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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)    

ý

 

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

For the fiscal year ended December 31, 2013

o

 

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

For the transition period from                        to                       

Commission File Number 001-32657

NABORS INDUSTRIES LTD.
(Exact name of registrant as specified in its charter)


Bermuda
Crown House Second Floor
4 Par-la-Ville Road
Hamilton, HM08

Bermuda
(State or Other Jurisdiction of
Incorporation or Organization)
(Address of principal executive offices)

 

980363970
(I.R.S. Employer Identification No.)
N/A
(Zip Code)

(441) 292-1510
(Registrant's telephone number, including area code)

          Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class   Name of each exchange on which registered
Common shares, $.001 par value per share   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 ý    NO o

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

YES o    NO ý

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 ý    NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to file such reports).

YES ý    NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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 ý   Accelerated Filer o   Non-accelerated Filer o   Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES o    NO ý

The aggregate market value of the 253,104,759 common shares held by non-affiliates of the registrant outstanding as of the last business day of our most recently completed second fiscal quarter, June 28, 2013, based on the closing price of our common shares as of such date of $15.31 per share as reported on the New York Stock Exchange, was $3,875,033,860. 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 outstanding as of February 24, 2014 was 296,508,410.

DOCUMENTS INCORPORATED BY REFERENCE (to the extent indicated herein)

Specified portions of the definitive Proxy
Statement to be distributed in connection with our 2014 Annual General Meeting of Shareholders (Part III).

   


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NABORS INDUSTRIES LTD.
Form 10-K Annual Report
For the Year Ended December 31, 2013

Table of Contents

 

PART I

   

Item 1.

 

Business

  4

Item 1A.

 

Risk Factors

  12

Item 1B.

 

Unresolved Staff Comments

  17

Item 2.

 

Properties

  17

Item 3.

 

Legal Proceedings

  20

Item 4.

 

Mine Safety Disclosures

  22

 

PART II

 
 

Item 5.

 

Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

  23

Item 6.

 

Selected Financial Data

  26

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

  28

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  53

Item 8.

 

Financial Statements and Supplementary Data

  55

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

  153

Item 9A.

 

Controls and Procedures

  153

Item 9B.

 

Other Information

  154

 

PART III

 
 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  154

Item 11.

 

Executive Compensation

  154

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

  154

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

  156

Item 14.

 

Principal Accounting Fees and Services

  157

 

PART IV

 
 

Item 15.

 

Exhibits, Financial Statement Schedules

  157

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        Our internet address is www.nabors.com. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the "SEC"). In addition, a glossary of drilling terms used in this document and documents relating to our corporate governance (such as committee charters, governance guidelines and other internal policies) can be found on our website. In addition, the public may read and copy any material that we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE., Washington, DC 20549 and may obtain information the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reference in this document to our website address does not constitute incorporation by reference of the information contained on the website into this Annual Report on Form 10-K. 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, quarterly and current 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 oil and natural gas;

    fluctuations in levels of oil and natural gas 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 oil or natural gas 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 not all-inclusive, but highlights certain factors that we believe are important for your consideration. 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"), our wholly owned subsidiary.

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PART I

ITEM 1.    BUSINESS

Introduction

        Nabors has grown from a land drilling business centered in the United States and Canada to a global business aimed at optimizing the entire well life cycle, with operations on land and offshore in most of the major oil and gas markets in the world. The majority of our business is conducted through two business lines:

    Drilling & Rig Services

    This business line is comprised of our global drilling rig operations and drilling-related services, consisting of equipment manufacturing, instrumentation optimization software and directional drilling services.

    Completion & Production Services

        This business line is comprised of our operations involved in the completion, life-of-well maintenance and eventual plugging and abandonment of a well. These services include stimulation, coiled-tubing, cementing, wireline, workover, well-servicing and fluids management.

As a global provider of services for land-based and offshore oil and natural gas wells, on land and offshore, Nabors' fleet of rigs and equipment includes:

    485 actively marketed land drilling rigs for oil and gas land drilling operations in the United States, Canada and over 20 other countries throughout the world.

    445 actively marketed rigs for land well-servicing and workover services in the United States and approximately 104 rigs for land well-servicing and workover services in Canada.

    38 platform, 8 jackup and 4 barge rigs actively marketed in the United States and multiple international markets.

    Approximately 800,000 hydraulic horsepower for hydraulic fracturing, cementing, nitrogen and acid pressure pumping services in key basins throughout the United States and Canada.

In addition:

    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 5 rigs in addition to the rigs we lease to the joint venture.

        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.

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Our Rig Fleet

Land Rigs.  A land-based drilling rig generally consists of engines, a drawworks, a mast (or derrick), pumps to circulate drilling fluid 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 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 workover services rather than larger drilling rigs typically used for initial drilling.

    Land-based drilling rigs are moved between well sites and among geographic areas 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. Our shallow workover jackup rigs are typically limited to a maximum water depth of approximately 125 feet, and some may drill in water depths as shallow as 13 feet. We also have deeper water jackup rigs 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. 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.

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Additional information regarding the geographic markets in which we operate and our business segments can be found in Note 23—Segment Information in Part II, Item 8.—Financial Statements and Supplementary Data.

Types of Drilling Contracts

        Our contracts for land-based drilling generally have terms with durations ranging from one to five years. Under these contracts, our rigs are committed to one customer. Offshore workover projects are often contracted on a single-well basis. We generally receive drilling contracts through competitive bidding, although we occasionally enter into contracts by direct negotiation. Most of our single-well contracts are subject to termination by the customer on short notice, but some can be firm for a number of wells or a period of time, and may provide for early termination compensation in certain circumstances. Contract terms and rates differ depending on a variety of factors, including competitive conditions, the geographical area, the geological formation to be drilled, the equipment and services to be supplied, the on-site drilling conditions and the anticipated duration of the work to be performed.

        Our drilling contracts are typically 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).

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

        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.

Production 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 wells characteristically require more maintenance than flowing wells because 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

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    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, pumps and tanks for drilling fluids, blowout preventers and 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.

Production and Other Specialized Services.  We also 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 where 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.

Other Services

        Through various subsidiaries, we manufacture top drives and catwalks, which are installed on both onshore and offshore drilling rigs. We provide heavy equipment to move drilling rigs, water, other fluids and construction materials as well as the means to move such equipment. We offer specialized drilling technologies, including patented steering systems and rig instrumentation software systems including:

    ROCKITTM directional drilling system, which is used to provide data collection services to oil and gas exploration and service companies, and

    RIGWATCHTM software, which is computerized software and equipment that monitors a rig's real-time performance and daily reporting for drilling operations, making this data available through the internet.

Our Customers

        Our customers include major, national and independent oil and gas companies. No customer accounted for more than 10% of our consolidated revenues in 2013 or 2012.

Our Employees

        As of December 31, 2013, we employed approximately 29,000 people, of whom approximately 3,150 were employed by unconsolidated affiliates. We believe our relationship with our employees is generally good.

        Some rig employees in Alaska, 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

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affected by seasonal weather conditions, primarily in the spring, as many municipalities impose weight restrictions on the paved roads leading 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, but seasonality does not materially impact the remaining portions of our business.

Research and Development

        Research and development continues to be 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 oil and natural gas 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 an area. 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.

        In all of our geographic markets the ability to deliver rigs with new technology and features is the most significant factor in determining which drilling contractor is awarded a job. In recent years, rigs equipped with moving systems and configured to accommodate the drilling of multiple wells on a single site have offered a competitive advantage. In international markets, experience in operating in certain environments, as well as customer alliances, have been significant factors in the selection of Nabors. Other factors include the overall quality of service and safety record, price and the availability and condition of equipment; and the availability of trained personnel possessing specialized skills; and the ability to offer ancillary services.

        Certain competitors are present in more than one of our operating regions, although no one competitor operates in all of these areas. In the United 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. Production Services operating segment, we compete with Basic Energy Services, Inc., Key Energy Services, Inc., Superior Energy Services, Inc., Forbes Energy Services Ltd. and numerous other competitors having smaller regional or local rig operations. In Canada and the United States, 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 Completion Services operating segment competes with large operators such as Halliburton, Baker Hughes, Weatherford International Ltd., Schlumberger Limited, and FTS International Services LLC. as well as, smaller companies such as C&J Energy Services, Inc., RPC, Inc., and other 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

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land drilling, well-servicing and workover and pressure pumping contracts will continue to be competitive.

        Our other operating segments represent a relatively smaller part of our business, and we have numerous competitors in each area.

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. During 2012 and 2013, we continued to strengthen our balance sheet, which enhanced stability, reduced our borrowing costs and allowed us to better navigate challenges and capitalize on market opportunities. The principal elements of our strategy to build shareholder value during 2013 were to:

    Leverage our global infrastructure to enhance revenue and profitability growth;

    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.

        We operate from two business lines to provide a solid foundation for sustained long-term growth, leveraging the benefits of our size and becoming a more customer-focused organization. We believe the deployment of our newer and higher-margin rigs under long-term contracts will also enhance our competitive position.

        Our current focus is to continue improving flexibility in our balance sheet, optimize capital deployment and continue to incorporate value enhancing technology and innovation. In addition, we continue to:

    Emphasize execution and operational excellence in our core businesses;

    Impose more stringent investment criteria for new projects;

    Optimize intra-company synergies and technological advancements; and

    Monetize 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 most 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 490 land drilling rigs, 549 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.

        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.

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Acquisitions

        In September 2010, we acquired 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. The acquisition added a number of services to our portfolio, including a wide range of wellsite solutions to oil and natural gas companies, primarily technical pumping services and down-hole surveying services. During 2012, we ceased using the Superior trade name.

        In December 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 Production Services 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 July 2011, we paid $65 million in cash to acquire the remaining 50% equity interest of Peak Oilfield Service Company, making it a wholly owned subsidiary. Previously, we held a 50% 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 was reflected in losses (gains) on sales and disposals of long-lived assets and other expense (income) for 2011. The excess of the purchase price over the fair value was $8.0 million and was recorded as goodwill. In October 2013, we sold Peak (as described below).

        In January 2013, we purchased the business of Navigate Energy Services, Inc. ("NES") for a total cash price of approximately $37.5 million. This acquisition expands our technology and development capability for drilling and measurement tools and services, and is included in our Rig Services operating segment. The purchase price was allocated to the net tangible and intangible assets acquired based on fair value. The excess of the purchase price over the fair values of the assets acquired was recorded as goodwill in the amount of $15.8 million.

        In October 2013, we purchased KVS Transportation, Inc. and D&D Equipment Investments, LLC, (collectively, "KVS") for total consideration of $149.0 million, $66.8 million of which is payable in three equal annual installments through 2016. KVS provided various logistics and support services operating in the oilfield and well-servicing industry. Services are provided by tractor trucks, bobtail trucks, winch trucks, other truck types, trailers, container bins, eyewash stations, various types of tanks, shop equipment and other related support equipment. This acquisition expands our truck fleet, vacuum truck services, and tank and related equipment services, and is included in our Production Services operating segment.

Divestitures

        In 2011, we sold some of our wholly owned oil and gas assets in Colombia and our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. Additionally in 2011, Remora Energy International LP ("Remora"), a former unconsolidated oil and gas joint venture of ours, completed sales of its oil and gas assets in Colombia. During 2011, we received gross cash proceeds of $303.8 million from sales of oil and gas assets.

        In 2012, we sold our remaining wholly owned oil and gas business in Colombia and sold additional wholly owned oil and gas assets in the United States. In December 2012, we sold our 49.7% ownership interest in NFR Energy LLC, the U.S. unconsolidated oil and gas joint venture, to the remaining equity

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owners. Subsequent to this transaction, NFR Energy LLC changed its name to Sabine Oil & Gas LLC ("Sabine"). During 2012, we received cumulative gross cash proceeds of $254.5 million from sales of oil and gas assets.

        In 2013, we sold the assets of one of our former Canadian subsidiaries that provided logistics services for proceeds of $9.3 million. In addition, we sold Peak, one of our businesses in Alaska, for gross cash proceeds of $135.5 million. The accompanying consolidated statements of income (loss) and notes to the consolidated financial statements have been updated to retroactively reclassify the operating results of these divested assets as discontinued operations for all periods presented. We also sold some of our oil and gas assets and received proceeds of approximately $90.0 million, which were reclassified to discontinued operations in the prior year.

        See Note 5—Assets Held for Sale and Discontinued Operations for additional discussion in Part II, Item 8.—Financial Statements and Supplementary Data.

Environmental Compliance

        We do not anticipate that compliance with currently applicable environmental regulations and controls will significantly change our competitive position, capital spending or earnings during 2014. 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 our results of operations.

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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 we face. 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. Lower oil and natural gas prices have caused some of our customers to terminate, seek to 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.

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. In recent years the ability to deliver rigs with new technology and features can determine which drilling contractor is awarded a job, which requires continued technology advancement. The land drilling market generally is more competitive than the offshore drilling market because there are a greater number 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

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offshore operations involve the additional 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 facing 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, terrorist activity or other 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 war, civil disturbances, terrorist activity and governmental actions 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.

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

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

Our financial and operating flexibility could be affected by our long-term debt and other financial commitments

        As of December 31, 2013, we had approximately $3.9 billion in outstanding long-term debt. We also have various commitments for leases, firm transportation and processing, and purchase commitments. Our ability to service our debt and other obligations depends in large part upon the level of cash flows generated by our subsidiaries' operations, possible dispositions of non-core assets, availability under our unsecured revolving credit facility and our ability to access the capital markets.

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A downgrade in our credit rating could negatively impact our cost of and ability to access capital

        Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by the major credit rating agencies in the United States and our historical ability to access those markets as needed. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, and commodity pricing levels and others are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.

The loss of key executives or difficulty attracting and retaining experienced technical personnel could reduce our competitiveness and prospects for future success

        The successful execution of the strategies central to our future success will depend, in part, on a few of our key executive officers. We have employment agreements with some of our key personnel within the company. We do not carry significant amounts of key man insurance. Our operations depend, in part, on our ability to attract and retain experienced technical professionals. Competition for such professionals is intense. The loss of key executive officers, or our inability to retain or attract experienced technical personnel, could harm our ability to compete.

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

        Drilling of oil and gas wells is subject to various laws, rules and regulations in the jurisdictions where we operate. Our cost of compliance with these laws may be substantial. For example, the U.S. Environmental Protection Agency ("EPA") has promulgated rules requiring the reporting of greenhouse gas emissions applicable to certain offshore oil and natural gas production and onshore oil and natural gas production, processing, transmission, storage and distribution facilities. In addition, U.S. federal law strictly regulates the prevention of oil spills, release of hazardous substances, and imposes liability for removal costs and natural resource, real or personal property and certain economic damages arising from any spills. Some of these laws may impose strict and/or joint and several liability for clean-up costs and damages without regard to the conduct of the parties. As an owner and operator of onshore and offshore rigs and other equipment, we may be deemed to be a responsible party under federal law. In addition, our completion 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. We are subject to various laws governing 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.

        Changes in environmental laws 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 and costly handling, disposal and clean-up requirements. 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. 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

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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, which could result in increased costs of operations in covered jurisdictions. In addition, the EPA has published findings that emissions of greenhouse gases present an endangerment to public health and the environment, paving the way for further regulations that could restrict emissions of greenhouse gases under existing provisions of the Clean Air Act. The EPA has already issued rules requiring monitoring and reporting of greenhouse gas emissions from oil and gas systems. Future or more stringent regulation could dramatically increase operating costs for oil and natural gas companies and could reduce the market for our services by making wells and/or oilfields uneconomical to operate.

Changes in environmental laws related to hydraulic fracturing or other operations could result in increased costs of compliance and reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the demand for fracturing and other services or our results of operations

        Operations in our Completion Services operating segment include 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. Hydraulic fracturing activities are currently exempt under the federal Safe Drinking Water Act, except for those using diesel fuel, for which the EPA has asserted regulatory authority and is drafting guidance documents. The EPA is also conducting a study of the potential environmental impacts from hydraulic fracturing on drinking water resources. In addition, the federal Bureau of Land Management has imposed new requirements on hydraulic fracturing conducted on federal lands, including the disclosure of chemical additives used. In 2011, the U.S. Department of Energy released a report on hydraulic fracturing, recommending the implementation of a variety of measures to reduce the environmental impacts from shale-gas production. In addition, there has been public opposition to hydraulic fracturing. As a result, there have been legislative 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 requiring 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. The EPA has indicated an intent to regulate wastewater discharges under the Federal Clean Water Act from hydraulic fracturing and other natural gas production. In 2012, the EPA also promulgated new rules establishing new air emission controls for oil and gas production and natural gas processing operations. These rules require, among other things, controlling emissions through flaring until 2015 and thereafter through reduced emissions completions, as well as imposing new requirements on emissions from tanks and other equipment. These rules and any other new laws regulating exploration, production and completion activities could cause operational delays, increased costs of compliance or increased costs in exploration and production, which could adversely affect our business and the demand for fracturing services.

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

        As of February 24, 2014, we had 800,000,000 authorized common shares, of which 324,921,245 shares were outstanding. In addition, 29,004,477 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

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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 may be insufficient to thwart a coercive hostile takeover attempt; conversely, they may deter a change of control transaction and decrease the likelihood of a shareholder receiving a change of control premium

        Companies generally seek to prevent coercive takeovers by parties unwilling to pay fair value for the enterprise they acquire. Historically, we have sought to avoid a coercive takeover by:

    Classifying our Board of Directors so that all the directors could not be replaced at a single meeting.

    Authorizing the Board 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.

    Adopting a shareholder rights plan that limits the number of shares of our common stock a potential acquiror can purchase without either securing the approval of our Board of Directors or having their voting interest severely diluted. The plan is scheduled to expire in July 2016 unless it is extended.

    Limiting the ability of our shareholders to call or bring business before special meetings.

    Prohibiting our shareholders from taking action by written consent in lieu of a meeting unless the consent is signed by all the shareholders then entitled to vote.

    Requiring advance notice of shareholder proposals for business to be conducted at general meetings and for nomination of candidates for election to our Board of Directors; and

    Reserving to our Board of Directors the ability to determine the number of directors comprising the full Board and to fill vacancies or newly created seats on the Board.

        At the request of shareholders, we declassified the Board, which makes it easier for another party to acquire control of the Company. The remaining provisions designed to avoid a coercive takeover might not be fully effective so a party might still be able to acquire the Company without paying what the Board considers to be fair value, including a control premium.

        On the other hand, some shareholders view the foregoing provisions as too likely to discourage a would-be acquiror and thus to reduce the likelihood that shareholders would receive a premium for their shares in a takeover.

We may have additional tax liabilities

        We are subject to income taxes in numerous other jurisdictions, including the United States. 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.

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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.

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 and Houston, Texas.

        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.

        We own certain mineral interests in connection with our investment in development and production of natural gas, oil and natural gas liquids in the United States and the Canadian provinces of Alberta and British Columbia.

        Beginning in 2010 and in accordance with the SEC's Final Rule, Modernization of Oil and Gas Reporting, our operating results from wholly owned oil and gas activities and from our U.S. unconsolidated oil and gas joint venture were deemed significant, and we provided the oil and gas disclosure required by the SEC's Industry Guide. In December 2012, we sold our U.S. unconsolidated oil and gas joint venture, which was the only remaining oil and gas investment classified as continuing operations. During 2013, we determined that the criteria for disclosing significant oil and gas activities was not met. Accordingly, we present below for 2011 and 2012, our oil and gas activities, during which time these investments were deemed significant.

        The estimates of net proved oil and gas reserves as of December 31, 2012 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. Cawley, Gillespie & Associates, Inc. prepared reports of estimated proved oil reserves for our wholly owned assets located in the Eagle

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Ford Shale, Texas. DeGolyer and MacNaughton Corp. prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Alaska.

        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 our wholly owned assets and interests in oil and natural gas properties located in the United States. Cawley, Gillespie & Associates, Inc. prepared reports of estimated proved oil reserves for our wholly owned assets located in the Eagle Ford Shale and Giddings field in Grimes County, Texas.

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 during the applicable reporting period presented. 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.

 
  Proved Developed   Undeveloped   Total  
Reserve Category
  Liquids
(MMBbls)
  Natural
Gas (Bcf)
  Liquids
(MMBbls)
  Natural
Gas (Bcf)
  Liquids
(MMBbls)
  Natural
Gas (Bcf)
 

For the year ended December 31, 2012:

                                     

Consolidated subsidiaries

                                     

United States

    1.1     0.4     14.3     0.7     15.4     1.1  

Canada

        7.7                 7.7  

Colombia

                         
                           

Total consolidated

    1.1     8.1     14.3     0.7     15.4     8.8  
                           

Total(1)

    1.1     8.1     14.3     0.7     15.4     8.8  
                           

For the year ended December 31, 2011:

                                     

Consolidated subsidiaries

                                     

United States

    0.9     13.6     0.9     3.3     1.8     16.9  

Canada

        8.2                 8.2  

Colombia

                         
                           

Total consolidated

    0.9     21.8     0.9     3.3     1.8     25.1  

Equity companies(2)

   
 
   
 
   
 
   
 
   
 
   
 
 

United States

    6.3     256.4     9.6     326.1     15.9     582.5  

Canada

                         

Colombia

                         
                           

Total equity companies

    6.3     256.4     9.6     326.1     15.9     582.5  
                           

Total

    7.2     278.2     10.5     329.4     17.7     607.6  
                           

(1)
We held no interests in equity companies at December 31, 2012.

(2)
Represents our proportionate interests in our equity companies for the applicable period.

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Oil and Gas Production, Production Prices and Production Costs

Oil and Gas Production

        The table below summarizes production by final product sold, average production sales price and average production cost, each by geographic area for 2012 and 2011. 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, 2012:

                                                 

Oil and natural gas liquids production

                                                 

Consolidated subsidiaries

    0.268     0.938         2.00     0.003         0.271     2.938  
                                   

Equity companies(1)

    0.545     19.01                     0.545     19.010  

Average production sales prices:

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Consolidated subsidiaries

  $ 76.74   $ 3.04   $   $ 2.36   $ 130.04   $   $ 77.33   $ 2.58  
                                   

Equity companies(1)

  $ 53.94   $ 2.70   $   $   $   $   $   $  

Average production costs ($/bce):

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Consolidated subsidiaries

        $ 3.52/Mcfe (2)       $ 2.91/Mcfe   $ 31.75/Boe                    
                                             

Equity companies(1)

        $ 1.47/Mcfe         $   $                    

As of December 31, 2011:

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Oil and natural gas liquids production

                                                 

Consolidated subsidiaries

    0.140     2.944         2.117     0.111     0.011     0.251     5.072  
                                   

Equity companies(1)

    0.409     18.634         0.380     0.316         0.725     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                    

(1)
Represents our proportionate interests in our equity companies for the applicable period.

(2)
Reflects the thousand cubic feet ("Mcf") 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".

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Drilling and Other Exploratory and Development Activities

        During 2012 and 2011, our drilling program focused on proven and emerging oil and natural gas basins in the United States. The following tables provide the number of oil and gas wells completed during 2012 and 2011.

Number of Net Productive and Exploratory Wells Drilled

 
  Net Productive
Exploratory
Wells Drilled
  Net Dry
Exploratory
Wells Drilled
  Net Productive
Development
Wells Drilled
  Net Dry
Development
Wells Drilled
 

For the year ended December 31, 2012:

                         

Consolidated subsidiaries

                         

United States

    2.40         6.50      

Canada

                 

Colombia

    1.15              
                   

Total consolidated

    3.55         6.50      
                   

Equity companies(1)

                         

United States

    1.49         3.48      
                   

Total equity companies

    1.49         3.48      
                   

For the year ended December 31, 2011:

                         

Consolidated subsidiaries

                         

United States

    5.14     3.63     2.04     3.28  

Canada

    3.00     4.00          

Colombia

            2.00     1.40  
                   

Total consolidated

    8.14     7.63     4.04     4.68  
                   

Equity companies(1)

                         

United States

            10.45      
                   

Total equity companies

            10.45      
                   

(1)
Represents our proportionate interests in our equity companies for the applicable period.

        Additional information about our oil and gas properties can be found in Note 19—Commitments and Contingencies (under the caption Minimum volume commitment) and our Schedule of Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) in Part II, Item 8.—Financial Statements and Supplementary Data.

        Our revenues and property, plant and equipment by geographic area can be found in Note 23—Segment Information in Part I, Item 8.—Financial Statements and Supplementary Data. A description of our rig fleet is included under the caption Introduction in Part II, 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

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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.

        In 2009, the Court of Ouargla entered a judgment of approximately $17.7 million (at current exchange rates) against us relating to alleged customs infractions in Algeria. We believe we did not receive proper notice of the judicial proceedings, and that the amount of the judgment was excessive in any case. We asserted the lack of legally required notice as a basis for challenging the judgment on appeal to the Algeria Supreme Court. In May 2012, that court reversed the lower court and remanded the case to the Ouargla Court of Appeals for treatment consistent with the Supreme Court's ruling. In January 2013, the Ouargla Court of Appeals reinstated the judgment. We have again lodged an appeal to the Algeria Supreme Court, asserting the same challenges as before. Based upon our understanding of applicable law and precedent, we continue to believe that we will prevail. Although the appeal remains ongoing at this time, the Hassi Messaoud customs office recently initiated efforts to collect the judgment prior to the Supreme Court's decision in the case. As a result, we paid approximately $3.1 million and posted security of approximately $1.33 million to suspend those collection efforts and to enter into a formal negotiations process with the customs authority. We have recorded a reserve in the amount of the posted security. If we are ultimately required to pay a fine or judgment related to this matter, the resulting loss could be up to $13.3 million in excess of amounts accrued.

        In March 2011, the Court of Ouargla entered a judgment of approximately $34.8 million (at current exchange rates) against us 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 us 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. 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, as well as interpretations of the law by the Central Bank of Algeria, the ultimate resolution of this matter could result in a loss of up to $26.8 million in excess of amounts accrued.

        In March 2012, Nabors Global Holdings II Limited ("NGH2L") signed a contract with ERG Resources, LLC ("ERG") relating to the sale of all of the Class A shares of NGH2L's wholly owned subsidiary, Ramshorn International Limited, an oil and gas exploration company. When ERG failed to meet its closing obligations, NGH2L terminated the transaction on March 19, 2012 and, as contemplated in the agreement, retained ERG's $3.0 million escrow deposit. ERG filed suit the following day in the 61st Judicial District Court of Harris County, Texas, in a case styled ERG Resources, LLC v. Nabors Global Holdings II Limited, Ramshorn International Limited, and Parex Resources, Inc.; Cause No. 2012-16446, seeking injunctive relief to halt any sale of the shares to a third party, specifically naming as defendant Parex Resources, Inc. ("Parex"). The lawsuit also seeks monetary damages of up to $750.0 million based on an alleged breach of contract by NGH2L and alleged tortious interference with contractual relations by Parex. Nabors successfully defeated ERG's

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effort to obtain a temporary restraining order from the Texas court on March 20, 2012. Nabors completed the sale of Ramshorn's Class A shares to a Parex affiliate in April 2012, which mooted ERG's application for a temporary injunction. The lawsuit is staid, pending further court actions. ERG retains its causes of action for monetary damages, but Nabors believes the claims are foreclosed by the terms of the agreement and are without factual or legal merit. Although we are vigorously defending the lawsuit, its ultimate outcome cannot be determined at this time.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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PART II

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

STOCK PERFORMANCE GRAPH

        The following graph illustrates comparisons of five-year cumulative total returns among Nabors, the S&P 500 Index and the Dow Jones Oil Equipment and Services Index. Total return assumes $100 invested on December 31, 2008 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, 2009 - 2013.

GRAPHIC

 
  2009   2010   2011   2012   2013  

Nabors Industries Ltd

    183     196     145     121     143  

S&P Index

    126     146     149     172     228  

Dow Jones Oil Equipment and Services Index

    165     210     184     185     237  

        This graph shall not be deemed "soliciting" material or to be "filed" with the SEC.

Market and Share Prices

        Our common shares are traded on the New York Stock Exchange under the symbol "NBR". At February 24, 2014, there were approximately 1,857 shareholders of record.

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        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  

2012

 

First Quarter

  $ 22.73   $ 16.36  

 

Second Quarter

  $ 17.84   $ 12.40  

 

Third Quarter

  $ 16.83   $ 12.77  

 

Fourth Quarter

  $ 15.50   $ 12.75  

2013

 

First Quarter

  $ 18.24   $ 14.35  

 

Second Quarter

  $ 17.35   $ 14.34  

 

Third Quarter

  $ 16.72   $ 14.50  

 

Fourth Quarter

  $ 18.33   $ 15.32  

        The following table provides information relating to Nabors' repurchase of common shares during the three months ended December 31, 2013:

Period
(In thousands, except per share amounts)
  Total
Number of
Shares
Repurchased
  Average
Price
Paid per
Share(1)
  Total Number
of Shares
Purchased as
Part of Publicly
Announced
Program
  Approximated
Dollar Value of
Shares that May
Yet Be
Purchased
Under the
Program(2)
 

October 1 - October 31

    11   $ 17.39          

November 1 - November 30

    <1   $ 17.74          

December 1 - December 31

    <1   $ 15.45          

(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. 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 have a current share repurchase program authorized by the Board of Directors.

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

Dividend Policy

        On February 21, 2014, our Board of Directors declared a cash dividend of $0.04 per share to the holders of our common shares as of March 10, 2014 to be paid on March 31, 2014.

        In 2013, our Board of Directors approved the payment of cash dividends on our common stock. Dividends in the amount of $0.04 per share were paid in March, June, September and December of 2013. There were no dividends paid in 2012 or 2011. The Board of Directors intends to continue paying quarterly dividends in the future. However, the declaration and payment of future dividends will be at the discretion of the Board of Directors and will depend, among other things, on future earnings, general financial condition and liquidity, success in business activities, capital requirements, and general business conditions.

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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).

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ITEM 6.    SELECTED FINANCIAL DATA

 
  Year Ended December 31,  
Operating Data(1)(2)
  2013   2012   2011   2010   2009  
 
  (In thousands, except per share amounts and ratio data)
 
 
   
  Revised
  Revised
  Revised
  Revised
 

Revenues and other income:

                               

Operating revenues

  $ 6,152,015   $ 6,843,051   $ 6,013,480   $ 4,134,483   $ 3,662,220  

Earnings (losses) from unconsolidated affiliates

    39     (288,718 )   85,448     58,641     (211,961 )

Investment income

    96,577     63,137     19,939     7,263     25,522  
                       

Total revenues and other income

    6,248,631     6,617,470     6,118,867     4,200,387     3,475,781  
                       

Costs and other deductions:

                               

Direct costs

    3,981,828     4,367,106     3,738,506     2,397,061     1,971,711  

General and administrative expenses

    525,330     527,953     487,808     338,720     421,462  

Depreciation and amortization

    1,086,677     1,039,923     918,122     760,962     663,958  

Interest expense

    223,418     251,904     256,632     272,712     266,047  

Losses (gains) on sales and disposals of long-lived assets and other expense (income), net

    37,977     (136,636 )   4,474     45,334     6,665  

Impairments and other charges

    287,241     290,260     198,072     61,292     118,543  
                       

Total costs and other deductions

    6,142,471     6,340,510     5,603,614     3,876,081     3,448,386  
                       

Income (loss) from continuing operations before income taxes

    106,160     276,960     515,253     324,306     27,395  

Income tax expense (benefit)

    (55,181 )   40,986     165,083     49,190     (91,380 )

Subsidiary preferred stock dividend

    3,000     3,000     3,000     750      
                       

Income (loss) from continuing operations, net of tax

    158,341     232,974     347,170     274,366     118,775  

Income (loss) from discontinued operations, net of tax

    (11,179 )   (67,526 )   (97,601 )   (161,090 )   (218,609 )
                       

Net income (loss)

    147,162     165,448     249,569     113,276     (99,834 )

Less: Net (income) loss attributable to noncontrolling interest

    (7,180 )   (621 )   (1,045 )   (85 )   342  
                       

Net income (loss) attributable to Nabors

  $ 139,982   $ 164,827   $ 248,524   $ 113,191   $ (99,492 )
                       

Earnings (losses) per share:

                               

Basic from continuing operations

  $ 0.51   $ 0.80   $ 1.21   $ 0.96   $ 0.42  

Basic from discontinued operations

    (0.04 )   (0.23 )   (0.34 )   (0.56 )   (0.77 )
                       

Total Basic

  $ 0.47   $ 0.57   $ 0.87   $ 0.40   $ (0.35 )
                       

Diluted from continuing operations

  $ 0.51   $ 0.79   $ 1.18   $ 0.95   $ 0.42  

Diluted from discontinued operations

    (0.04 )   (0.23 )   (0.33 )   (0.56 )   (0.77 )
                       

Total Diluted

  $ 0.47   $ 0.56   $ 0.85   $ 0.39   $ (0.35 )
                       

Weighted-average number of common shares outstanding:

                               

Basic

    294,182     289,965     287,118     285,145     283,326  

Diluted

    296,592     292,323     292,484     289,996     286,502  

Capital expenditures and acquisitions of businesses(3)

 
$

1,365,994
 
$

1,433,586
 
$

2,247,735
 
$

1,878,063
 
$

990,287
 

Interest coverage ratio(4)

    7.4:1     7.7:1     7.0:1     5.2:1     4.9:1  

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  Year Ended December 31,  
Balance Sheet Data(1)(2)
  2013   2012   2011   2010   2009  
 
  (In thousands, except per share amounts and ratio data)
 
 
   
   
  Revised
  Revised
  Revised
 

Cash, cash equivalents and short-term investments

  $ 507,133   $ 778,204   $ 539,489   $ 801,190   $ 1,090,851  

Working capital

    1,442,406     2,000,475     1,285,752     458,550     1,568,042  

Property, plant and equipment, net

    8,597,813     8,712,088     8,629,946     7,815,419     7,646,050  

Total assets

    12,159,811     12,656,022     12,899,538     11,605,166     10,577,913  

Long-term debt

    3,904,117     4,379,336     4,348,490     3,064,126     3,940,605  

Shareholders' equity

    5,969,086     5,944,929     5,587,022     5,322,524     5,143,523  

Debt to capital ratio:

                               

Gross(5)

    0.40:1     0.42:1     0.45:1     0.45:1     0.43:1  

Net(6)

    0.36:1     0.38:1     0.42:1     0.41:1     0.36:1  

(1)
All periods present the operating activities of our wholly owned oil and gas businesses, our previously held equity interests in oil and gas joint ventures in Canada and Colombia, aircraft logistics operations and construction services as discontinued operations.

(2)
Our acquisitions' results of operations and financial position have been included beginning on the respective dates of acquisition and include KVS (October 2013), Navigate Energy Services, Inc. (January 2013), Peak (July 2011), Stone Mountain Venture Partnership (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) operating revenues and earnings (losses) from unconsolidated affiliates, direct costs and general administrative expenses less earnings (losses) from the U.S. unconsolidated oil and gas joint venture divided by (y) interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by accounting principles generally accepted in the United States of America ("GAAP") and may not be comparable to similarly titled measures presented by other companies.

(5)
The gross debt to capital ratio is calculated by dividing (x) total debt by (y) total capital. Total capital is defined as total debt plus shareholders' equity. The gross 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.

(6)
The net debt to capital ratio is calculated by dividing (x) net debt by (y) net capital. Net debt is total debt minus the sum of cash and cash equivalents and short-term investments. Net capital is the sum of net debt plus shareholders' equity. The net 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.

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

Management Overview

        This section is intended to help you understand our results of 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.

        Nabors has grown from a land drilling business centered in the United States and Canada to a global business aimed at optimizing the entire well life cycle, with operations on land and offshore in most of the major oil and gas markets in the world. The majority of our business is conducted through two business lines:

    Drilling & Rig Services

    This business line is comprised of our global drilling rig operations and drilling-related services, consisting of equipment manufacturing, instrumentation optimization software and directional drilling services.

    Completion & Production Services

    This business line is comprised of our operations involved in the completion, life-of-well maintenance and eventual plugging and abandonment of a well. These product lines include stimulation, coiled-tubing, cementing, wireline, workover, well-servicing and fluids management.

        Our businesses depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. A sustained increase or decrease in the price of oil or natural gas could materially impact exploration, development and production activities of our customers and, consequently, 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 Drilling & Rig Services business line, operations have traditionally been driven by natural gas prices, but the majority of current activity is driven by the price of oil and to a lesser extent natural gas liquids from unconventional reservoirs (shales). Activity in our international markets is increasingly driven by the development of natural gas reserves. In our Completion & Production Services business line, operations are primarily driven by oil prices.

        During 2013, the West Texas Intermediate crude oil spot price averaged $98.02 per barrel, up from $94.10 in 2012 and $95.05 in 2011. The Henry Hub natural gas spot price averaged $3.72 per mcf versus $2.75 in 2012 and $4.00 in 2011. While the commodity price environment has impacted demand for drilling, the technologies used to gain drilling efficiencies have increased. Two factors that have contributed to this increase are the high-performance capabilities of modern A/C rigs, which address the more complex horizontal drilling requirements of the unconventional reservoirs, and the shift by exploration and production operators toward pad drilling.

        Crude oil pricing remains volatile and potentially vulnerable, which keeps our customers' forward-spending plans in check. For 2014, we believe natural gas and liquids prices, as well as crude oil prices, are likely to remain in the same range as 2013. With that outlook, it is likely that continuing additions of new rig capacity and improving rig efficiency will result in a continued oversupply of rigs for most, if not all, of the year in our U.S. markets.

        Until recently, our international markets have been generally slower to respond to the improving oil prices of the last three years. During 2013, we signed several multiyear contracts for new rigs and

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rig renewals with revenue expected to commence during 2014. Those contracts are consistent with a general tightening of the international rig market. Many of those rigs are likely to deploy on large-scale natural gas projects. For 2014, we expect the international rig market to remain tight, and we anticipate additional opportunities to contract rigs at rates commensurate with this market.

        The following table sets forth oil and natural gas price data per Bloomberg for the last three years:

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  

Commodity prices:

                                           

Average Henry Hub natural gas spot price ($/mcf)

  $ 3.72   $ 2.75   $ 4.00   $ 0.97     35 % $ (1.25 )   (31 )%

Average West Texas intermediate crude oil spot price ($/barrel)

  $ 98.02   $ 94.10   $ 95.05   $ 3.92     4 % $ (0.95 )   (1 )%

        Operating revenues and Earnings (losses) from unconsolidated affiliates in 2013 totaled $6.2 billion, representing a decrease of $402.3 million, or 6%, over 2012. Adjusted income derived from operating activities and net income (loss) from continuing operations for 2013 totaled $558.2 million and $158.3 million ($0.51/per diluted share), respectively, representing decreases of 39% and 32% when compared to 2012.

        Operating revenues and Earnings (losses) from unconsolidated affiliates for 2012 totaled $6.6 billion, representing an increase of $455.4 million, or 7%, over 2011. Adjusted income derived from operating activities for 2012 totaled $908.6 million, representing an increase of 5% over 2011, while net income (loss) from continuing operations for 2012 totaled $233.0 million ($0.79/per diluted share), representing a decrease of 33% over 2011.

        During 2013, our income (loss) from continuing operations was negatively impacted primarily by the $208.2 million loss recognized when we repurchased $785.4 million aggregate principal amount of the 9.25% senior notes in September. Excluding this, our operating results in North American drilling and completion operations decreased due to the industry-wide decrease in land drilling activity and overcapacity in the pressure pumping markets. Our International operations increased significantly resulting from the deployment of additional rigs under long-term contracts and the renewal of existing contracts at current market rates.

        During 2012, our income (loss) from continuing operations was negatively impacted by impairments and other charges, including full-cost ceiling test writedowns from Sabine totaling $283.4 million, representing our proportionate share of the writedowns, a $75.0 million impairment of an intangible asset related to the Superior trade name, a provision for the retirement of long-lived assets totaling $138.7 million in multiple operating segments, a $50.4 million impairment of some coil-tubing rigs and a goodwill impairment totaling $26.3 million. Partially offsetting these charges were $160 million of asset gains, primarily relating to selling our interest in Sabine at the end of 2012. Excluding these items, our operating results improved as a result of increased demand for our services and products due to increased drilling activity in oil- and liquids-rich shale plays and increased well-servicing activity in the U.S. and Canada. This increase in activity has more than offset the drop in demand from gas-related plays.

        During 2011, operating results improved as compared to 2010 primarily due to the incremental revenue and positive operating results from the addition of our Completion Services 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 states and Canada drilling operations and increased well-servicing activity in the U.S. and Canada. However, our operating results and activity levels were negatively impacted in our U.S. offshore operations in response to uncertainty in the regulatory

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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.

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

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
  (In thousands, except percentages and rig activity)
 
 
   
  Revised
  Revised
   
   
  Revised
 

Reportable segments:

                                           

Operating revenues and Earnings (losses) from unconsolidated affiliates

                                           

Drilling & Rig Services:

                                           

U.S. 

  $ 1,914,786   $ 2,276,808   $ 1,999,241   $ (362,022 )   (16 )% $ 277,567     14 %

Canada

    361,676     429,411     426,455     (67,735 )   (16 )%   2,956     1 %

International

    1,464,264     1,265,060     1,104,461     199,204     16 %   160,599     15 %

Rig Services(2)

    516,004     688,310     626,169     (172,306 )   (25 )%   62,141     10 %
                                   

Subtotal Drilling & Rig Services(3)

    4,256,730     4,659,589     4,156,326     (402,859 )   (9 )%   503,263     12 %

Completion & Production Services:

                                           

Completion Services

    1,074,713     1,462,767     1,237,306     (388,054 )   (27 )%   225,461     18 %

Production Services

    1,009,214     1,000,873     849,522     8,341     1 %   151,351     18 %
                                   

Subtotal Completion & Production Services(4)

    2,083,927     2,463,640     2,086,828     (379,713 )   (15 )%   376,812     18 %

Other reconciling items(5)(7)

   
(188,603

)
 
(568,896

)
 
(144,226

)
 
380,293
   
67

%
 
(424,670

)
 
(294

)%
                                   

Total

  $ 6,152,054   $ 6,554,333   $ 6,098,928   $ (402,279 )   (6 )% $ 455,405     7 %
                                   

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  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
  (In thousands, except percentages and rig activity)
 
 
   
  Revised
  Revised
   
   
  Revised
 

Adjusted income (loss) derived from operating activities(1)(6)

                                           

Drilling & Rig Services:

                                           

U.S. 

  $ 315,496   $ 509,894   $ 442,831   $ (194,398 )   (38 )% $ 67,063     15 %

Canada

    61,193     91,360     89,344     (30,167 )   (33 )%   2,016     2 %

International

    177,833     91,226     123,813     86,607     95 %   (32,587 )   (26 )%

Rig Services(2)

    (3,918 )   67,366     55,856     (71,284 )   (106 )%   11,510     21 %
                                   

Subtotal Drilling & Rig Services(3)

    550,604     759,846     711,844     (209,242 )   (28 )%   48,002     7 %

Completion & Production Services:

                                           

Completion Services

    51,722     188,518     229,125     (136,796 )   (73 )%   (40,607 )   (18 )%

Production Services

    102,130     108,835     80,018     (6,705 )   (6 )%   28,817     36 %
                                   

Subtotal Completion & Production

                                           

Services(4)

    153,852     297,353     309,143     (143,501 )   (48 )%   (11,790 )   (4 )%

Other reconciling items(7)

    (146,237 )   (148,649 )   (154,981 )   2,412     2 %   6,332     4 %
                                   

Total adjusted income (loss) derived from operating activities

  $ 558,219   $ 908,550   $ 866,006   $ (350,331 )   (39 )% $ 42,544     5 %
                                   

U.S. oil and gas joint venture earnings (losses)

        (289,199 )   88,486     289,199     100 %   (377,685 )   (427 )%

Interest expense

    (223,418 )   (251,904 )   (256,632 )   28,486     11 %   4,728     2 %

Investment income (loss)

    96,577     63,137     19,939     33,440     53 %   43,198     217 %

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

    (37,977 )   136,636     (4,474 )   (174,613 )   (128 )%   141,110     n/m (8)

Impairments and other charges

    (287,241 )   (290,260 )   (198,072 )   3,019     1 %   (92,188 )   (47 )%
                                   

Income (loss) from continuing operations before income taxes

    106,160     276,960     515,253     (170,800 )   (62 )%   (238,293 )   (46 )%

Income tax expense (benefit)

    (55,181 )   40,986     165,083     (96,167 )   (235 )%   (124,097 )   (75 )%

Subsidiary preferred stock dividend

    3,000     3,000     3,000                  
                                   

Income (loss) from continuing operations, net of tax

    158,341     232,974     347,170     (74,633 )   (32 )%   (114,196 )   (33 )%

Income (loss) from discontinued operations, net of tax

    (11,179 )   (67,526 )   (97,601 )   56,347     83 %   30,075     31 %
                                   

Net income (loss)

    147,162     165,448     249,569     (18,286 )   (11 )%   (84,121 )   (34 )%

Less: Net (income) loss attributable to noncontrolling interest

    (7,180 )   (621 )   (1,045 )   (6,559 )   n/m (8)   424     41 %

Net income (loss) attributable to Nabors

  $ 139,982   $ 164,827   $ 248,524   $ (24,845 )   (15 )% $ (83,697 )   (34 )%
                                   

Rig activity:

                                           

Rig years:(9)

                                           

U.S. 

    195.0     219.1     214.7     (24.1 )   (11 )%   4.4     2 %

Canada

    29.9     34.8     39.8     (4.9 )   (14 )%   (5.0 )   (13 )%

International(10)

    124.2     119.3     105.3     4.9     4 %   14.0     13 %
                                   

Total rig years

    349.1     373.2     359.8     (24.1 )   (6 )%   13.4     4 %
                                   

Rig hours:(11)

                                           

Production Services

    865,939     853,373     791,956     12,566     1 %   61,417     8 %

Canada Production Services

    152,747     181,185     184,908     (28,438 )   (16 )%   (3,723 )   (2 )%
                                   

Total rig hours

    1,018,686     1,034,558     976,864     (15,872 )   (2 )%   57,694     6 %
                                   

(1)
All periods present the operating activities of our wholly owned oil and gas businesses, our previously held equity interests in oil and gas joint ventures in Canada and Colombia and aircraft logistics operations and construction services as discontinued operations.

(2)
Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software services. These services represent our other companies that are not aggregated into a reportable operating segment.

(3)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of ($0.4) million and ($3.1) million for the years ended December 31, 2013 and 2011, respectively.

(4)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $0.4 million and $0.5 million for the years ended December 31, 2013 and 2012, respectively.

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(5)
Represents the elimination of inter-segment transactions and earnings (losses), net from the U.S. unconsolidated oil and gas joint venture, accounted for using the equity method until sold in December 2012, of ($289.2) million and $88.5 million for the years ended December 31, 2012 and 2011, respectively.

(6)
Adjusted income (loss) derived from operating activities is computed by subtracting the sum of direct costs, general and administrative expenses, depreciation and amortization and earnings (losses) from the U.S. oil and gas joint venture from the sum of Operating revenues and Earnings (losses) from unconsolidated affiliates. These amounts should not be used as a substitute for the 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.

(7)
Represents the elimination of inter-segment transactions and unallocated corporate expenses.

(8)
Number is so large that it is not meaningful.

(9)
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.

(10)
International rig years includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates, which totaled 2.5 years in years 2013 and 2012 and 2.1 years in 2011.

(11)
Rig hours represents the number of hours that our well-servicing rig fleet operated during the year.

Segment Results of Operations

Drilling & Rig Services

        Our Drilling & Rig Services business line is comprised of drilling on land and offshore, by geographic region. This business line also includes our drilling technology, top drive manufacturing, directional drilling, construction services and rig instrumentation and software businesses.

 
  Years Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
  (In thousands, except percentages and rig activity)
 

U.S.

                                           

Revenues

  $ 1,914,786   $ 2,276,808   $ 1,999,241   $ (362,022 )   (16 )% $ 277,567     14 %

Adjusted income

  $ 315,496   $ 509,894   $ 442,831   $ (194,398 )   (38 )% $ 67,063     15 %

Rig years

    195.0     219.1     214.7     (24.1 )   (11 )%   4.4     2 %

Canada

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 361,676   $ 429,411   $ 426,455   $ (67,735 )   (16 )% $ 2,956     1 %

Adjusted income

  $ 61,193   $ 91,360   $ 89,344   $ (30,167 )   (33 )% $ 2,016     2 %

Rig years

    29.9     34.8     39.8     (4.9 )   (14 )%   (5.0 )   (13 )%

International

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 1,464,264   $ 1,265,060   $ 1,104,461   $ 199,204     16 % $ 160,599     15 %

Adjusted income

  $ 177,833   $ 91,226   $ 123,813   $ 86,607     95 % $ (32,587 )   (26 )%

Rig years

    124.2     119.3     105.3     4.9     4 %   14.0     13 %

Rig Services

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 516,004   $ 688,310   $ 626,169   $ (172,306 )   (25 )% $ 62,141     10 %

Adjusted income (loss)

  $ (3,918 ) $ 67,366   $ 55,856   $ (71,284 )   (106 )% $ 11,510     21 %

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    U.S.

        Our U.S. drilling segment includes land drilling activities in the lower 48 states, Alaska and offshore operations in the Gulf of Mexico.

        Operating results decreased from 2012 to 2013 primarily as a result of an industry-wide decrease in land drilling activity over the latter part of 2012 in response to declines in commodity prices. Throughout 2013, this resulted in both reduced drilling activity and lower dayrates for our lower 48 fleet. Expiring term contracts also contributed to the decrease as contracts were renewed at the lower market prices. These decreases were partially offset by slight improvements in margins and costs for our offshore fleet operating in the Gulf of Mexico.

        Operating results increased from 2011 to 2012 primarily due to higher average dayrates and a slight increase in drilling activity, as well as $39.6 million in revenues recognized that were related to early contract terminations. These increases were partially offset by higher depreciation expense related to new rigs placed into service during 2012.

    Canada

        Operating results decreased from 2012 to 2013 also as a result of the industry-wide decrease in land drilling activity, similar to the United States. Strong oil prices and oil-related drilling activities have partially mitigated the impact of the overall natural gas oversupply in North America and the resulting reductions in customer demand for gas drilling.

        Operating results increased slightly from 2011 to 2012 primarily due to higher average dayrates, which offset the decreases in drilling and well-servicing activities. The natural gas oversupply in North America and resulting low natural gas prices decreased customer demand for gas drilling and well-servicing activity in 2012. Reduced natural gas drilling activity was largely offset by increased demand in oil exploration. Strong oil prices increased in oil drilling activity and drilling dayrates, with more demand for larger rigs required to drill long-reach horizontal wells in the shale plays and oil sands.

    International

        Operating results increased from 2012 to 2013 primarily as a result of increases in the utilization of our overall rig fleet and higher average margins from recent rig deployments in Papua New Guinea, Northern Iraq and Abu Dhabi. Results were also impacted by favorable moves on the land rigs, favorable activity on the offshore rigs in Saudi Arabia and overall improvements in operational efficiencies.

        Operating revenues and Earnings from unconsolidated affiliates increased from 2011 to 2012 as a result of increases in utilization of our overall rig fleet albeit at lower margins. Adjusted income derived from operating activities decreased from 2011 to 2012 primarily from the decreases in average dayrates and lower utilization of our jackup rigs in Saudi Arabia and lower offshore activity in Congo. These decreases were partially offset by new activity in Papua New Guinea and increased utilization of rigs in Mexico.

    Rig Services

        The decrease in operating results from 2012 to 2013 primarily resulted from reductions to our Canrig activities during 2013 compared to 2012 due to lower demand in the United States and Canada drilling markets for top drives, rig instrumentation and data collection services from oil and gas exploration companies, along with lower third-party rental and RigWatchTM units, which generate higher margins.

        The increase in operating results from 2011 to 2012 primarily resulted from higher demand in the United States and Canada drilling markets for top drives, rig instrumentation and data collection

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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.

Completion & Production Services

        Our Completion & Production Services business line includes well-servicing, fluid logistics, workover operations and stimulation services in the U.S. and Canada.

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
  (In thousands, except percentages and rig activity)
 

Completion Services

                                           

Revenues

  $ 1,074,713   $ 1,462,767   $ 1,237,306   $ (388,054 )   (27 )% $ 225,461     18 %

Adjusted income

  $ 51,722   $ 188,518   $ 229,125   $ (136,796 )   (73 )% $ (40,607 )   (18 )%

Production Services

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 1,009,214   $ 1,000,873   $ 849,522   $ 8,341     1 % $ 151,351     18 %

Adjusted income

  $ 102,130   $ 108,835   $ 80,018   $ (6,705 )   (6 )% $ 28,817     36 %

Rig hours

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

U.S. 

    865,939     853,373     791,956     12,566     1 %   61,417     8 %

Canada

    152,747     181,185     184,908     (28,438 )   (16 )%   (3,723 )   (2 )%
                                   

    1,018,686     1,034,558     976,864     (15,872 )   (2 )%   57,694     6 %
                                   

    Completion Services

        Operating results decreased from 2012 to 2013 primarily due to downward pricing pressure across all regions due to continued overcapacity in the pressure pumping market and reduced customer activity in part caused by severe weather in our northern operating areas. During 2013, we suspended some of our stimulation operations in Canada and some of our coil-tubing operations in the United States. We relocated the Canadian assets to the United States.

        Operating revenues increased from 2011 to 2012 primarily due to the increased levels of fracturing activity and associated increase in our assets deployed in the major producing areas in the United States. Adjusted income derived from operating activities decreased from 2011 to 2012 due to lower margins on product sales as a result of higher commodity prices.

    Production Services

        Operating revenues increased from 2012 to 2013 primarily due to our acquisition of KVS. From 2011 to 2012, operating revenues increased primarily due to the mix of higher and lower rate rigs working in our U.S. markets, partially offset by weaker Canada markets. Our U.S. markets have had higher utilization and increases in rig and truck fleets as well as frac tank counts, despite continued pricing challenges. The decrease in adjusted income from 2012 to 2013 reflect the costs that have increased in rig and truck fleets as a result of capital invested over the past few years to increase those fleets.

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OTHER FINANCIAL INFORMATION

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
  (In thousands, except percentages)
 

General and administrative expenses

  $ 525,330   $ 527,953   $ 487,808   $ (2,623 )     $ 40,145     8 %

Depreciation and amortization

    1,086,677     1,039,923     918,122     46,754     4 %   121,801     13 %

Interest expense

    223,418     251,904     256,632     (28,486 )   (11 )%   (4,728 )   (2 )%

Investment income

    96,577     63,137     19,939     33,440     53 %   43,198     217 %

Losses (gains) on sales and disposals of long-lived assets and other expense (income), net

    (37,977 )   136,636     (4,474 )   (174,613 )   (128 )%   141,110     n/m (1)

(1)
Number is so large that it is not meaningful.

    General and administrative expenses

        General and administrative expenses decreased slightly from 2012 to 2013 primarily as a result of lower activities and cost-reduction efforts across all business units. As a percentage of operating revenues, general and administrative expenses have increased primarily as a result of the similar drop in operating revenues during 2013.

        General and administrative expenses increased from 2011 to 2012 primarily as a result of increases in wages to support a higher headcount as a result of increased operations for a majority of our operating segments. As a percentage of operating revenues, general and administrative expenses decreased from 2011 to 2012.

    Depreciation and amortization

        Depreciation and amortization expense increased from 2012 to 2013 and from 2011 to 2012 as a result of the incremental depreciation expense from 41 newly constructed rigs placed into service during 2012 and 2013 and rig upgrades and other capital expenditures made since 2012.

    Interest expense

        Interest expense decreased from 2012 to 2013 primarily as a result of the redemptions of some of our 9.25% senior notes in September 2013 and our 5.375% senior notes in August 2012. During 2013, our overall debt was lower and average interest rates were lower on our outstanding senior notes, revolving credit facility and commercial paper balances as compared to 2012. These reductions were partially offset by the September 2013 issuance of $700 million aggregate principal amount of 2.35% and 5.10% senior notes.

        Interest expense decreased from 2011 to 2012 primarily as a result of the redemption in May 2011 of our remaining 0.94% senior exchangeable notes, aggregate principal amount $1.4 billion, and the redemption in August 2012 of our 5.375% senior notes, aggregate principal amount $275 million. The decrease was partially offset by interest expense increases related to our August 2011 issuance of 4.625% senior notes due September 2021 and interest on larger amounts outstanding on our revolving credit facilities.

    Investment income

        Investment income during 2013 was $96.6 million and included $89.0 million related to realized gains from short-term and other long-term investments and net gains of $2.5 million from our trading

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securities. The balance was attributable to $5.1 million in interest and dividend income and $2.5 million in realized gains on the trading securities.

        Investment income during 2012 was $63.1 million and included (i) $41.1 million net realized gains from our trading securities, (ii) $14.5 million realized gains from short-term and other long-term investments and (iii) $7.5 million interest and dividend income from our cash, other short-term and long-term investments.

        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.

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

        The amount of gains (losses) on sales and disposals of long-lived assets and other income (expense), net for 2013 was a net loss of $38.0 million, which was primarily comprised of (i) net losses on sales and disposals of assets of approximately $13.6 million, (ii) increases to litigation reserves of $11.7 million and (iii) foreign currency exchange losses of $6.2 million.

        The amount of gains (losses) on sales and disposals of long-lived assets and other income (expense), net for 2012 was a net gain of $136.6 million, which included net gains on sales and disposals of long-lived assets of approximately $147.5 million, primarily as result of the gain from the sale of our equity interest in Sabine. These gains were partially offset by (i) increases to our litigation reserves of $5.4 million and (ii) foreign currency exchange losses of approximately $4.8 million.

        The amount of gains (losses) on sales and disposals of long-lived assets and other income (expense), 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 disposals 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% equity interest of Peak.

    Impairments and Other Charges

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
  (In thousands, except percentages)
 

Loss on tendered notes

  $ 208,197   $   $   $ 208,197     100 % $      

Provision for retirement of assets

    14,044     138,666     98,072     (124,622 )   (90 )%   40,594     41 %

Impairment of long-lived assets

    20,000     50,355         (30,355 )   (60 )%   50,355     100 %

Termination of employment contract

    45,000         100,000     45,000     100 %   (100,000 )   (100 )%

Intangible asset impairment

        74,960         (74,960 )   (100 )%   74,960     100 %

Goodwill impairment

        26,279         (26,279 )   (100 )%   26,279     100 %
                                   

Total

  $ 287,241   $ 290,260   $ 198,072   $ (3,019 )   (1 )% $ 92,188     47 %
                                   

    Loss on tendered notes

        During 2013, we recognized a loss related to the extinguishment of debt in connection with the tender offer for our 9.25% senior notes. See Note 13—Debt in Part II, Item 8—Financial Statements and Supplementary Data for additional discussion. In 2013, we completed a cash tender offer for these

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notes and repurchased $785.4 million aggregate principal amount. We paid the holders an aggregate of approximately $1.0 billion in cash, reflecting principal, accrued and unpaid interest and recognized a loss as part of the debt extinguishment.

    Provision for retirement of assets

        During 2013, we recorded a provision for retirement of long-lived assets in multiple operating segments totaling $14.0 million, which reduced the carrying value of some assets to their salvage value. The retirements related to assets in Saudi Arabia and included obsolete top-drives, nonworking trucks, generators, engines and other miscellaneous equipment. The retirements in our Canada operations included functionally inoperable rigs and other drilling equipment. In our Completion & Production operations, the retirements related to rigs and vehicles that would require significant repair to return to work and other non-core assets.

        During 2012, we recorded a provision for retirement of long-lived assets in multiple operating segments, including $37.1 million in U.S., $33.7 million in Canada, $16.5 million in International and $2.0 million in Rig Services, all from our Drilling & Rig Services business line. The retirements in this business line included mechanical rigs, a jackup rig and other assets that have become inoperable or functionally obsolete and that we do not believe could be returned to service without significant costs to refurbish.

        Additionally in 2012, we recorded similar provisions for retirement of long-lived assets of $49.4 million in our Completion & Production Services business line. During 2012, we streamlined our operations and consolidated our Completion Services and Production Services into this business line, and retired some non-core assets. As we continue to streamline our lines of business, there could be future retirement or impairment charges, which could have a potential impact on our future operating results.

        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 and trucks. Our U.S., International and Production Services 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.

        A continued period of lower oil and natural gas prices and their 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.

    Impairment of long-lived assets

        During 2013, we recognized an impairment of $20.0 million to our fleet of coil-tubing units in our Completion & Production Services business line. Intense competition and oversupply of equipment has led to lower utilization and margins for this product line. When these factors were considered as part of our annual impairment tests on long-lived assets, the sum of the estimated future cash flows, on an undiscounted basis, was less than the carrying amount of these assets. The estimated fair values of these assets were calculated using discounted cash flow models involving assumptions based on our utilization of the assets, revenues and direct costs, capital expenditures and working capital requirements. We believe the fair value estimated for purposes of these tests represents a Level 3 fair value measurement. In 2013, we suspended our coil-tubing operations in the United States. A prolonged period of slow economic recovery could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges for other reporting units due to the potential impact on our estimate of our future operating results.

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        During the fourth quarter of 2012, we determined that some of our coil-tubing rigs would not be fully utilized as forecasted, which resulted in a triggering event and required a year-end long-lived asset impairment test. Our year-end impairment test resulted in impairment charges of $17.4 million in our U.S. and $32.9 million in our Canada operations.

        We did not record any impairment of long-lived assets in 2011.

    Termination of employment contract

        During 2013, we recognized a one-time stock grant valued at $27.0 million, which vested immediately, and $18.0 million in cash awarded and paid to Mr. Petrello in connection with the termination of his prior employment agreement. See Note 19—Commitments and Contingencies in Part II, Item 8—Financial Statements and Supplementary Data for additional discussion.

        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 2011. This charge resulted from a potential termination payment to our former Chief Executive Officer, Eugene 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, we did not owe or make the termination payment. During 2012, we made charitable contributions to benefit the needs of our employees and other community-based causes. We 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, was recorded as a capital contribution during the first quarter of 2012.

    Intangible asset impairment

        During 2012, we recorded impairment of the Superior trade name totaling $75.0 million. The Superior trade name was initially classified as a ten-year intangible asset at the date of acquisition in September 2010. The impairment is a result of the decision to cease using the Superior trade name to reduce confusion in the marketplace and enhance the Nabors brand.

        There were no intangible asset impairment in 2013 or 2011.

    Goodwill impairment

        During 2012, we recognized the impairment of goodwill associated with our operations in the U.S. and International drilling operations. The impairments were deemed necessary due to the prolonged 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 and our international markets. A prolonged period of lower 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 future operating results.

        There were no goodwill impairment in 2013 or 2011.

    Income tax rate

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
   
  Revised
  Revised
  Revised
  Revised
 

Effective income tax rate from continuing operations

    (52.0 )%   14.8 %   32.0 %   (67 )%   (451 )%   (17 )%   (54 )%

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        The changes in our effective tax rate from 2012 to 2013 resulted mainly from the proportion of income generated in the United States versus other countries where we operate and settlements of tax disputes. In general, the effective tax rate reflects the proportion of income generated in the United States versus other countries where we operate. Income generated in the United States is generally taxed at a higher rate than other jurisdictions.

        The changes in our effective tax rate from 2011 to 2012 resulted mainly from the proportion of income generated in the United States versus other countries where we operate. Income generated in the United States is generally taxed at a higher rate than other jurisdictions.

        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 2002 reorganization as a Bermuda company. Legislation enacted by the U.S. Congress in 2004 provides that a corporation reorganizing in a foreign jurisdiction on or after March 4, 2003 be treated as a domestic corporation for U.S. federal income tax purposes. There has 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.

    Assets Held-for-Sale

 
  December 31,  
 
  2013   2012  
 
  (In thousands)
 

Oil and Gas

  $ 239,936   $ 377,625  

Rig Services

    3,328     6,232  
           

  $ 243,264   $ 383,857  
           

Oil and Gas Properties

        The carrying value of our assets held for sale represents the lower of carrying value or fair value less costs to sell. We continue to market these properties at prices that are reasonable compared to current fair value.

        We have contracts with pipeline companies to pay specified fees based on committed volumes for gas transport and processing. In December 2013 we entered into agreements to restructure these contracts, assigning a portion of the obligation to third parties and reducing our future payment commitments. At December 31, 2013, our undiscounted contractual commitments for these contracts

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approximated $171.2 million, and we had liabilities of $113.6 million, $64.4 million of which were classified as current and are included in accrued liabilities.

        At December 31, 2012, we had liabilities of $206 million, $69 million of which were classified as current and included in accrued liabilities. The amounts at December 31, 2012 represented our best estimate of the fair value of the excess capacity of the pipeline commitments calculated using a discounted cash flow model, when considering our disposal plan, current production levels, natural gas prices and expected utilization of the pipeline over the remaining contractual term.

    Discontinued Operations

        Our condensed statements of income (loss) from discontinued operations for each operating segment were as follows:

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2013   2012   2011   2013 to 2012   2012 to 2011  
 
  (In thousands, except percentages)
   
 

Operating revenues

                                           

Oil and Gas

  $ 25,327   $ 27,363   $ 125,654 (1) $ (2,036 )   (7 )% $ (98,291 )   (78 )%

Rig Services

  $ 127,154   $ 172,335   $ 76,584   $ (45,181 )   (26 )% $ 95,751     125 %

Income (loss) from discontinued operations:

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Oil and Gas

  $ (27,396) (2) $ (66,033) (3)   (91,394) (4) $ 38,637     59 % $ 25,361     28 %

Rig Services

  $ 16,217   $ (1,493) (5)   (6,207) (5) $ 17,710     n/m (6) $ 4,714     76 %

Oil and Gas

(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 impairments during 2013 of $61.5 million to write down the carrying value of some of our wholly owned oil and gas-centered assets, partially offset by a gain related to our restructure of our future pipeline obligations.

(3)
Includes adjustments during 2012 to increase our pipeline contractual commitments by $128.1 million and other gains and losses related to the sale of our wholly owned oil and gas-centered assets.

(4)
Includes impairments during 2011 of $255.0 million to write down the carrying value of our wholly owned oil and gas-centered assets.

Rig Services

(5)
Includes $7.8 million and $7.9 million, respectively, of impairment (a Level 3 measurement) in 2012 and 2011 to our aircraft and logistics assets as a result of the continued downturn in the oil and gas industry in Canada.

(6)
Number is so large that it is not meaningful.

        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 and in Note 3—Summary of Significant Accounting Policies in Part II, Item 8.—Financial Statements and Supplementary Data. Additional information relating to discontinued operations is provided in Note 5—Assets Held for Sale and Discontinued Operations and our Schedule of 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.

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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 oil or natural gas 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 or acquisitions, 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. We discuss our 2013 and 2012 cash flows below.

        Operating Activities.    Net cash provided by operating activities totaled $1.4 billion during 2013, compared to net cash provided by operating activities of $1.6 billion during 2012. 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 impact 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 $1.4 billion and $1.6 billion in 2013 and 2012, 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 provided $2.9 million and used $61.1 million, respectively, in cash flows during 2013 and 2012.

        Investing Activities.    Net cash used for investing activities totaled $815.5 million during 2013 compared to net cash used for investing activities of $1.2 billion in 2012. Our 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 2013 and 2012, we used cash for capital expenditures totaling $1.2 billion and $1.5 billion, respectively.

        In 2013, cash of $318.9 million was provided in proceeds from sales of our oil and gas assets and other non-core operations.

        In 2013, we used cash of $79.5 million to purchase KVS and $37.5 million to purchase NES. We also sold our trading equity securities and some of our available-for-sale debt and equity securities, providing $164.5 million in cash.

        In 2012, cash of $254.5 million was provided in proceeds from sales of our oil and gas assets and equity interests in unconsolidated oil and gas joint ventures.

        Financing Activities.    Net cash used for financing activities totaled $729.6 million during 2013. In 2013 we issued $329.8 million, net in commercial paper. Additionally, in 2013, we received proceeds of $694.3 million (net of financing costs) from the issuance of 2.35% senior notes and 5.10% senior notes and used these proceeds (plus proceeds from our commercial paper and cash on hand) to repurchase $785.4 million aggregate principal amount of our 9.25% senior notes due 2019 for $991.3 million. We also repaid borrowings under our revolving credit facility of $720.0 million during 2013. During 2013, we paid cash dividends of $47.2 million.

        Net cash used for financing activities totaled $254.1 million during 2012, including repayment of $282.4 million, representing principal and accrued interest, of our $275 million 5.375% senior notes. Of that amount $30 million, net, of the required cash came from our revolving credit facilities.

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    Future Cash Requirements

        We expect capital expenditures over the next 12 months to approximate $1.6—$1.8 billion. Purchase commitments outstanding at December 31, 2013 totaled approximately $788 million, 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 reflect a number of capital programs that are currently underway or planned. These programs will result in an expansion in the number of land drilling and offshore rigs and the amount of well-servicing equipment and technology assets that we own and operate. We expect to be able to reduce the planned expenditures if necessary or increase them if market conditions and new business opportunities warrant it.

        We have historically completed a number of acquisitions and will continue to evaluate opportunities to acquire assets or businesses to enhance our operations. Several of our previous acquisitions were funded through issuances of debt or our common shares. Future acquisitions may be funded 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, 2013:

 
  Payments due by Period  
 
  Total   < 1 Year   1 - 3 Years   3 - 5 Years   Thereafter  
 
  (In thousands)
 

Contractual cash obligations:

                               

Long-term debt:(1)

                               

Principal

  $ 3,914,451   $   $ 350,000 (2) $ 1,474,844 (3) $ 2,089,607 (4)

Interest

    1,149,950     184,858     369,763     323,247     272,082  

Operating leases(5)

    58,750     24,689     19,661     6,474     7,926  

Purchase commitments(6)

    787,821     766,537     21,284          

Employment contracts(5)

    24,341     6,984     12,217     4,840     300  

Pension funding obligations

    1,400     1,400              

Transportation and processing contracts(5)(7)

    171,150     44,365     44,807     28,024     53,954  

        The table above excludes liabilities for unrecognized tax benefits totaling $68.2 million as of December 31, 2013 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 14—Income Taxes in Part II, Item 8—Financial Statements and Supplementary Data.

(1)
See Note 13—Debt in part II, Item 8—Financial Statements and Supplementary Data.

(2)
Represents Nabors Delaware's aggregate 2.35% senior notes due September 2016.

(3)
Represents Nabors Delaware's aggregate 6.15% senior notes due February 2018, commercial paper and amounts drawn on our revolving credit facility which expires November 2017.

(4)
Represents Nabors Delaware's aggregate 9.25% senior notes due January 2019, 5.0% senior notes due September 2020, 4.625% senior notes due September 2021 and 5.10% senior notes due September 2023.

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(5)
See Note 19—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. See Notes 5—Assets Held for Sale and Discontinued Operations and 19—Commitments and Contingencies in Part II, Item 8.—Financial Statements and Supplementary Data.

        During the three months ended December 31, 2013, our Board declared a cash dividend of $0.04 per common share to our shareholders. This quarterly cash dividend was paid on December 31, 2013 to shareholders of record on December 10, 2013. During the year ended December 31, 2013, we paid cash dividends totaling $47.2 million.

        We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, 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.

Financial Condition and Sources of Liquidity

        Our primary sources of liquidity are cash and investments, availability under our revolving credit facility, our commercial paper program, and cash generated from operations. As of December 31, 2013, we had cash and short-term investments of $507.1 million and working capital of $1.4 billion. As of December 31, 2012, we had cash and short-term investments of $778.2 million and working capital of $2.0 billion. At December 31, 2013, we had $1.0 billion of availability remaining under our $1.5 billion revolving credit facility and commercial paper program.

        In September 2013, Nabors Delaware completed a private placement of $700 million aggregate principal amount of senior notes, comprised of $350 million principal amount of 2.35% senior notes due 2016 and $350 million principal amount of 5.10% senior notes due 2023, which are unsecured and fully and unconditionally guaranteed by us. The notes are subject to registration rights. The indenture governing the notes includes covenants customary for transactions of this type that, subject to significant exceptions, limit our ability and that of our subsidiaries to incur certain liens or enter into sale and leaseback transactions. Nabors Delaware used the proceeds of these senior notes, borrowings under its commercial paper program and cash on hand to redeem $785.4 billion, including accrued and unpaid interest, of its 9.25% senior notes due 2019 for approximately $1.0 billion.

        During 2013, we sold Peak, one of our businesses in Alaska, for gross cash proceeds of $135.5 million. We also sold logistic assets from one of our Canadian subsidiaries for proceeds of $9.3 million. In addition, we sold some of our oil and gas assets to an unrelated party and received proceeds of $90 million.

        In 2013, we sold our trading equity securities and some of our available-for-sale debt and equity securities for $164.5 million. During 2013, Nabors established a commercial paper program, allowing for the issuance of up to $1.5 billion in commercial paper with a maturity of no more than 397 days. As of December 31, 2013, we had approximately $329.8 million of borrowings from commercial paper outstanding.

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        We had 10 letter-of-credit facilities with various banks as of December 31, 2013. Availability under these facilities as of December 31, 2013 was as follows:

 
  (In thousands)  

Credit available

  $ 523,204  

Letters of credit outstanding, inclusive of financial and performance guarantees

    321,818  
       

Remaining availability

  $ 201,386  
       

        Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by the major credit rating agencies in the United States and our historical ability to access these 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 ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.

        Our gross debt to capital ratio was 0.40:1 as of December 31, 2013 and 0.42:1 as of December 31, 2012, respectively. Our net debt to capital ratio was 0.36:1 as of December 31, 2013 and 0.38:1 as of December 31, 2012. The gross debt to capital ratio is calculated by dividing (x) total debt by (y) total capital. Total capital is defined as total debt plus shareholders' equity. Net debt is total debt minus the sum of cash and cash equivalents and short-term investments. Neither the gross debt to capital ratio nor the net debt to capital ratio is a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.

        Our interest coverage ratio was 7.4:1 as of December 31, 2013 and 7.7:1 as of December 31, 2012. The interest coverage ratio is a trailing 12-month quotient of the sum of (x) operating revenues and earnings (losses) from unconsolidated affiliates, direct costs and general administrative expenses less earnings (losses) from the U.S. unconsolidated oil and gas joint venture divided by (y) 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 facility are expected to adequately finance our purchase commitments, capital expenditures, acquisitions, scheduled debt service requirements, and all other expected cash requirements for the next 12 months.

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.

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        The following table summarizes the total maximum amount of financial guarantees issued by Nabors:

 
  Maximum Amount  
 
  2014   2015   2016   Thereafter   Total  
 
  (In thousands)
 

Financial standby letters of credit and other financial surety instruments

  $ 70,144     34         11,933   $ 82,111  

Other Matters

        Our Investments in Unconsolidated Affiliates (Note 11 in Part II, Item 8.—Financial Statements and Supplementary Data) included our equity interest in Sabine through the third quarter of 2012. We disposed of our entire interest during the fourth quarter of 2012.

        We were recently informed by Sabine that it is restating its previously issued financial statements to correct errors identified with respect to the accounting for certain derivative financial transactions previously accounted for as cash flow hedges. These errors affect our historical earnings (losses) from unconsolidated affiliates and related income tax expense (benefit) recorded during certain periods in 2012 and earlier. These errors have no effect on our consolidated financial statements for 2013. They also have no effect on our balance sheet or shareholders' equity as of December 31, 2012 or subsequent periods, our income statement for the year ended December 31, 2013 or our cash flows from operating, investing or financing activities for any historical period.

        We assessed the materiality of these errors in accordance with the SEC's Staff Accounting Bulletin 99 and concluded that the previously issued annual financial statements were not materially misstated. However, the impact is material to the quarters ended March 31, 2012 and June 30, 2012. Accordingly, we have corrected these errors in the quarters and annual periods by revising our consolidated financial statements for the years 2012 and prior and restating the unaudited quarterly financial information (Note 22—Unaudited Quarterly Financial Information in Part II, Item 8.—Financial Statements and Supplementary Data) for quarters ended March 31, 2012 and June 30, 2012. In addition, as a result of revising our prior years' consolidated financial statements, we have also corrected certain other immaterial items that had been previously recorded during the period identified, to reflect such items in the proper period. The effect of the adjustments was to increase our net income for the years ended December 31, 2012 and 2011 by $0.8 million and $4.8 million, respectively. The effect of these adjustments for periods prior to January 1, 2011 have been reflected as revisions to retained earnings as of December 31, 2010 in our consolidated statements of changes in equity.

        The tables below present the financial statement line items impacted by the revisions to our consolidated financial statements for the years ended December 31, 2012 and 2011.

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        The effect on our consolidated statements of income (loss) is as follows:

 
  Year Ended December 31,  
 
  2012   2011  
(In thousands, except per share
amounts)
  As
Reported(1)
  Adjustment   Revised   As
Reported(1)
  Adjustment   Revised  

Earnings (losses) from unconsolidated affiliates

  $ (301,320 ) $ 12,602   $ (288,718 ) $ 56,647   $ 28,801   $ 85,448  

Total revenues and other income

    6,604,868     12,602     6,617,470     6,090,066     28,801     6,118,867  

Direct costs

    4,368,702     (1,596 )   4,367,106     3,736,910     1,596     3,738,506  

Total costs and other deductions

    6,342,106     (1,596 )   6,340,510     5,602,018     1,596     5,603,614  

Income (loss) from continuing operations before income taxes

    262,762     14,198     276,960     488,048     27,205     515,253  

Deferred income tax expense (benefit)

    (115,413 )   13,405     (102,008 )   33,021     22,360     55,381  

Income tax expense (benefit)

    27,581     13,405     40,986     142,723     22,360     165,083  

Income (loss) from continuing operations, net of tax

    232,181     793     232,974     342,325     4,845     347,170  

Net income (loss)

    164,655     793     165,448     244,724     4,845     249,569  

Net income (loss) attributable to Nabors

    164,034     793     164,827     243,679     4,845     248,524  

Earnings (losses) per share:(2)

                                     

Basic from continuing operations

  $ 0.80   $   $ 0.80   $ 1.19   $ 0.02   $ 1.21  
                           

Total Basic

  $ 0.57   $   $ 0.57   $ 0.85   $ 0.02   $ 0.87  
                           

Diluted from continuing operations

  $ 0.79   $   $ 0.79   $ 1.17   $ 0.02   $ 1.18  
                           

Total Diluted

  $ 0.56   $   $ 0.56   $ 0.83   $ 0.02   $ 0.85  
                           

(1)
Amounts reflect the retrospective of the results of Peak as discontinued operations in the third quarter of 2013. Refer to Note 5—Assets Held for Sale and Discontinued Operations in Part II, Item 8.—Financial Statements and Supplementary Data for additional information.

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

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        The effect on our consolidated statements of other comprehensive income (loss) is as follows:

 
  Year Ended December 31,  
 
  2012   2011  
(In thousands)
  As
Reported
  Adjustment   Revised   As
Reported
  Adjustment   Revised  

Net income (loss) attributable to Nabors

  $ 164,034   $ 793   $ 164,827   $ 243,679   $ 4,845   $ 248,524  

Comprehensive income (loss) attributable to Nabors

    274,365     793     275,158     222,891     4,845     227,736  

Comprehensive income (loss)

    275,297     793     276,090     223,751     4,845     228,596  

        While these adjustments had no impact on our overall cash flows from operating, investing or financing activities for any period, the presentation of certain line items within our operating activities on our consolidated statements of cash flow were revised and are presented as follows:

 
  Year Ended December 31,  
 
  2012   2011  
(In thousands)
  As
Reported
  Adjustment   Revised   As
Reported
  Adjustment   Revised  

Net income (loss) attributable to Nabors

  $ 164,034   $ 793   $ 164,827   $ 243,679   $ 4,845   $ 248,524  

Deferred income tax expense (benefit)

    (145,147 )   13,405     (131,742 )   (34,739 )   22,360     (12,379 )

Equity in (earnings) losses of unconsolidated affiliates, net of dividends

    312,319     (12,602 )   299,717     (132,388 )   (28,801 )   (161,189 )

Trade accounts payable and accrued liabilities

    (223,199 )   (1,596 )   (224,795 )   517,615     1,596     519,211  

                                     
                           

Net cash provided by operating activities

    1,562,705         1,562,705     1,456,487         1,456,487  
                           

        The effect on our consolidated statements of changes in equity is as follows:

 
  Year Ended December 31,  
 
  2011   2010  
(In thousands)
  As
Reported
  Adjustment   Revised   As
Reported
  Adjustment   Revised  

Retained earnings

    3,956,364     (793 )   3,955,571     3,707,881     (5,638 )   3,702,243  

Total equity

    5,601,217     (793 )   5,600,424     5,342,863     (5,638 )   5,337,225  

    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

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following is a discussion of our critical accounting estimates. Management considers an accounting estimate to be critical if:

    it requires assumptions to be made that were uncertain at the time the estimate was made; and

    changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated financial position or results of operations.

        For a summary of all of our significant accounting policies, see Note 3—Summary of Significant Accounting Policies in Part II, Item 8.—Financial Statements and Supplementary Data.

        Financial Instruments.    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 nature.

        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 71.0% of our total assets as of December 31, 2013, and depreciation constituted 18.0% of our total costs and other deductions in 2013.

        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 4,927-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

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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 indicating that these estimates do not continue to be appropriate. Accordingly, for the years ended December 31, 2013, 2012 and 2011, 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 their carrying amounts 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 2013, 2012 and 2011, no significant changes have been made to the methodology utilized to determine future cash flows.

        For an asset classified as held for sale, we consider the asset impaired when its carrying amount exceeds fair value less its cost to sell. Fair value is determined in the same manner as an impaired long-lived asset that is held and used.

        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.    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 2013, we assessed qualitative factors and determined it was necessary to perform the two-step annual goodwill impairment test for all of our reporting units within our operating segments. Our Drilling & Rig Services business line consists of U.S., Canada, International and Rig Services operating segments. Our Rig Services operating segment includes Canrig Drilling Technology Ltd. and Ryan Directional Services Inc. Our Completion & Production Services business line consists of Completion & Production Services operating segments. 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

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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 2013, we concluded that all our operating segments' fair values were substantially in excess of their carrying value.

        The fair values calculated in these impairment tests are determined using discounted cash flow models involving assumptions based on our utilization of rigs or other oil and gas service equipment, 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 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.

        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.

        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 where we operate as the calculation of deferred taxes is completed at that level. 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 ownership. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given concerning their realization or whether or not they 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

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Factors—We may have additional tax liabilities and Note 14—Income Taxes in Part II, Item 8.—Financial Statements and Supplementary Data for additional discussion.

        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 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.

        Our 2013 provision for income taxes from continuing operations was $55.2 million tax benefit, consisting of $39.8 million of current tax expense and $95.0 million of deferred tax benefit. 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 (51.9%) to (50.9%) would decrease the current year income tax benefit by approximately $1.1 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 and 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 our 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

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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 2013, 2012 and 2011, no significant changes were made to the methodology used to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2013 reserves were adjusted by 10%, total costs and other deductions would change by $18.2 million, or 0.3%.

        Fair Value of Assets Acquired and Liabilities Assumed.    We have completed a number of acquisitions in recent years as discussed in Note 8—Fair Value Measurements in Part II, Item 8.—Financial Statements and Supplementary Data. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed in the various business combinations using various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations or technology could substantially alter management's assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our consolidated statements of income (loss). As the determination of the fair value of assets acquired and liabilities assumed is subject to significant management judgment and a change in purchase price allocations could result in a material difference in amounts recorded in our consolidated financial statements, management believes that accounting estimates related to the valuation of assets acquired and liabilities assumed are critical.

        The determination of the fair value of assets and liabilities is based on the market for the assets and the settlement value of the liabilities. These estimates are made by management based on our experience with similar assets and liabilities. During 2013, 2012 and 2011, 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.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

        At various times, we utilize local currency borrowings (foreign-currency-denominated debt), the payment structure of customer contracts and foreign exchange contracts to selectively hedge our exposure to exchange rate fluctuations in connection with monetary assets, liabilities, cash flows and commitments denominated in certain foreign currencies. A foreign exchange contract is a foreign currency transaction, defined as an agreement to exchange different currencies at a given future date and at a specified rate. A hypothetical 10% decrease in the value of all our foreign currencies relative to the U.S. dollar as of December 31, 2013 would result in a $13.3 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 and accounts receivable. 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 2.35%, 5.10%, 6.15%, 9.25%, 5.0% and 4.625% senior notes, 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

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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.

        Fair Value of Financial Instruments.    The fair value of our fixed rate long-term debt, revolving credit facility, commercial paper 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,  
 
  2013   2012  
 
  Effective
Interest
Rate
  Carrying
Value
  Fair Value   Effective
Interest
Rate
  Carrying
Value
  Fair Value  
 
  (In thousands)
 

2.35% senior notes due September 2016

    2.56 % $ 349,820   $ 354,694     6.42 % $   $  

6.15% senior notes due February 2018

    6.42 %   969,928     1,097,480     6.42 %   968,708     1,164,813  

9.25% senior notes due January 2019

    9.33 %   339,607     428,733     9.33 %   1,125,000     1,492,819  

5.00% senior notes due September 2020

    5.20 %   697,947     731,955     5.20 %   697,648     770,707  

4.625% senior notes due September 2021

    4.75 %   698,148     709,793     4.75 %   697,907     755,517  

5.10% senior notes due September 2023

    5.26 %   348,765     349,731     0.00 %        

Subsidiary preferred stock

    4.00 %   69,188     69,000     4.00 %   69,188     68,625  

Revolving credit facilities

    2.28 %   170,000     170,000     2.17 %   890,000     890,000  

Commercial paper

    0.45 %   329,844     329,844     0.00 %        

Other

    0.00 %   10,243     10,243     0.00 %   437     437  
                               

Total

        $ 3,983,490   $ 4,251,473         $ 4,448,888   $ 5,142,918  
                               

        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,  
 
  2013   2012  
 
  Fair Value   Interest Rates   Weighted-
Average
Life
(Years)
  Fair Value   Interest Rates   Weighted-
Average
Life
(Years)
 
 
  (In thousands, except rates)
 

Cash and cash equivalents

  $ 389,915   0 - .25%       $ 524,922   0 - .22%      

Short-term investments:

                                 

Trading equity securities

              52,705        

Available-for-sale equity securities

    96,942           174,610        

Available-for-sale debt securities:

                                 

Commercial paper and CDs

              206   1.0%     0.6  

Corporate debt securities

    19,388   10.0 - 11.52%     6.2     23,399   10.0 - 14.0%     4.3  

Mortgage-backed debt securities

    210   2.39%     11.8     244   2.75%     0.7  

Mortgage-CMO debt securities

    20   2.41 - 2.58%     4.9     523   .32 - 4.09%     0.3  

Asset-backed debt securities

    658   0.67 - 4.81%     4.8     1,595   .71 - 4.81%     3.8  

Total available-for-sale debt securities

    20,276               25,967            

Total available-for-sale securities

    117,218               200,577            

Total short-term investments

    117,218               253,282            

Long-term investments

    3,236   N/A           4,269   N/A        
                               

Total cash, cash equivalents, short-term and long-term investments

  $ 510,369             $ 782,473            
                               

        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, 2013 would decrease the fair value of our available-for-sale securities by $11.7 million.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX

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Report of Independent Registered Public Accounting Firm

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

        In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss), other comprehensive 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, 2013 and December 31, 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in Internal Control—Integrated Framework (1992) 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.

        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, TX
March 3, 2014

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 
  December 31,  
 
  2013   2012  
 
  (In thousands, except per
share amounts)

 

ASSETS

             

Current assets:

             

Cash

  $ 389,915   $ 524,922  

Short-term investments

    117,218     253,282  

Assets held for sale

    243,264     383,857  

Accounts receivable, net

    1,399,543     1,382,623  

Inventory

    209,793     251,133  

Deferred income taxes

    121,316     110,480  

Other current assets

    272,781     226,560  
           

Total current assets

    2,753,830     3,132,857