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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, 2014

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
(State or Other Jurisdiction of
Incorporation or Organization)
  980363970
(I.R.S. Employer
Identification No.)

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

(Address of principal executive offices)

 

N/A
(Zip Code)

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

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

Title of each class   Name of each exchange on which registered
Common shares, $.001 par value per share   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
(Do not check if a
smaller reporting company)
  Smaller Reporting Company o

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

         The aggregate market value of the 276,503,079 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 30, 2014, based on the closing price of our common shares as of such date of $29.37 per share as reported on the New York Stock Exchange, was $8,120,895,430. 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 26, 2015 was 329,376,998.

DOCUMENTS INCORPORATED BY REFERENCE

Specified portions of the definitive Proxy
Statement to be distributed in connection with our 2015 Annual General Meeting of Shareholders (Part III).

   


Table of Contents


NABORS INDUSTRIES LTD.
Form 10-K Annual Report
For the Year Ended December 31, 2014

Table of Contents

PART I

Item 1.

 

Business

 

5

Item 1A.

 

Risk Factors

  12

Item 1B.

 

Unresolved Staff Comments

  20

Item 2.

 

Properties

  20

Item 3.

 

Legal Proceedings

  22

Item 4.

 

Mine Safety Disclosures

  24

PART II

Item 5.

 

Market Price of and Dividends on the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

 

24

Item 6.

 

Selected Financial Data

  27

Item 7.

 

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

  29

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  52

Item 8.

 

Financial Statements and Supplementary Data

  55

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

  141

Item 9A.

 

Controls and Procedures

  141

Item 9B.

 

Other Information

  143

PART III

Item 10.

 

Directors, Executive Officers and Corporate Governance

 

144

Item 11.

 

Executive Compensation

  144

Item 12.

 

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

  144

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

  146

Item 14.

 

Principal Accounting Fees and Services

  147

PART IV

Item 15.

 

Exhibits, Financial Statement Schedules

 

148

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        Our internet address is www.nabors.com. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the "SEC"). In addition, a glossary of drilling terms used in this document and documents relating to our corporate governance (such as committee charters, governance guidelines and other internal policies) can be found on our website. The 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 on 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.

        Factors to consider when evaluating these forward-looking statements include, but are not limited to:

    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;

    our ability to complete, and realize the expected benefits of, strategic transactions, including the proposed transaction with C&J Energy Services, Inc.;

    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.

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        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

    Overview

        We own and operate the world's largest land-based drilling rig fleet and have one of the largest completion services and well-servicing and workover rig fleets in North America. We are a leading provider of offshore platform workover and drilling rigs in the United States and multiple international markets.

        As a global provider of services for land-based and offshore oil and natural gas wells, our fleet of rigs and drilling-related equipment as of December 31, 2014 includes:

    466 actively marketed rigs for land-based 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 98 actively marketed rigs for land well-servicing and workover services in Canada;

    42 actively marketed rigs for offshore drilling operations in the United States and multiple international markets; and

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

        We provide innovative drilling technology and equipment and comprehensive well-site services in many of the most significant oil and gas markets in the world, including engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services. In addition, we manufacture and lease or sell top drives and other rig equipment.

        We are a Bermuda exempted company formed on December 11, 2001, which has been continuously operating in the drilling sector through predecessors and acquired entities since the early 1900s.

        The majority of our business is conducted through two business lines: Drilling & Rig Services and Completion & Production Services. Additional information regarding our business segments can be found in Note 23—Segment Information in Part II, Item 8.—Financial Statements and Supplementary Data.

        In June 2014, we and certain of our wholly owned subsidiaries entered into definitive agreements to merge our Completion & Production Services business line with C&J Energy Services, Inc. ("CJES"), an independent oilfield services and manufacturing company (the "Merger"). Under the amended terms of the Merger and related transactions, we will receive total consideration comprised of approximately $688 million in cash and approximately 62.5 million common shares in the combined company. CJES has obtained commitments from certain financial institutions to provide debt financing to the combined company in an amount sufficient to fund the payment to us of the cash consideration at closing. Immediately following the closing of the Merger, we will own approximately 53% of the issued and outstanding common shares of the combined company with the other CJES shareholders owning the remainder of the outstanding common shares. The combined company will be renamed C&J Energy Services, Ltd. and is expected to be listed on the NYSE under the ticker symbol CJES.

        We expect to account for our investment in the combined company using the equity method of accounting. Closing of the Merger is subject to customary approvals and conditions, including, among others, approval of the Merger by the holders of a majority of outstanding CJES common stock and the availability of the proceeds of the debt financing to effect the cash payment to Nabors in

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connection with the closing. We expect that the closing of the Merger will occur in March 2015 following the special meeting of CJES stockholders to be held on March 20, 2015. See Part 1A.—Risk Factors—Risks Related to the Merger.

    Drilling & Rig Services

    General

        The Drilling & Rig Services business line is comprised of our global land-based and offshore drilling rig operations and other rig services, consisting of equipment manufacturing, rig instrumentation, optimization software and directional drilling services. Our Drilling & Rig Services business contributed 67% of our Operating revenues for the year ended December 31, 2014. This business line consists of four operating segments: U.S., Canada, International and Rig Services.

    U.S. Drilling

        We operate one of the largest land-based drilling rig fleets in the United States, consisting of 170 AC rigs and 100 SCR rigs as of December 31, 2014. Our new PACE®-X rig is the latest generation AC rig designed specifically for multi-well drilling on a single pad. As of December 31, 2014, we have placed 32 PACE®-X rigs into service.

        We also operate 16 platform rigs in the U.S. Gulf of Mexico. In 2014, we delivered two new 4600 horsepower deepwater platform rigs, which will be among the largest and most sophisticated rigs in this category.

        Our U.S. drilling operations contributed 32% of our Operating revenues for the year ended December 31, 2014.

    Canada Drilling

        We operate 57 land-based drilling rigs in Canada. Our Canadian drilling operations contributed 5% of our Operating revenues for the year ended December 31, 2014.

    International Drilling

        We operate 138 land-based drilling rigs in more than 20 countries as of December 31, 2014. We also operate 19 platforms and 6 jack-up rigs in the international offshore drilling markets. 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. Many of our rigs in our international drilling markets were designed to address the challenges inherent in specific drilling applications such as those required in the desert, remote/environmentally sensitive locations and the various shale plays. We continue to upgrade and deploy high-specification desert rigs specifically for gas drilling in the Middle East.

        Our International drilling operations contributed 24% of our Operating revenues for the year ended December 31, 2014.

    Rig Services

        Through various subsidiaries, we manufacture and sell top drives, catwalks, wrenches, drawworks and other drilling related equipment which are installed on both onshore and offshore drilling rigs. We offer specialized drilling technologies, including patented steering systems and rig instrumentation software systems including:

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

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    RIGWATCH® 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.

        We have engaged in specific acquisitions in order to develop projects to enhance our drilling related service offerings. See Acquisitions and Divestitures.

        Our Rig Services operations contributed 6% of our Operating revenues for the year ended December 31, 2014.

    Drilling Contracts

        Our contracts for land-based and offshore drilling have durations that are single-well, multi-well or term. Term contracts generally have durations ranging from six months to five years. Under term 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, while multi-well contracts and term contracts may provide us with 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 between drilling locations, 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 anticipated 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). See Part 1A.—Risk Factors—Our drilling contracts may in certain instances be renegotiated or terminated without an early termination payment.

    Completion & Production Services

        Our Completion & Production Services business line is comprised of our operations involved in the completion, life-of-well maintenance and plugging and abandonment of a well in the United States and Canada. These services include stimulation, coiled-tubing, cementing, wireline, workover, well-servicing and fluids management. Our Completion & Production Services business contributed 33% of our Operating revenues for the year ended December 31, 2014. This business line consists of two operating segments: Completion Services and Production Services. In connection with the Merger, this business line will be merged with CJES and we will own 53% of the combined company.

    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. Our Completion Services operations contributed 18% of our Operating revenues for the year ended December 31, 2014.

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    Production Services

        We operate a fleet of 543 land workover and well-servicing rigs in the U.S. and Canada as of December 31, 2014, which are utilized to perform well maintenance and workover services during the production phase of an oil or natural gas well. Well maintenance services are generally performed on a call-out basis and can usually be completed within 48 hours. The services include the repair and replacement of pumps, sucker rods, tubing and other mechanical apparatuses at the wellsite that are used to pump or lift hydrocarbons from producing wells. We also utilize our well service rigs to perform plugging services for wells in which the oil and natural gas has been depleted or further production has become uneconomical. Workover services can be utilized 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 are typically 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. We also provide equipment, including fluid service trucks, frac tanks and salt water disposal wells, to supply, store, remove and dispose of specialized fluids utilized in the completion and workover operations used in daily operations for producing wells.

        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.

        Our Production Services operations contributed 15% of our Operating revenues for the year ended December 31, 2014.

    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 2014.

    Our Employees

        As of December 31, 2014, we employed approximately 29,000 people, of whom approximately 4,300 were employed by unconsolidated affiliates. Our number of employees fluctuates depending on the current and expected demand for our services. We believe our relationship with our employees is generally good. We employed approximately 1,400 unionized employees internationally.

    Seasonality

        Our operations are subject to seasonal factors. Specifically, our drilling and workover operations in Canada and Alaska generally experience reduced levels of activity and financial results during the second quarter of each year, due to the annual spring thaw. Our pressure pumping operations located in the Appalachian, Mid-Continent, and Rocky Mountain regions of the United States can be adversely affected by seasonal weather conditions, primarily in the spring, as many municipalities impose weight restrictions on the paved roads leading to our jobsites due to the muddy conditions and during winter months due to inclement weather. In addition, our U.S. offshore market can be impacted during summer months by tropical weather systems in the Gulf of Mexico. Global warming could lengthen these periods of reduced activity, but we cannot currently estimate to what degree. Our well-servicing and pressure pumping operations may also experience lower activity at the end of the year due to holidays and shorter daylight hours. Our overall financial results reflect the seasonal variations experienced in these operations, but seasonality does not materially impact the remaining portions of our business.

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    Research and Development

        Research and development continues to be an important 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. During recent months, there has been substantial volatility in oil prices due to increases in global oil production with stagnant demand. For example, within the past year, oil prices have been as high as $107 per barrel and have recently been as low as $44 per barrel in 2015. Currently, based on the average crude oil price in January 2015, prices have declined approximately 49% from the average of the preceding twelve months and the decline has caused a reduction in the level of capital spending by oil companies. A prolonged period of these lower oil prices could continue to depress the level of exploration, development and production activities and result in a corresponding decline in the demand for our services and/or a reduction in dayrates and utilization, which could have an adverse effect on 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.

        The markets in which we provide our services are highly competitive. We provide our drilling and rig services in the United States, Canada and over 20 countries throughout the world. We provide our completion and production services in the United States and Canada. We believe that competitive pricing is a significant factor in determining which service provider is awarded a job in these markets. Historically, the number of available rigs and drilling-related equipment has exceeded demand in many of the markets in which we operate, resulting in strong price competition. This is due in part to the fact that most rigs and drilling-related equipment can be readily moved from one region to another in response to changes in the levels of exploration, development and production activities and market conditions, which may result in an oversupply of rigs and drilling-related equipment in certain areas. Most available contracts for our services are currently awarded on a bid basis, which further increases competition based on price.

        In addition to price, other competitive factors in the markets we serve are the overall quality of service and safety record, the technical specification and condition of equipment, the availability of skilled personnel and the ability to offer ancillary services. Our drilling business is subject to certain additional competitive factors. For example, our ability to deliver rigs with new technology and features and, in certain international markets, our experience operating in certain environments and strong customer relationships have been significant factors in the selection of Nabors for the provision of drilling services. We expect that the market for our drilling and completion and production services will continue to be highly competitive.

        Certain competitors are present in more than one of the markets in which we operate, although no one competitor operates in all such markets. In our drilling services business, we compete with (1) Helmerich & Payne, Inc., Patterson-UTI Energy, Inc. and several other competitors with national, regional or local rig operations in the United States, (2) Saipem S.p.A, KCA Deutag, and Weatherford International Ltd. and others in our international markets and (3) Precision Drilling, Ensign Energy Services, and others in Canada. In our completion and production services business, we compete with (1) completion services providers in the United States and Canada, such as Halliburton, Schlumberger Limited, Baker Hughes, FTS International Services LLC., and Weatherford International Ltd. as well as other small and mid-sized independent contractors, and (2) production services providers such as Basic Energy Services, Inc., Key Energy Services, Inc., Superior Energy Services, Inc., Forbes Energy

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Services Ltd. and numerous other competitors having smaller regional or local well servicing and/or fluids management operations in the United States and Precision, Ensign, and Savanna Well Servicing in Canada.

Our Business Strategy

        Our business strategy is to build shareholder value and enhance our competitive position by:

    leveraging our existing global infrastructure and operating reputation to capitalize on growth opportunities;

    achieving superior operational and health, safety and environmental performance;

    continuing to develop our existing portfolio of value-added services to our customers;

    enhancing our technology position and advancing drilling technology both on the rig and downhole; and

    achieving returns above our cost of capital.

        In 2014, we focused on initiatives aimed at strengthening our drilling and rig services business services, including the pending merger of our Completion & Production Services business line with CJES and completion of the sale of a significant portion of our oil and gas proved properties in Alaska in July 2014. In addition, as our customers are forced to reduce spending due to the decline in crude oil prices, we believe they will be more likely to embrace the full breadth of our services and technologies. As such, we continue to enhance our engineering and technological position in drilling and rig services, as evidenced by the acquisition in October 2014 of 2TD Drilling AS ("2TD"), a Norwegian drilling technology company developing a rotary steerable platform for directional drilling. Further, we continued our newbuild program with the delivery of 16 PACE®-X rigs during 2014, which are our latest generation rigs designed specifically for multi-well drilling on a single pad. We also completed and delivered 10 newbuild rigs in Saudi Arabia and 5 newbuild rigs in Argentina.

        As we move into 2015, we continue to actively pursue international prospects for these PACE®-X rigs. Our global scale and international presence provides us with a unique balance compared to other drilling contractors. Although activity in the lower 48 has been decreasing rapidly in response to the recent decline in crude oil prices, we should continue to benefit from the recent upside in international markets, such as the continued deployment of new and substantially-upgraded rig awards in Saudi Arabia, Kazakhstan and offshore Mexico. We also focused on enhancing our financial flexibility by streamlining operations, shedding non-core businesses and reducing net debt and interest expense.

    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 466 land drilling rigs, 543 rigs for land well-servicing and workover work in the United States and Canada, 36 offshore platform rigs, 7 jackup units and a large component of trucks and fluid hauling vehicles. This growth was fueled in part by strategic acquisitions. Although we continue to examine opportunities, including acquisitions, divestitures and other strategic transactions, there can be no assurance that such 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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        In addition to the proposed Merger, we undertook the following transactions over the last three years.

    Acquisitions

        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 expanded our technology and development capability for drilling and measurement tools and services, and is included in our Rig Services operating segment.

        In October 2013, we purchased KVS Transportation, Inc. and D&D Equipment Investments, LLC, (collectively, "KVS") for total consideration of $149.0 million. KVS provides 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 expanded our truck fleet, vacuum truck services, tank and related equipment services and is included in our Production Services operating segment.

        In October 2014, we purchased the outstanding shares of 2TD. 2TD is in the process of developing a rotary steerable system for directional drilling which, once developed, will be included in our Rig Services segment. Under the terms of the transaction, we paid an initial amount of $40.3 million for the purchase of the shares. We may also be required to make future payments of up to an additional $40.0 million, contingent on the achievement of various milestone objectives.

    Divestitures

        In 2012, we sold our remaining wholly owned oil and gas business in Colombia and sold some of our wholly owned oil and gas assets in the United States. In December 2012, we sold our 49.7% ownership interest in NFR Energy LLC, ("NFR Energy"), a U.S. unconsolidated oil and gas joint venture, to the remaining equity owners. Subsequent to this transaction, NFR Energy changed its name to Sabine Oil & Gas LLC ("Sabine"). During 2012, we received cumulative gross cash proceeds of $254.5 million from these 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 Oilfield Service Company ("Peak"), one of our businesses in Alaska, for gross cash proceeds of $135.5 million. We also sold some of our oil and gas assets and received proceeds of approximately $90.0 million.

        In July 2014, we sold a large portion of our interest in our oil and gas proved properties located on the North Slope of Alaska. Under the terms of the agreement, we received $35.1 million at closing and expect to receive additional payments of $27.0 million upon certain future dates or the properties achieving certain production targets. We retained a working interest at various interests and an overriding royalty interest in the properties at various interests. The working interest is fully carried up to $600 million of total project costs. The transaction generally remains subject to the approval of local Alaska regulatory authorities, among other usual and customary conditions.

        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 2015. We believe we are in material compliance with applicable environmental rules and regulations and that 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.

Risks Related to the Business

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. For example, within the past year, oil prices have been as high as $107 per barrel and have recently been as low as $44 per barrel in 2015. 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. A prolonged period of lower oil and natural gas prices could depress the level of drilling, exploration and production activity and result in a corresponding decline in the demand for our services and/or a reduction in dayrates and utilization, which could have an adverse effect on our revenues, cash flows and profitability. 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. For the year ended December 31, 2014, we recorded impairment charges of approximately $1.0 billion, reflecting the effect of the recent decline in oil prices on our assets. If there is a prolonged period of lower oil and natural gas prices, it 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 also 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. Most rigs and drilling-related equipment 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 such rigs and drilling-related equipment in certain areas, and accordingly, significant price competition. In addition, in recent years, the ability to deliver rigs with new technology and features has become an important factor in determining job awards. Our customers are increasingly demanding the services of newer, higher specification drilling rigs, which requires continued technological developments and increased capital expenditures, and our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements for equipment. As a result of these and other competitive factors, we may be unable to maintain or increase our market share, utilization

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rates and/or prices for our services, which could adversely affect our business, financial condition and results of operations.

Our drilling contracts may in certain instances be renegotiated or terminated without an early termination payment

        Most of our drilling contracts require that an early termination payment be made to us if a contract is terminated by the customer prior to its expiration. Such payments may not fully compensate us for the loss of a contract, and in certain circumstances, such as, but not limited to, destruction of a drilling rig that is not replaced within a specified period of time or other breach of our contractual obligations, the customer may not be obligated to make an early termination payment to us. During depressed market conditions or otherwise, customers may seek to terminate, renegotiate or fail to honor their contractual obligations for various reasons, including those described above. The renegotiation or termination of such contracts without an adequate early termination payment could adversely affect our business, financial condition, cash flows and results of operations.

The nature of our operations presents inherent risks of loss that could adversely affect our results of operations

        Our operations are subject to many hazards inherent in the drilling, workover and well-servicing and pressure pumping industries, including blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental and natural resources damage and damage to the property of others. Our offshore operations 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 increase 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 instability, 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, political or economic instability, 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

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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, 2014, we had approximately $4.4 billion in outstanding debt. We also have various financial commitments, such as leases, firm transportation and processing, contracts and purchase commitments. Our ability to service our debt and other financial obligations depends in large part upon the level of cash flows generated by our subsidiaries' operations, our ability to monetize and/or divest non-core assets, availability under our unsecured revolving credit facility and our ability to access the capital markets.

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 U.S. credit rating agencies 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 inability to attract and retain experienced technical personnel could reduce our competitiveness and harm prospects for future success

        The successful execution of our business strategies will depend, in part, on the continued service of certain 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. In addition, 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 and/or our inability to retain or attract experienced technical personnel, could reduce our competitiveness and harm prospects for future success, which may adversely affect our business, financial condition and results of operations.

Changes to or 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

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gas production, processing, transmission, storage and distribution facilities. In addition, U.S. federal law strictly regulates the prevention of oil spills and the 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 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 natural 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.

        The expansion of the scope of laws protecting the environment has accelerated in recent years, particularly outside the United States, and we expect this trend to continue. The violation of environmental laws can lead to the imposition of administrative, civil or criminal penalties, remedial obligations, and in some cases injunctive relief. Violations may also result in liabilities for personal injuries, property and natural resource damage and other costs and claims. We are not always successful in allocating all risks of these environmental liabilities to customers, and it is possible that customers who assume the risks will be financially unable to bear any resulting costs.

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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 Safe Drinking Water Act ("SDWA"), except for such activities that use diesel fuel, for which the EPA has asserted federal regulatory authority over and issued permitting guidance on in February 2014. In 2012, the EPA promulgated new rules establishing new air emission controls for oil and gas production and natural gas processing operations. More recently, in May 2014, the EPA issued an advanced notice of proposed rulemaking regarding the agency's intent to develop regulations under the Toxic Substances and Control Act related to the disclosure of chemicals used in hydraulic fracturing. The EPA is also conducting a study of the potential environmental impacts from hydraulic fracturing on drinking water resources and developing rules on effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities, both which are expected for publication in early 2015. In addition, the federal Bureau of Land Management has proposed 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. From time to time, legislation has also been introduced in the U.S. Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require the disclosure of chemicals used in the hydraulic fracturing process. In addition, various states and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements and temporary or permanent bans. For example, Texas has adopted legislation that requires the public disclosure of information regarding the substances used in the hydraulic fracturing process, and, on December 17, 2014, the State of New York announced a ban on hydraulic fracturing due to public health and environmental concerns identified in its several years study. In addition, municipalities in Colorado and several other states have adopted or are in the process of adopting ordinances restricting or prohibiting hydraulic fracturing within their jurisdictions. New or further changes in laws and regulations imposing reporting obligations on, or otherwise banning or limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, cause operational delays, increase costs of regulatory compliance or in exploration and production, which could adversely affect our business and the demand for fracturing services.

Any violation of the Foreign Corrupt Practices Act or any other similar anti-corruption laws could have a negative impact on us

        A significant portion of our revenue is derived from operations outside the United States, which exposes us to complex foreign and U.S. regulations inherent in doing cross-border business and in each of the countries in which we transact business. We are subject to compliance with the United States Foreign Corrupt Practices Act ("FCPA") and other similar anti-corruption laws, which generally prohibit companies and their intermediaries from making improper payments to foreign government officials for the purpose of obtaining or retaining business. While our employees and agents are required to comply with these laws, we cannot be sure that our internal policies and procedures will always protect us from violations of these laws, despite our commitment to legal compliance and corporate ethics. Violations of these laws may result in severe criminal and civil sanctions as well as other penalties, and the SEC and U.S. Department of Justice have increased their enforcement

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activities with respect to the FCPA. The occurrence or allegation of these types of risks may adversely affect our business, performance, prospects, value, financial condition, and results of operations.

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

        As of February 26, 2015, we had 800,000,000 authorized common shares, of which 329,376,998 shares were outstanding. In addition, 19,449,499 common shares were reserved for issuance pursuant to stock option and employee benefit plans. The sale, or availability for sale, of substantial amounts of our common shares in the public market, whether directly by us or resulting from the exercise of options (and, where applicable, sales pursuant to Rule 144 under the Securities Act), would be dilutive to existing security holders, could adversely affect the prevailing market price of our common shares and could impair our ability to raise additional capital through the sale of equity securities.

Provisions in our organizational documents 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 ("Board") 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 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; and

    Reserving to our Board 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 may not be fully effective so that a party may still be able to acquire the Company without paying what the Board considers to be fair value, including a control premium. Conversely, such provisions could discourage a would-be acquiror and thus reduce the likelihood that shareholders would receive a premium for their shares in a takeover.

We may have additional tax liabilities

        Income tax returns that we file will be subject to review and examination. We will not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany

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pricing policies or the taxable presence of our subsidiaries in certain countries, if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and result in a material adverse effect on our financial condition.

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 and commodity markets

        Changes in general financial and political conditions may negatively impact our business, financial condition, results of operations and cash flows in ways that we cannot predict. If global financial and commodity markets and economic conditions deteriorate in the future, there could be a material adverse impact on our liquidity and those of our customers and other worldwide business partners. For example, as a result of a dramatic decline in oil prices in the fourth quarter of 2014 which remained suppressed into 2015, our customers have reduced or curtailed their capital spending and drilling activities. As a result, we and our customers may experience difficulties forecasting future capital expenditures, which in turn could negatively impact the worldwide rig count and our future financial results.

We previously identified a material weakness in our internal control over financial reporting, and our business and stock price may be adversely affected if our internal control over financial reporting is not effective

        Under Section 404 of the Sarbanes-Oxley Act of 2002 and rules promulgated by the SEC, companies are required to conduct a comprehensive evaluation of their internal control over financial reporting. As part of this process, we are required to document and test our internal control over financial reporting; management is required to assess and issue a report concerning our internal control over financial reporting; and our independent registered public accounting firm is required to attest to the effectiveness of our internal control over financial reporting. Our internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements.

        We have identified a material weakness in our controls over the accounting for and disclosures related to a non-routine complex legal entity restructuring in the interim consolidated financial statements. A more complete description of this material weakness is included in Item 9A, "Controls and Procedures" in this Form 10-K, together with our remediation plan.

        The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, which could cause us to fail to meet our reporting obligations, lead to a loss of investor confidence and have a negative impact on the trading price of our common stock.

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Failure to realize the anticipated benefits of acquisitions, divestitures and other strategic transactions may adversely affect our business, results of operations and financial position

        We undertake from time to time acquisitions, divestitures and other strategic transactions, such as the proposed Merger with CJES, that we expect to further our business objectives. The anticipated benefits of such transactions may not be realized, or may be realized more slowly than expected, and may result in operational and financial consequences, including, but not limited to, the loss of key customers, suppliers or employees and significant transactional expenses, which may have an adverse effect on our business, results of operations and financial position.

Our business is subject to cybersecurity risks

        Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Risks associated with these threats include, among other things, loss of intellectual property, disruption of our and customers' business operations and safety procedures, loss or damage to our worksite data delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events. Although we utilize various procedures and controls to mitigate our exposure to such risk, cybersecurity attacks are evolving and unpredictable. The occurrence of such an attack could go unnoticed for a period time and could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to the Merger

The Merger is subject to customary approvals and conditions which may adversely impact the timing of the transaction and our ability to consummate the transaction

        In June 2014, we and certain of our wholly owned subsidiaries, including Nabors Red Lion Limited ("Red Lion"), agreed to the proposed Merger with CJES. Under the amended terms of the Merger and related transactions, we expect to receive total consideration comprised of approximately $688 million in cash and approximately 62.5 million common shares in the combined company upon the closing of the Merger. The Merger is subject to customary approvals and conditions, many of which are outside of our control, including, among others, the approval of the Merger by the holders of a majority of outstanding CJES common stock and the availability of the proceeds of CJES's debt financing to effect the cash payment to us at closing. Although we expect the Merger to be completed in March of 2015 following the special meeting of CJES stockholders on March 20, 2015, we cannot assure you that the Merger will be consummated within the anticipated time period or at all, including as the result of regulatory, market or other factors. Further, any delay in the consummation of the Merger could result in additional transaction costs or other effects associated with uncertainty about the Merger, which may adversely impact our ability to realize the anticipated benefits of the transaction.

        In addition, failure to consummate the Merger could have an adverse effect on our business for a number of reasons, including that we will have incurred significant transaction costs without achieving the anticipated benefits from the transaction, including the expected cash payment from CJES, and will have lost the opportunity to pursue other strategic transactions. In addition, the market and price for our common stock could be adversely impacted from such delay or failure.

Following completion of the Merger, we will not be able to exert complete control over New C&J

        Following the completion of the Merger, we will own 53% of the outstanding and issued common shares of the newly combined company. While we will have the ability to exert a significant degree of influence as a substantial shareholder, we will not be able to directly manage the daily operations of the newly combined company, including our Completion & Production Services business line, and will not be able to exert complete control over the decision-making of the board of directors of the newly combined company, including with respect to cash distributions to shareholders or the transfer of assets, under normal circumstances.

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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. During 2013, we determined that the criteria for disclosing significant oil and gas activities was not met. Accordingly, we present below for 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 Ford Shale, Texas. DeGolyer and MacNaughton Corp. prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Alaska.

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 for 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.

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Reserve Category

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

As of 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)

    1.1     8.1     14.3     0.7     15.4     8.8  

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

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. 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)
 

For the year ended 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   $   $   $   $   $ 53.94   $ 2.70  

Average production costs ($/boe):

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Consolidated subsidiaries

        $ 3.52/Mcfe (2)       $ 2.91/Mcfe   $ 31.75/Boe (3)                  

Equity companies(1)

        $ 1.47/Mcfe         $   $                    

(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 "Mcfe".

(3)
Reflects the barrel of oil equivalent or "Boe".

Drilling and Other Exploratory and Development Activities

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

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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      

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      

(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 II, Item 8.—Financial Statements and Supplementary Data. Information about our rig fleet is included under the caption Overview in Part I, Item 1.—Business.

ITEM 3.    LEGAL PROCEEDINGS

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

        In 2009, the Court of Ouargla entered a judgment of approximately $16.4 million (at December 31, 2014 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

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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. Algerian Customs have recently demanded 50% of the total fine as a final settlement which would require an additional payment of approximately $4.425 million. We have elected to await the ruling from the Supreme Court. The matter was heard on February 26, 2015, and a decision will be issued on March 26, 2015. If we are ultimately required to pay a fine or judgment related to this matter, the resulting loss could be up to $12.0 million in excess of amounts accrued.

        In March 2011, the Court of Ouargla entered a judgment of approximately $32.2 million (at December 31, 2014 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 upheld the lower court's ruling, and we appealed the matter to the Algeria Supreme Court. On September 25, 2014, the Supreme Court of Algeria overturned the verdict against us, and the case will now be reheard by the Court of Appeal Ouargla in light of the Algeria Supreme Court's opinion. The rehearing has been set for March 8, 2015. 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 $24.2 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 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 including appeals of the jurisdictional decisions. 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.

        On July 30, 2014, Nabors and Red Lion, along with CJES and its board of directors, were sued in a putative shareholder class action filed in the Court of Chancery of the State of Delaware (the "Court of Chancery"). The plaintiff alleges that the members of the CJES board of directors breached their fiduciary duties in connection with the Merger, and that Nabors Red Lion and CJES aided and abetted these alleged breaches. The plaintiff seeks to enjoin the defendants from proceeding with or

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consummating the Merger and the CJES stockholder meeting for approval of the Merger and, to the extent that the Merger is completed before any relief is granted, to have the Merger rescinded. On November 10, 2014, the plaintiff filed a motion for a preliminary injunction, and, on November 24, 2014, the Court of Chancery entered a bench ruling, followed by a written order on November 25, 2014, that (i) ordered certain members of the CJES board of directors to solicit for a 30 day period alternative proposals to purchase CJES (or a controlling stake in CJES) that are superior to the Merger, and (ii) preliminarily enjoined CJES from holding its stockholder meeting until it complied with the foregoing. CJES complied with the order while it simultaneously pursued an expedited appeal of the Court of Chancery's order to the Supreme Court of the State of Delaware (the "Delaware Supreme Court"). On December 19, 2014, the Delaware Supreme Court overturned the Court of Chancery's judgment and vacated the order.

        We cannot predict the outcome of this lawsuit or any others that might be filed in the future in connection with the Merger, nor can we predict the amount of time and expense that will be required to resolve such litigation. One of the conditions to the completion of the Merger is that no temporary restraining order, preliminary or permanent injunction or other order or judgment or any governmental authority of competent jurisdiction enjoining or prohibiting the consummation of the Merger be in effect and completion of the Merger is not illegal under any applicable law, rule, regulation or order of any governmental authority of competent jurisdiction, which condition, if not satisfied, could delay or jeopardize the consummation of the Merger. An adverse judgment granting permanent injunctive relief could indefinitely enjoin the Merger, and an adverse judgment for rescission or monetary damages could have a material adverse effect on us following the Merger.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.


PART II

ITEM 5.    MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information.

        Our common shares, par value $0.001 per share, are publicly traded on the New York Stock Exchange under the symbol "NBR".

        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  
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  
2014   First Quarter   $ 25.06   $ 16.43  
    Second Quarter   $ 29.90   $ 23.36  
    Third Quarter   $ 30.24   $ 22.51  
    Fourth Quarter   $ 23.08   $ 9.91  

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Holders.

        At February 26, 2015, there were approximately 1,799 shareholders of record of our common shares.

Dividends.

        On February 20, 2015, our Board declared a cash dividend of $0.06 per common share, which will be paid on March 31, 2015 to shareholders of record at the close of business on March 10, 2015.

        In 2013, our Board 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 and March and June of 2014. The dividend was increased to $0.06 per share in July 2014 by our Board, and this new amount was paid in September and December 2014. There were no dividends paid in 2012. The declaration and payment of future dividends will be at the discretion of the Board and will depend, among other things, on future earnings, general financial condition and liquidity, success in business activities, capital requirements, and general business conditions.

Issuer Purchases of Equity Securities.

        The following table provides information relating to our repurchase of common shares during the three months ended December 31, 2014:

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

    2   $ 21.51          

November 1 - November 30

    7   $ 17.85          

December 1 - December 31

    < 1   $ 11.97          

(1)
Shares were withheld from employees and directors to satisfy certain tax withholding obligations due in connection with grants of stock under our 2003 Employee Stock Plan and 2013 Stock Plan. The 2003 Employee Stock Plan, 2013 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 purchased in the open market.

(2)
We do not have a current share repurchase program authorized by the Board.

        During 2014, with approval of the Board, we purchased 10.375 million of our common shares, at $24.10 per share, for a total aggregate amount of approximately $250 million. This purchase was an isolated event and was not part of a broader Board approved repurchase program. The Board continuously seeks to increase returns to shareholders, and as a result, this could lead to additional repurchases in the future, although we do not have a plan in place to do so at this time.

        For a description of securities authorized for issuance under equity compensation plans, see Part III, Item 12.—Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.

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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, 2009 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, presented in the table below.

GRAPHIC

 
  2010   2011   2012   2013   2014  

Nabors Industries Ltd

    107     79     66     78     61  

S&P Index

    115     117     136     180     205  

Dow Jones Oil Equipment and Services Index

    127     112     112     144     119  

        The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be "soliciting material" or "filed" with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under the Exchange Act.

Related 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

        The following table summarizes selected financial information and should be read in conjunction with Part II, Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and related notes thereto included under Part II, Item 8.—Financial Statements and Supplementary Data.

 
  Year Ended December 31,  
Operating Data(1)(2)
  2014   2013   2012   2011   2010  
 
  (In thousands, except per share amounts and ratio data)
 

Revenues and other income:

                               

Operating revenues

  $ 6,804,197   $ 6,152,015   $ 6,843,051   $ 6,013,480   $ 4,134,483  

Earnings (losses) from unconsolidated affiliates

    (6,301 )   39     (288,718 )   85,448     58,641  

Investment income

    11,831     96,577     63,137     19,939     7,263  

Total revenues and other income

    6,809,727     6,248,631     6,617,470     6,118,867     4,200,387  

Costs and other deductions:

                               

Direct costs

    4,505,064     3,981,828     4,367,106     3,738,506     2,397,061  

General and administrative expenses

    549,734     525,330     527,953     487,808     338,720  

Depreciation and amortization

    1,145,100     1,086,677     1,039,923     918,122     760,962  

Interest expense

    177,948     223,418     251,904     256,632     272,712  

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

    9,073     37,977     (136,636 )   4,474     45,334  

Impairments and other charges

    1,027,423     287,241     290,260     198,072     61,292  

Total costs and other deductions

    7,414,342     6,142,471     6,340,510     5,603,614     3,876,081  

Income (loss) from continuing operations before income taxes

    (604,615 )   106,160     276,960     515,253     324,306  

Income tax expense (benefit)

    62,666     (55,181 )   40,986     165,083     49,190  

Subsidiary preferred stock dividend

    1,984     3,000     3,000     3,000     750  

Income (loss) from continuing operations, net of tax

    (669,265 )   158,341     232,974     347,170     274,366  

Income (loss) from discontinued operations, net of tax

    21     (11,179 )   (67,526 )   (97,601 )   (161,090 )

Net income (loss)

    (669,244 )   147,162     165,448     249,569     113,276  

Less: Net (income) loss attributable to noncontrolling interest

    (1,415 )   (7,180 )   (621 )   (1,045 )   (85 )

Net income (loss) attributable to Nabors

  $ (670,659 ) $ 139,982   $ 164,827   $ 248,524   $ 113,191  

Earnings (losses) per share:

                               

Basic from continuing operations

  $ (2.28 ) $ 0.51   $ 0.80   $ 1.21   $ 0.96  

Basic from discontinued operations

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

Total Basic

  $ (2.28 ) $ 0.47   $ 0.57   $ 0.87   $ 0.40  

Diluted from continuing operations

  $ (2.28 ) $ 0.51   $ 0.79   $ 1.18   $ 0.95  

Diluted from discontinued operations

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

Total Diluted

  $ (2.28 ) $ 0.47   $ 0.56   $ 0.85   $ 0.39  

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  Year Ended December 31,  
Operating Data(1)(2)
  2014   2013   2012   2011   2010  
 
  (In thousands, except per share amounts and ratio data)
 

Weighted-average number of common shares outstanding:

                               

Basic

    290,694     294,182     289,965     287,118     285,145  

Diluted

    290,694     296,592     292,323     292,484     289,996  

Capital expenditures and acquisitions of businesses(3)

  $ 1,923,779   $ 1,365,994   $ 1,433,586   $ 2,247,735   $ 1,878,063  

Interest coverage ratio(4)

    9.8:1     7.4:1     7.7:1     7.0:1     5.2:1  

 

 
  As of December 31,  
Balance Sheet Data(1)(2)
  2014   2013   2012   2011   2010  
 
  (In thousands, except per share amounts and ratio data)
 

Cash, cash equivalents and short-term investments

  $ 536,169   $ 507,133   $ 778,204   $ 539,489   $ 801,190  

Working capital

    1,174,399     1,442,406     2,000,475     1,285,752     458,550  

Property, plant and equipment, net

    8,599,125     8,597,813     8,712,088     8,629,946     7,815,419  

Total assets

    11,879,942     12,159,811     12,656,022     12,899,538     11,605,166  

Long-term debt

    4,348,859     3,904,117     4,379,336     4,348,490     3,064,126  

Shareholders' equity

    4,908,619     5,969,086     5,944,929     5,587,022     5,322,524  

Debt to capital ratio:

                               

Gross(5)

    0.47:1     0.40:1     0.42:1     0.45:1     0.45:1  

Net(6)

    0.44:1     0.36:1     0.38:1     0.42:1     0.41:1  

(1)
All periods present the operating activities of most 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 2TD (October 2014), KVS (October 2013), Navigate Energy Services, Inc. (January 2013), Peak (July 2011), Stone Mountain Venture Partnership (June 2011), Energy Contractors (December 2010) and Superior Well Services, Inc. (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 and 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 generally accepted accounting principles 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

        The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with, our consolidated financial statements and the related notes thereto included under Part II, Item 8.—Financial Statements and Supplementary Data. This discussion and analysis contains forward-looking statements that involve risks and uncertainties. Actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under Part 1A.—Risk Factors and elsewhere in this annual report. See "Forward-Looking Statements."

Management Overview

        We own and operate the world's largest land-based drilling rig fleet and have one of the largest completion services and well-servicing and workover rig fleets in North America. We are a leading provider of offshore platform workover and drilling rigs in the United States and multiple international markets. The majority of our business is conducted through two business lines:

    Drilling & Rig Services

        The Drilling & Rig Services business line is comprised of our global land-based and offshore drilling rig operations and other rig services, consisting of equipment manufacturing, rig instrumentation, optimization software and directional drilling services. This business line consists of four operating segments: U.S., Canada, International and Rig Services.

    Completion & Production Services

        Our Completion & Production Services business line is comprised of our operations involved in the completion, life-of-well maintenance and plugging and abandonment of a well in the United States and Canada. These services include stimulation, coiled-tubing, cementing, wireline, workover, well-servicing and fluids management. This business line consists of two operating segments: Completion Services and Production Services. We expect to merge this business line with CJES by the end of the first quarter of 2015, as described under Part 1, Item 1.—Business—Overview.

Outlook

        The demand for our services is a function of the level of spending by oil and gas companies for exploration, development and production activities. The primary driver of customer spending is their cash flow and earnings which are largely driven by oil and natural gas prices. The oil and natural gas markets have traditionally been volatile and tend to be highly sensitive to supply and demand cycles.

        The following table sets forth the 12-month daily average of oil and natural gas prices according to Bloomberg for the last three fiscal years:

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  

Commodity prices:

                                           

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

  $ 4.35   $ 3.72   $ 2.75   $ 0.63     17 % $ 0.97     35 %

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

  $ 93.03   $ 98.02   $ 94.10   $ (4.99 )   (5 )% $ 3.92     4 %

        During the latter part of 2014, the markets experienced a dramatic decline in oil prices which have remained depressed into 2015 due, at least in part, to an increase in global crude supply with stagnant demand. While the average oil price for 2014 appears to have remained in line with that of 2013, a

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significant drop was experienced in the fourth quarter of 2014 reaching a low for 2014 of $53.27 per barrel in December. Oil prices remain depressed, averaging $47.61 per barrel during the month of January 2015. Natural gas prices, which averaged $4.35 per mcf during 2014, have also experienced a recent decline in early 2015, although less severe than oil prices. Natural gas prices averaged $2.97 per mcf during the month of January 2015, down 31% from the proceeding 12-month daily average and still significantly below the 2008 average price of $8.89 for an extended period of time.

        As a result of the reduced price of oil, we have experienced a decline in the demand for drilling and completion services as customers have begun reducing or curtailing their capital spending and drilling activities. The reduction in demand for drilling services, coupled with the increased supply of newly built high specification rigs in the drilling market, has led to a highly competitive market for all rigs, including high specification rigs. This has accelerated the under-utilization of our legacy rig fleet (non AC rigs). We have also experienced downward pricing pressure for our services.

        Due to the aforementioned factors, we have recently experienced a decline in our dayrates as well as the average number of rigs operating. While the recent decline in industry conditions, as a whole, did not materially impact our operating results for fiscal year 2014, we anticipate operating results for 2015 to decrease from levels realized in 2014 given our current expectation of the continuation of lower commodity prices and the related impact on drilling, completion and well-servicing activity and dayrates. The decrease in drilling activity and dayrates is expected to have a significant impact on our Drilling & Rig Services operating segment, most notably in the lower 48. We expect our International operations to remain steady during 2015, resulting from the recent deployment of additional new rigs, throughout 2014 and early 2015, all of which are under long-term contracts.

Financial Results

        During 2014, our income (loss) from continuing operations was adversely affected by approximately $1.03 billion in impairments and other charges. Net loss from continuing operations totaled $669.3 million for 2014 ($2.28 per diluted share) compared to net income from continuing operations of $158.3 million ($0.51 per diluted share) in 2013.

        The impairments and retirement provisions stemmed from the sharp decline in crude oil prices during the fourth quarter of 2014 and the resulting impact on our customers' spending programs and demand for our services. The impairments and retirement provisions were comprised of approximately $611.6 million in charges related to drilling rigs and rig equipment and $386.5 million in impairments to our goodwill and intangible assets. The goodwill and intangible assets were primarily attributable to our Completion Services operating segment from the acquisition of Superior Well Services, Inc. ("Superior") in 2010.

        Of the $611.6 million in charges related to our drilling rigs and rig equipment, the majority is attributable to retirements and impairments to our lower 48 legacy rig fleet (non AC rigs), including the functional retirement of 25 mechanical rigs, an impairment to the SCR fleet and the resultant reduction in yard assets and spare rig components due to reduced operating fleet size. The balance is attributable to charges for the impairment or retirement of our jack-up rig fleet in the Gulf of Mexico, our coil tubing drilling rigs in Canada and various other under-performing rigs and related equipment in Canada and our international markets.

        Excluding these items, our operating results increased in 2014 over 2013. Operating revenues and Earnings (losses) from unconsolidated affiliates in 2014 totaled $6.8 billion, representing an increase of $645.8 million, or 10%, over 2013. The increase in revenues was driven by increases from virtually all of our operating segments with the exception of Canada Drilling. Adjusted income derived from operating activities for 2014 totaled $598.0 million, representing an increase of $40.0 million, or 7%, over 2013. This increase was driven primarily by our U.S. and International Drilling and Rig Services segments, which more than offset declines in our Completion and Production Services and Canada Drilling

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segments. Operating revenues and Earnings (losses) from unconsolidated affiliates for 2013 totaled $6.2 billion, representing a decrease of $402.3 million, or 6%, from 2012. Adjusted income derived from operating activities for 2013 totaled $558.2 million, representing a decrease of 39% from 2012.

        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 higher 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 $160.0 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.

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

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  
 
  (In thousands, except percentages and rig activity)
 

Reportable segments:

                                           

Operating revenues and Earnings (losses) from unconsolidated affiliates

                                           

Drilling & Rig Services:

                                           

U.S. 

  $ 2,159,968   $ 1,914,786   $ 2,276,808   $ 245,182     13 % $ (362,022 )   (16 )%

Canada

    335,192     361,676     429,411     (26,484 )   (7 )%   (67,735 )   (16 )%

International

    1,623,102     1,464,264     1,265,060     158,838     11 %   199,204     16 %

Rig Services(2)

    687,302     516,004     688,310     171,298     33 %   (172,306 )   (25 )%

Subtotal Drilling & Rig Services(3)

    4,805,564     4,256,730     4,659,589     548,834     13 %   (402,859 )   (9 )%

Completion & Production Services:

                                           

Completion Services

    1,218,361     1,074,713     1,462,767     143,648     13 %   (388,054 )   (27 )%

Production Services

    1,033,538     1,009,214     1,000,873     24,324     2 %   8,341     1 %

Subtotal Completion & Production Services(4)

    2,251,899     2,083,927     2,463,640     167,972     8 %   (379,713 )   (15 )%

Other reconciling items(5)(7)

    (259,567 )   (188,603 )   (568,896 )   (70,964 )   (38 )%   380,293     67 %

Total

  $ 6,797,896   $ 6,152,054   $ 6,554,333   $ 645,842     10 % $ (402,279 )   (6 )%

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  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  
 
  (In thousands, except percentages and rig activity)
 

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

                                           

Drilling & Rig Services:

                                           

U.S. 

  $ 370,173   $ 315,496   $ 509,894   $ 54,677     17 % $ (194,398 )   (38 )%

Canada

    52,468     61,193     91,360     (8,725 )   (14 )%   (30,167 )   (33 )%

International

    242,818     177,833     91,226     64,985     37 %   86,607     95 %

Rig Services(2)

    47,768     (3,918 )   67,366     51,686     n/m (8)   (71,284 )   (106 )%

Subtotal Drilling & Rig Services(3)

    713,227     550,604     759,846     162,623     30 %   (209,242 )   (28 )%

Completion & Production Services:

                                           

Completion Services

    (15,078 )   51,722     188,518     (66,800 )   (129 )%   (136,796 )   (73 )%

Production Services

    93,414     102,130     108,835     (8,716 )   (9 )%   (6,705 )   (6 )%

Subtotal Completion & Production Services(4)

    78,336     153,852     297,353     (75,516 )   (49 )%   (143,501 )   (48 )%

Other reconciling items(7)

    (193,565 )   (146,237 )   (148,649 )   (47,328 )   (32 )%   2,412     2 %

Total adjusted income (loss) derived from operating activities            

  $ 597,998   $ 558,219   $ 908,550   $ 39,779     7 % $ (350,331 )   (39 )%

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

            (289,199 )           289,199     100 %

Interest expense

    (177,948 )   (223,418 )   (251,904 )   45,470     20 %   28,486     11 %

Investment income (loss)

    11,831     96,577     63,137     (84,746 )   (88 )%   33,440     53 %

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

    (9,073 )   (37,977 )   136,636     28,904     76 %   (174,613 )   (128 )%

Impairments and other charges

    (1,027,423 )   (287,241 )   (290,260 )   (740,182 )   (258 )%   3,019     1 %

Income (loss) from continuing operations before income taxes

    (604,615 )   106,160     276,960     (710,775 )   (670 )%   (170,800 )   (62 )%

Income tax expense (benefit)

    62,666     (55,181 )   40,986     117,847     214 %   (96,167 )   (235 )%

Subsidiary preferred stock dividend

    1,984     3,000     3,000     (1,016 )   (34 )%        

Income (loss) from continuing operations, net of tax

    (669,265 )   158,341     232,974     (827,606 )   (523 )%   (74,633 )   (32 )%

Income (loss) from discontinued operations, net of tax

    21     (11,179 )   (67,526 )   11,200     100 %   56,347     83 %

Net income (loss)

    (669,244 )   147,162     165,448     (816,406 )   (555 )%   (18,286 )   (11 )%

Less: Net (income) loss attributable to noncontrolling interest            

    (1,415 )   (7,180 )   (621 )   5,765     80 %   (6,559 )   n/m (8)

Net income (loss) attributable to Nabors

  $ (670,659 ) $ 139,982   $ 164,827   $ (810,641 )   (579 )% $ (24,845 )   (15 )%

Rig activity:

                                           

Rig years:(9)

                                           

U.S. 

    212.5     195.0     219.1     17.5     9 %   (24.1 )   (11 )%

Canada

    34.1     29.9     34.8     4.2     14 %   (4.9 )   (14 )%

International(10)

    127.1     124.2     119.3     2.9     2 %   4.9     4 %

Total rig years

    373.7     349.1     373.2     24.6     7 %   (24.1 )   (6 )%

Rig hours:(11)

                                           

Production Services

    809,438     865,939     853,373     (56,501 )   (7 )%   12,566     1 %

Canada Production Services

    139,938     152,747     181,185     (12,809 )   (8 )%   (28,438 )   (16 )%

Total rig hours

    949,376     1,018,686     1,034,558     (69,310 )   (7 )%   (15,872 )   (2 )%

(1)
All periods present the operating activities of most 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)
Includes our other services comprised of our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software services.

(3)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of ($6.8) million and ($0.4) million for the years ended December 31, 2014 and 2013, respectively.

(4)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $0.5 million, $0.4 million, and $0.5 million for the years ended December 31, 2014, 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 for the year ended December 31, 2012.

(6)
Adjusted income (loss) derived from operating activities is computed by subtracting the sum of direct costs, general and administrative expenses, depreciation and amortization from the sum of Operating revenues and Earnings (losses) from unconsolidated affiliates. Adjusted income (loss) derived from operating activities is a non-GAAP measure and should not be used in isolation 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 include our equivalent percentage ownership of rigs owned by unconsolidated affiliates, which totaled 2.5 years in 2014, 2013 and 2012.

(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 four operating segments: U.S., Canada, International and Rig Services. For a description of this business line and its operating segments, see Part I, Item 1.—Business—Drilling & Rig Services. The following table presents our revenues, adjusted income and rig years by operating segment, as applicable, for the years ended December 31, 2014, 2013 and 2012.

 
  Years Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  
 
  (In thousands, except percentages and rig activity)
 

U.S.

                                           

Revenues

  $ 2,159,968   $ 1,914,786   $ 2,276,808   $ 245,182     13 % $ (362,022 )   (16 )%

Adjusted income

  $ 370,173   $ 315,496   $ 509,894   $ 54,677     17 % $ (194,398 )   (38 )%

Rig years

    212.5     195.0     219.1     17.5     9 %   (24.1 )   (11 )%

Canada

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 335,192   $ 361,676   $ 429,411   $ (26,484 )   (7 )% $ (67,735 )   (16 )%

Adjusted income

  $ 52,468   $ 61,193   $ 91,360   $ (8,725 )   (14 )% $ (30,167 )   (33 )%

Rig years

    34.1     29.9     34.8     4.2     14 %   (4.9 )   (14 )%

International

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 1,623,102   $ 1,464,264   $ 1,265,060   $ 158,838     11 % $ 199,204     16 %

Adjusted income

  $ 242,818   $ 177,833   $ 91,226   $ 64,985     37 % $ 86,607     95 %

Rig years

    127.1     124.2     119.3     2.9     2 %   4.9     4 %

Rig Services

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 687,302   $ 516,004   $ 688,310   $ 171,298     33 % $ (172,306 )   (25 )%

Adjusted income (loss)

  $ 47,768   $ (3,918 ) $ 67,366   $ 51,686     n/m (1) $ (71,284 )   (106 )%

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

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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 increased from 2013 to 2014 primarily due to an increase in drilling activity and dayrates in the lower 48 states. We deployed approximately 16 new PACE®-X rigs into service in 2014, bringing our total operating fleet of PACE®-X rigs to 32. The deployment of these newly built rigs was the primary factor for the increase in 2014 of rig years (a measure of activity and utilization), operating revenues and adjusted income.

        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.

    Canada

        Operating results decreased slightly from 2013 to 2014 primarily due to an unfavorable foreign exchange variance. The Canadian dollar weakened approximately 7% against the U.S. dollar. In addition, the Canadian operations were impacted by a decline in average drilling dayrates. These decreases were partially offset by streamlining activities and cost saving initiatives.

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

    International

        Operating results increased from 2013 to 2014 primarily as a result of higher dayrates from existing land rigs in Algeria, Colombia, Northern Iraq, Russia and Saudi Arabia and as well as newly built rig deployments in Saudi Arabia and Argentina. These increases were partially offset by decreased land drilling activity in Mexico.

        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 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.

    Rig Services

        Operating results increased from 2013 to 2014 primarily due to higher demand in the United States and Canada drilling markets for top drives, rig instrumentation and data collection services from oil and gas exploration companies, along with higher third-party rental and RIGWATCH® units, which generate higher margins. These increases were partially offset by the continued decline in financial results in our directional drilling businesses due to intense competition.

        Operating results decreased from 2012 to 2013 primarily due to 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 RIGWATCH® units, which generate higher margins.

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Completion & Production Services

        Our Completion & Production Services business line is comprised of two operating segments: Completion Services and Production Services. For a description of this business line and its operating segments, see Part I, Item 1.—Business—Completion & Production Services. The following table presents our revenues and adjusted income by operating segment, and rig hours by geographic region, for the years ended December 31, 2014, 2013 and 2012.

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  
 
  (In thousands, except percentages and rig activity)
 

Completion Services

                                           

Revenues

  $ 1,218,361   $ 1,074,713   $ 1,462,767   $ 143,648     13 % $ (388,054 )   (27 )%

Adjusted income

  $ (15,078 ) $ 51,722   $ 188,518   $ (66,800 )   (129 )% $ (136,796 )   (73 )%

Production Services

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Revenues

  $ 1,033,538   $ 1,009,214   $ 1,000,873   $ 24,324     2 % $ 8,341     1 %

Adjusted income

  $ 93,414   $ 102,130   $ 108,835   $ (8,716 )   (9 )% $ (6,705 )   (6 )%

Rig hours

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

U.S. 

    809,438     865,939     853,373     (56,501 )   (7 )%   12,566     1 %

Canada

    139,938     152,747     181,185     (12,809 )   (8 )%   (28,438 )   (16 )%

    949,376     1,018,686     1,034,558     (69,310 )   (7 )%   (15,872 )   (2 )%

    Completion Services

        Operating revenues increased by $143.6 million, or 13%, from 2013 to 2014 due to a significant increase in activity levels, due in part to a move toward 24 hour operations. However, adjusted income decreased from 2013 to 2014 due to lower prices for our services primarily caused by the expiration of several multi-year take-or-pay contracts and downward pricing pressure across all regions. Severe weather in our northern operating areas in the first half of the year also negatively affected operating results.

        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.

    Production Services

        Operating results decreased from 2013 to 2014 primarily due to reduced activity levels for workover rigs in California caused by reduced customer activity and in West Texas due to rain and wet conditions in the third quarter of the year. These decreases in activity were partially offset by incremental revenue and income associated with a full year's contribution from our acquisition of KVS during the fourth quarter of 2013.

        Operating results were essentially flat to slightly down from 2012 to 2013 due to higher depreciation and other costs associated with our rig and truck fleet, as a result of capital invested over the past few years to increase those fleets. This was partially offset by the increase in revenue associated with our acquisition of KVS. Additionally, 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.

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OTHER FINANCIAL INFORMATION

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  
 
  (In thousands, except percentages)
 

General and administrative expenses

  $ 549,734   $ 525,330   $ 527,953   $ 24,404     5 % $ (2,623 )   (0 )%

As a percentage of operating revenue

    8.1 %   8.5 %   8.1 %   (0.5 )%   (5.3 )%   0.5 %   6.0 %

Depreciation and amortization

    1,145,100     1,086,677     1,039,923     58,423     5 %   46,754     4 %

Interest expense

    177,948     223,418     251,904     (45,470 )   (20 )%   (28,486 )   (11 )%

Investment income

    11,831     96,577     63,137     (84,746 )   (88 )%   33,440     53 %

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

    9,073     37,977     (136,636 )   (28,904 )   (76 )%   174,613     128 %

    General and administrative expenses

        General and administrative expenses increased slightly from 2013 to 2014 primarily as a result of increased activity across the operating units, particularly within our U.S. and International drilling segments. As a percentage of operating revenues, general and administrative expenses are comparable for each period relative to fluctuations in activity levels.

        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 are comparable for each period relative to fluctuations in activity levels.

    Depreciation and amortization

        Depreciation and amortization expense increased from 2013 to 2014 and from 2012 to 2013 as a result of the incremental depreciation expense related to newly constructed rigs placed into service during 2013 and 2014, and to a lesser extent, rig upgrades and other capital expenditures.

    Interest expense

        Interest expense decreased from 2013 to 2014 primarily as a result of the redemptions of some of our 9.25% senior notes in September 2013. During 2014, our average outstanding debt balances were similar to the levels of debt outstanding during 2013. However, our average interest rates were lower on those outstanding balances, primarily due to replacing the high coupon 9.25% senior notes in September 2013, with the issuance of $700 million aggregate principal senior notes at lower coupon rates of 2.35% and 5.10%. Additionally, we expanded the use of our low cost commercial paper program during 2014, resulting in a favorable mix between balances outstanding on the revolving line of credit and commercial paper.

        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.

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    Investment income

        Investment income during 2014 was $11.8 million and included $5.6 million of realized gains from short-term and other long-term investments and $6.2 million in interest and dividend income.

        Investment income during 2013 was $96.6 million and included $89.0 million of realized gains from short-term and other long-term investments and net gains of $2.5 million from our trading securities. The balance was attributable to $5.1 million in interest and dividend income.

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

    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 2014 was a net loss of $9.1 million, which was primarily comprised of (i) increases to litigation reserves of $8.9 million, (ii) losses on debt buybacks of $5.6 million and (iii) foreign currency exchange losses of $1.0 million. These losses were partially offset by the net gain on sales and disposals of assets of approximately $8.8 million.

        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, (iii) foreign currency exchange losses of $6.2 million and (iv) losses on debt buybacks of $3.8 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.

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    Impairments and Other Charges

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  
 
  (In thousands, except percentages)
 

Tangible Assets & Equipment:

                                           

Provision for retirement of assets

  $ 393,962   $ 14,044   $ 138,666   $ 379,918     n/m (1) $ (124,622 )   (90 )%

Impairment of long-lived assets

    217,627     20,000     50,355     197,627     n/m (1)   (30,355 )   (60 )%

Subtotal

    611,589     34,044     189,021     577,545     n/m (1)   (154,977 )   (82 )%

Goodwill & Intangible Assets:

                                           

Goodwill impairments

    356,605         26,279     356,605     100 %   (26,279 )   (100 )%

Intangible asset impairment

    29,942         74,960     29,942     100 %   (74,960 )   (100 )%

Subtotal

    386,547         101,239     386,547     100 %   (101,239 )   (100 )%

Other Charges:

                                           

Transaction costs

    22,313             22,313     100 %        

Other-than-temporary impairment on equity security

    6,974             6,974     100 %        

Loss on tendered notes

        208,197         (208,197 )   (100 )%   208,197     100 %

Termination of employment contract

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

Total

  $ 1,027,423   $ 287,241   $ 290,260   $ 740,182     258 % $ (3,019 )   (1 )%

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

For the year ended December 31, 2014

Tangible Assets and Equipment

        The following table summarizes the 2014 retirement and impairment charges for tangible assets and equipment by operating segment:

 
  Provision for
Retirements
  Tangible Asset
Impairments
  Total  

Drilling & Rig Services:

                   

U.S. 

  $ 271,141   $ 137,000   $ 408,141  

Canada

    24,211     10,176     34,387  

International

    56,472     70,451     126,923  

Rig Services

    42,138         42,138  

Total

  $ 393,962   $ 217,627   $ 611,589  

        Approximately two-thirds of the 2014 charges from drilling rigs and rig equipment is related to the U.S. lower 48 legacy rig fleet. Given the recent sharp decline in crude oil prices and the resultant impact on our customers' spending programs that we have experienced or are expecting for 2015, and the disproportionate impact of the reduced activity that we believe our legacy rig fleet will absorb, we have retired 25 mechanical rigs and impaired our fleet of SCR rigs, including the resultant retirement of and reduction in yard assets and spare rig components associated with a reduced overall size of our working rig fleet.

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        Also included in the 2014 charges for our U.S. drilling rigs and rig equipment is a retirement provision of approximately $54.4 million for our Gulf of Mexico jackup fleet. This market has been challenged for the past several years and we believe the drop in oil prices will exacerbate the lack of demand for these rigs. The majority of these rigs would require substantial amounts of capital in order for them to be operable again.

        The balance of the drilling rigs and rig equipment charges relate to our coil tubing drilling rig fleet in Canada and various under-utilized or under-performing rigs or asset classes throughout our International and Canada drilling fleets.

Goodwill and Intangible Assets

        During 2014, we recognized an impairment of goodwill totaling $356.6 million, the majority of which was for the remaining goodwill balance of $335.0 million in our Completion Services operating segment related to the acquisition of Superior in 2010. We expect to merge this operating segment with CJES, and the value attributable to the transaction has declined sharply beginning in the fourth quarter of 2014, with a drop in the market price of CJES's stock and the agreed upon reduction to the amount of cash we expect to receive from this transaction. The combination of these events and a sharp decline in the market price of our stock, led us to believe that a triggering event had occurred in the fourth quarter of 2014, and we performed an impairment test on our remaining goodwill balances. We determined that our Completion Services goodwill balances should be fully impaired. The balance of the impairment relates to $21.6 million in goodwill related to Ryan Directional Services, Inc. ("Ryan") our directional drilling operations included in our Rig Services operating segment. The recent decline in oil prices and the impact it is having on our businesses, along with the lack of certainty surrounding an eventual recovery, led us to impair these goodwill balances. A prolonged period of lower natural gas or oil prices could continue to adversely affect demand for our services and lead to further goodwill impairment charges for other operating units in the future.

        Additionally, during 2014, we recognized an impairment of $29.9 million primarily related to various intangible assets, such as customer relationships within our Completion & Production Services and Rig Services operating segments related to previous acquisitions.

Transaction costs

        During 2014, we incurred $22.3 million in transaction costs related to the Merger with CJES, including professional fees and other costs incurred to reorganize the business in contemplation of the Merger.

Other-than-temporary impairment

        During 2014, we recorded an other-than-temporary impairment of $7.0 million related to an equity security. Because the trading price of this security remained below our cost basis for an extended period, we determined the investment was other than temporarily impaired and it was appropriate to write down the investment's carrying value to its current estimated fair value.

For the years ended December 31, 2013 and 2012

Provision for retirement of long-lived 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 Services operations, the retirements related to rigs and vehicles that would require significant repair to return to work and other non-core assets.

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        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 retired some non-core assets.

Impairments 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.

        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.

Goodwill impairments

        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.

        There were no goodwill impairments in 2013.

Intangible asset impairment

        During 2012, we recorded an 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 was 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 impairments in 2013.

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 for additional discussion. In 2013, we completed a cash tender offer for these notes and repurchased $785.4 million aggregate principal amount. We paid the holders an aggregate of approximately $1.0 billion in cash, reflecting principal and accrued and unpaid interest and prepayment premium and recognized a loss as part of the debt extinguishment.

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Provision for 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 for additional discussion.

    Income tax rate

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  

Effective income tax rate from continuing operations

    (10.4 )%   (52.0 )%   14.8 %   (42 )%   (80 )%   (67 )%   (451 )%

        The change in our worldwide effective tax rate from 2013 to 2014 is primarily attributable to the tax effect related to impairments and internal restructuring. The change in geographic mix of pre-tax earnings also contributed to the change.

        The change in our worldwide effective tax rate from 2012 to 2013 resulted mainly from the geographic mix of pre-tax earnings and settlements of tax disputes.

    Assets Held-for-Sale

 
  As of December 31,  
 
  2014   2013  
 
  (In thousands)
 

Oil and Gas

  $ 146,467   $ 239,936  

Other Rig Services

        3,328  

  $ 146,467   $ 243,264  

        Assets held for sale as of December 31, 2014 consisted solely of our oil and gas holdings in the Horn River basin in western Canada.

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, 2014, our undiscounted contractual commitments for these contracts approximated $84.6 million, and we had liabilities of $40.2 million, $19.6 million of which were classified as current and are included in accrued liabilities.

        At December 31, 2013, our undiscounted contractual commitments for these contracts 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.

        The amounts at each balance sheet date 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

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the pipeline over the remaining contractual term. Decreases in actual production or natural gas prices could result in future charges related to excess pipeline commitments.

    Discontinued Operations

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

 
  Year Ended December 31,   Increase/(Decrease)  
 
  2014   2013   2012   2014 to 2013   2013 to 2012  
 
  (In thousands, except percentages)
 

Operating revenues

                                           

Oil and Gas

  $ 13,143   $ 25,327   $ 27,363   $ (12,184 )   (48 )% $ (2,036 )   (7 )%

Rig Services

  $   $ 127,154   $ 172,335   $ (127,154 )   (100 )% $ (45,181 )   (26 )%

Income (loss) from discontinued operations:

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Oil and Gas

  $ 21   $ (27,396) (1)   (66,033) (2) $ 27,417     100 % $ 38,637     59 %

Rig Services

  $   $ 16,217 (3)   (1,493) (4) $ (16,217 )   (100 )% $ 17,710     n/m (5)

Oil and Gas

(1)
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.

(2)
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.

Rig Services

(3)
Includes a gain recognized from the sale of Peak, one of our businesses in Alaska, for which we received cash proceeds of $135.5 million.

(4)
Includes $7.8 million of impairment (a Level 3 measurement) in 2012 to our aircraft and logistics assets as a result of the continued downturn in the oil and gas industry in Canada.

(5)
Number is so large that it is not meaningful.

        During 2014, we sold a large portion of our interest in oil and gas proved properties located on the North Slope of Alaska. Under the terms of the agreement, we received $35.1 million at closing and expect to receive additional payments of $27.0 million upon certain future dates or the properties achieving certain production targets. We retained a working interest at various interests and an overriding royalty interest in the properties at various interests. The working interest is fully carried up to $600 million of total project costs. The transaction generally remains subject to approval of local Alaska regulatory authorities, among other usual and customary conditions. The $22.2 million gain from the transaction is included in losses (gains) on sales and disposals of long-lived assets and other expense (income), net in our consolidated statements of income (loss) for the twelve months ended December 31, 2014. The retained interest, which is valued at approximately $26.2 million, is no longer classified as assets-held-for-sale and is included in other long-term assets. We have not recast prior period results as the balances are not material to our consolidated statements of income (loss) for any period

        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

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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.

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 2014 and 2013 cash flows below.

        Operating Activities.    Net cash provided by operating activities totaled $1.8 billion during 2014, compared to net cash provided by operating activities of $1.4 billion during 2013. 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 $1.3 billion and $1.4 billion in 2014 and 2013, 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 $487.8 million and $2.9 million, respectively, in cash flows during 2014 and 2013, respectively.

        Investing Activities.    Net cash used for investing activities totaled $1.7 billion during 2014 compared to net cash used for investing activities of $815.5 million in 2013. 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 2014 and 2013, we used cash for capital expenditures totaling $1.8 billion and $1.2 billion, respectively.

        In 2014, we used cash of $40.3 million to purchase 2TD. We also received $156.8 million in proceeds from sales of our oil and gas assets, other non-core operations and insurance claims.

        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.

        Financing Activities.    Net cash provided by financing activities totaled $69.8 million during 2014. In 2014, we repaid net amounts of $27.7 million under our commercial paper program and revolving credit facility. During 2014, we paid cash dividends of $59.1 million.

        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.

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    Future Cash Requirements

        We expect capital expenditures over the next 12 months to approximate $1.0—$1.2 billion. Purchase commitments outstanding at December 31, 2014 totaled approximately $1.1 billion, 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 have the ability to reduce the planned expenditures if necessary or increase them if market conditions and new business opportunities warrant it. In light of the recent decline in crude oil prices, we have already undertaken many cost cutting initiatives in an effort to minimize the negative impact to our business. We have undertaken efforts to reduce capital expenditures, operating costs and administrative expenses. Since the last downturn in 2009, we have strengthened our financial flexibility by streamlining operations, shedding non-core businesses and reducing net debt and interest expense.

        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.

        During 2014, with approval of the Board, we purchased 10.375 million of our common shares, at $24.10 per share, for a total aggregate amount of approximately $250 million. This purchase was an isolated event and was not part of a broader Board approved repurchase program. The Board continuously seeks to increase returns to shareholders, and as a result, this could lead to additional repurchases in the future, although we do not have a plan in place to do so at this time.

        We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, both in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors and may involve material amounts.

        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)".

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        The following table summarizes our contractual cash obligations as of December 31, 2014:

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

Contractual cash obligations:

                               

Long-term debt:(1)

                               

Principal

  $ 4,357,098   $   $ 1,333,119 (2) $ 1,273,979 (3) $ 1,750,000 (4)

Interest

    985,488     192,009     375,911     246,328     171,240  

Operating leases(5)

    96,364     22,740     23,508     10,107     40,009  

Purchase commitments(6)

    1,062,283     1,042,490     19,793          

Employment contracts(5)

    19,114     6,887     10,727     1,500      

Pension funding obligations

    886     886              

Transportation and processing contracts(5)(7)

    84,580     21,938     21,743     16,815     24,084  

The table above excludes liabilities for uncertain tax positions totaling $56.5 million as of December 31, 2014 because we are unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the uncertain tax positions 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, commercial paper and amounts drawn on our revolving credit facility, which expires November 2017.

(3)
Represents Nabors Delaware's aggregate 6.15% senior notes due February 2018 and 9.25% senior notes due January 2019.

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

(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, 2014, our Board declared a cash dividend of $0.06 per common share. This quarterly cash dividend was paid on December 31, 2014 to shareholders of record on December 10, 2014. During the year ended December 31, 2014, we paid cash dividends totaling $59.1 million. See Item 5.—Market Price of and Dividends on the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity—Dividends.

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, 2014, we had cash and short-term investments of $536.2 million and working capital of $1.2 billion. As of

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December 31, 2013, we had cash and short-term investments of $507.1 million and working capital of $1.4 billion. At December 31, 2014, we had $516.9 million of availability remaining under our $1.5 billion revolving credit facility and commercial paper program.

        In February 2015, we exercised an option under our revolving credit facility to increase the borrowing capacity by $225.0 million. In addition, Nabors Industries, Inc., our wholly owned subsidiary, entered into a new unsecured term loan facility for $300.0 million with a three-year maturity, which is fully and unconditionally guaranteed by us. As a result, our total available borrowing capacity increased by $525.0 million, effectively bringing our availability in excess of $1.0 billion as of the date of this report. Under the new term loan facility, we are required to prepay the loan upon the closing of the Merger, or if we otherwise dispose of assets, issue term debt, or issue equity with net proceeds of more than $70.0 million, subject to certain exceptions. The term loan agreement contains customary representations and warranties, covenants, and events of default for loan facilities of this type.

        We had 11 letter-of-credit facilities with various banks as of December 31, 2014. Availability under these facilities as of December 31, 2014 was as follows:

 
  December 31,
2014
 
 
  (In thousands)
 

Credit available

  $ 650,204  

Less: Letters of credit outstanding, inclusive of financial and performance guarantees

    326,650  

Remaining availability

  $ 323,554  

        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 0.47:1 as of December 31, 2014 and 0.40:1 as of December 31, 2013, respectively. Our net debt to capital ratio was 0.44:1 as of December 31, 2014 and 0.36:1 as of December 31, 2013. 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 9.8:1 as of December 31, 2014 and 7.4:1 as of December 31, 2013. 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.

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Off-Balance Sheet Arrangements (Including Guarantees)

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

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

 
  Maximum Amount  
 
  2015   2016   2017   Thereafter   Total  
 
  (In thousands)
 

Financial standby letters of credit and other financial surety instruments

  $ 191,015     75     18       $ 191,108  

    Critical Accounting Estimates

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

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

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

        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

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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 72% of our total assets as of December 31, 2014, and depreciation and amortization constituted 15% of our total costs and other deductions in 2014.

        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 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, 2014, 2013 and 2012, no significant changes have been made to the depreciation rates applied to property, plant and equipment, the underlying assumptions related to estimates of depreciation, or the methodology applied. However, certain events could occur that would materially affect our estimates and assumptions related to depreciation. Unforeseen changes in operations or technology could substantially alter management's assumptions regarding our ability to realize the return on our investment in operating assets and therefore affect the useful lives and salvage values of our assets.

        Impairment of Long-Lived Assets.    As discussed above, the drilling, workover and well-servicing and pressure pumping industry is very capital intensive. We review our assets for impairment when events or changes in circumstances indicate that 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.

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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 2014, 2013 and 2012, 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.

        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. We perform our impairment tests for goodwill 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 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.

        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.    We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We are currently contesting tax assessments throughout the world and may contest future assessments. We believe the ultimate resolution of the outstanding assessments, for which we have not made any accrual, will not have a material adverse effect on our consolidated financial statements. We recognize uncertain tax positions that we believe have a greater than 50 percent likelihood of being

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sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments.

        Audit claims of approximately $209.5 million attributable to income, customs and other business taxes have been assessed against us. We have contested, or intend to contest, these assessments, including through litigation if necessary, and we believe the ultimate resolution, for which we have not made any accrual, will not have a material adverse effect on our consolidated financial statements. Tax authorities may issue additional assessments or pursue legal actions as a result of tax audits and we cannot predict or provide assurance as to the ultimate outcome of such assessments and legal actions.

        Applicable income and withholding taxes have not been provided on undistributed earnings of our subsidiaries. We do not intend to repatriate such undistributed earnings except for distributions upon which incremental income and withholding taxes would not be material.

        In certain jurisdictions we have recognized deferred tax assets and liabilities. Judgment and assumptions are required in determining whether deferred tax assets will be fully or partially utilized. When we estimate that all or some portion of certain deferred tax assets such as net operating loss carryforwards will not be utilized, we establish a valuation allowance for the amount ascertained to be unrealizable. We continually evaluate strategies that could allow for future utilization of our deferred assets. Any change in the ability to utilize such deferred assets will be accounted for in the period of the event affecting the valuation allowance. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting adjustments could have a material effect on our financial results or cash flow.

        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 or acts of terrorism, 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 recorded in our financial statements for claims have historically been reasonable in light of the actual amount of claims paid.

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        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 2014, 2013 and 2012, no significant changes were made to the methodology used to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2014 reserves were adjusted by 10%, total costs and other deductions would change by $16.1 million, or 0.2%.

        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 2014, 2013 and 2012, 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.

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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, 2014 would result in a $12.2 million decrease in the fair value of our net monetary assets denominated in currencies other than U.S. dollars.

        Credit Risk.    Our financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash equivalents, short-term and long-term investments 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 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 counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty would owe us, which can create credit risk for us. When the fair value of a derivative contract is negative, we would owe the counterparty, and therefore, we would not be exposed to credit risk. We attempt to minimize credit risk in derivative instruments by entering into transactions with major financial institutions that have a significant asset base. Market risk related to derivatives is the adverse effect on the value of a financial instrument that results from changes in interest rates. We try to manage market risk associated with

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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,  
 
  2014   2013  
 
  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 % $ 349,887   $ 346,980     2.56 % $ 349,820   $ 354,694  

6.15% senior notes due February 2018

    6.42 %   930,693     991,920     6.42 %   969,928     1,097,480  

9.25% senior notes due January 2019

    9.33 %   339,607     403,531     9.33 %   339,607     428,733  

5.00% senior notes due September 2020

    5.20 %   698,253     687,953     5.20 %   697,947     731,955  

4.625% senior notes due September 2021

    4.75 %   698,388     661,619     4.75 %   698,148     709,793  

5.10% senior notes due September 2023

    5.26 %   348,893     332,759     5.26 %   348,765     349,731  

Subsidiary preferred stock

    0.00 %           4.00 %   69,188     69,000  

Revolving credit facility

    3.47 %   450,000     450,000     2.28 %   170,000     170,000  

Commercial paper

    0.59 %   533,119     533,119     0.45 %   329,844     329,844  

Other

    0.00 %   6,209     6,209     0.00 %   10,243     10,243  

Total

        $ 4,355,049   $ 4,414,090         $ 3,983,490   $ 4,251,473  

        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,

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short-term and long-term investments and other receivables as of December 31, 2014 and 2013 are included in the table below:

 
  December 31,  
 
  2014   2013  
 
  Fair
Value
  Interest
Rates
  Weighted-
Average
Life
(Years)
  Fair
Value
  Interest
Rates
  Weighted-
Average
Life
(Years)
 
 
  (In thousands, except rates)
 

Cash and cash equivalents

  $ 501,149   0.01 - 0.25%       $ 389,915   0 - .25%      

Short-term investments:

                                 

Trading equity securities

                     

Available-for-sale equity securities

    35,002           96,942        

Available-for-sale debt securities:

                                 

Commercial paper and CDs

                     

Corporate debt securities

      0.0 - 0.0%         19,388   10.0 - 11.52%     6.2  

Mortgage-backed debt securities

      0.00%         210   2.39%     11.8  

Mortgage-CMO debt securities

    18   2.39 - 2.73%     5.6     20   2.41 - 2.58%     4.9  

Asset-backed debt securities

      0.0 - 0.0%         658   0.67 - 4.81%     4.8  

Total available-for-sale debt securities

    18               20,276            

Total available-for-sale securities

    35,020               117,218            

Total short-term investments

    35,020               117,218            

Long-term investments

    2,806   N/A           3,236   N/A        

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

  $ 538,975             $ 510,369            

        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, 2014 would decrease the fair value of our available-for-sale securities by $3.5 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), 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 at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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 did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the accounting for income taxes existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2014 consolidated financial statements, and our opinion regarding the effectiveness of the Company's internal control over financial reporting does not affect our opinion on those consolidated financial statements. 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 referred to above. 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

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reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 2, 2015

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 
  December 31,  
 
  2014   2013  
 
  (In thousands, except per
share amounts)

 

ASSETS

             

Current assets:

             

Cash and cash equivalents

  $ 501,149   $ 389,915  

Short-term investments

    35,020     117,218  

Assets held for sale

    146,467     243,264  

Accounts receivable, net

    1,517,503     1,399,543  

Inventory

    230,067     209,793  

Deferred income taxes

    118,230     121,316  

Other current assets

    193,438     272,781  

Total current assets

    2,741,874     2,753,830  

Long-term investments

    2,806     3,236  

Property, plant and equipment, net

    8,599,125     8,597,813  

Goodwill

    173,928     512,964  

Investment in unconsolidated affiliates

    58,251     64,260  

Other long-term assets

    303,958     227,708  

Total assets

  $ 11,879,942   $ 12,159,811  

LIABILITIES AND EQUITY

             

Current liabilities:

             

Current debt

  $ 6,190   $ 10,185  

Trade accounts payable

    780,060     545,512  

Accrued liabilities

    728,004     697,093  

Income taxes payable

    53,221     58,634  

Total current liabilities

    1,567,475     1,311,424  

Long-term debt

    4,348,859     3,904,117  

Other long-term liabilities

    601,816     377,744  

Deferred income taxes

    443,003     516,161  

Total liabilities

    6,961,153     6,109,446  

Commitments and contingencies (Note 19)

   
 
   
 
 

Subsidiary preferred stock (Note 16)

        69,188  

Equity:

   
 
   
 
 

Shareholders' equity:

             

Common shares, par value $0.001 per share:

             

Authorized common shares 800,000; issued 328,196 and 323,711, respectively                    

    328     324  

Capital in excess of par value

    2,452,261     2,392,585  

Accumulated other comprehensive income

    77,522     216,140  

Retained earnings

    3,573,172     4,304,664  

Less: treasury shares, at cost, 38,788 and 28,414 common shares, respectively                    

    (1,194,664 )   (944,627 )

Total shareholders' equity

    4,908,619     5,969,086  

Noncontrolling interest

    10,170     12,091  

Total equity

    4,918,789     5,981,177  

Total liabilities and equity

  $ 11,879,942   $ 12,159,811  

   

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

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

 
  Year Ended December 31,  
 
  2014   2013   2012  
 
  (In thousands, except per share amounts)
 

Revenues and other income:

                   

Operating revenues

  $ 6,804,197   $ 6,152,015   $ 6,843,051  

Earnings (losses) from unconsolidated affiliates

    (6,301 )   39     (288,718 )

Investment income (loss)

    11,831     96,577     63,137  

Total revenues and other income

    6,809,727     6,248,631     6,617,470  

Costs and other deductions:

   
 
   
 
   
 
 

Direct costs

    4,505,064     3,981,828     4,367,106  

General and administrative expenses

    549,734     525,330     527,953  

Depreciation and amortization

    1,145,100     1,086,677     1,039,923  

Interest expense

    177,948     223,418     251,904  

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

    9,073     37,977     (136,636 )

Impairments and other charges

    1,027,423     287,241     290,260  

Total costs and other deductions

    7,414,342     6,142,471     6,340,510  

Income (loss) from continuing operations before income taxes

    (604,615 )   106,160     276,960  

Income tax expense (benefit):

                   

Current

    302,313     39,865     142,994  

Deferred

    (239,647 )   (95,046 )   (102,008 )

Total income tax expense (benefit)

    62,666     (55,181 )   40,986  

Subsidiary preferred stock dividend

    1,984     3,000     3,000  

Income (loss) from continuing operations, net of tax

    (669,265 )   158,341     232,974  

Income (loss) from discontinued operations, net of tax

    21     (11,179 )   (67,526 )

Net income (loss)

    (669,244 )   147,162     165,448  

Less: Net (income) loss attributable to noncontrolling interest

    (1,415 )   (7,180 )   (621 )

Net income (loss) attributable to Nabors

  $ (670,659 ) $ 139,982   $ 164,827  

Earnings (losses) per share:

                   

Basic from continuing operations

  $ (2.28 ) $ 0.51   $ 0.80  

Basic from discontinued operations

        (0.04 )   (0.23 )

Total Basic

  $ (2.28 ) $ 0.47   $ 0.57  

Diluted from continuing operations

  $ (2.28 ) $ 0.51   $ 0.79  

Diluted from discontinued operations

        (0.04 )   (0.23 )

Total Diluted

  $ (2.28 ) $ 0.47   $ 0.56  

Weighted-average number of common shares outstanding:

                   

Basic

    290,694     294,182     289,965  

Diluted

    290,694     296,592     292,323  

   

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

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 
  Year Ended December 31,  
 
  2014   2013   2012  
 
  (In thousands)
 

Net income (loss) attributable to Nabors

  $ (670,659 ) $ 139,982   $ 164,827  

Other comprehensive income (loss), before tax:

                   

Translation adjustment attributable to Nabors

    (79,059 )   (65,447 )   21,073  

Unrealized gains/(losses) on marketable securities:

                   

Unrealized gains/(losses) on marketable securities

    (59,932 )   23,007     98,138  

Less: reclassification adjustment for (gains)/losses included in net income (loss)

    2,337     (88,158 )   (13,405 )

Unrealized gains/(losses) on marketable securities

    (57,595 )   (65,151 )   84,733  

Pension plan

    (5,050 )   5,916     (324 )

Unrealized gains/(losses) on cash flow hedges

    612     613     702  

Other comprehensive income (loss), before tax

    (141,092 )   (124,069 )   106,184  

Income tax expense (benefit) related to items of other comprehensive income (loss)

    (2,474 )   (66 )   (4,147 )

Other comprehensive income (loss), net of tax

    (138,618 )   (124,003 )   110,331