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could result in future impairments. A significantly prolonged period of lower oil and natural gas prices could adversely affect the demand for and prices of our services, which could result in future impairment charges. 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.

Oil and Gas Properties

Oil and Gas Properties

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 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. 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 Securities and Exchange Commission (“SEC”) rules. During 2011 and 2009, our proportionate share of those ventures’ full-cost ceiling test writedowns was $15.6 million and $237.1 million, respectively. No full-cost ceiling test writedowns were recorded by our unconsolidated oil and gas joint ventures during 2010.

Our wholly owned oil and gas investment portfolio and our unconsolidated ownership interest in Remora is reflected in Assets held for sale in our consolidated balance sheet at December 31, 2011. We evaluate the carrying value of our assets held for sale to the fair value of the assets less costs to sale to determine whether impairment is indicated.

A significantly prolonged period of lower oil and natural gas prices or a reduction to the estimation of reserve quantities could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges to our oil and gas properties.

Oil and Gas Reserves

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.

Goodwill

Goodwill

Goodwill represents the cost in excess of fair value of the net assets of companies acquired. 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 the reporting unit exceeds its fair value. All our operating segment’s fair values were substantially in excess of their carrying value with the exception of the U.S. Land Well-servicing and International segments. These operating segments had an excess of fair value over carrying value of approximately 20%. As further discussed below in Recent Accounting Pronouncements, we changed the manner in which we initially assess goodwill for impairment during 2012. Under new guidance, we will assess qualitative factors to determine whether to perform the two-step quantitative goodwill impairment tests. A significantly prolonged period of lower oil and natural gas prices 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 Note 3 — Impairments and Other Charges for discussion of goodwill impairments.

The change in the carrying amount of goodwill for our various Contract Drilling segments, Pressure Pumping segment and Other Operating segments for the years ended December 31, 2011 and 2010 was as follows:

	Balance as of December 31, 2009		Acquisitions and Purchase Price Adjustments			Impairments			Cumulative Translation Adjustment		Balance as of December 31, 2010
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—		$	—	$	30,154
U.S. Land Well-servicing		50,839		5,000	(1)		—			—		55,839
U.S. Offshore		18,003		—			(10,707	)(2)		—		7,296
Alaska		19,995		—			—			—		19,995
International		18,983		—			—			—		18,983
Subtotal Contract Drilling		137,974		5,000			(10,707	)		—		132,267
Pressure Pumping		—		334,992	(3)		—			—		334,992
Other Operating Segments		26,291		—			—			822		27,113
Total	$	164,265	$	339,992		$	(10,707	)	$	822	$	494,372

	Balance as of December 31, 2010		Acquisitions and Purchase Price Adjustments			Impairments		Cumulative Translation Adjustment			Balance as of December 31, 2011
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—	$	—		$	30,154
U.S. Land Well-servicing		55,839		(767	)(1)		—		—			55,072
U.S. Offshore		7,296		—			—		—			7,296
Alaska		19,995		—			—		—			19,995
International		18,983		—			—		—			18,983
Subtotal Contract Drilling		132,267		(767	)		—		—			131,500
Pressure Pumping		334,992		—			—		—			334,992
Other Operating Segments		27,113		8,000	(4)		—		(347	)		34,766
Total	$	494,372	$	7,233		$	—	$	(347	)	$	501,258

(1) Represents the goodwill recorded in connection with our acquisition of Energy Contractors during 2010 and an adjustment to the goodwill recorded during 2011. See Note 5 — Acquisitions for additional discussion.

(2) Represents goodwill impairment associated with our U.S. Offshore operating segment. 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. See Note 3 — Impairments and Other Charges for additional information.

(3) Represents the goodwill recorded in connection with our acquisition of Superior. See Note 5 — Acquisitions for additional discussion.

(4) Represents goodwill recorded in connection with our acquisition of the remaining 50 percent equity interest of Peak. See Note 5 — Acquisitions for additional discussion.

Our Oil and Gas segment does not have any goodwill. Goodwill for the consolidated company, totaling approximately $12.9 million, is expected to be deductible for tax purposes.

Derivative Financial Instruments

Derivative Financial Instruments

We record derivative financial instruments (including certain derivative instruments embedded in other contracts) in our consolidated balance sheets at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Any change in fair value of derivative financial instruments that are speculative in nature and do not qualify for hedge accounting treatment is also recognized immediately in earnings. Proceeds received upon termination of derivative financial instruments qualifying as fair value hedges are deferred and amortized into income over the remaining life of the hedged item using the effective interest rate method.

Litigation and insurance reserves

Litigation and Insurance Reserves

We estimate our reserves related to litigation and insurance based on the facts and circumstances specific to the litigation and insurance claims and our past experience with similar claims. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions. See Note 18 — Commitments and Contingencies regarding self-insurance accruals. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can reasonably 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. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure.

Revenue Recognition

Revenue Recognition

We recognize revenues and costs on daywork contracts daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. We defer revenue related to mobilization periods and recognize the revenue over the term of the related drilling contract. Costs incurred related to a mobilization period for which a contract is secured are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. We defer recognition of revenue on amounts received from customers for prepayment of services until those services are provided.

We recognize revenue for top drives and instrumentation systems we manufacture when the earnings process is complete. This generally occurs when products have been shipped, title and risk of loss have been transferred, collectability is probable, and pricing is fixed and determinable.

In connection with the performance of our cementing services, we recognize product and service revenue when the products are delivered or services are provided to the customer and collectability is reasonably assured. Product sale prices are determined by published price lists provided to our customers.

We recognize, as operating revenue, proceeds from business interruption insurance claims in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements in excess of the carrying value of damaged assets are recognized in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements that are expected to be less than the carrying value of damaged assets are recognized at the time the loss is incurred and recorded in losses (gains) on sales and retirements of long-lived assets and other expense (income), net.

We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.

We recognize revenue on our interests in oil and gas properties as production occurs and title passes. We apply the entitlement method of accounting for natural gas revenue. Under this method, revenues are recognized based on our revenue interest of production from our properties in which sales are disproportionately allocated to owners because of marketing or other contractual arrangements. Accordingly, revenue is not recognized for deliveries in excess of our net revenue interest, while revenue is recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. Production volume is monitored to minimize these natural gas imbalances.

Share-Based Compensation

Share-Based Compensation

We record compensation expense for all share-based awards granted. The amount of compensation expense recognized is based on the grant-date fair value. See Note 8 — Share-Based Compensation for additional discussion.

Income Taxes

Income Taxes

We are a Bermuda exempted company and are not subject to income taxes in Bermuda. Consequently, income taxes have been provided based on the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income taxes in these jurisdictions vary substantially. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year because our operations are conducted in different taxing jurisdictions.

We recognize increases to our tax reserves for uncertain tax positions along with interest and penalties as an increase to other long-term liabilities.

For U.S. and other jurisdictional income tax purposes, we have net operating and other loss carryforwards that we are required to assess quarterly for potential valuation allowances. We consider the sufficiency of existing temporary differences and expected future earnings levels in determining the amount, if any, of valuation allowance required against such carryforwards and against deferred tax assets.

Nabors realizes an income tax benefit associated with certain awards issued under our stock plans. We recognize the benefits related to tax deductions up to the amount of the compensation expense recorded for the award in the consolidated statements of income (loss). Any excess tax benefit (i.e., tax deduction in excess of compensation expense) is reflected as an increase in capital in excess of par. Any shortfall is recorded as a reduction to capital in excess of par to the extent of our aggregate accumulated pool of windfall benefits, beyond which the shortfall would be recognized in the consolidated statements of income (loss).

Foreign Currency Translation

Foreign Currency Translation

For certain of our foreign subsidiaries, such as those in Canada and Argentina, the local currency is the functional currency, and therefore translation gains or losses associated with foreign-denominated monetary accounts are accumulated in a separate section of the consolidated statements of changes in equity. For our other international subsidiaries, the U.S. dollar is the functional currency, and therefore local currency transaction gains and losses, arising from remeasurement of payables and receivables denominated in local currency, are included in our consolidated statements of income (loss).

Cash flows

Cash Flows

We treat the redemption price, including accrued original issue discount, on our convertible debt instruments as a financing activity for purposes of reporting cash flows in our consolidated statements of cash flows.

Use of estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:

• financial instruments;

• depreciation of property, plant and equipment;

• impairment of long-lived assets;

• impairment of goodwill and intangible assets;

• impairment of oil and gas properties;

• valuation of oil and gas reserves;

• income taxes;

• litigation and self-insurance reserves;

• fair value of assets acquired and liabilities assumed; and

• share-based compensation.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revised 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 Financial Accounting Standards Board (“FASB”) issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The 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 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 were effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. 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 were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we had significant oil and gas activities under the new definition. Our oil and gas disclosures for the years ended December 31, 2011 and 2010 are provided in Note 24 — Supplementary Information on Oil and Gas Exploration and Production Activities.

Effective January 1, 2010, we adopted the revised provisions relating to consolidation of variable interest entities within the Consolidations Topic of the FASB’s Accounting Standards Codification (“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 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, became applicable to us for contracts entered into after June 15, 2010. The adoption of these rules did not have a significant impact on our consolidated financial statements.

In May 2011, the FASB issued an Accounting Standards Update (“ASU”) to clarify the application of some of the existing fair value measurement and disclosure requirements. These changes are effective for interim and annual periods that begin after December 15, 2011. The disclosure requirements did not have a significant impact on our consolidated financial statements.

In June 2011, the FASB issued an ASU relating to the presentation of other comprehensive income (“OCI”). This ASU does not change the items that are reported in OCI, but does remove the option to present the components of OCI within the statement of changes in equity. In addition, this ASU will require OCI presentation on the face of the financial statements. These changes are effective for interim and annual periods that begin after December 15, 2011, and are applied retrospectively to all periods presented. Early adoption is permitted. We adopted the ASU beginning January 1, 2012 and it did not have an impact on our consolidated financial statements.

In September 2011, the FASB issued a revised ASU relating to goodwill impairment tests. An entity is allowed to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on its qualitative assessment, that it is more likely than not that the fair value is less than its carrying amount. The amendment is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. We adopted the ASU beginning January 1, 2012 and will apply it to our goodwill impairment tests.

XML

Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment Information [Abstract]

Financial information with respect to reportable segments

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Operating revenues and earnings (losses) from unconsolidated affiliates from continuing operations:(1)
Contract Drilling:(2)
U.S. Lower 48 Land Drilling	$	1,698,620		$	1,294,853		$	1,082,531
U.S. Land Well-servicing		701,223			444,665			412,243
U.S. Offshore		170,727			123,761			157,305
Alaska		129,894			179,218			204,407
Canada		574,754			389,229			298,653
International		1,104,461			1,093,608			1,265,097
Subtotal Contract Drilling(3)		4,379,679			3,525,334			3,420,236
Pressure Pumping(4)		1,237,306			321,295			—
Oil and Gas(5)(6)		59,685			18,657			(182,654	)
Other Operating Segments(7)(8)		674,206			427,154			417,531
Other reconciling items(9)		(233,878	)		(124,690	)		(148,325	)
Total	$	6,116,998		$	4,167,750		$	3,506,788
Depreciation and amortization, and depletion:(1)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	288,373		$	241,258		$	226,875
U.S. Land Well-servicing		78,314			65,561			69,557
U.S. Offshore		37,242			37,059			37,204
Alaska		34,989			37,195			29,946
Canada		75,919			74,735			65,883
International		273,315			247,134			208,949
Subtotal Contract Drilling		788,152			702,942			638,414
Pressure Pumping(4)		102,009			32,204			—
Oil and Gas		—			—			—
Other Operating Segments		34,162			28,452			27,441
Other reconciling items(9)		(229	)		(2,636	)		(1,897	)
Total depreciation and amortization, and depletion	$	924,094		$	760,962		$	663,958
Adjusted income (loss) derived from operating activities from continuing operations:(1)(10)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	414,317		$	274,215		$	294,679
U.S. Land Well-servicing		74,725			31,597			28,950
U.S. Offshore		843			9,245			30,508
Alaska		27,671			51,896			62,742
Canada		94,637			22,970			(7,019	)
International		123,813			254,744			365,566
Subtotal Contract Drilling(3)		736,006			644,667			775,426
Pressure Pumping(4)		229,125			66,651			—
Oil and Gas(5)(6)		59,685			18,657			(182,654	)
Other Operating Segments(7)(8)		55,617			42,401			35,319
Other reconciling items(11)		(153,385	)		(104,827	)		(188,257	)
Total adjusted income derived from operating activities	$	927,048		$	667,549		$	439,834
Interest expense		(256,633	)		(272,712	)		(266,047	)
Investment income (loss)		19,940			7,263			25,522
Gains (losses) on sales and retirements of long-lived assets and other (income) expense, net		(4,514	)		(47,238	)		(11,982	)
Impairments and other charges(12)		(198,072	)		(61,292	)		(118,543	)
Income (loss) from continuing operations before income taxes		487,769			293,570			68,784
Income tax expense (benefit)		142,605			36,950			(63,937	)
Subsidiary preferred stock dividend		3,000			750			—
Income (loss) from continuing operations, net of tax		342,164			255,870			132,721
Income (loss) from discontinued operations, net of tax		(97,440	)		(161,090	)		(218,609	)
Net income (loss)		244,724			94,780			(85,888	)
Less: Net income (loss) attributable to noncontrolling interest		(1,045	)		(85	)		342
Net income (loss) attributable to Nabors	$	243,679		$	94,695		$	(85,546	)

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Capital expenditures and acquisitions of businesses:(13)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	650,342		$	294,239		$	327,269
U.S. Land Well-servicing		165,953			84,657			16,671
U.S. Offshore		63,817			23,625			48,694
Alaska		5,582			891			55,426
Canada		95,001			53,834			29,214
International		653,759			365,597			328,252
Subtotal Contract Drilling		1,634,454			822,843			805,526
Pressure Pumping(4)		285,304			924,693			—
Oil and Gas		208,995			113,361			184,185
Other Operating Segments		136,515			28,799			20,446
Other reconciling items(11)(17)		(17,533	)		(11,633	)		(19,870	)
Total capital expenditures and acquisitions of businesses	$	2,247,735		$	1,878,063		$	990,287

	December 31,
	2011		2010		2009
	(In thousands)
Total assets:
Contract Drilling:(14)
U.S. Lower 48 Land Drilling	$	3,216,803	$	2,762,362	$	2,609,101
U.S. Land Well-servicing		812,049		630,518		594,456
U.S. Offshore		402,506		379,292		440,556
Alaska		288,253		313,123		373,146
Canada		962,239		1,065,268		984,740
International		3,702,611		3,279,763		3,151,513
Subtotal Contract Drilling		9,384,461		8,430,326		8,153,512
Pressure Pumping(4)		1,503,298		1,163,236		—
Oil and Gas(15)		796,327		805,410		835,465
Other Operating Segments(16)		720,775		539,373		502,501
Other reconciling items(11)(17)		507,279		708,224		1,153,212
Total assets	$	12,912,140	$	11,646,569	$	10,644,690

(1) All periods present the operating activities of our wholly owned oil and gas assets in the United States, Canada and Colombia, including equity interests in Canada and Colombia, as well as the Nabors Blue Sky Ltd. business as discontinued operations.

(2) These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore.

(3) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.2) million, $6.9 million and $9.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.

(4) Includes operating results of the Superior acquisition beginning September 10, 2010.

(5) Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(15.6) million and $(189.3) million for the years ended December 31, 2011 and 2009, respectively.

(6) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $59.7 million, $18.7 million and $(182.6) million for the years ended December 31, 2011, 2010 and 2009, respectively. Additional information is provided in Note 24 — Supplemental Information on Oil and Gas Exploration and Production Activities.

(7) Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction operations.

(8) Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(1.9) million, $7.7 million and $17.5 million for the years ended December 31, 2011, 2010 and 2009, 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 in accordance with 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 accurately reflect 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 in the above table.

(11) Represents the elimination of inter-segment transactions and unallocated corporate expenses, assets and capital expenditures.

(12) Represents impairments and other charges recorded during the years ended December 31, 2011, 2010 and 2009, respectively.

(13) Includes the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.

(14) Includes $51.5 million, $54.8 million and $49.8 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(15) Includes $294.1 million, $146.5 million and $190.1 million investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(16) Includes $25.4 million, $64.5 million and $65.8 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2011, 2010 and 2009, respectively.

(17) Includes $1.9 million and $.9 million of investments in unconsolidated affiliates accounted for using the cost method as of December 31, 2010 and 2009, respectively.

Financial Information with respect to Nabor's operations by geographic

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Operating revenues and earnings (losses) from unconsolidated affiliates from continuing operations:
U.S.	$	4,329,079	$	2,612,954	$	1,817,374
Outside the U.S.		1,787,919		1,554,796		1,689,414
	$	6,116,998	$	4,167,750	$	3,506,788
Property, plant and equipment, net:
U.S.	$	4,974,239	$	4,447,388	$	4,107,250
Outside the U.S.		3,655,707		3,368,031		3,538,800
	$	8,629,946	$	7,815,419	$	7,646,050
Goodwill:
U.S.	$	466,794	$	459,560	$	130,275
Outside the U.S.		34,464		34,812		33,990
	$	501,258	$	494,372	$	164,265

XML

Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

Note 13    Income Taxes

We apply the provisions of the Income Taxes Topic in the ASC relating to uncertain tax positions. The change in our unrecognized tax benefits for years ended December 31, 2011, 2010 and 2009 were as follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Balance as of January 1,	$	81,174		$	69,048		$	51,819
Additions based on tax positions related to the current year(1)		1,850			1,026			4,787
Additions for tax positions of prior years(1)		11,748			17,060			12,889
Reductions for tax positions of prior years		(11,082	)		(4,709	)		(447	)
Settlements(2)		(14,842	)		(1,251	)		—
Balance as of December 31,	$	68,848		$	81,174		$	69,048

(1) Includes an unrecognized tax benefit of $10.8 million related to an Algeria audit assessment.

(2) Includes $8.6 million related to a settlement of the 1995 to 1997 income tax audits with the Canada Revenue Agency.

The balance also represents the amount of unrecognized tax benefits that, if recognized, would favorably impact the effective income tax rate in future periods. As of December 31, 2011, 2010 and 2009, we had approximately $28.2 million, $42.9 million and $38.5 million, respectively, of interest and penalties related to our total gross unrecognized tax benefits. During the years ended December 31, 2011, 2010 and 2009, we accrued and recognized estimated interest related to unrecognized tax benefits and penalties of approximately $4.6 million, $5.1 million and $5.2 million, respectively. We recognize interest and penalties related to income tax matters in the income tax expense line item in our consolidated statements of income (loss).

We are subject to income taxes in the United States and numerous other jurisdictions. A number of our United States and non-United States income tax returns from 1998 through 2010 are currently under audit examination. We anticipate that several of these audits could be finalized within the next 12 months. It is possible that the benefit relating to our unrecognized tax positions could significantly increase or decrease within the next 12 months. However, based on the current status of examinations, and the protocol for finalizing audits with the relevant tax authorities, which could include formal legal proceedings, it is not possible to estimate the future impact of the amount of changes, if any, to recorded uncertain tax positions at December 31, 2011.

Income (loss) from continuing operations before income taxes was comprised of the following:

	Year Ended December 31,
	2011		2010			2009
	(In thousands)
United States and Other Jurisdictions:
United States	$	178,270	$	(82,723	)	$	(505,264	)
Other jurisdictions		309,499		376,293			574,048
Income (loss) before income taxes from continuing operations	$	487,769	$	293,570		$	68,784

Income taxes have been provided based upon the tax laws and rates in the countries where we operate. We are a Bermuda exempted company. Bermuda does not impose corporate income taxes. Our U.S. subsidiaries are subject to a U.S. federal tax rate of 35%.

Income tax expense (benefit) from continuing operations consisted of the following:

	2011			2010			2009
	(In thousands)
Current:
U.S. federal	$	27,649		$	(137,847	)	$	(15,434	)
Outside the U.S.		43,732			54,779			84,221
State		38,321			5,859			2,671
		109,702			(77,209	)		71,458
Deferred:
U.S. federal		41,540			97,114			(80,353	)
Outside the U.S.		4,413			13,607			(46,603	)
State		(13,050	)		3,438			(8,439	)
		32,903			114,159			(135,395	)
Income tax expense (benefit)	$	142,605		$	36,950		$	(63,937	)

Nabors is not subject to tax in Bermuda. A reconciliation of the differences between taxes on income (loss) before income taxes computed at the appropriate statutory rate and our reported provision for income taxes follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Income tax provision at statutory rate (Bermuda rate of 0%)	$	—		$	—		$	—
Taxes on U.S. and other international earnings (losses) at greater than the Bermuda rate		112,094			18,686			(60,741	)
Increase (decrease) in valuation allowance		(6,450	)		2,407			6,062
Effect of change in tax rate		(258	)		40			(9,248	)
Tax reserves and interest		11,948			8,808			14,652
State income taxes		25,271			7,009			(14,662	)
Income tax expense (benefit)	$	142,605		$	36,950		$	(63,937	)
Effective tax rate		29.2	%		12.6	%		(93.0	)%

The increase in our effective tax rate from 2010 to 2011 is mainly a result of the increase in the proportion of income generated in the United States versus the international jurisdictions in which we operate. Income generated in the United States is generally taxed at a higher rate than international jurisdictions.

Our effective income tax rate for 2010 and 2009 reflected 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 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 represents a meaningful basis for comparing our 2009 effective income tax rate to the 2010 effective income tax rate.

The significant components of our deferred tax assets and liabilities were as follows:

	December 31,
	2011			2010
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	2,009,318		$	1,848,956
Equity compensation		25,937			19,262
Deferred revenue		32,200			13,428
Tax credit and other attribute carryforwards		90,297			89,141
Insurance loss reserve		24,598			28,537
Other		114,043			62,324
Subtotal		2,296,393			2,061,648
Valuation allowance		(1,485,540	)		(1,514,153	)
Deferred tax assets	$	810,853		$	547,495
Deferred tax liabilities:
Depreciation, amortization and depletion for tax in excess of book expense	$	1,317,256		$	1,123,622
Variable interest investments		116,005			75,204
Other		34,822			54,738
Deferred tax liability		1,468,083			1,253,564
Net deferred assets (liabilities)	$	(657,230	)	$	(706,069	)
Balance Sheet Summary
Net current deferred asset	$	127,874		$	31,510
Net noncurrent deferred asset(1)		13,090			33,694
Net current deferred liability(2)		(269	)		(1,027	)
Net noncurrent deferred liability		(797,925	)		(770,246	)
Net deferred asset (liability)	$	(657,230	)	$	(706,069	)

(1) This amount is included in other long-term assets.

(2) This amount is included in accrued liabilities.

For U.S. federal income tax purposes, we have net operating loss (“NOL”) carryforwards of approximately $1.2 billion that, if not utilized, will expire between 2016 and 2031. The NOL carryforwards for alternative minimum tax purposes are approximately $680 million. Additionally, we have NOL carryforwards in other jurisdictions of approximately $5.4 billion of which $408 million that, if not utilized, will expire at various times from 2012 to 2031. We provide a valuation allowance against NOL carryforwards in various tax jurisdictions based on our consideration of existing temporary differences and expected future earning levels in those jurisdictions. We have recorded a deferred tax asset of approximately $1.45 billion as of December 31, 2011 relating to NOL carryforwards that have an indefinite life in several non-U.S. jurisdictions. A valuation allowance of approximately $1.45 billion has been recognized because we believe it is more likely than not that substantially all of the deferred tax asset will not be realized.

The NOL carryforwards by year of expiration:

Year Ended December 31,	Total		U.S. Federal		Non-U.S.
	(In thousands)
2012	$	8,778	$		$	8,778
2013		30,348				30,348
2014		3,980				3,980
2015		12,824				12,824
2016		50,176		7,504		42,672
2017		26,601		5,423		21,178
2018		68,888		33,111		35,777
2019		35,986		17,722		18,264
2020		14,612				14,612
2021		7,895				7,895
2027		2,014				2,014
2028		31,237				31,237
2029		184,463		130,842		53,621
2030		533,825		485,648		48,177
2031		626,288		549,795		76,493
Subtotal: expiring NOLs		1,637,915		1,230,045		407,870
Non-expiring NOLs		5,021,678		—		5,021,678
Total	$	6,659,593	$	1,230,045	$	5,429,548

In addition, for state income tax purposes, we have net operating loss carryforwards of approximately $649 million that, if not utilized, will expire at various times from 2012 to 2031.

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 these carryforwards could be limited or effectively lost upon certain changes in our shareholder base. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given that they will be available in the future.

Various bills have been introduced in the U.S. Congress that could reduce or eliminate the U.S. 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 United States federal income tax purposes. Our reorganization was completed June 24, 2002. There has been and we expect that there may continue to be legislation proposed in 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 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.

XML

Unaudited Quarterly Financial Information (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Unaudited Quarterly Financial Information
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)	$ 1,731,979	$ 1,642,227	$ 1,352,950	$ 1,389,842	$ 1,310,242	$ 1,068,870	$ 898,169	$ 890,469	$ 6,116,998	$ 4,167,750	$ 3,506,788
Income (loss) from continuing operations, net of tax	89,535	87,190	70,887	94,552	152,097	12,347	44,949	46,477	342,164	255,870	132,721
Income (loss) from discontinued operations, net of tax	(193,985)	(12,226)	121,167	(12,396)	(100,323)	(51,501)	(1,887)	(7,379)	(97,440)	(161,090)	(218,609)
Less: Net (income) loss attributable to noncontrolling interest	(1,400)	(708)	394	669	(1,293)	(453)	559	1,102	(1,045)	(85)	342
Net income (loss) attributable to Nabors	(105,850)	74,256	192,448	82,825	50,481	(39,607)	43,621	40,200	243,679	94,695	(85,546)
Earnings (loss) per share: (2)
Basic from continuing operations	$ 0.31	$ 0.30	$ 0.25	$ 0.33	$ 0.53	$ 0.04	$ 0.16	$ 0.17	$ 1.19	$ 0.90	$ 0.47
Basic from discontinued operations	$ (0.68)	$ (0.04)	$ 0.42	$ (0.04)	$ (0.35)	$ (0.18)	$ (0.01)	$ (0.03)	$ (0.34)	$ (0.57)	$ (0.77)
Total Basic	$ (0.37)	$ 0.26	$ 0.67	$ 0.29	$ 0.18	$ (0.14)	$ 0.15	$ 0.14	$ (0.85)	$ 0.33	$ (0.30)
Diluted from continuing operations	$ 0.30	$ 0.30	$ 0.24	$ 0.33	$ 0.52	$ 0.04	$ 0.16	$ 0.16	$ 1.17	$ 0.88	$ 0.46
Diluted from discontinued operations	$ (0.66)	$ (0.05)	$ 0.41	$ (0.05)	$ (0.35)	$ (0.18)	$ (0.01)	$ (0.02)	$ (0.34)	$ (0.55)	$ (0.76)
Total Diluted	$ (0.36)	$ 0.25	$ 0.65	$ 0.28	$ 0.17	$ (0.14)	$ 0.15	$ 0.14	$ 0.83	$ 0.33	$ (0.30)
Unaudited Quarterly Financial Information (Textual) [Abstract]
Earnings (losses) from unconsolidated affiliates	$ (2,700)	$ 33,700	$ 9,300	$ 16,300	$ 4,900	$ 11,800	$ 8,900	$ 7,700	$ 56,647	$ 33,267	$ (155,432)

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 18    Commitments and Contingencies

Commitments

Leases

Nabors and its subsidiaries occupy various facilities and lease certain equipment under various lease agreements.

The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2011, were as follows:

	(In thousands)
2012	$	25,288
2013		20,060
2014		14,363
2015		7,273
2016		4,020
Thereafter		9,857
	$	80,861

The above amounts do not include property taxes, insurance or normal maintenance that the lessees are required to pay. Rental expense relating to operating leases with terms greater than 30 days amounted to $36.3 million, $26.7 million and $25.5 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Minimum Volume Commitment

We have contracts with pipeline companies to pay specified fees based on committed volumes for gas transport and processing. At the end of the term or annually, we are invoiced for any shortfalls in the volume deliveries at the rate specified in the agreement. Volume commitments remaining under the contracts as of December 31, 2011 were as follows:

	(In thousands)
2012	$	54,287
2013		68,056
2014		66,373
2015		64,845
2016		48,330
Thereafter(1)		86,808
	$	388,699

(1) Final commitment period is for the period ending October 2029.

Employment Contracts

We have entered into employment contracts with certain of our employees. Our minimum salary and bonus obligations under these contracts as of December 31, 2011 were as follows:

	(In thousands)
2012	$	9,752
2013		3,905
2014		501
2015		—
2016		—
Thereafter		—
	$	14,158

Nabors’ Deputy Chairman, President and Chief Executive Officer, Anthony G. Petrello, had an employment agreement (“prior employment agreement”) in effect through the first quarter of 2009. Effective April 1, 2009, the Company entered into an amended and restated employment agreement (“new employment agreement”) with him, which extended the terms through March 30, 2013. Pursuant to its provisions, the term of the new employment agreement has subsequently extended through March 30, 2014.

For the three months ended March 31, 2009, the prior employment agreement provided for an annual cash bonus in an amount equal to 2% of Nabors’ net cash flow (as defined in the employment agreements) in excess of 15% of the average shareholders’ equity for each fiscal year. The bonus was subject to a minimum of $700,000 per year.

The new employment agreement increased Mr. Petrello’s base salary to $1.3 million and provides for an extension of the employment term through March 30, 2013, with automatic one-year extensions beginning April 1, 2011, unless either party gives notice of non-renewal. On June 29, 2009, the new employment agreement was amended to provide for a reduction in the annual rate of base salary payable to $990,000 per year for the period from June 29, 2009 to December 27, 2009. On December 28, 2009, the agreement was further amended to extend through June 27, 2010 the previously agreed salary reduction.

In addition to a base salary, the new employment agreement provides for an annual cash bonus in an amount equal to 1.5% of Nabors’ net cash flow (as defined in the new employment agreement) in excess of 15% of the average shareholders’ equity for each fiscal year. As provided in the new employment agreement, the 1.5% of Nabors’ net cash flow was replaced with 2.0% on October 28, 2011 in connection with his appointment as Chief Executive Officer. For 2011, the annual cash bonus pursuant to the formula was $13.6 million. The new employment agreement also provides a quarterly deferred bonus of $.25 million to Mr. Petrello’s account under Nabors’ executive deferred compensation plan for each quarter he is employed beginning June 30, 2009 and ending March 30, 2019.

Mr. Petrello is also eligible for awards under Nabors’ equity plans, may participate in annual long-term incentive programs and pension and welfare plans on the same basis as other executives, and may receive special bonuses from time to time as determined by the Board of Directors. The new employment agreement effectively eliminated the risk of forfeiture of outstanding stock awards. Accordingly, we recognized compensation expense during the second quarter of 2009 with respect to all previously granted unvested awards to him.

Termination in the event of death, disability, or termination without cause (including in the event of a Change in Control).     The new employment agreement provides for a severance payment in the event that it is terminated (i) upon death or disability, (ii) by Nabors prior to its expiration date for any reason other than for Cause (as defined in the agreement), or (iii) by Mr. Petrello for Constructive Termination Without Cause, as defined in the agreement. Termination in the event of a Change in Control (as defined in the new employment agreement) is considered a Constructive Termination Without Cause. Mr. Petrello would be entitled to receive within 30 days of his death or disability a payment of $50 million or in the event of Termination Without Cause or Constructive Termination Without Cause, a payment based on a formula of three times the average of his base salary and annual bonus (calculated as though the bonus formula under the new employment agreement had been in effect) paid during the three fiscal years preceding the termination. If, by way of example, Mr. Petrello were Terminated Without Cause subsequent to December 31, 2011, his payment would be approximately $31.1 million. The formula will be further reduced to two times the average stated above effective April 1, 2015.

The Company does not have insurance to cover its obligations in the event of Mr. Petrello’s death, disability, or termination without cause, and the Company has not recorded an expense or accrued a liability relating to the potential obligation.

In addition, under the new employment agreement, Mr. Petrello would be entitled to receive (a) any unvested restricted stock or stock options outstanding, which would immediately and fully vest; (b) any amounts earned, accrued or owing to him but not yet paid (including executive benefits, life insurance, disability benefits and reimbursement of expenses and perquisites), which would be continued through the later of the expiration date or three years after the termination date; (c) continued participation in medical, dental and life insurance coverage until he received equivalent benefits or coverage through a subsequent employer or until his death or the death of his spouse, whichever were later; and (d) any other or additional benefits in accordance with applicable plans and programs of Nabors. The vesting of unvested equity awards would not result in the recognition of any additional compensation expense, as all compensation expense related to his outstanding awards had been recognized by December 31, 2011. In addition, the new employment agreement eliminates all tax gross-ups, including tax gross-ups on golden parachute excise taxes, which applied under the prior employment agreement. Estimates of the cash value of Nabors’ obligations to Mr. Petrello under (b), (c) and (d) above are included in the payment amounts above.

Other Obligations.     In addition to salary and bonus, Mr. Petrello receives group life insurance at an amount at least equal to three times his base salary, various split-dollar life insurance policies, reimbursement of expenses, various perquisites and a personal umbrella insurance policy in the amount of $5 million. Premiums payable under the split-dollar life insurance policies were suspended as a result of the adoption of the Sarbanes-Oxley Act of 2002.

Nabors’ Chairman, Eugene M. Isenberg, had an employment agreement in effect through the first quarter of 2009, which was amended and restated effective April 1, 2009. The provisions of the amended and restated employment agreement were similar to Mr. Petrello’s new employment agreement, but provided for a $100 million payment in the event of death, disability, or termination without cause (including in the event of a Change in Control). Mr. Isenberg was also eligible for awards under Nabors’ equity plans, participation in annual long-term incentive programs and pension and welfare plans and special bonuses from time to time as determined by the Board of Directors.

Effective April 1, 2009, Mr. Isenberg’s base salary was $1.3 million. He agreed to donate the after-tax proceeds to an educational fund benefiting Company employees or to other worthy candidates. His annual cash bonus equaled 2.25% of Nabors’ net cash flow (as defined in the employment agreement) in excess of 15% of the average shareholders’ equity for each fiscal year. For 2011, the annual cash bonus pursuant to the formula was $19.5 million. Mr. Isenberg’s employment agreement also provided a quarterly deferred bonus of $.6 million to an account under Nabors’ executive deferred compensation plan for each quarter he was employed beginning June 30, 2009.

Effective December 31, 2011, Mr. Isenberg voluntarily terminated both his employment with the Company and his Employment Agreement, and forwent any right to payment in connection with such termination. See Note 17 — Related-Party Transactions for additional discussion.

Contingencies

Income Tax Contingencies

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 possible that future changes to 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 2002 corporate reorganization. See Note 13 — Income Taxes for additional discussion.

On September 14, 2006, Nabors Drilling International Limited, one of our wholly owned Bermuda subsidiaries (“NDIL”), received a Notice of Assessment 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 2005 through 2008 and against NDIL II for 2007 to 2010. We believe that the potential assessments will range from $6 million to $26 million per year for the period from 2005 to 2009, and in the aggregate, would be approximately $90 million to $95 million. Although we believe that any assessments related to the 2003 and 2005 to 2010 years lack merit, a reserve has been recorded in accordance with GAAP. The statute of limitations for NDIL’s 2004 tax year 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 made and we ultimately did not prevail, we would be required to recognize additional tax for the amount in excess of the current reserve.

Self-Insurance

We estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Our estimates are based on the facts and circumstances specific to existing claims and our past experience with similar 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. Although we believe our insurance coverage and reserve estimates are reasonable, a significant accident or other event that is not fully covered by insurance or contractual indemnity could occur and could materially affect our financial position and results of operations for a particular period.

We self-insure for certain losses relating to workers’ compensation, employers’ liability, general liability, automobile liability and property damage. Some workers’ compensation claims are subject to a minimum $1.0 million deductible liability, plus an additional $3.0 million corridor deductible. Some employers’ liability and marine employers’ liability claims are subject to a $2.0 million per-occurrence deductible. Some automobile liability is subject to a $.5 million per-occurrence deductible, plus an additional $1.0 million corridor deductible. General liability claims are subject to a $5.0 million per-occurrence deductible.

In addition, we are subject to a $5.0 million deductible for all land rigs and for offshore rigs. This applies to all kinds of risks of physical damage except for named windstorms in the U.S. Gulf of Mexico for which we are self-insured.

Political risk insurance is procured for select operations in South America, Africa, the Middle East and Asia. Losses are subject to a $.25 million deductible, except for Colombia, which is subject to a $.5 million deductible. There is no assurance that such coverage will adequately protect Nabors against liability from all potential consequences.

As of December 31, 2011 and 2010, our self-insurance accruals totaled $157.8 million and $145.6 million, respectively, and our related insurance recoveries/receivables were $18.7 million and $9.0 million, respectively.

Litigation

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. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure. 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 U.S. 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. The inquiry has focused on transactions in Kazakhstan, Saudi Arabia, Algeria and Nigeria. The Audit Committee of our Board of Directors has 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 Department of Justice have been advised of our investigation. 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. In November 2011, we received a notice from the Algeria Supreme Court that a decision is expected in March 2012. 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 March 2011, the Court of Ouargla (in Algeria), sitting at first instance, entered a judgment of approximately $39.1 million against NDIL relating to alleged violations of Algeria’s foreign currency exchange controls, which require that goods and services provided locally be invoiced and paid in local currency. The case relates to certain foreign currency payments made to NDIL by CEPSA, a Spanish operator, for wells drilled in 2006. Approximately $7.5 million of the total contract amount was paid offshore in foreign currency, and approximately $3.2 million was paid in local currency. The judgment includes fines and penalties of approximately four times the amount at issue, and is not payable pending appeal. We have appealed the ruling based on our understanding that the law in question applies only to resident entities incorporated under Algerian law. An intermediate court of appeals has upheld the lower court’s ruling, and we have appealed the matter to the Algeria Supreme Court. While our payments were consistent with our historical operations in the country, and, we believe, those of other multinational corporations there, and interpretations of the law by the Central Bank of Algeria, the ultimate resolution of this matter could result in a loss of up to $31.1 million in excess of amounts accrued.

On September 21, 2011, we received an informal inquiry from the SEC related to perquisites and personal benefits received by the officers and directors of Nabors, including their use of non-commercial aircraft. Our Audit Committee and Board of Directors have been apprised of this inquiry and we are cooperating with the SEC. The ultimate outcome of this process cannot be determined at this time.

Nabors Industries Ltd. and its Board of Directors have been sued by purported shareholders in three separate shareholder’s derivative lawsuits filed in federal and state court in Houston, Texas. The cases were filed on November 18, 2011, January 9, 2012, and November 30, 2011, and are pending, respectively, before Judges Ewing Werlein and Gray Miller in the United States Southern District of Texas, Houston Division, and Judge Mike Miller of the 11th Judicial District Court of Harris County, Texas. The case filed on January 9, 2012 was voluntarily dismissed on January 31, 2012. The other cases remain pending. The allegations of each lawsuit were substantially similar, alleging that the members of the Board breached their fiduciary duties to the Company, wasted corporate assets, and committed oppressive conduct against the shareholders by agreeing to and/or acquiescing in certain compensation arrangements with two senior officers of the Company, Eugene M. Isenberg and Anthony G. Petrello. The remaining lawsuits seek relief that includes an award of monetary damages in an unspecified amount, disgorgement by Messrs. Isenberg and Petrello of allegedly excessive compensation in an unspecified amount of at least $90 million, and equitable relief to reform Nabors’ compensation practices. The ultimate outcome of these lawsuits cannot be determined at this time.

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
	2012		2013		2014		Thereafter		Total
	(In thousands)
Financial standby letters of credit and other financial surety instruments	$	105,055	$	38	$	—	$	—	$	105,093

XML

Common Shares (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Common Shares (Textual) [Abstract]
Common shares, shares authorized	800,000,000	800,000,000
Common shares, par value	$ 0.001	$ 0.001
Common shares, shares issued	317,042,000	315,034,000
Preferred shares, shares authorized	25,000,000	25,000,000
Preferred shares, par value	$ 0.001	$ 0.001
Repurchase of treasury shares	0	0	0
Preferred shares, shares issued	0	0
Restricted shares awarded, average market price	$ 27.32	$ 22.15	$ 11.55
Vested options exercised by employees , shares	(1,116,000)	700,000	1,500,000
Proceeds from issuance of common shares	$ 11,605,000	$ 8,201,000	$ 11,249,000
Anthony G Petrello [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Issuance of common shares for stock options exercised	82,138	110,805	218,835
Value of surrendered unexercised vested stock options	7,600,000	24,500,000	5,600,000
Officers And Directors [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Restricted stock awarded to executive officers, key employees & directors	1,096,379	538,496	85,000
Gene M Isenberg [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Issuance of common shares for stock options exercised		22,385
Value of surrendered unexercised vested stock options		$ 50,100,000

XML

Supplemental Balance Sheet, Income Statement and Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Balance Sheet, Income Statement and Cash Flow Information [Abstract]

Accrued liabilities

	December 31, 2011		December 31, 2010
	(In thousands)
Accrued compensation	$	173,732	$	116,680
Deferred revenue		172,578		88,389
Other taxes payable		44,652		25,227
Workers’ compensation liabilities		22,645		31,944
Interest payable		99,869		89,276
Due to joint venture partners		6,041		6,030
Warranty accrual		5,237		3,376
Litigation reserves		23,687		12,301
Provision for termination payment(1)		100,000		—
Current liability to discontinued operations		54,287		—
Professional fees		6,413		3,222
Current deferred tax liability		269		1,027
Other accrued liabilities		7,363		16,820
	$	716,773	$	394,292

(1) Represents a $100 million provision for a termination payment. See Note 3 — Impairments and Other Charges for additional discussion.

Investment income (loss)

Investment income (loss) includes the following:

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Interest and dividend income	$	9,930		$	7,457		$	15,700
Gains (losses) on investments, net		10,010	(1)		(194	)(2)		9,822	(3)
	$	19,940		$	7,263		$	25,522

(1) Reflects gain (loss) on sale of debt securities and gains (losses) from our long-term investments of $18.0 million, partially offset by net unrealized losses of $8.0 million from our trading securities.

(2) Includes net unrealized losses of $4.4 million from our trading securities, partially offset by gains on the sale of debt securities and gains from our long-term investments of $4.2 million.

(3) Reflects net unrealized gains of $9.8 million from our trading securities.

Losses (gains) on sales and retirements of long-lived assets and other expense (income), net

	Year Ended December 31,
	2011			2010		2009
	(In thousands)
Losses (gains) on sales, retirements and involuntary conversions of long-lived assets	$	(11,155	)(1)	$	6,430	$	5,927
Acquisition-related costs		151			7,021		—
Litigation expenses		11,301			6,356		11,474
Foreign currency transaction losses (gains)		5,499			18,100		7,993
Losses (gains) on derivative instruments		(2,159	)		119		(1,399	)
Losses (gains) on debt extinguishment(2)		58			7,042		(11,197	)
Other losses (gains)		819			2,170		(816	)
	$	4,514		$	47,238	$	11,982

(1) Includes a $13.1 million pre-tax gain from our acquisition of Peak during the year ended December 31, 2011 representing the excess of the estimated fair value of the assets and liabilities over the net carrying value of our previously held equity interest. See Note 5 — Acquisitions for additional discussion.

(2) Includes $.1 million, $(7.0) million and $11.5 million pre-tax (losses) gains on our purchases of our 0.94% senior exchangeable notes in the open market during 2011, 2010 and 2009, respectively.

Supplemental cash flow information

	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Cash paid for income taxes	$	53,759		$	58,574		$	107,994
Cash paid for interest, net of capitalized interest		208,212			180,731			126,796
Acquisitions of businesses:
Fair value of assets acquired		80,585			796,399			—
Goodwill		8,000			339,992			—
Liabilities assumed		(10,471	)		(332,528	)		—
Common stock of acquired company previously owned		—			—			—
Subsidiary preferred stock obligation		—			(69,188	)		—
Gain on acquisition		(13,114	)		—			—
Cash paid for acquisitions of businesses		65,000			734,675			—
Cash acquired in acquisitions of businesses		(9,541	)		(1,045	)		—
Cash paid for acquisitions of businesses, net	$	55,459		$	733,630		$	—

XML

Commitments and Contingencies (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Minimum salary and bonus obligations under employment contracts
2012	$ 9,752
2013	3,905
2014	501
2015	0
2016	0
Thereafter	0
Total	$ 14,158

XML

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2011

Share-Based Compensation [Abstract]

Stock option transactions under various stock-based employee compensation plans

Options	Shares			Weighted-Average Exercise Price		Weighted- Average Remaining Contractual Term		Aggregate Intrinsic Value
	(In thousands, except exercise price)
Options outstanding as of December 31, 2010		28,932		$	18.73
Granted		931			15.67
Exercised		(1,116	)		12.50
Surrendered(1)		(418	)		13.53
Forfeited		(459	)		20.74
Options outstanding as of December 31, 2011		27,870		$	18.94		3.65 years	$	83,306
Options exercisable as of December 31, 2011		24,939		$	19.83		3.14 years	$	65,949

(1) Represents unexercised vested stock options that were surrendered by key officers and directors, to satisfy the option exercise price and related income taxes. See related discussion at Note 14 — Common Shares.

Fair value of stock options

	Year Ended December 31,
	2011			2010			2009
Weighted average fair value of options granted:	$	6.24		$	6.62		$	2.85
Weighted average risk free interest rate:		.65	%		1.49	%		1.75	%
Dividend yield:		0	%		0	%		0	%
Volatility:(1)		51.09	%		41.44	%		34.78	%
Expected life:		4.0 years			4.0 years			4.0 years

(1) Expected volatilities are based on implied volatilities from publicly traded options to purchase Nabors’ common shares, historical volatility of Nabors’ common shares and other factors.

Unvested stock options

Unvested Stock Options	Outstanding			Weighted-Average Grant-Date Fair Value
	(In thousands, except fair values)
Unvested as of December 31, 2010		3,941		$	2.81
Granted		931			6.24
Vested		(1,800	)		2.87
Forfeited		(172	)		2.73
Unvested as of December 31, 2011		2,900		$	3.88

Unvested restricted stock

Restricted Stock	Outstanding			Weighted-Average Grant-Date Fair Value
	(In thousands, except fair values)
Unvested as of December 31, 2010		1,945		$	19.23
Granted		1,096			27.32
Vested		(1,400	)		17.43
Forfeited		(85	)		28.11
Unvested as of December 31, 2011		1,556		$	26.07

XML

Commitments and Contingencies (Details Textual) (USD $)	3 Months Ended			9 Months Ended	12 Months Ended				3 Months Ended		12 Months Ended		3 Months Ended		12 Months Ended
	Mar. 31, 2011	Dec. 31, 2010	Jun. 30, 2009	Sep. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Sep. 14, 2006	Mar. 31, 2019 Messrs. Isenberg [Member]	Jun. 30, 2009 Messrs. Isenberg [Member]	Dec. 31, 2011 Messrs. Isenberg [Member]	Dec. 31, 2009 Messrs. Isenberg [Member]	Dec. 31, 2011 Petrello [Member]	Jun. 30, 2009 Petrello [Member]	Dec. 31, 2010 Petrello [Member]	Dec. 31, 2009 Petrello [Member]	Jun. 29, 2009 Petrello [Member]	Dec. 31, 2011 Minimum Range [Member]	Jun. 30, 2009 Minimum Range [Member]	Dec. 31, 2011 Maximum Range [Member]	Jun. 30, 2009 Maximum Range [Member]
Income Tax Examination [Line Items]
Aggregate potential tax assessments range																		$ 90,000,000	$ 6,000,000	$ 95,000,000	$ 26,000,000
Commitments and Contingencies (Textual) [Abstract]
Percentage of annual cash bonuses										1.50%		2.25%	2.00%	2.00%		1.50%
Minimum Cash Bonus			700,000								19,500,000
Increased base salary										1,300,000				1,300,000
Reduced base salary																	990,000
Annual cash bonuses amount															13,600,000
Quarterly deferred bonus									600,000					250,000
Amount of payment due to death, disability or termination											100,000,000		50,000,000
Approximate amount of payment due to death, disability or termination													31,000,000
Commitments and Contingencies (Additional Textual) [Abstract]
Rental expense relating to operating leases					36,300,000	26,700,000	25,500,000
Threshold limit of the average shareholders equity for cash bonuses			15.00%
Other Insurance Policies Amount					5,000,000
Group life insurance amount					at least 3 times of base salaries
Assessed income tax amount of NDIL's Mexico branch								19,800,000
Potential tax assessments range					$6 million to $26 million per year for the period from 2005 to 2009
Unrecognized tax benefits reductions resulting from lapse of applicable statute of limitations		7,400,000
Workers' compensation claims deductible minimum liability					1,000,000
Worker's compensation additional corridor deductible.					3,000,000
Employer's liability claims subject to Per-occurrence deductible					2,000,000
Automobile liability claims subject to per-occurrence deductible					500,000
Automobile liability additional corridor deductible					1,000,000
General liability claims subject to per-occurrence deductible					5,000,000
Deductions in land rigs and for offshore rigs					5,000,000
Political risk insurance losses deductible				250,000
Political Risk Insurance Deductible for foreign operation					500,000
Self-insurance accruals total		145,600,000			157,800,000	145,600,000
Self-insurance recoveries/receivables		9,000,000			18,700,000	9,000,000
Alleged customs infractions amount							19,700,000
Amount of loss range, minimum							140,000
Amount of loss range, maximum							19,700,000
Possible Loss Relating to Foreign Currency Exchange Control	39,100,000
Payment of Contract Amount in Foreign Currency	7,500,000
Payment of Contract Amount in Domestic Currency	3,200,000
Potential judgment in excess of accrual	31,100,000
Period within which payment received				30 days
Allegedly excessive compensation					$ 90,000,000

XML

CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CONSOLIDATED STATEMENTS OF INCOME (LOSS) [Abstract]
Other-than-temporary impairment on debt security	$ 0	$ 0	$ 40,300
Less: other-than-temporary impairment recognized in accumulated other comprehensive income (loss)	0	0	(4,651)
Credit-related impairment on investment	$ 0	$ 0	$ 35,649

XML

Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Change in unrecognized tax benefits
Balance as of January 1	$ 81,174	$ 69,048	$ 51,819
Additions based on tax positions related to the current year	1,850	1,026	4,787
Additions for tax positions of prior years	11,748	17,060	12,889
Reductions for tax positions of prior years	(11,082)	(4,709)	(447)
Settlements	(14,842)	(1,251)
Balance as of December 31	$ 68,848	$ 81,174	$ 69,048

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2    Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of Nabors, as well as all majority owned and non-majority owned subsidiaries required to be consolidated under GAAP. Our consolidated financial statements exclude majority owned entities for which we do not have either (1) the ability to control the operating and financial decisions and policies of that entity or (2) a controlling financial interest in a variable interest entity. All significant intercompany accounts and transactions are eliminated in consolidation.

Investments in operating entities where we have the ability to exert significant influence, but where we do not control operating and financial policies, are accounted for using the equity method. Our share of the net income (loss) of these entities is recorded as earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss), and our investment in these entities is included as a single amount in our consolidated balance sheets. Investments in unconsolidated affiliates accounted for using the equity method totaled $371.0 million and $265.8 million as of December 31, 2011 and 2010, respectively. Investments in unconsolidated affiliates accounted for using the cost method totaled $1.9 million as of December 31, 2010. At December 31, 2011 and 2010, assets held for sale included investments in unconsolidated affiliates accounted for using the equity method totaling $13.7 million and $79.5 million, respectively. See Note 4 — Discontinued Operations for additional information.

We have investments in offshore funds, which are classified as long-term investments and are accounted for using the equity method of accounting based on our ownership interest in each fund. The carrying value of these investments totaled $5.9 million and $7.4 million as of December 31, 2011 and 2010, respectively.

Cash and Cash Equivalents

Cash and cash equivalents include demand deposits and various other short-term investments with original maturities of three months or less.

Investments

Short-term investments

Short-term investments consist of equity securities, certificates of deposit, corporate debt securities, mortgage-backed debt securities and asset-backed debt securities. Securities classified as available-for-sale or trading are stated at fair value. Unrealized holding gains and temporary losses for available-for-sale securities are excluded from earnings and, until realized, are reported net of taxes in a separate component of equity. Unrealized holding losses are included in earnings during the period for which the loss is determined to be other-than-temporary. Gains and losses from changes in the market value of securities classified as trading are reported in earnings currently.

In computing realized gains and losses on the sale of equity securities, the specific-identification method is used. In accordance with this method, the cost of the equity securities sold is determined using the specific cost of the security when originally purchased.

Long-term investments and other receivables

We have 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). These investments are non-marketable and do not have published fair values. We account for these funds under the equity method of accounting based on our percentage ownership interest and recognize gains or losses as investment income (loss), currently based on changes in the net asset value of our investment during the current period.

Our oil and gas financing receivables, previously included in long-term investments, have been reclassified to assets held for sale. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment.

Inventory

Inventory is stated at the lower of cost or market. Cost is determined using the first-in, first-out method and includes the cost of materials, labor and manufacturing overhead. Inventory included the following:

	December 31, 2011		December 31, 2010
	(In thousands)
Raw materials	$	133,480	$	81,308
Work-in-progress		50,951		23,629
Finished goods		88,421		53,899
	$	272,852	$	158,836

Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We provide for the depreciation of our drilling and workover rigs using 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 jackup 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 jackup rigs, where a 30-year depreciable life is used, after provision for salvage value.

Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings — 10 to 30 years; well-servicing rigs — 3 to 15 years; marine transportation and supply vessels — 10 to 25 years; oilfield hauling and mobile equipment and other machinery and equipment — 3 to 10 years). Amortization of capitalized leases is included in depreciation and amortization expense. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations.

We review our assets for impairment annually or 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. Impairment charges are recorded using discounted cash flows which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could result in future impairments. A significantly prolonged period of lower oil and natural gas prices could adversely affect the demand for and prices of our services, which could result in future impairment charges. 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.

Oil and Gas Properties

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 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. 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 Securities and Exchange Commission (“SEC”) rules. During 2011 and 2009, our proportionate share of those ventures’ full-cost ceiling test writedowns was $15.6 million and $237.1 million, respectively. No full-cost ceiling test writedowns were recorded by our unconsolidated oil and gas joint ventures during 2010.

Our wholly owned oil and gas investment portfolio and our unconsolidated ownership interest in Remora is reflected in Assets held for sale in our consolidated balance sheet at December 31, 2011. We evaluate the carrying value of our assets held for sale to the fair value of the assets less costs to sale to determine whether impairment is indicated.

A significantly prolonged period of lower oil and natural gas prices or a reduction to the estimation of reserve quantities could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges to our oil and gas properties.

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.

Goodwill

Goodwill represents the cost in excess of fair value of the net assets of companies acquired. 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 the reporting unit exceeds its fair value. All our operating segment’s fair values were substantially in excess of their carrying value with the exception of the U.S. Land Well-servicing and International segments. These operating segments had an excess of fair value over carrying value of approximately 20%. As further discussed below in Recent Accounting Pronouncements, we changed the manner in which we initially assess goodwill for impairment during 2012. Under new guidance, we will assess qualitative factors to determine whether to perform the two-step quantitative goodwill impairment tests. A significantly prolonged period of lower oil and natural gas prices 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 Note 3 — Impairments and Other Charges for discussion of goodwill impairments.

The change in the carrying amount of goodwill for our various Contract Drilling segments, Pressure Pumping segment and Other Operating segments for the years ended December 31, 2011 and 2010 was as follows:

	Balance as of December 31, 2009		Acquisitions and Purchase Price Adjustments			Impairments			Cumulative Translation Adjustment		Balance as of December 31, 2010
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—		$	—	$	30,154
U.S. Land Well-servicing		50,839		5,000	(1)		—			—		55,839
U.S. Offshore		18,003		—			(10,707	)(2)		—		7,296
Alaska		19,995		—			—			—		19,995
International		18,983		—			—			—		18,983
Subtotal Contract Drilling		137,974		5,000			(10,707	)		—		132,267
Pressure Pumping		—		334,992	(3)		—			—		334,992
Other Operating Segments		26,291		—			—			822		27,113
Total	$	164,265	$	339,992		$	(10,707	)	$	822	$	494,372

	Balance as of December 31, 2010		Acquisitions and Purchase Price Adjustments			Impairments		Cumulative Translation Adjustment			Balance as of December 31, 2011
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—	$	—		$	30,154
U.S. Land Well-servicing		55,839		(767	)(1)		—		—			55,072
U.S. Offshore		7,296		—			—		—			7,296
Alaska		19,995		—			—		—			19,995
International		18,983		—			—		—			18,983
Subtotal Contract Drilling		132,267		(767	)		—		—			131,500
Pressure Pumping		334,992		—			—		—			334,992
Other Operating Segments		27,113		8,000	(4)		—		(347	)		34,766
Total	$	494,372	$	7,233		$	—	$	(347	)	$	501,258

(1) Represents the goodwill recorded in connection with our acquisition of Energy Contractors during 2010 and an adjustment to the goodwill recorded during 2011. See Note 5 — Acquisitions for additional discussion.

(2) Represents goodwill impairment associated with our U.S. Offshore operating segment. 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. See Note 3 — Impairments and Other Charges for additional information.

(3) Represents the goodwill recorded in connection with our acquisition of Superior. See Note 5 — Acquisitions for additional discussion.

(4) Represents goodwill recorded in connection with our acquisition of the remaining 50 percent equity interest of Peak. See Note 5 — Acquisitions for additional discussion.

Our Oil and Gas segment does not have any goodwill. Goodwill for the consolidated company, totaling approximately $12.9 million, is expected to be deductible for tax purposes.

Derivative Financial Instruments

We record derivative financial instruments (including certain derivative instruments embedded in other contracts) in our consolidated balance sheets at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Any change in fair value of derivative financial instruments that are speculative in nature and do not qualify for hedge accounting treatment is also recognized immediately in earnings. Proceeds received upon termination of derivative financial instruments qualifying as fair value hedges are deferred and amortized into income over the remaining life of the hedged item using the effective interest rate method.

Litigation and Insurance Reserves

We estimate our reserves related to litigation and insurance based on the facts and circumstances specific to the litigation and insurance claims and our past experience with similar claims. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions. See Note 18 — Commitments and Contingencies regarding self-insurance accruals. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can reasonably 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. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure.

Revenue Recognition

We recognize revenues and costs on daywork contracts daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. We defer revenue related to mobilization periods and recognize the revenue over the term of the related drilling contract. Costs incurred related to a mobilization period for which a contract is secured are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. We defer recognition of revenue on amounts received from customers for prepayment of services until those services are provided.

We recognize revenue for top drives and instrumentation systems we manufacture when the earnings process is complete. This generally occurs when products have been shipped, title and risk of loss have been transferred, collectability is probable, and pricing is fixed and determinable.

In connection with the performance of our cementing services, we recognize product and service revenue when the products are delivered or services are provided to the customer and collectability is reasonably assured. Product sale prices are determined by published price lists provided to our customers.

We recognize, as operating revenue, proceeds from business interruption insurance claims in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements in excess of the carrying value of damaged assets are recognized in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements that are expected to be less than the carrying value of damaged assets are recognized at the time the loss is incurred and recorded in losses (gains) on sales and retirements of long-lived assets and other expense (income), net.

We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.

We recognize revenue on our interests in oil and gas properties as production occurs and title passes. We apply the entitlement method of accounting for natural gas revenue. Under this method, revenues are recognized based on our revenue interest of production from our properties in which sales are disproportionately allocated to owners because of marketing or other contractual arrangements. Accordingly, revenue is not recognized for deliveries in excess of our net revenue interest, while revenue is recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. Production volume is monitored to minimize these natural gas imbalances.

Share-Based Compensation

We record compensation expense for all share-based awards granted. The amount of compensation expense recognized is based on the grant-date fair value. See Note 8 — Share-Based Compensation for additional discussion.

Income Taxes

We are a Bermuda exempted company and are not subject to income taxes in Bermuda. Consequently, income taxes have been provided based on the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income taxes in these jurisdictions vary substantially. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year because our operations are conducted in different taxing jurisdictions.

We recognize increases to our tax reserves for uncertain tax positions along with interest and penalties as an increase to other long-term liabilities.

For U.S. and other jurisdictional income tax purposes, we have net operating and other loss carryforwards that we are required to assess quarterly for potential valuation allowances. We consider the sufficiency of existing temporary differences and expected future earnings levels in determining the amount, if any, of valuation allowance required against such carryforwards and against deferred tax assets.

Nabors realizes an income tax benefit associated with certain awards issued under our stock plans. We recognize the benefits related to tax deductions up to the amount of the compensation expense recorded for the award in the consolidated statements of income (loss). Any excess tax benefit (i.e., tax deduction in excess of compensation expense) is reflected as an increase in capital in excess of par. Any shortfall is recorded as a reduction to capital in excess of par to the extent of our aggregate accumulated pool of windfall benefits, beyond which the shortfall would be recognized in the consolidated statements of income (loss).

Foreign Currency Translation

For certain of our foreign subsidiaries, such as those in Canada and Argentina, the local currency is the functional currency, and therefore translation gains or losses associated with foreign-denominated monetary accounts are accumulated in a separate section of the consolidated statements of changes in equity. For our other international subsidiaries, the U.S. dollar is the functional currency, and therefore local currency transaction gains and losses, arising from remeasurement of payables and receivables denominated in local currency, are included in our consolidated statements of income (loss).

Cash Flows

We treat the redemption price, including accrued original issue discount, on our convertible debt instruments as a financing activity for purposes of reporting cash flows in our consolidated statements of cash flows.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:

• financial instruments;

• depreciation of property, plant and equipment;

• impairment of long-lived assets;

• impairment of goodwill and intangible assets;

• impairment of oil and gas properties;

• valuation of oil and gas reserves;

• income taxes;

• litigation and self-insurance reserves;

• fair value of assets acquired and liabilities assumed; and

• share-based compensation.

Recent Accounting Pronouncements

In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revised 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 Financial Accounting Standards Board (“FASB”) issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The 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 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 were effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. 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 were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we had significant oil and gas activities under the new definition. Our oil and gas disclosures for the years ended December 31, 2011 and 2010 are provided in Note 24 — Supplementary Information on Oil and Gas Exploration and Production Activities.

Effective January 1, 2010, we adopted the revised provisions relating to consolidation of variable interest entities within the Consolidations Topic of the FASB’s Accounting Standards Codification (“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 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, became applicable to us for contracts entered into after June 15, 2010. The adoption of these rules did not have a significant impact on our consolidated financial statements.

In May 2011, the FASB issued an Accounting Standards Update (“ASU”) to clarify the application of some of the existing fair value measurement and disclosure requirements. These changes are effective for interim and annual periods that begin after December 15, 2011. The disclosure requirements did not have a significant impact on our consolidated financial statements.

In June 2011, the FASB issued an ASU relating to the presentation of other comprehensive income (“OCI”). This ASU does not change the items that are reported in OCI, but does remove the option to present the components of OCI within the statement of changes in equity. In addition, this ASU will require OCI presentation on the face of the financial statements. These changes are effective for interim and annual periods that begin after December 15, 2011, and are applied retrospectively to all periods presented. Early adoption is permitted. We adopted the ASU beginning January 1, 2012 and it did not have an impact on our consolidated financial statements.

In September 2011, the FASB issued a revised ASU relating to goodwill impairment tests. An entity is allowed to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on its qualitative assessment, that it is more likely than not that the fair value is less than its carrying amount. The amendment is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. We adopted the ASU beginning January 1, 2012 and will apply it to our goodwill impairment tests.

XML

Impairments and Other Charges (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Component of impairment and other charges
Provision for termination payment	$ 100,000
Provision for retirement of long-lived assets	98,072	23,213	64,229
Impairment of long-lived assets		27,372
Goodwill impairments		10,707
Less other-than-temporary impairment recognized in accumulated other comprehensive income (loss)			(4,651)
Credit related impairment on debt securities			35,649
Impairments and other charges	198,072	61,292	118,543
Equity Securities [Member]
Component of impairment and other charges
Impairments and other charges			18,665
Debt Securities [Member]
Component of impairment and other charges
Impairments and other charges			$ 40,300

XML

Investments in Unconsolidated Affiliates (Details Textual) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investments in Unconsolidated Affiliates (Textual) [Abstract]
Investments in unconsolidated affiliates accounted for using equity method	$ 371.0	$ 265.8
Investments in unconsolidated affiliates accounted for using cost method		1.9	0.9
Assets held for sale include investments in unconsolidated affiliates accounted for using the equity method	13.7	79.5
Earnings (losses) from unconsolidated affiliates included in discontinued operations, net of tax	76.5	(10.6)	(59.2)
Cumulative undistributed (losses) earnings	404.6	(373.9)
Impairment charges for unconsolidated oil and gas joint ventures included in continuing operations	15.6		189.3
Impairment charges for unconsolidated oil and gas joint ventures included in discontinued operations			$ 47.8
Drilling and Workover Operations Located in Saudi Arabia [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment ownership percentage	51.00%
Oil and Gas Exploration Development and Production Joint Ventures in the US and Colombia [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment ownership percentage	49.70%

XML

Commitments and Contingencies (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Summary of total maximum amount of financial guarantees issued
2012	$ 105,055
2013	38
2014	0
Thereafter	0
Total	$ 105,093

XML

Cash and Cash Equivalents and Short-term Investments (Details 4) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Available-for-sale:
Proceeds from sales and maturities	$ 12,672	$ 13,062	$ 23,411
Realized gains (losses), net	$ 3,036	$ 1,692	$ (54,311)

XML

Earnings (Losses) Per Share

12 Months Ended

Dec. 31, 2011

Earnings (Losses) Per Share [Abstract]

Earnings (Losses) Per Share

Note 19    Earnings (Losses) Per Share

We include unvested restricted stock awards in the calculation of basic and diluted earnings per share using the two-class method as required by the Earnings Per Share Topic of the ASC.

A reconciliation of the numerators and denominators of the basic and diluted earnings (losses) per share computations is as follows:

	Year Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Net income (loss) (numerator):
Income (loss) from continuing operations, net of tax	$	342,164		$	255,870		$	132,721
Less: net (income) loss attributable to noncontrolling interest		(1,045	)		(85	)		342
Net income (loss) from continuing operations — basic		341,119			255,785			133,063
Add interest expense on assumed conversion of our 0.94% senior exchangeable notes, net of tax(1)		—			—			—
Adjusted net income (loss) attributable to Nabors — diluted	$	341,119		$	255,785		$	133,063
Earnings (losses) per share:
Basic from continuing operations	$	1.19		$	.90		$	.47
Diluted from continuing operations	$	1.17		$	.88		$	.46
Income from discontinued operations, net of tax	$	(97,440	)	$	(161,090	)	$	(218,609	)
Earnings (losses) per share, discontinued operations:
Basic from discontinued operations	$	(.34	)	$	(.57	)	$	(.77	)
Diluted from discontinued operations	$	(.34	)	$	(.55	)	$	(.76	)
Shares (denominator):
Weighted-average number of shares outstanding — basic(2)		287,118			285,145			283,326
Net effect of dilutive stock options, warrants and restricted stock awards based on the if-converted method		5,366			4,851			3,176
Assumed conversion of our 0.94% senior exchangeable notes(1)		—			—			—
Weighted-average number of shares outstanding — diluted		292,484			289,996			286,502

(1) At maturity in May 2011, we redeemed the remaining aggregate principal amount of $1.4 billion of our 0.94% senior exchangeable notes. Prior to maturity, we had purchased $1.4 billion par value of these notes in the open market for cash of $1.2 billion. Diluted earnings (losses) per share for the years ended December 31, 2010 and 2009 exclude any incremental shares that would have been issuable upon exchange of these notes based on a calculation using our stock price. Our stock price did not exceed the threshold during any period for the years ended December 31, 2010 and 2009.

(2) On July 31, 2009, the exchangeable shares of Nabors Exchangeco were exchanged for Nabors’ common shares on a one-for-one basis. Basic shares outstanding includes the following weighted-average number of common shares and restricted stock of Nabors and weighted-average number of exchangeable shares of Nabors Exchangeco, respectively: 287.1 million shares for the year ended December 31, 2011; 285.1 million shares for the year ended December 31, 2010; and 283.3 million shares for the year ended December 31, 2009.

For all periods presented, the computation of diluted earnings (losses) per Nabors’ share excludes outstanding stock options and warrants with exercise prices greater than the average market price of Nabors’ common shares, because their inclusion would be anti-dilutive and because they are not considered participating securities. The average number of options and warrants that were excluded from diluted earnings (losses) per share that would potentially dilute earnings per share in the future was 9,241,543, 14,004,749 and 34,113,887 shares during the years ended December 31, 2011, 2010 and 2009, respectively. In any period during which the average market price of Nabors’ common shares exceeds the exercise prices of these stock options and warrants, such stock options and warrants will be included in our diluted earnings (losses) per share computation using the if-converted method of accounting. Restricted stock will be included in our basic and diluted earnings (losses) per share computation using the two-class method of accounting in all periods because such stock is considered participating securities.

XML

Segment Information (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)	$ 1,731,979	$ 1,642,227	$ 1,352,950	$ 1,389,842	$ 1,310,242	$ 1,068,870	$ 898,169	$ 890,469	$ 6,116,998	$ 4,167,750	$ 3,506,788
Property, plant and equipment, net:
Property, plant and equipment, net	8,629,946				7,815,419				8,629,946	7,815,419	7,646,050
Goodwill:
Goodwill	501,258				494,372				501,258	494,372	164,265
U.S. [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									4,329,079	2,612,954	1,817,374
Property, plant and equipment, net:
Property, plant and equipment, net	4,974,239				4,447,388				4,974,239	4,447,388	4,107,250
Goodwill:
Goodwill	466,794				459,560				466,794	459,560	130,275
Outside the U.S. [Member]
Operating revenues and earnings losses from unconsolidated affiliates from continuing operations
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations (1)									1,787,919	1,554,796	1,689,414
Property, plant and equipment, net:
Property, plant and equipment, net	3,655,707				3,368,031				3,655,707	3,368,031	3,538,800
Goodwill:
Goodwill	$ 34,464				$ 34,812				$ 34,464	$ 34,812	$ 33,990

XML

Valuation and Qualifying Accounts (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Allowance for Doubtful Accounts [Member]
VALUATION AND QUALIFYING ACCOUNTS
Balance at Beginning of period	$ 22,507	$ 23,681	$ 23,224
Charged to Costs and Expenses	5,352	1,545	5,793
Charged to Other Accounts	(29)	167	239
Deductions	13,873	(2,886)	(5,575)
Balance at End of Period	41,703	22,507	23,681
Inventory Reserve [Member]
VALUATION AND QUALIFYING ACCOUNTS
Balance at Beginning of period	6,784	4,824	4,483
Charged to Costs and Expenses	(1,185)	(182)	1,429
Charged to Other Accounts	1,889	1,695
Deductions	(504)	447	(1,088)
Balance at End of Period	6,894	6,784	4,824
Valuation Allowance on Deferred Tax Assets [Member]
VALUATION AND QUALIFYING ACCOUNTS
Balance at Beginning of period	1,514,153	1,570,890	132,262
Charged to Costs and Expenses			1,438,628
Deductions	(28,613)	(56,737)
Balance at End of Period	$ 1,485,540	$ 1,514,153	$ 1,570,890

XML

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details 3)	12 Months Ended
	Dec. 31, 2011 Bcf	Dec. 31, 2010 Bcf	Dec. 31, 2009 Bcf
Net proved reserves
Purchases in place	20.8
Natural Gas Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			509.0
Net proved reserves, Ending balance	607.6	583.3	509.0
Natural Gas Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance	25.3	34.6
Revisions	(3.0)	(8.1)
Extensions, additions and discoveries	4.0	5.0
Production	(5.1)	(6.2)
Purchases in place	3.9
Net proved reserves, Ending balance	25.1	25.3
Proved Developed Reserves	21.9	22.6	23.4
Proved Undeveloped Reserve	3.3	2.7	11.2
Natural Gas Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance	558.0	474.4
Revisions	(359.0)	(119.9)
Extensions, additions and discoveries	103.1	108.5
Production	(19.0)	(13.8)
Purchases in place	304.2	109.8
Sales in place	(4.8)	(1.0)
Net proved reserves, Ending balance	582.5	558.0
Proved Developed Reserves	256.4	152.3	114.1
Proved Undeveloped Reserve	326.1	405.7	360.3
Natural Gas Liquids Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			7.1
Net proved reserves, Ending balance	17.7	33.0	7.1
Natural Gas Liquids Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance	23.2	1.3
Revisions	0.1	(0.6)
Extensions, additions and discoveries	1.6	2.0
Production	(0.3)	(0.3)
Purchases in place	0.0	20.8
Sales in place	(22.8)
Net proved reserves, Ending balance	1.8	23.2
Proved Developed Reserves	0.9	4.3	0.8
Proved Undeveloped Reserve	0.9	18.9	0.5
Natural Gas Liquids Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance	9.8	5.8
Revisions	(4.2)	2.0
Extensions, additions and discoveries	3.2	1.9
Production	(0.7)	(0.5)
Purchases in place	9.4	0.8
Sales in place	(2.0)	(0.2)
Net proved reserves, Ending balance	15.9	9.8
Proved Developed Reserves	6.3	3.5	2.3
Proved Undeveloped Reserve	9.6	6.3	3.5
U.S. [Member] | Natural Gas Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			496.5
Net proved reserves, Ending balance	599.4	572.6	496.5
U.S. [Member] | Natural Gas Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance	19.8	29.6
Revisions	(3.9)	(11.7)
Extensions, additions and discoveries	4.0	5.0
Production	(3.0)	(3.1)
Net proved reserves, Ending balance	16.9	19.8
Proved Developed Reserves	13.6	17.1	18.4
Proved Undeveloped Reserve	3.3	2.7	11.2
U.S. [Member] | Natural Gas Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance	552.8	466.9
Revisions	(359.0)	(119.1)
Extensions, additions and discoveries	103.1	108.5
Production	(18.6)	(12.3)
Purchases in place	304.2	109.8
Sales in place	0.0	(1.0)
Net proved reserves, Ending balance	582.5	552.8
Proved Developed Reserves	256.4	147.1	106.6
Proved Undeveloped Reserve	326.1	405.7	360.3
U.S. [Member] | Natural Gas Liquids Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			5.6
Net proved reserves, Ending balance	17.7	29.1	5.6
U.S. [Member] | Natural Gas Liquids Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance	21.2	0.4
Revisions	0.1	0.1
Extensions, additions and discoveries	1.6
Production	(0.2)	(0.1)
Purchases in place	0.0	20.8
Sales in place	(20.9)
Net proved reserves, Ending balance	1.8	21.2
Proved Developed Reserves	0.9	2.7	0.2
Proved Undeveloped Reserve	0.9	18.5	0.2
U.S. [Member] | Natural Gas Liquids Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance	7.9	5.2
Revisions	(4.2)	1.5
Extensions, additions and discoveries	3.2	0.6
Production	(0.4)	(0.2)
Purchases in place	9.4	0.8
Net proved reserves, Ending balance	15.9	7.9
Proved Developed Reserves	6.3	3.0	1.8
Proved Undeveloped Reserve	9.6	4.9	3.4
Canada [Member] | Natural Gas Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			12.5
Net proved reserves, Ending balance	8.2	10.7	12.5
Canada [Member] | Natural Gas Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance	5.5	5.0
Revisions	0.9	3.6
Production	(2.1)	(3.1)
Purchases in place	3.9
Net proved reserves, Ending balance	8.2	5.5
Proved Developed Reserves	8.2	5.5	5.0
Proved Undeveloped Reserve	0.0	0.0	0.0
Canada [Member] | Natural Gas Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance	5.2	7.5
Revisions	0.0	(0.8)
Production	0.4	(1.5)
Sales in place	(4.8)
Net proved reserves, Ending balance	0.0	5.2
Proved Developed Reserves	0.0	5.2	7.5
Proved Undeveloped Reserve	0.0	0.0	0.0
Canada [Member] | Natural Gas Liquids Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			0.0
Net proved reserves, Ending balance	0.0	0.0	0.0
Canada [Member] | Natural Gas Liquids Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance			0.0
Net proved reserves, Ending balance	0.0	0.0	0.0
Proved Developed Reserves	0.0	0.0	0.0
Proved Undeveloped Reserve	0.0	0.0	0.0
Canada [Member] | Natural Gas Liquids Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance			0.0
Net proved reserves, Ending balance	0.0	0.0	0.0
Proved Developed Reserves	0.0	0.0	0.0
Proved Undeveloped Reserve	0.0	0.0	0.0
Colombia [Member] | Natural Gas Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			0.0
Net proved reserves, Ending balance	0.0	0.0	0.0
Colombia [Member] | Natural Gas Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance			0.0
Net proved reserves, Ending balance	0.0	0.0	0.0
Proved Developed Reserves	0.0	0.0	0.0
Proved Undeveloped Reserve	0.0	0.0	0.0
Colombia [Member] | Natural Gas Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance			0.0
Net proved reserves, Ending balance		0.0	0.0
Proved Developed Reserves	0.0	0.0	0.0
Proved Undeveloped Reserve	0.0	0.0	0.0
Colombia [Member] | Natural Gas Liquids Reserves [Member]
Net proved reserves
Net proved reserves, Beginning balance			1.5
Net proved reserves, Ending balance	0.0	3.9	1.5
Colombia [Member] | Natural Gas Liquids Reserves [Member] | Consolidated Subsidiary [Member]
Net proved reserves
Net proved reserves, Beginning balance	2.0	0.9
Revisions	0.0	(0.7)
Extensions, additions and discoveries	0.0	2.0
Production	(0.1)	(0.2)
Sales in place	(1.9)
Net proved reserves, Ending balance	0.0	2.0
Proved Developed Reserves	0.0	1.6	0.6
Proved Undeveloped Reserve	0.0	0.4	0.3
Colombia [Member] | Natural Gas Liquids Reserves [Member] | Equity Companies [Member]
Net proved reserves
Net proved reserves, Beginning balance	1.9	0.6
Revisions	0.0	0.5
Extensions, additions and discoveries	0.0	1.3
Production	0.3	(0.3)
Sales in place	(1.6)	(0.2)
Net proved reserves, Ending balance	0.0	1.9
Proved Developed Reserves	0.0	0.5	0.5
Proved Undeveloped Reserve	0.0	1.4	0.1

XML

Share Based Compensation (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Y	Dec. 31, 2010	Dec. 31, 2009
Share-Based Compensation [Abstract]
Options outstanding, Beginning Balance, Shares	28,932,000
Options outstanding, Beginning Balance, Weighted Average Exercise Price	$ 18.73
Granted, Shares	931,000	32,115	10,015,883
Granted, Weighted Average Exercise Price	$ 15.67
Vested options exercised by employees , shares	(1,116,000)	700,000	1,500,000
Exercised, Weighted-Average Exercise Price	$ 12.50
Surrendered, Shares	(418,000)
Surrendered, Weighted Average Exercise Price	$ 13.53
Forfeited, Shares	(459,000)
Forfeited, Weighted Average Exercise Price	$ 20.74
Options outstanding, Ending Balance, Shares	27,870,000	28,932,000
Options outstanding, Ending Balance, Weighted Average Exercise Price	$ 18.94	$ 18.73
Options outstanding, Ending Balance, Weighted Average Remaining Contractual Term	3.65
Options outstanding, Ending Balance, Aggregate Intrinsic Value	$ 83,306
Options exercisable, Ending Balance, Shares	24,939,000	24,900,000	27,200,000
Options exercisable, Ending Balance, Weighted Average Exercise Price	$ 19.83	$ 20.19	$ 21.04
Options exercisable, Ending Balance, Weighted Average Remaining Contractual Term	3.14
Options exercisable, Ending Balance, Aggregate Intrinsic Value	$ 65,949

XML

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2011

Acquisitions [Abstract]

Preliminary Estimates for Allocation of Purchase Price as of Acquisition Date

	Estimated Fair Value
	(In thousands)
Assets:
Cash and cash equivalents	$	1,045
Accounts receivable		143,842
Inventory		33,963
Other current assets		7,612
Property, plant and equipment		415,000
Intangible assets		131,811
Goodwill		334,992
Other long-term assets		14,726
Total assets		1,082,991
Liabilities:
Current liabilities	$	78,277
Deferred income taxes		119,201
Long-term debt		124,792
Other long-term liabilities		10,258
Total liabilities		332,528
Preferred stock		69,188
Net assets acquired	$	681,275

Intangible assets

	Estimated Fair Value		Monthly Amortization		Estimated Useful Life
	(In thousands)
Superior trade name	$	88,767	$	740		10 years
Technology		5,294		88		5 years
Employment contracts and non-compete agreements		675		33		1-3 years
Customer relationships		37,075		308		10 years
Total identifiable intangible assets	$	131,811	$	1,169

XML

Debt

12 Months Ended

Dec. 31, 2011

Debt [Abstract]

Debt

Note 12    Debt

Long-term debt consisted of the following:

	December 31, 2011		December 31, 2010
	(In thousands)
5.375% senior notes due August 2012	$	274,604	$	273,977
6.15% senior notes due February 2018		967,490		966,276
9.25% senior notes due January 2019		1,125,000		1,125,000
5.00% senior notes due September 2020		697,343		697,037
4.625% senior notes due September 2021		697,667		—
0.94% senior exchangeable notes due May 2011		—		1,378,178
Revolving credit facilities		860,000		—
Other		1,712		2,676
		4,623,816		4,443,144
Less: current portion		275,326		1,379,018
	$	4,348,490	$	3,064,126

As of December 31, 2011, the maturities of our primary debt for each of the five years after 2011 and thereafter are as follows:

	Paid at Maturity
	(In thousands)
2012	$	275,000	(1)
2013		—
2014		860,000	(2)
2015		—
2016		—
Thereafter		3,500,000	(3)
	$	4,635,000

(1) Represents our 5.375% senior notes due August 2012.

(2) Represents amounts drawn on revolving credit facilities, which expire September 2014.

(3) Represents our 6.15% senior notes due February 2018, 9.25% senior notes due January 2019, 5.0% senior notes due September 2020 and 4.625% senior notes due September 2021.

5.375% Senior Notes Due August 2012

At December 31, 2011, the current portion of our long-term debt included Nabors Delaware’s 5.375% senior notes of $274.6 million.

On August 22, 2002, Nabors Delaware issued $275 million aggregate principal amount of 5.375% senior notes due 2012, which are fully and unconditionally guaranteed by us. The notes were resold by a placement agent to qualified institutional buyers under Rule 144A of the Securities Act of 1933. Interest on the notes is payable semi-annually on February 15 and August 15 of each year.

The notes are unsecured and are effectively junior in right of payment to any of Nabors Delaware’s future secured debt. The notes rank equal in right of payment with any of Nabors Delaware’s future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s subordinated debt. The guarantee of Nabors with respect to the notes issued by Nabors Delaware, is similarly unsecured and has a similar ranking to the series of notes so guaranteed.

Subject to certain qualifications and limitations, the indentures governing the notes issued by Nabors Delaware limit the ability of Nabors and its subsidiaries to incur liens and to enter into sale and lease-back transactions. In addition, the indentures limit our ability to enter into mergers, consolidations or transfers of all or substantially all of our assets unless the successor company assumes their obligations under the applicable indenture.

6.15% Senior Notes Due February 2018

On February 20, 2008, Nabors Delaware completed a private placement of $575 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. On July 22, 2008, Nabors Delaware completed an additional private placement under the same indenture of $400 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. These new notes are subject to the same rates, terms and conditions and together will be treated as a single class of debt securities under the indenture (together $975 million 6.15% senior notes due 2018). The issue of notes was resold by the initial purchasers to qualified institutional buyers under Rule 144A of the Securities Act and to certain investors outside of the United States under Regulation S of the Securities Act. The notes bear interest at a rate of 6.15% per year, payable semi-annually on February 15 and August 15 and will mature on February 15, 2018.

The notes are unsecured and are effectively junior in right of payment to any of Nabors Delaware’s future secured debt. The senior notes rank equally with any of Nabors Delaware’s other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s future senior subordinated debt. Our guarantee of the senior notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The notes are subject to redemption by Nabors Delaware, in whole or in part, at any time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes then outstanding to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest, determined in the manner set forth in the indenture. In the event of a change in control triggering event, as defined in the indenture, the holders of notes may require Nabors Delaware to purchase all or any part of each note in cash equal to 101% of the principal amount plus accrued and unpaid interest, if any, to the date of purchase, except to the extent Nabors Delaware has exercised its right to redeem the notes.

9.25% Senior Notes Due January 2019

On January 12, 2009, Nabors Delaware completed a private placement of $1.125 billion aggregate principal amount of 9.25% senior notes due 2019 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The notes bear interest at a rate of 9.25% per year, payable semi-annually on January 15 and July 15 and will mature on January 15, 2019.

The notes are unsecured and are junior in right of payment to any of Nabors Delaware’s future secured debt. The notes rank equally with any of Nabors Delaware’s other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s future senior subordinated debt. Our guarantee of the notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The notes are subject to redemption by Nabors Delaware, in whole or in part, at any time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes then outstanding to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest, determined in the manner set forth in the applicable indenture. In the event of a change in control triggering event, as defined in the indenture, the holders of notes may require Nabors Delaware to purchase all or any part of each note in cash equal to 101% of the principal amount plus accrued and unpaid interest, if any, to the date of purchase, except to the extent Nabors Delaware has exercised its right to redeem the notes.

5.0% Senior Notes Due September 2020

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 fully and unconditionally guaranteed by us. The notes are subject to registration rights. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The notes pay interest semi-annually on March 15 and September 15, beginning on March 15, 2011 and will mature on September 15, 2020.

The notes rank equal in right of payment to all of Nabors Delaware’s existing and future unsubordinated indebtedness, and senior in right of payment to all of Nabors Delaware’s existing and future senior subordinated and subordinated indebtedness. Our guarantee of the notes is unsecured and an unsubordinated obligation and ranks equal in right of payments to all of our unsecured and unsubordinated indebtedness from time to time outstanding. In the event of a change of control triggering event, as defined in the indenture, the holders of the notes may require Nabors Delaware to purchase all or a portion of the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture. Nabors Delaware used a portion of the proceeds to repay the borrowing under a revolving credit facility incurred to fund the Superior Merger.

Prior to the issuance of the notes during September 2010, we entered into a Treasury rate lock with a total notional amount of $500 million to hedge the risk of changes in semiannual interest payments. We designated the Treasury rate lock derivative as a cash flow hedge and upon settlement paid $5.7 million, due to the change in the fair value of the derivative. The loss was recognized as a component of accumulated other comprehensive income in our consolidated statement of changes in equity and is being amortized as additional interest expense over the life of the notes. There was no ineffectiveness associated with this hedge during the year ended December 31, 2010.

4.625% Senior Notes Due September 2021

On August 23, 2011, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 4.625% senior notes due 2021, which are unsecured and fully and unconditionally guaranteed by us. The notes have registration rights. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The notes pay interest semi-annually on March 15 and September 15, beginning on March 15, 2012 and will mature on September 15, 2021.

The notes rank equal in right of payment to all of Nabors Delaware’s existing and future unsubordinated indebtedness, and senior in right of payment to all of Nabors Delaware’s existing and future senior subordinated and subordinated indebtedness. Our guarantee of the notes is unsecured and an unsubordinated obligation and ranks equal in right of payments to all of our unsecured and unsubordinated indebtedness from time to time outstanding. In the event of a change of control triggering event, as defined in the indenture, the holders of the notes may require Nabors Delaware to purchase all or a portion of the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture. Nabors Delaware used a portion of the proceeds to pay back borrowings on our revolving credit facilities and for other general corporate purposes.

On November 21, 2011, we and Nabors Delaware filed a registration statement on Form S-4 under the Securities Act. The registration statement related to the exchange offer to noteholders required under the registration rights agreement related to the 4.625% senior notes. On December 19, 2011, the registration statement was declared effective by the SEC. On January 17, 2012, we and Nabors Delaware filed a prospectus and commenced the exchange offer. The exchange offer expired on February 13, 2012 and the exchange closed on February 15, 2012.

Senior Exchangeable Notes

On May 16, 2011, the remaining aggregate principal amount of $1.4 billion of our 0.94% senior exchangeable notes matured and we redeemed them with $1.2 billion of borrowings under our revolving credit facilities and available cash. During 2011, 2010 and 2009, we recognized pre-tax gains (losses) of $(.1) million, $(7.0) million and $11.5 million, respectively, all of which 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) for the respective year.

Revolving Credit Facilities

As of December 31, 2011, we had $540 million of remaining availability from a combined total of $1.4 billion under our existing revolving credit facilities. The existing revolving credit facilities mature in September 2014, and can be used for general corporate purposes, including capital expenditures and working capital. The weighted average interest rate on borrowings at December 31, 2011 was 1.8%. We fully and unconditionally guarantee the obligations under all of these credit facilities.

Nabors Delaware has two senior unsecured revolving credit facilities, which total $1.35 billion, and, as of December 31, 2011, $810 million had been utilized. A third unsecured revolving credit facility for $50 million exists with one of our other subsidiaries and, as of December 31, 2011, had been fully utilized. We have the option to increase the aggregate principal amount of commitments by an additional $200 million by either adding new lenders to these facilities or by requesting existing lenders under the facilities to increase their commitments (in each case with the consent of the new lenders or the increasing lenders).

Borrowings under the senior unsecured revolving credit facilities bear interest, at Nabors Delaware’s option, for 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 LIBOR for the corresponding deposits of U.S. dollars, plus the applicable interest margin. 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 the administrative agent, as established from time to time and (iii) LIBOR for an interest period of one month beginning on such day plus 1%.

The revolving credit facilities contain various covenants and restrictive provisions that limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain a net funded indebtedness to total capitalization ratio, as defined in each agreement. We were in compliance with all covenants under the agreement at December 31, 2011. If we should fail to perform our obligations under the covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable.

Other Debt Transactions

In January and February 2009, Nabors Holdings 1, ULC, one of our wholly owned subsidiaries (“Nabors Holdings”), repurchased $56.6 million par value of the $225 million principal amount of its 4.875% senior notes due August 2009 in the open market for cash totaling $56.8 million. In August 2009, Nabors Holdings paid $168.4 million to redeem the remaining notes. The redemption resulted in no gain or loss as the notes were redeemed at a price equal to their carrying value.

Short-Term Borrowings

We had six letter-of-credit facilities with various banks as of December 31, 2011. Availability and borrowings under our letter-of-credit facilities are as follows:

	December 31,
	2011			2010
	(In thousands)
Credit available	$	215,901		$	270,263
Letters of credit outstanding, inclusive of financial and performance guarantees		(80,408	)		(70,605	)
Remaining availability	$	135,493		$	199,658

XML

Pension, Postretirement And Postemployment Benefits (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Postretirement and Postemployment Benefits (Textual) [Abstract]
Contribution to defined contribution plans	$ 22,900,000	$ 13,600,000
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss included in accumulated other comprehensive income (loss)	(12,100,000)	(6,700,000)	(6,300,000)
Prior service costs relating to pension costs included in accumulated other comprehensive income (loss)	0	0	0
Transition obligation related to pension cost included in accumulated other comprehensive income (loss)	0	0	0
Amount expected to recognize as a components of net periodic benefit costs	1,000,000
Equity securities investment target allocation percentage	55.00%
Debt securities investment target allocation percentage	45.00%
Contribution to defined benefit pool pension plan	1,312,000	439,000
Expected Contribution to defined benefit pool pension plan in 2011	1,500,000
Defined benefit plan terminated, obligation	(10,307,000)	(5,409,000)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan terminated, obligation	$ 200,000	$ 200,000