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Section 1: 10-K (10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

 

 

(Mark One)

 

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

For the fiscal year ended December 31, 2016

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)

 

Crown House Second Floor
4 Par‑la‑Ville Road
Hamilton, HM08
Bermuda
(Address of principal executive offices)

980363970
(I.R.S. Employer
Identification No.)

 

 

 

N/A
(Zip Code)

 

(441) 292‑1510

(Registrant’s telephone number, including area code)

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

 

 

 

Title of each class

    

Name of each exchange on which registered

Common shares, $.001 par value per share

 

New York Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934: None.

 

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  YES ☐  NO ☒

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  YES ☐  NO ☒

 

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 ☒  NO ☐

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to file such reports).  YES ☒  NO ☐

 

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

 

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 ☒

Accelerated Filer ☐

Non‑accelerated Filer ☐

(Do not check if a
smaller reporting company)

Smaller Reporting Company ☐

 

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

 

The aggregate market value of the 206,707,782 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, 2016, based on the closing price of our common shares as of such date of $10.05 per share as reported on the New York Stock Exchange, was $2,077,413,209. 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 21, 2017 was 285,346,410, excluding 49,672,636 common shares held by our subsidiaries, or 335,019,046 in the aggregate.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Specified portions of the definitive Proxy

Statement to be distributed in connection with our 2017 Annual General Meeting of Shareholders (Part III).

 

 

 


 

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NABORS INDUSTRIES LTD.

Form 10-K Annual Report

For the Year Ended December 31, 2016

 

Table of Contents

 

 

 

 

 

PART I 

Item 1. 

Business

    

Item 1A. 

Risk Factors

 

10 

Item 1B. 

Unresolved Staff Comments

 

18 

Item 2. 

Properties

 

18 

Item 3. 

Legal Proceedings

 

18 

Item 4. 

Mine Safety Disclosures

 

20 

PART II 

Item 5. 

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

 

21 

Item 6. 

Selected Financial Data

 

24 

Item 7. 

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

 

26 

Item 7A. 

Quantitative and Qualitative Disclosures About Market Risk

 

41 

Item 8. 

Financial Statements and Supplementary Data

 

43 

Item 9. 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

102 

Item 9A. 

Controls and Procedures

 

102 

Item 9B. 

Other Information

 

103 

PART III 

Item 10. 

Directors, Executive Officers and Corporate Governance

 

104 

Item 11. 

Executive Compensation

 

104 

Item 12. 

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

 

104 

Item 13. 

Certain Relationships and Related Transactions and Director Independence

 

105 

Item 14. 

Principal Accounting Fees and Services

 

105 

PART IV 

Item 15. 

Exhibits, Financial Statement Schedules

 

106 

Item 16. 

Form 10-K Summary

 

106 

 

 

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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”). 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 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. 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. In addition, documents relating to our corporate governance (such as committee charters, governance guidelines and other internal policies) can be found on our website.

 

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 and volatility 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;

 

·

competitive and technological changes and other developments in the oil and gas and oilfield services industries;

 

·

our ability to complete, and realize the expected benefits of, strategic transactions, including our recently announced joint venture in Saudi Arabia;

 

·

the existence of operating risks inherent in the oil and gas and oilfield services industries;

 

·

the possibility of changes in tax laws and other laws and regulations;

 

·

the possibility of political or economic instability, civil disturbance, war or acts of terrorism in any of the countries in which we do business; 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, sustained lower oil or natural gas prices that have a material impact on exploration, development or production activities could also materially affect our financial position, results of operations and cash flows.

 

The above description of risks and uncertainties is by no means all-inclusive, but 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 annual report to “we,” “us,” “our,” “the Company,” or “Nabors” mean Nabors Industries Ltd., together with our subsidiaries where the context requires.

 

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PART I

 

ITEM 1.  BUSINESS

 

Overview

 

Since its founding in 1952, Nabors has grown from a small land drilling business in Canada to one of the world’s largest drilling contractors. Nabors Industries, Ltd. (NYSE: NBR) was formed as a Bermuda exempted company on December 11, 2001. Today, Nabors owns and operates the world’s largest land-based drilling rig fleet and are a leading provider of offshore platform drilling rigs in the United States and multiple international markets. Nabors also provides advanced wellbore placement services, drilling software and performance tools, drilling equipment and innovative technologies throughout the world’s most significant oil and gas markets. In today’s performance-driven environment, we believe we are well positioned to seamlessly integrate downhole hardware, surface equipment and software solutions into our AC rig designs. Leveraging our advanced drilling automation capabilities, Nabors’ highly skilled workforce continues to set new standards for operational excellence and transform our industry.

 

Our Drilling & Rig Services business is comprised of our global land-based and offshore drilling rig operations and other rig services, consisting of equipment manufacturing, rig instrumentation and optimization software. We also specialize in wellbore placement solutions and are a leading provider of directional drilling and measurement while drilling (“MWD”) systems and services. Our Drilling & Rig Services business consists of four reportable operating segments: U.S., Canada, International and Rig Services.

 

As a global provider of drilling and drilling-related services for land-based and offshore oil and natural gas wells, our fleet of rigs and drilling-related equipment as of December 31, 2016 includes:

 

·

400 actively marketed rigs for land-based drilling operations in the United States, Canada and approximately 20 other countries throughout the world; and

 

·

41 actively marketed rigs for offshore drilling operations in the United States and multiple international markets.

 

We experienced a reduction in the number of rigs working during 2015 and into early 2016 due to low oil and natural gas prices which caused a decrease in exploration and production spending. Oil prices reached lows in early 2016 and have since begun to rebound and producers have responded by beginning to increase activity. The following table presents our average rigs working (a measure of activity and utilization over the year) and average utilization for the years ended December 31, 2016, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

Year Ended December 31,

 

 

2016

 

2015

 

2014

 

 

Average

    

Average

 

Average

    

Average

 

Average

    

Average

 

 

Rigs Working

 

Utilization

 

Rigs Working

 

Utilization

 

Rigs Working

 

Utilization

U.S.

 

62.0

 

24%

 

120.0

 

41%

 

212.5

 

68%

Canada

 

9.7

 

14%

 

16.7

 

25%

 

34.1

 

50%

International

 

100.2

 

62%

 

124.0

 

79%

 

127.1

 

90%

 

 

171.9

 

35%

 

260.7

 

50%

 

373.7

 

72%

 

Additional information regarding the geographic markets in which we operate and our business segments can be found in Note 21—Segment Information in Part II, Item 8.—Financial Statements and Supplementary Data.

 

U.S. Drilling

 

Our U.S. Drilling operations include land drilling activities in the lower 48 states and Alaska as well as offshore operations in the Gulf of Mexico. We operate one of the largest land-based drilling rig fleets in the United States, consisting of 184 AC rigs and 33 SCR rigs which were actively marketed as of December 31, 2016.

 

Nabors’ first AC land rig was built during 2002. Since then, the technology has significantly evolved as more than 900 AC rigs have been added to the U.S. land market. As the industry shifted to multi well pad drilling, operators demanded greater efficiencies and adaptability through batch drilling. We believe our latest generation of PACE®

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drilling rigs are ideal for batch drilling, with pad optimal features, such as our unique side saddle design, and advanced walking capabilities.

 

In 2013, we introduced our PACE®-X800 rig with an advanced walking system that enables the rig to move quickly over existing wells, along the X and Y axes. Most of the ancillary equipment moves with the rig, enabling it to move easily between adjacent rows of wells. Through December 31, 2016, we have placed a total of 44 PACE®-X800 rigs into service within the lower 48 market, including four rigs during fiscal year 2016.

 

During the second half of 2016, we introduced our new PACE®-M800 and PACE®-M1000 rigs which complements our existing PACE®-X800 rigs. The PACE®-M800 rig is designed for lower-density multi-well pads whereas the PACE®-M1000 is designed for higher density pads. Both are designed to move rapidly between pads. Featuring the same advanced walking capabilities as the PACE®-X800 rig, the PACE®-M800 rig can quickly move efficiently on pads and over short distances, with minimal rig-up and rig-down components. As of December 31, 2016, we have placed four PACE®-M800 rigs into service.

 

In addition to land drilling operations throughout the lower 48 states and Alaska, we also actively marketed 17 platform rigs in the U.S. Gulf of Mexico as of December 31, 2016.

 

Our U.S. drilling operations contributed approximately 25% of our consolidated operating revenues for the year ended December 31, 2016, compared with approximately 33% of our consolidated operating revenues for the year ended December 31, 2015.

 

International Drilling

 

We maintain a footprint in nearly every major oil and gas market across the globe, most notably in Saudi Arabia, Algeria, Colombia, Venezuela and Russia. Many of our rigs in our international drilling markets were designed to address the challenges inherent in specific drilling locations such as those required in the desert and remote or environmentally sensitive locations, as well as the various shale plays. As of December 31, 2016, our fleet consisted of 135 land-based drilling rigs in approximately 20 countries. We also actively marketed 18 platforms and six jackup rigs in the international offshore drilling markets as of the same date. We continue to upgrade and deploy high-specification desert rigs specifically for gas drilling in the Middle East. We have been able to extend the utilization of the PACE®-X800 rigs in international markets by deploying six such rigs in Latin America.

 

On October 31, 2016, we entered into an agreement with Saudi Arabian Development Company, a wholly-owned subsidiary of Saudi Arabian Oil Company (“Saudi Aramco”), to form a new joint venture to own, manage and operate onshore drilling rigs in The Kingdom of Saudi Arabia. The joint venture, which will be equally owned by Saudi Aramco and Nabors, is anticipated to be formed and commence operations in the second half of 2017. The joint venture will leverage our established business in Saudi Arabia to begin operations, with a focus on Saudi Arabia's existing and future onshore oil and gas fields. Saudi Aramco and Nabors will each contribute land rigs to the joint venture in the first years of operation along with capital commitments toward future onshore drilling rigs which will be manufactured in Saudi Arabia.

 

Our International drilling operations contributed approximately 68% of our consolidated operating revenues for the year ended December 31, 2016, compared with approximately 48% of our consolidated operating revenues for the year ended December 31, 2015.

 

Canada Drilling

 

Our rig fleet consisted of 47 land-based drilling rigs in Canada as of December 31, 2016. Our Canada drilling operations contributed approximately 2% of our consolidated operating revenues for the year ended December 31, 2016, compared with approximately 4% of our consolidated operating revenues for the year ended December 31, 2015.

 

Rig Services

 

In order to advance today’s drilling technology and move toward complete drilling automation, we believe it is critical to create a holistic environment of integrated hardware and software. The breadth of our operations provides a competitive advantage because we design integrated drilling rigs, software and equipment. Our new modular

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RigtelligentTM operating control system automates many repetitive drilling and wellbore placement tasks. The integration of data from both downhole tools and surface systems enables us to provide innovative drilling solutions to our customers, reducing the need for third-party contractors. We focus on creating and advancing our innovative technologies through our Rig Services segment, which includes Canrig and Nabors Drilling Solutions.

 

Drilling Equipment

 

Through Canrig, we manufacture and sell top drives, catwalks, wrenches, drawworks and other drilling related equipment which are installed on both onshore and offshore drilling rigs.

 

Drilling Performance Tools and Advanced Wellbore Placement Technologies

 

Through Nabors Drilling Solutions, we offer specialized drilling technologies, such as patented steering systems and rig instrumentation software systems that enhance drilling performance and wellbore placement. These products include:

 

·

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

 

·

REVit®  control system, which is a real-time stick slip mitigation system that extends bit life, reduces tool failures and increases penetration rates, resulting in significant savings in drilling time and costs;

 

·

RIGWATCH® software, which is computerized software and equipment that monitors a rig’s real-time performance and provides daily reporting for drilling operations, making this data available through the internet; and

 

·

DRILLSMART® software, which allows the drilling system to adapt to operating parameters and drilling conditions while optimizing performance.

 

Nabors specializes in wellbore placement solutions and is a leading provider of directional drilling and MWD systems and services. Our MWD product line is a proprietary family of advanced systems, representing the latest technology developed specifically for the unique requirements of land-based drilling applications. Our tools are ideal for applications where high reliability, precise wellbore placement and drilling efficiency are crucial. Nabors’ patented directional drilling tools enable a higher level of precision and cost effectiveness. These products include:

 

·

AccuMP® mud pulse MWD system, which is designed to address many of the current MWD reliability issues present in the market today;

 

·

AccuWave® collar mounted Electromagnetic MWD system that addresses the needs of the land market through the latest technology and design techniques; and

 

·

Nabors’ AccuSteer® Measurement While Drilling (M/LWD) Suite is a premier dynamics evaluation MWD system for performance drilling with integrated advanced geosteering measurements. The AccuSteer® system is a collar based M/LWD designed specifically for the unconventional market.

 

Our Rig Services operations contributed approximately 5% of our consolidated operating revenues, net of intercompany sales, for the year ended December 31, 2016, compared with approximately 6% of our consolidated operating revenues for the year ended December 31, 2015.

 

Our Business Strategy

 

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

 

·

achieving superior operational and health, safety and environmental performance;

 

·

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

 

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·

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.

 

During 2016, we made significant progress in expanding our technology portfolio. All of our new-build rigs have been deployed with our new RigtelligentTM modular-code operating system and we have commenced retrofitting most of our AC fleet.  We believe these actions position us well to address the changing market dynamic both in the United States and internationally. Our technological development efforts are focused on advanced rig designs with emphasis on automation of the drilling floor, a suite of downhole measurement and sensing tools and the seamless integration of the rig’s operations with downhole sensing. In addition, we are adding complementary services to our traditional rig offering and in many cases replacing third-party providers of these complementary services as a single service provider. These efforts support our strategy to differentiate our drilling services, and ultimately reduce our customers’ unit costs, through advanced drilling technology and value added enhancements.

 

Additionally, in the Lower 48 market, we commenced the formal rollout of a suite of related services — including wellbore placement, performance drilling tools, managed pressure drilling services, and other services — which complement our core drilling activities. We believe these services represent an opportunity to increase our revenue per rig, and since our rig crews provide the services, our incremental cost is generally lower than the costs incurred by existing third-party service providers.

 

We also introduced our new PACE®-M800 rig in the second half of 2016, designed for optimal well construction with minimal time spent mobilizing between well pads.  Customers have been very receptive to this new rig, with each rig receiving a contract prior to completion of construction, and all the rigs have achieved 100% utilization through December 31, 2016.  These new rigs complement our existing pad-optimal PACE®-X rigs, which also operate at near-100% utilization as of the end of 2016.

 

Drilling Contracts

 

Our drilling contracts are typically daywork contracts. A daywork contract generally provides for a basic rate per day when drilling (the dayrate for 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).

 

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. Such payments may not fully compensate us for the loss of a contract, and in certain circumstances the customer may not be obligated, able or willing to make an early termination payment to us. Contract terms and rates differ depending on a variety of factors, including competitive conditions, the geographical area, the geological formation to be drilled, the equipment and services to be supplied, the on-site drilling conditions and the anticipated duration of the work to be performed. In addition, throughout 2015 and 2016, we experienced downward pricing-pressure for our drilling services from existing customers in light of the industry conditions and, as a result, renegotiated pricing and other terms in our drilling contracts with certain customers. See Part I, Item 1A.—Risk Factors Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows, profitability and ability to retain skilled employees and Our drilling contracts may in certain instances be renegotiated, suspended or terminated without an early termination payment.

 

Our Customers

 

Our customers include major national and independent oil and gas companies. One customer, Saudi Aramco, accounted for approximately 33% and 12% of our consolidated operating revenues during the years ended December 31,

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2016 and 2015, respectively, and is included in our International drilling operating segment. The increase from 2015 to 2016 was primarily as a result of our acquisition of the remaining interest in Nabors Arabia Company Limited (“Nabors Arabia”), our joint venture in Saudi Arabia, in May 2015 and our consolidation of Nabors Arabia’s results of operations. Nabors Arabia was historically a joint venture in the Kingdom, which now is wholly-owned by Nabors. Our contracts with Saudi Aramco are on a per rig basis. No customer accounted for more than 10% of our consolidated operating revenues during the year ended December 31, 2014. As mentioned previously, we have entered into a new joint venture agreement with this customer.

 

Our Employees

 

As of December 31, 2016, we employed approximately 13,000 people in approximately 20 countries. Our number of employees fluctuates depending on the current and expected demand for our services. Some rig-based employees in Alaska, Argentina, Mexico and Australia are represented by collective bargaining units. We believe our relationship with our employees is generally good.

 

Seasonality

 

Our operations are subject to seasonal factors. Specifically, our drilling 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. In addition, our U.S. offshore market can be impacted during summer months by tropical weather systems in the Gulf of Mexico. Global climate change could lengthen these periods of reduced activity, but we cannot currently estimate to what degree. Our overall financial results reflect the seasonal variations experienced in these operations, but seasonality does not materially impact the remaining portions of our business.

 

Research and Engineering

 

Research and engineering continues to be an important part of our overall business. During 2016, we spent approximately $33.6 million on research and engineering activities. The effective use of technology is critical to maintaining our competitive position within the drilling industry. We expect to continue developing technology internally and/or 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. The level of exploration, development and production activities is to a large extent tied to the prices of oil and natural gas, which can fluctuate significantly and are highly volatile. Since the second half of 2014, the oil and gas industry has experienced a significant decline as a result of decreasing oil and natural gas prices, resulting in a reduction of exploration, development and production activities of our customers. The level of activity in the sector remained suppressed throughout 2016 and into 2017. A continued decrease or further prolonged decline in the price of oil or natural gas or in the exploration, development and production activities of our customers could result in a corresponding decline in the demand for our services and/or a reduction in dayrates and utilization, which could have a material 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, profitability and ability to retain skilled employees and Item 7.— Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

The markets in which we provide our services are highly competitive. We provide our drilling and rig services in the United States, Canada and approximately 20 other countries throughout the world. We believe that competitive pricing is a significant factor in determining which service provider is awarded a job in these markets and customers are increasingly sensitive to pricing during periods of market instability. 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.

 

In late 2014, falling oil prices forced a curtailment of drilling-related expenditures by many companies and resulted in an oversupply of rigs in the markets where we operate. This reduction in drilling and related activity impacted our key markets through both 2015 and 2016. Although many rigs can be readily moved from one region to another in

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response to changes in levels of activity and many of the total available contracts are currently awarded on a bid basis, competition has increased based on the supply of existing and new rigs across all of our markets. 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 services will continue to be highly competitive. See Part I, Item 1A.—Risk Factors—We operate in a highly competitive industry with excess drilling capacity, which may adversely affect our results of operations.

 

Certain competitors are present in more than one of the markets in which we operate, although no one competitor operates in all such markets. 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 various contractors in our international markets and (3) Precision Drilling, Ensign Energy Services, and others in Canada.

 

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 400 land drilling rigs, 35 offshore platform rigs and 6 jackup units. This growth was fueled in part by strategic acquisitions. While we continuously consider and review strategic opportunities, including acquisitions, divestitures, joint ventures, alliances 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 completing and realizing the expected benefits of such transactions in the future.

 

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.

 

On March 24, 2015, we completed the merger (the “Merger”) of our Completion & Production Services business with C&J Energy Services, Inc. (“C&J Energy”). In the Merger and related transactions, our wholly-owned interest in our Completion & Production Services business was exchanged for cash and an equity interest in the combined entity, C&J Energy Services Ltd. (“CJES”). Prior to the Merger, our Completion & Production Services business conducted our operations involved in the completion, life-of-well maintenance and plugging and abandonment of wells in the United States and Canada. On July 20, 2016, CJES and certain of its subsidiaries commenced voluntarily cases under chapter 11 of the U.S. Bankruptcy Code. For more information on the accounting for our investment in CJES, see Note 9—Investments in Unconsolidated Affiliates in Part II, Item 8.—Financial Statements and Supplementary Data. On December 12, 2016, we entered into a mediated settlement agreement with various other parties in the CJES bankruptcy proceedings and on January 6, 2017, CJES announced it had emerged from bankruptcy. See further discussion in Item 3.—Legal Proceedings.

 

In addition to the Merger, we undertook the following strategic transactions over the last three years.

 

Acquisitions

 

In October 2014, we purchased the outstanding shares of 2TD Drilling AS (“2TD”), a drilling technology company based out of Norway. 2TD is in the process of developing a rotary steerable system for directional drilling which, once developed, will be included in our Rig Services operating 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 contingent on the achievement of various milestone objectives. As of December 31, 2016, these future payments are estimated to be $13.9 million.

 

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In May 2015, we paid $106.0 million in cash to acquire the remaining 49% equity interest in Nabors Arabia, our prior joint venture in Saudi Arabia, making it a wholly owned subsidiary. Previously, we held a 51% equity interest with a carrying value of $44.7 million, and we had accounted for the joint venture as an equity method investment. The acquisition of the remaining interest allows us to strategically align our future growth in this market by providing additional flexibility to invest capital and pursue future investment opportunities. As a result, we consolidated the assets and liabilities of Nabors Arabia on the acquisition date based on their respective fair values. We have also consolidated the operating results of Nabors Arabia since the acquisition date and reported those results in our International drilling segment.

 

Divestitures

 

In 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 expected to receive additional payments of $27.0 million upon certain future dates or the properties achieving certain production targets. During 2016, we recorded an impairment charge of $22.4 million to reserve for these future amounts payable to Nabors and our retained interest in these properties.  We retained a working interest in the properties at various interests.  The working interest is fully carried up to $600 million of total project costs.

 

See Note 4—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 2017. 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 laws and regulations or exposure to environmental liabilities could adversely affect our results of operations.

 

ITEM 1A.  RISK FACTORS

 

In addition to the other information set forth elsewhere in this annual report, the following factors should be carefully considered when evaluating Nabors. The risks described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations.

 

Our business, financial condition or results of operations could be materially adversely affected by any of these risks.

 

Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows, profitability and ability to retain skilled employees.

 

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 activity levels. Oil and natural gas prices, as well as the level of drilling, exploration and production activity, can be highly volatile. For example, oil prices were as high as $107 per barrel during 2014 and were as low as $26.21 per barrel in February 2016. The decrease in oil prices has been caused by, among other things, an oversupply of crude oil and stagnant demand. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, affect both the supply of and demand for oil and natural gas. In addition, weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand for oil and natural gas, general economic conditions, the availability and demand for drilling equipment and pipeline capacity, and other factors beyond our control may also affect the supply of and demand for oil and natural gas.

 

As a result of the sustained low oil price environment beginning at the end of 2014, the level of drilling, exploration and production activity declined in 2015 and remained low throughout 2016, resulting in a corresponding decline in the demand for our drilling services and/or a reduction in our dayrates and rig utilization. The continuation of

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lower oil and natural gas prices or the further decline in such prices could have an adverse effect on our revenues, cash flows, liquidity and profitability.

 

A continuation of the lower oil and natural gas price environment could also adversely impact our cash forecast models used to determine whether the carrying values of our long-lived assets exceed our future cash flows, which could result in future impairment to our long-lived assets. Additionally, these circumstances could indicate that the carrying amount of our goodwill and intangible assets may exceed their fair value, which could result in a future goodwill impairment. A continuation 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.

 

Our customers and thereby our business and profitability could be adversely affected by turmoil in the global economy.

Changes in general economic and political conditions may negatively impact our business, financial condition, results of operations and cash flows. As a result of the volatility of oil and natural gas prices and the depressed economic environment, we are unable to predict the level of exploration, drilling and production activities of our customers and whether our customers and/or vendors will be able to sustain their operations and fulfill their commitments and obligations. If oil prices remain low and/or global economic conditions remain tepid or if either or both further deteriorate in the future, there could be a material adverse impact on the liquidity and operations of our customers, vendors and other worldwide business partners, which in turn could have a material impact on our results of operations and liquidity. Furthermore, these conditions may result in certain of our customers experiencing an inability to pay vendors, including us. In addition, we may experience difficulties forecasting future capital expenditures by our customers, which in turn could lead to either over capacity or, in the case of a recovery in oil prices and the world wide economy, undercapacity, either of which could adversely affect our operations. There can be no assurance that the global economic environment will not deteriorate again in the future due to one or more factors.

 

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, increased price competition, as we have observed over the past two years in certain markets. 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. Our ability to continually provide technologically competitive drilling-related equipment and services can impact our ability to defend, maintain or increase prices, maintain market share, and negotiate acceptable contract terms with our customers. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements for equipment. New technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could adversely impact our ability to compete. Another key factor in job award determinations is our ability to maintain a strong safety record. If we are unable to remain competitive based on these and/or other competitive factors, we may be unable to maintain or increase our market share, utilization rates and/or day rates for our services, which could adversely affect our business, financial condition, results of operations and cash flows.

 

We must renew customer contracts to remain competitive. 

 

 We had a number of customer contracts that expired in 2016, and have a number that will expire in 2017. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions and our customers’ future drilling plans, which are subject to change. For example, during 2015 and 2016, a number of oil and gas companies, including some of our customers, publicly announced significant reductions in their planned exploration and development spending. Due to the highly competitive nature of the industry, which can be exacerbated during periods of depressed market conditions, such as the one we are currently experiencing, we may not be able to renew or replace expiring contracts or, if we are able to, we may not be able to secure or improve existing day

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rates or other material terms, which could have an adverse effect on our business, financial condition 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 and workover industries, including blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental 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 for which we are 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 that could adversely affect our business, financial condition and liquidity. 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, which could exacerbate the impact of our losses on our financial condition and liquidity.

 

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

 

 Most of our multi-well and term drilling contracts require that an early termination payment be made to us if a contract is terminated by the customer prior to its expiration. However, such payments may not fully compensate us for the loss of a contract, and in certain circumstances, such as, but not limited to, non-performance caused by significant operational or equipment issues (such as destruction of a drilling rig that is not replaced within a specified period of time), sustained periods of downtime due to a force majeure event or other events beyond our control or some other breach of our contractual obligations, our customer may not be obligated to make an early termination payment to us at all. In addition, some contracts may be suspended, rather than terminated early, for an extended period of time, in some cases without adequate compensation. The early termination or suspension of a contract may result in a rig being idle for an extended period of time, which could have a material adverse effect on our business, financial condition and results of operations.

 

 During periods of depressed market conditions, we may be subject to an increased risk of our customers (including government-controlled entities) seeking to renegotiate, repudiate or terminate their contracts and/or to otherwise exert commercial influence to our disadvantage. During 2016, we experienced continued downward pricing pressure and decreased demand for our drilling services with existing customers, resulting in renegotiations of pricing and other terms in our drilling contracts with certain customers and early termination of contracts by others. Our customers’ ability to perform their obligations under the contract, including their ability to pay us or fulfill their indemnity obligations, may also be impacted by an economic or industry downturn or other adverse conditions in the oil and gas industry. If we were to sustain a loss and our customers were unable to honor their indemnification and/or payment obligations, it could adversely affect our liquidity. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and/or on substantially similar terms — which may prove difficult during a depressed market — or if contracts are suspended for an extended period of time with or without adequate compensation or renegotiated with pricing or other terms less favorable to us, it could adversely affect our financial condition and results of operations.

 

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We may record additional losses or impairment charges related to sold or idle rigs.

 

 In 2016 and 2015, we recognized impairment charges of $245.2 million and $118.1 million, respectively, related to tangible assets and equipment. Prolonged periods of low utilization or low dayrates, the cold stacking of idle assets, the sale of assets below their then carrying value or the decline in market value of our assets may cause us to experience further losses. If future cash flow estimates, based upon information available to management at the time, including oil and gas prices and expected utilization levels, indicate that the carrying value of any of our rigs may not be recoverable or if we sell assets for less than their then carrying value, we may recognize additional impairment charges on our fleet.

 

The loss of one or a number of our large customers could have a material adverse effect on our business, financial condition and results of operations.

 

 In 2016 and 2015, we received approximately 46% and 26%, respectively, of our consolidated operating revenues from our three largest contract drilling customers (including their affiliates), with our largest customer Saudi Aramco representing 33% and 12% of our consolidated operating revenues, respectively, for these years.  The loss of one or more of our larger customers would have a material adverse effect on our business, financial condition, results of operations and prospects.  In addition, if a significant customer experiences liquidity constraints or other financial difficulties they may be unable to make required payments or seek to renegotiate contracts, which could adversely affect our liquidity and profitability. Financial difficulties experienced by customers could also adversely affect our utilization rates in the affected market.

 

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 the Middle East, Canada, South America, Algeria, the Far East, North Africa and Russia. These operations are subject to various risks, including war, civil disturbances, labor strikes, 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 contractual 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 also subject to various laws and regulations that govern the operation and taxation of our business and the import and export of our equipment from country to country, the imposition, application and interpretation of which can prove to be uncertain. To the extent that any of these risks arising from our operations in global markets are realized, it could have a material adverse effect on our business, financial condition and results of operations.

 

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

 

As of December 31, 2016, we had approximately $3.6 billion in outstanding debt and no amounts outstanding under our $2.25 billion revolving credit facility and commercial paper program. On January 13, 2017, we consummated an offering of $575 million in aggregate principal amount of Nabors Delaware’s 0.75% exchangeable senior notes due 2024 (the “Exchangeable Notes”).  After giving effect to this offering, our total outstanding debt was approximately $4.0 billion.  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 operating 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 and/or other sources of financing. If we cannot repay or refinance our debt as it becomes due, we may be forced to sell assets or reduce funding in the future for working capital, capital expenditures and general corporate purposes.

 

Our ability to access capital markets could be limited.

 

 From time to time, we may need to access capital markets to obtain long-term and short-term financing. However, our ability to access capital markets could be limited by, among other things, oil and gas prices, our existing capital structure, our credit ratings and the health of the drilling and overall oil and gas industry and the global economy. In addition, many of the factors that affect our ability to access capital markets, such as the liquidity of the overall capital markets and the state of the economy and oil and gas industry, are outside of our control. No assurance can be given that

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we will be able to access capital markets on terms acceptable to us when required to do so, which could adversely affect our business, liquidity and results of operations.

 

A downgrade in our credit rating could negatively impact our cost of and ability to access capital markets or other financing sources.

 

 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. Factors that may impact our credit ratings include debt levels, asset purchases or sales, as well as near-term and long-term growth opportunities and industry conditions. Liquidity, asset quality, cost structure, market diversity, and commodity pricing levels and others are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access capital markets or other financing sources in the future, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations, any of which could adversely affect our financial condition, results of operations and cash flows.

 

As a holding company, we depend on our operating subsidiaries and investments to meet our financial obligations.

 

Nabors and its wholly owned subsidiary, Nabors Industries, Inc., a Delaware corporation (“Nabors Delaware”), are holding companies with no significant assets other than the stock of our operating subsidiaries and investment in unconsolidated affiliates. In order to meet our financial needs, we rely exclusively on repayments of interest and principal on intercompany loans that have been made to operating subsidiaries and income from dividends and other cash flows from these operating subsidiaries. There can be no assurance that our operating subsidiaries will generate sufficient net income to pay us dividends or sufficient cash flows to make payments of interest and principal on the intercompany loans. In addition, from time to time, our operating subsidiaries may enter into financing arrangements or be made subject to laws or regulations that restrict or prohibit these types of upstream payments. There can also be adverse tax consequences associated with our subsidiaries and equity method investees paying dividends to us.

 

We may be subject to changes in tax laws and have additional tax liabilities.

 

 We operate through various subsidiaries in numerous countries throughout the world. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the United States or jurisdictions in which we or any of our subsidiaries operate or are organized. Furthermore, the Organization for Economic Co-Operation and Development (“OECD”) published a Base Erosion and Profit Shifting Action Plan in July 2013, seeking to reform the taxation of multinational companies. The recommendations made by the OECD may result in unilateral, uncoordinated changes in tax laws in the countries in which we operate or are organized, which may result in double taxation or otherwise increase our tax liabilities which in turn could have a material adverse effect on our financial condition and results of operations.

 

Tax laws, treaties and regulations are highly complex and subject to interpretation. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If these tax laws, treaties or regulations change or any tax authority successfully challenges our assessment of the effects of such laws, treaties and regulations in any country, including our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries, this could have a material adverse effect on us, resulting in a higher effective tax rate on our consolidated earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

 

Changes to or noncompliance with governmental laws and regulations or exposure to environmental liabilities could adversely affect our results of operations.

 

Drilling of oil and gas wells is subject to various laws and regulations in the jurisdictions where we operate. Our costs to comply with these laws and regulations may be substantial. For example, the U.S. Environmental Protection Agency (“EPA”) has promulgated rules requiring the reporting of greenhouse gas emissions applicable to certain offshore oil and natural gas production and onshore oil and natural gas production, processing, transmission, storage and distribution facilities. In June 2016, the EPA published final standards to reduce methane emissions for certain new, modified, or reconstructed facilities in the oil and gas industry and, through the issuance of a final Information Collection Request, is seeking additional information from oil and gas producing operators as necessary to expand these standards to include existing equipment and processes. In addition, U.S. federal laws and the laws of other jurisdictions

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strictly regulate the prevention of oil spills and the release of hazardous substances, and impose 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, we are subject to various laws governing the containment and disposal of hazardous substances, oilfield waste and other waste materials and the use of underground storage tanks.

 

Changes in environmental laws and regulations may also negatively impact the operations of oil and natural gas exploration and production companies, which in turn could have an adverse effect on us. For example, drilling, fluids, produced water and most of the other wastes associated with the exploration, development and production of oil or gas, if properly handled, are currently exempt from regulation as hazardous waste under the Resource Conservation and Recovery Act (‘‘RCRA’’) and instead, are regulated under RCRA’s less stringent non-hazardous waste provisions. However, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the  EPA take final action following notice and comment rulemaking no later than July 15, 2021. Any reclassification of such wastes as RCRA hazardous wastes could result in 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, but not adopted, 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 in the western United States, which establish greenhouse gas inventories and/or cap-and-trade programs. Some international initiatives have been or may be adopted, which could result in increased costs of operations in covered jurisdictions. In December 2015, the United States joined the international community of the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals every five years beginning in 2010. Although this international agreement does not create any binding obligations for nations to limit their greenhouse gas emissions, it does include pledges to voluntarily limit or make future emissions. In addition, the EPA has published findings that emissions of greenhouse gases present an endangerment to public health and the environment, which may lead to further regulations of greenhouse gas emissions under existing provisions of the Clean Air Act. The EPA has already issued rules requiring monitoring and reporting of greenhouse gas emissions from the oil and natural gas sector, including onshore and offshore production activities. Future or more stringent regulation could dramatically increase operating costs for oil and natural gas companies, curtail production and demand for oil and natural gas in areas of the world where our customers operate, and reduce the market for our services by making wells and/or oilfields uneconomical to operate, which may in turn adversely affect results of operations.

 

The expansion of the scope of laws or regulations protecting the environment has accelerated in recent years, particularly outside the United States, and we expect this trend to continue. Violation of environmental laws or regulations could lead to the imposition of administrative, civil or criminal penalties, remedial obligations, capital expenditures, delays in the permitting or performance of projects, 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.

 

We rely on third-party suppliers, manufacturers and service providers to secure equipment, components and parts used in rig operations, conversions, upgrades and construction.

 

Our reliance on third-party suppliers, manufacturers and service providers to provide equipment and services exposes us to volatility in the quality, price and availability of such items. Certain components, parts and equipment that

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we use in our operations may be available only from a small number of suppliers, manufacturers or service providers. The failure of one or more third-party suppliers, manufacturers or service providers to provide equipment, components, parts or services, whether due to capacity constraints, production or delivery disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment, is beyond our control and could materially disrupt our operations or result in the delay, renegotiation or cancellation of drilling contracts, thereby causing a loss of contract drilling backlog and/or revenue to us, as well as an increase in operating costs.

 

 Additionally, our suppliers, manufacturers and service providers could be negatively impacted by current industry conditions or global economic conditions. If certain of our suppliers, manufacturers or service providers were to curtail or discontinue their business as a result of such conditions, it could result in a reduction or interruption in supplies or equipment available to us and/or a significant increase in the price of such supplies and equipment, which could adversely impact our business, financial condition and results of operations.

 

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.  The SEC and U.S. Department of Justice have continued to focus on enforcement activities with respect to the FCPA. While our employees and agents are required to comply with applicable anti-corruption laws, and we have adopted policies and procedures and related training programs meant to ensure compliance, we cannot be sure that our internal policies, procedures and programs will always protect us from violations of these laws. Violations of these laws may result in severe criminal and civil sanctions as well as other penalties. The occurrence or allegation of these types of risks may adversely affect our business, financial condition and results of operations.

 

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.  Provisions in our organizational documents that are meant to help us avoid a coercive takeover include:

 

·

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;

 

·

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, in June 2012 we adopted an amendment to our bye-laws to declassify the Board.  In addition, our shareholder rights plan expired in July 2016.  Each of these changes may make 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.

 

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Legal proceedings and governmental investigations 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 or other whistle blower-related matters. Lawsuits or claims could result in decisions against us that could have an adverse effect on our financial condition or results of operations. See Item 3—Legal Proceedings for a discussion of certain existing legal proceedings.

 

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, but no assurance can be given that any employee will remain with us, whether or not they have entered into an employment agreement with us. We do not carry 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.

 

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

 

We undertake from time to time acquisitions, divestitures, investments, joint ventures, alliances and other strategic transactions that we expect to further our business objectives.  For example, in October 2016, we announced an agreement to form a new joint venture in the Kingdom of Saudi Arabia, which is expected to commence operations by the second half of 2017. The success of this joint venture depends, to a large degree, on the satisfactory performance of our joint venture partner’s obligations, including contributions of capital, drilling units and related equipment, and our ability to maintain an effective, working relationship with our joint venture partner.    The anticipated benefits of such joint venture and other strategic 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, financial condition and results of operations.

 

Our business is subject to cybersecurity risks.

 

Our operations are increasingly dependent on information technologies and services.  Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow, and include, among other things, storms and natural disasters, terrorist attacks, utility outages, theft, viruses, malware, design defects, human error, or complications encountered as existing systems are maintained, repaired, replaced, or upgraded. Risks associated with these threats include, among other things:

 

·

loss, corruption, or misappropriation of intellectual property, or other proprietary or confidential information (including customer, supplier, or employee data);

 

·

disruption or impairment of our and our 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 and other cyber events are evolving and unpredictable. Moreover, we have no control over the information technology systems of our customers, suppliers, and others with which our systems may connect and communicate. As a result, the occurrence of a cyber incident could go unnoticed for a period time. Any such incident could have a material adverse effect on our business, financial condition and results of operations.

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

 

As of February 21, 2017, we had 800,000,000 authorized common shares, of which 335,019,046 shares were outstanding and entitled to vote, of which 49,672,636 million were held by our subsidiaries and entitled to vote. In addition, 11,918,025 common shares were reserved for issuance pursuant to stock option and employee benefit plans, and 31,997,773 common shares were reserved for issuance upon exchange of outstanding Exchangeable Notes . The sale, or availability for sale, of substantial amounts of our common shares in the public market, whether directly by us or resulting from the exercise of options (and, where applicable, sales pursuant to Rule 144 under the Securities Act) or the exchange of Exchangeable Notes for common shares, would be dilutive to existing shareholders, 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.

 

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 Houston, Texas; Anchorage, Alaska; Calgary, Canada; Dubai in the United Arab Emirates; Bogota, Colombia; and Dhahran, Saudi Arabia.

 

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 province of British Columbia, Canada.

 

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 $13.0 million (at December 31, 2016 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 (the “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 again lodged an appeal to the Supreme Court, asserting the same challenges as before. While the appeal was pending, the Hassi Messaoud customs office 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

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to suspend those collection efforts and to enter into a formal negotiations process with the customs authority. The customs authority demanded 50% of the total fine as a final settlement and seized additional funds of approximately $3.6 million. We have recorded a reserve in the amount of the posted security. The matter was heard by the Supreme Court on February 26, 2015, and on March 26, 2015, that court set aside the judgment of the Ouargla Court of Appeals and remanded the case to that court for further proceedings. A hearing was held on October 28, 2015 in the Ouargla Court of Appeals and on November 4, 2015, the court affirmed the Supreme Court’s decision that we were not guilty, concluding that portion of the case. We have filed a new action with the Conseil d’Etat in an effort to recover amounts previously paid by us. A portion of those amounts has been returned, and our efforts to recover the additional $4.4 million continue.

 

In March 2011, the Court of Ouargla entered a judgment of approximately $25.6 million (at December 31, 2016 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 Supreme Court. On September 25, 2014, the Supreme Court overturned the verdict against us, and the case was reheard by the Ouargla Court of Appeals on March 22, 2015 in light of the Supreme Court’s opinion. On March 29, 2015, the Ouargla Court of Appeals reinstated the initial judgment against us. We have appealed this decision again to the Supreme Court. While our payments were consistent with our historical operations in the country, and, we believe, those of other multinational corporations there, as well as interpretations of the law by the Central Bank of Algeria, the ultimate resolution of this matter could result in a loss of up to $17.6 million in excess of amounts accrued.

 

In March 2012, Nabors Global Holdings II Limited (“NGH2L”) signed an agreement 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 (“Ramshorn”) (the “ERG Agreement”). 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. We successfully defeated ERG’s effort to obtain a temporary restraining order from the Texas court on March 20, 2012 and 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 defendants made numerous jurisdictional challenges on appeal, and on April 30, 2015, ERG filed for bankruptcy under Chapter 11 of the United States Bankruptcy Code. Accordingly, the civil actions are currently subject to the bankruptcy stay and ERG’s claims in the lawsuit are assets of the estate. The lawsuit was stayed, pending further court actions, including appeals of the jurisdictional decisions. On June 17, 2016, the Texas Supreme Court issued its opinion on the jurisdictional appeal holding that jurisdiction exists in Texas for Ramshorn, but not for Parex Bermuda or Parex Canada. ERG retains its causes of action for monetary damages, but we believe the claims are foreclosed by the terms of the ERG Agreement and are without factual or legal merit. On December 28, 2016, the District Court granted Nabors’ Motion for Partial Summary Judgment to Enforce Exclusive Remedies Clause, holding that ERG’s potential recovery in the action may not exceed $4.5 million in accordance with the terms of the ERG Agreement. The plaintiffs have challenged this ruling by filing a motion for rehearing that is scheduled to be heard on March 6, 2017. Although we continue to vigorously defend the lawsuit, its ultimate outcome cannot be determined at this time.

 

On July 30, 2014, we and Nabors Red Lion Limited (“Red Lion”), along with C&J Energy 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 C&J Energy board of directors breached their fiduciary duties in connection with the Merger, and that Red Lion and C&J Energy aided and abetted these alleged breaches. The plaintiff sought to enjoin the defendants from proceeding with or consummating the Merger and the C&J Energy stockholder meeting for approval of the Merger and, to the extent that the Merger was completed before any relief was 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 C&J Energy board of directors to solicit for a 30 day period

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alternative proposals to purchase C&J Energy (or a controlling stake in C&J Energy) that were superior to the Merger, and (ii) preliminarily enjoined C&J Energy from holding its stockholder meeting until it complied with the foregoing. C&J Energy 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. Nabors and the C&J Energy defendants filed a motion to dismiss that was granted by the Chancellor on August 24, 2016, including a ruling that C&J Energy could recover on the bond that was posted to support the temporary restraining order. The plaintiffs filed a Notice of Appeal on September 22, 2016. A briefing was concluded, and no hearing date has been set.

 

On March 24, 2015, we completed the Merger of our Completion & Production Services business with C&J Energy. In the Merger and related transactions, we acquired common shares in the combined entity, CJES, and entered into certain ancillary agreements with CJES, including a tax matters agreement, pursuant to which both parties agreed to indemnify each other following the completion of the Merger with respect to certain tax matters. On July 20, 2016, CJES and certain of its subsidiaries (collectively, the “debtors”) commenced voluntarily cases under chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. On December 12, 2016, we entered into a mediated settlement agreement with various other parties in the CJES bankruptcy proceedings (the “Settlement Agreement”). Pursuant to the Settlement Agreement, we agreed to support the debtors' chapter 11 plan of reorganization in exchange for: (i) two allowed unsecured claims for which we will receive distributions of up to $4.85 million; (ii) an amendment to the tax matters agreement providing that CJES will likely pay up to $11.5 million of obligations for which we would have otherwise been responsible; (iii) cancellation of various other obligations we had to the debtors; (iv) our pro rata share of warrants to acquire 2% of the common equity in the reorganized debtors; and (v) a mutual release of claims. The bankruptcy court has approved the terms of the Settlement Agreement and confirmed the debtors' plan and, on January 6, 2017, CJES announced it had emerged from bankruptcy.

 

ITEM 4.  MINE SAFETY DISCLOSURES

 

Not applicable.

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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 (the “NYSE”) under the symbol “NBR”.

 

The following table sets forth the reported high and low sales prices of our common shares as reported on the NYSE for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Share Price

 

Calendar Year

    

 

    

High

    

Low

 

2015

 

First Quarter

 

$

14.09

 

$

9.96

 

 

 

Second Quarter

 

 

16.99

 

 

13.70

 

 

 

Third Quarter

 

 

14.43

 

 

8.94

 

 

 

Fourth Quarter

 

 

12.33

 

 

7.47

 

 

 

 

 

 

 

 

 

 

 

2016

 

First Quarter

 

$

9.84

 

$

4.93

 

 

 

Second Quarter

 

 

11.21

 

 

7.61

 

 

 

Third Quarter

 

 

12.33

 

 

8.46

 

 

 

Fourth Quarter

 

 

17.68

 

 

11.01

 

 

On February 21, 2017, the closing price of our common shares as reported on the NYSE was $15.43.

 

Holders.

 

At February 21, 2017, there were approximately 1,764 shareholders of record of our common shares.

 

Dividends.

 

On February 17, 2017, our Board declared a cash dividend of $0.06 per common share, which will be paid on April 4, 2017 to shareholders of record at the close of business on March 14, 2017.

 

Our quarterly cash dividends on our total outstanding common shares during the past two fiscal years are shown in the table below. 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 in addition to legal requirements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Paid per Share

 

Total Payment

 

 

    

2016

    

2015

    

2016

    

2015

 

 

 

(in thousands, except per share amounts)

 

Quarter

 

 

 

 

 

 

 

 

 

 

 

 

 

First

 

$

0.06

 

$

0.06

 

$

16,923

 

$

17,469

 

Second

 

 

0.06

 

 

0.06

 

 

17,003

 

 

17,511

 

Third

 

 

0.06

 

 

0.06

 

 

17,001

 

 

17,509

 

Fourth

 

 

0.06

 

 

0.06

 

 

17,039

(1)

 

16,873

 

 

(1)

This quarterly cash dividend was paid on January 4, 2017 to shareholders of record on December 14, 2016.

 

See Part I—Item 1.A. Risk Factors—As a holding company, we depend on our operating subsidiaries to meet our financial obligations.

 

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Issuer Purchases of Equity Securities.

 

The following table provides information relating to our repurchase of common shares during the three months ended December 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

    

    

 

    

    

    

Approximated

 

 

 

 

 

 

 

 

Total Number

 

Dollar Value of

 

 

 

 

 

 

 

 

of Shares

 

Shares that May

 

 

 

Total

 

Average

 

Purchased as

 

Yet Be

 

 

 

Number of

 

Price

 

Part of Publicly

 

Purchased

 

Period

 

Shares

 

Paid per

 

Announced

 

Under the

 

(In thousands, except per share amounts)

    

Repurchased

    

Share (1)

    

Program

    

Program (2)

 

October 1 - October 31

 

<1

 

$

12.16

 

 —

 

298,716

 

November 1 - November 30

 

5

 

$

11.90

 

 —

 

298,716

 

December 1 - December 31

 

22

 

$

16.40

 

 

298,716

 


(1)

Shares were withheld from employees and directors to satisfy certain tax withholding obligations due in connection with grants of shares under our 2003 Employee Stock Plan, the 2013 Stock Plan and the 2016 Stock Plan. Each of the 2016 Stock Plan, the 2013 Stock Plan, the 2003 Employee Stock Plan and the 1999 Stock Option Plan for Non-Employee Directors provide for the withholding of shares to satisfy tax obligations, but do not specify a maximum number of shares that can be withheld for this purpose. These shares were not purchased as part of a publicly announced program to purchase common shares.

 

(2)

In August 2015, our Board authorized a share repurchase program under which we may repurchase up to $400 million of our common shares in the open market or in privately negotiated transactions. Through December 31, 2016, we repurchased 10.9 million of our common shares for an aggregate purchase price of approximately $101.3 million under this program. As of December 31, 2016, we had approximately $298.7 million that remained authorized under the program that may be used to repurchase shares. The repurchased shares are held by our subsidiaries are registered and tradable subject to applicable securities law limitations and have the same voting, dividend and other rights as other outstanding shares. As of December 31, 2016, our subsidiaries held 49.7 million of our common shares.

 

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.

 

Performance Graph

 

The following graph illustrates comparisons of five-year cumulative total returns among Nabors, the S&P 500 Index, Dow Jones Oil Equipment and Services Index, S&P MidCap 400 Index and Russell 3000 Index. We are now included in the S&P MidCap 400 Index and Russell 3000 Index and therefore, are presenting these new indices below. Total return assumes $100 invested on December 31, 2011 in shares of Nabors and in the aforementioned indices noted above assuming reinvestment of dividends at the end of each calendar year, presented in the table below.

 

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Picture 2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

2011

    

2012

    

2013

    

2014

    

2015

    

2016

 

Nabors Industries Ltd.

 

100

 

83

 

99

 

76

 

51

 

101

 

S&P 500 Index

 

100

 

116

 

154

 

175

 

177

 

198

 

Dow Jones Oil Equipment and Services Index

 

100

 

100

 

129

 

107

 

83

 

105

 

S&P MidCap 400 Index

 

100

 

118

 

157

 

173

 

169

 

204

 

Russell 3000 Index

 

100

 

116

 

155

 

175

 

176

 

198

 

 

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 designated as non-resident for Bermuda exchange control purposes by the Bermuda Monetary Authority. Pursuant to our non-resident status, there are no Bermuda restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to non-residents who are holders of its common shares in all other currencies, including currency of the United States.

 

There is no reciprocal tax treaty between Bermuda and the United States. Under current Bermuda law, there is no Bermuda withholding tax on dividends or other distributions, nor any Bermuda tax computed on profit or income payable by Nabors or its operations. 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). Nabors has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed, Nabors will be exempt from taxation in Bermuda until March 31, 2035.

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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,

 

 

    

2016

    

2015

    

2014

    

2013

    

2012

 

Operating Data (1)(2)

 

(In thousands, except per share amounts and ratio data)

 

Operating revenues

 

$

2,227,839

 

$

3,864,437

 

$

6,804,197

 

$

6,152,015

 

$

6,843,051

 

Income (loss) from continuing operations, net of tax

 

 

(1,011,244)

 

 

(329,497)

 

 

(669,265)

 

 

158,341

 

 

232,974

 

Income (loss) from discontinued operations, net of tax

 

 

(18,363)

 

 

(42,797)

 

 

21

 

 

(11,179)

 

 

(67,526)

 

Net income (loss)

 

 

(1,029,607)

 

 

(372,294)

 

 

(669,244)

 

 

147,162

 

 

165,448

 

Less: Net (income) loss attributable to noncontrolling interest

 

 

(135)

 

 

(381)

 

 

(1,415)

 

 

(7,180)

 

 

(621)

 

Net income (loss) attributable to Nabors

 

 

(1,029,742)

 

 

(372,675)

 

 

(670,659)

 

 

139,982

 

 

164,827

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (losses) per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic from continuing operations

 

$

(3.58)

 

$

(1.14)

 

$

(2.28)

 

$

0.51

 

$

0.80

 

Basic from discontinued operations

 

 

(0.06)

 

 

(0.15)

 

 

 —

 

 

(0.04)

 

 

(0.23)

 

Total Basic

 

$

(3.64)

 

$

(1.29)

 

$

(2.28)

 

$

0.47

 

$

0.57

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted from continuing operations

 

$

(3.58)

 

$

(1.14)

 

$

(2.28)

 

$

0.51

 

$

0.79

 

Diluted from discontinued operations

 

 

(0.06)

 

 

(0.15)

 

 

 —

 

 

(0.04)

 

 

(0.23)

 

Total Diluted

 

$

(3.64)

 

$

(1.29)

 

$

(2.28)

 

$

0.47

 

$

0.56

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average number of common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

276,475

 

 

282,982

 

 

290,694

 

 

294,182

 

 

289,965

 

Diluted

 

 

276,475

 

 

282,982

 

 

290,694

 

 

296,592

 

 

292,323

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures and acquisitions of businesses (3)

 

$

414,379

 

$

923,236

 

$

1,923,779

 

$

1,365,994

 

$

1,433,586

 

Interest coverage ratio (4)

 

 

3.4:1

 

 

6.2:1

 

 

9.8:1

 

 

7.4:1

 

 

7.7:1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31,

 

 

    

2016

    

2015

    

2014

    

2013

    

2012

 

Balance Sheet Data (1)(2)

 

(In thousands, except ratio data)

 

Cash, cash equivalents and short-term investments

 

$

295,202

 

$

274,589

 

$

536,169

 

$

507,133

 

$

778,204

 

Working capital

 

 

333,905

 

 

469,398

 

 

1,174,399

 

 

1,442,406

 

 

2,000,475

 

Property, plant and equipment, net

 

 

6,267,583

 

 

7,027,802

 

 

8,599,125

 

 

8,597,813

 

 

8,712,088

 

Total assets

 

 

8,187,015

 

 

9,537,840

 

 

11,862,923

 

 

12,137,749

 

 

12,631,867

 

Long-term debt

 

 

3,578,335

 

 

3,655,200

 

 

4,331,840

 

 

3,882,055

 

 

4,355,181

 

Shareholders’ equity

 

 

3,247,025

 

 

4,282,710

 

 

4,908,619

 

 

5,969,086

 

 

5,944,929

 

Debt to capital ratio:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross (5)

 

 

0.52:1

 

 

0.46:1

 

 

0.47:1

 

 

0.39:1

 

 

0.42:1

 

Net (6)

 

 

0.50:1

 

 

0.44:1

 

 

0.43:1

 

 

0.36:1

 

 

0.38:1

 


(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.

 

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(2)

Our acquisitions’ results of operations and financial position have been included beginning on the respective dates of acquisition and include Nabors Arabia (May 2015), 2TD (October 2014), KVS (October 2013) and Navigate Energy Services, Inc. (January 2013). Following consummation of the Merger of our Completion & Production Services business with C&J Energy (March 2015), we ceased consolidating that business’s results with our results of operations and began reporting our share of the earnings (losses) of CJES through earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss). As a result of the CJES Chapter 11 filing, we ceased accounting for our investment in CJES under the equity method of accounting beginning on July 20, 2016. Accordingly, our financial results of operations and financial position for periods prior to the Merger are not directly comparable with our financial results of operations and financial position for the years ended December 31, 2016 and 2015.

 

(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, direct costs, general and administrative expenses and research and engineering expenses 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 are a leading provider of offshore platform and drilling rigs in the United States and multiple international markets. Our Drilling & Rig Services business is comprised of our global land-based and offshore drilling rig operations and other rig services, consisting of equipment manufacturing, rig instrumentation and optimization software. We also specialize in wellbore placement solutions and are a leading provider of directional drilling and MWD systems and services. Our business consists of four reportable operating segments: U.S., Canada, International and Rig Services.

 

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.

 

Persistently low oil and gas prices during 2015 and 2016 have had a significant impact on the number of rigs working, particularly in our U.S. and Canada segments although our International drilling segment has also felt the effect. The decline in global oil prices, and the extended duration of lower prices for both oil and gas, have resulted in dramatic reductions in capital spending by our customers. Together, these trends led to continued reductions in the level of drilling activity in the oil and gas industries on a worldwide basis and had a corresponding adverse impact on our results of operations. In the U.S., our customers' reaction to the decrease in commodity prices resulted in significant decreases in both the number of rigs that were working and the dayrates that we could obtain. We believe the U.S. market has stabilized and started to improve, as evidenced by a sharp increase in rig counts during the second half of 2016 as a result of the improvement in oil prices. In the U.S., our working rigs as of the end of the year represents a 50% increase over the trough in early April 2016. We have also increased our market share over these recent months, mainly on strong demand for our PACE®-X rigs. Internationally, spending cuts have resulted in lower activity levels, as reflected by an approximate 20% reduction in the average number of rigs working throughout 2016 when compared to 2015 and resulted in lower operating results for the same comparable period. International markets, although more resilient than the lower 48, have remained challenged by the depressed environment in 2016. However, we are seeing early signs of activity increases internationally. Although activity has begun to rebound, spot market pricing continues to remain competitive. To the extent that rig counts and activity continue to increase throughout 2017, we expect pricing to follow and our dayrates to increase accordingly.

 

In December 2016, Nabors Delaware completed an offering of $600 million aggregate principal amount of 5.50% senior unsecured notes due January 15, 2023, which are fully and unconditionally guaranteed by us. The proceeds from this offering were used to prepay the $162.5 million due in 2018 under our unsecured term loan and all amounts then outstanding under our $2.25 billion revolving credit facility and commercial paper program, or $392.1 million. The remaining proceeds were allocated for general corporate purposes, including to repay and repurchase other existing debt.

 

In January 2017, Nabors Delaware issued $575 million in aggregate principal amount of 0.75% exchangeable senior unsecured notes due 2024, which are fully and unconditionally guaranteed by Nabors. The exchangeable notes are exchangeable, under certain conditions, at an initial exchange rate of 39.75 common shares of the Company per $1,000 principal amount of notes (equivalent to an initial exchange price of approximately $25.16 per common share). Upon any exchange, Nabors Delaware will settle its exchange obligation in cash, common shares of the Company, or a combination of cash and common shares, at our election. In connection with the pricing of the notes, we entered into privately negotiated capped call transactions which are expected to reduce potential dilution to common shares and/or

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offset potential cash payments required to be made in excess of the principal amount upon any exchange of notes. Such reduction and/or offset is subject to a cap representing a price per share of $31.45, an approximately 75.0% premium over our share price of $17.97 as of the date of the transaction. The net proceeds from the offering of the exchangeable notes were used to prepay the remaining balance of our unsecured term loan originally scheduled to mature in 2020, as well as to pay the cost of the capped call transactions. Any remaining net proceeds from the offering were allocated for general corporate purposes, including to repurchase or repay other indebtedness.

 

At December 31, 2016, we had no borrowings outstanding under our $2.25 billion revolving credit facility and commercial paper program. Availability under the revolving credit facility is subject to a covenant not to exceed a net debt to capital ratio of 0.60:1. As of December 31, 2016, our net debt to capital ratio was 0.50:1. See Item 6. “Selected Financial Data”. This ratio does not give effect to the issuance of the exchangeable notes in January 2017 discussed above.

 

Financial Results

 

On March 24, 2015, we completed the merger (the “Merger”) of our Completion & Production Services business with C&J Energy Services, Inc. (“C&J Energy”). In the Merger and related transactions, our wholly-owned interest in our Completion & Production Services business was exchanged for cash and an equity interest in the combined entity, C&J Energy Services Ltd. (“CJES”). Prior to the Merger, our Completion & Production Services business conducted our operations involved in the completion, life-of-well maintenance and plugging and abandonment of wells in the United States and Canada. On July 20, 2016, CJES and certain of its subsidiaries commenced voluntarily cases under chapter 11 of the U.S. Bankruptcy Code at which point we ceased accounting for this investment under the equity method of accounting. For more information on the accounting for our investment in CJES, see Note 9—Investments in Unconsolidated Affiliates in Part II, Item 8.—Financial Statements and Supplementary Data. On December 12, 2016, we entered into a mediated settlement agreement with various other parties in the CJES bankruptcy proceedings and on January 6, 2017, CJES announced it had emerged from bankruptcy. See further discussion in Item 3.—Legal Proceedings.

 

As a result of ceasing to consolidate the results of our Completion & Production Services business beginning at the time of the Merger in 2014, our results of operations for the years ended December 31, 2016 and 2015 are not directly comparable to the year ended December 31, 2014. See Note 9—Investments in Unconsolidated Affiliates in Part II, Item 8.—Financial Statements and Supplementary Data.

 

Comparison of the years ended December 31, 2016 and 2015

 

Operating revenues in 2016 totaled $2.2 billion, representing a decrease of $1.6 billion, or 42%, from 2015. The decrease in revenues was due to the significant decline in the number of rigs working as evidenced by a 34% reduction in average rigs working during 2016 compared to 2015. Also contributing to the decline in revenue were lower dayrates as existing contracts expired and were repriced at the lower prevailing market dayrates for many rigs, while other rigs commenced standby rates, terminations or price concessions granted to certain customers. The remainder of the decrease in operating revenue was due to ceasing to consolidate the revenues associated with our Completion & Production Services business, which accounted for $0.4 billion, or 22%, of the overall decrease.

 

Net loss from continuing operations totaled $1.0 billion for 2016 ($3.58 per diluted share) compared to a net loss from continuing operations of $329.5 million ($1.14 per diluted share) in 2015. This equated to an increase in loss from continuing operations of $681.7 million.  Approximately $435.2 million of the increase in loss was attributable to our segment adjusted operating income (loss), which is our primary measure of operating performance.  See Segment Results of Operations for further information on the changes to segment adjusted operating income (loss).  The remainder of the increase in loss was attributable to higher losses from unconsolidated affiliates and an increase in the magnitude of impairments and other charges.  We recorded a $221.9 million loss in 2016 compared to a $81.3 million loss in 2015 for our share of the net income (loss) of CJES, which represents our portion (53%) of their net income (loss).  Our impairments and other charges were $505.2 million in 2016 compared to $369.0 million in 2015, for a $136.2 million increase in losses. These charges were primarily comprised of $285.4 million related to impairments and retirements of tangible assets and equipment as a result of the sustained decline in oil prices and the continued realization of lower demand for and obsolescence of legacy asset classes and $219.7 million related to other-than-temporary impairments on our equity method investments. Similarly, during 2015 we recognized approximately $369.0 million in impairments and other charges. These charges resulted from the impact of the industry downturn on our business activity

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and future outlook as the continuation of depressed oil prices led to considerable reductions in capital spending by some of our customers and diminished demand for our drilling services. These charges were primarily comprised of $140.1 million related to impairments and retirements of tangible assets and equipment, $180.6 million related to an other-than-temporary impairment on our equity method investment in CJES and $48.3 million for a provision for International operations. Additional information relating to impairments and other charges is provided in Note 3—Impairments and Other Charges in Part II, Item 8.—Financial Statements and Supplementary Data.

 

General and administrative expenses in 2016 totaled $227.6 million, representing a decrease of $96.7 million, or 30% from 2015. The decrease was partially attributable to the fact that we ceased consolidating the expenses from our former Completion & Production Services business as a result of the Merger, which accounted for approximately $26.0 million of the decrease. Also contributing to the decrease was a reduction in average headcount of approximately 22% as a result of our efforts to right size our back office functions to the level of operations. The remainder of the decrease is attributed to our continued cost-reduction efforts across our remaining operating units and our corporate offices.

 

Research and engineering expenses in 2016 totaled $33.6 million, representing a decrease of $7.7 million, or 19%, over 2015. The decrease was primarily attributable to a reduction in workforce and general cost-reduction efforts across the various operating units. Also contributing to the decrease was the reduction in drilling related projects as a result of the decline in overall activity.

 

Depreciation and amortization expense in 2016 was $871.6 million, representing a decrease of $98.8 million, or 10%, over 2015. The decrease was due largely to the fact that we ceased consolidating the expenses from our former Completion & Production Services business as a result of the Merger, which accounted for $51.1 million of the decrease. The remainder of the decrease primarily relates to an increased number of rigs that were not working during the period, which results in a lower inactive depreciation rate and the impact from various retirements of legacy fleet rigs in late 2015.

 

Segment Results of Operations

 

Our Drilling & Rig Services business is comprised of our global land-based and offshore drilling rig operations and other rig services, consisting of equipment manufacturing, rig instrumentation and optimization software. We also specialize in wellbore placement solutions and are a leading provider of directional drilling and MWD systems and services. Our Drilling & Rig Services business consists of four reportable operating segments: U.S., Canada, International and Rig Services. Our Rig Services segment includes our other services comprised of our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software services.

 

Management evaluates the performance of our operating segments using adjusted operating income (loss), which is our segment performance measure, because it believes that this financial measure reflects our ongoing profitability and performance. In addition, securities analysts and investors use this measure as one of the metrics on which they analyze our performance. Adjusted operating income (loss) is computed  by subtracting the sum of direct costs, general and administrative expenses, research and engineering expenses and depreciation and amortization from operating revenues.  

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

Increase/(Decrease)

 

 

 

2016

 

2015

 

2016 to 2015

 

 

 

(In thousands, except percentages and rig activity)

U.S.

 

 

 

    

    

 

    

    

 

    

    

    

    

Operating revenues

 

 

$

554,072

 

$

1,256,989

 

$

(702,917)

 

(56)

%  

Adjusted operating income (loss)

 

 

$

(197,710)

 

$

87,051

 

$

(284,761)

 

n/m

(2)

Average rigs working (1)

 

 

 

62.0

 

 

120.0

 

 

(58.0)

 

(48)

%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

$

51,472

 

$

137,494

 

$

(86,022)

 

(63)

%  

Adjusted operating income (loss)

 

 

$

(36,818)

 

$

(7,029)

 

$

(29,789)

 

n/m

(2)

Average rigs working (1)

 

 

 

9.7

 

 

16.7

 

 

(7.0)

 

(42)

%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

International

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

$

1,508,890

 

$

1,862,393

 

$

(353,503)

 

(19)

%  

Adjusted operating income (loss)

 

 

$

164,677

 

$

308,262

 

$

(143,585)

 

(47)

%  

Average rigs working (1)

 

 

 

100.2

 

 

124.0

 

 

(23.8)

 

(19)

%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rig Services

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

$

215,710

 

$

391,066

 

$

(175,356)

 

(45)

%  

Adjusted operating income (loss)

 

 

$

(48,484)

 

$

(12,641)

 

$

(35,843)

 

n/m

(2)

 

(1)

Represents 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 average rigs working. International average rigs working includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates.

 

(2)

The number is so large that it is not meaningful.


 

U.S.

 

Operating results decreased from 2015 to 2016 primarily due to the continued decline in drilling activity in the lower 48 states, reflected by a 48% reduction in the average number of rigs working during 2016 compared to the prior period. The decline in drilling activity is the result of lower customer demand for drilling rigs due to the currently depressed oil price environment. This lower demand also resulted in lower dayrates for rigs, both of which contributed to the decrease in revenue as well as adjusted operating income (loss). Partially offsetting the decrease in drilling activity during 2016 was a favorable resolution of negotiations for one of our rigs in the Gulf of Mexico, which resulted in partial recovery of standby revenues for past quarters of approximately $20.9 million. While activity levels were lower on average throughout 2016, we believe that activity levels bottomed in the earlier half of the year and we have seen a marked improvement over the second half of the year, reflected by an increase in our average rigs working of 50% from the lowest point early in the second quarter to the end of the year.

 

Canada

 

Operating results decreased from 2015 to 2016 due to a decline in both drilling rig activity and dayrates. These declines were the direct result of lower industry activity and pricing pressure from customers resulting from the decline in oil and gas prices. The lower activity is evidenced by a 42% reduction in average rigs working during 2016 compared to the prior period. The seasonal decline in the second quarter of 2016 was minimalized by the historically low first quarter rig counts, which averaged 4 rigs. However, we have experienced an increase over the course of the second half of 2016. We exited 2016 and through early 2017 with a marked increase in rigs working to 25 rigs at the end of January.

 

International

 

Operating results decreased from 2015 to 2016 primarily due to a decline in drilling activity, reflected by a 19% reduction in average rigs working during 2016 compared to the prior period. The decrease in our operating results was also adversely affected by pricing pressure and diminished demand as customers released rigs in response to the significant drop in oil prices. Partially offsetting the decrease in activity for the year ended December 31, 2016 was approximately $45.7 million in revenue related to early termination and demobilization payments, recovery of certain contractual disputes and a business interruption insurance claim.

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Rig Services

 

Operating results decreased from 2015 to 2016 primarily due to a broad-based decline in revenue-producing activities, including lower top drive and catwalk unit sales as well as the continued decline in our directional drilling businesses due to generally lower drilling activity and intense competition, all of which is driven by the current low prices of oil and gas.

 

Other Financial Information

 

Earnings (losses) from unconsolidated affiliates

 

Earnings (losses) from unconsolidated affiliates represents our share of the net income (loss), as adjusted for our basis differences, of our equity method investments, primarily composed of our investment in CJES. We accounted for our investment in CJES on a one-quarter lag through June 30, 2016. On July 20, 2016, CJES voluntarily filed for protection under chapter 11 of the Bankruptcy Code. As a result, beginning in the third quarter of 2016, we ceased accounting for our investment in CJES under the equity method of accounting. The year ended December 31, 2016 includes our share of the net income (loss) of CJES from October 1, 2015 through March 31, 2016, resulting in a loss of $221.9 million, inclusive of charges of $138.5 million representing our share of CJES’s fixed asset impairment charges for the period. As we wrote off the remaining carrying value of our investment in CJES during the second quarter of 2016, we did not record our share of the earnings (losses) of CJES for the three months ended June 30, 2016 as we are not contractually responsible for losses beyond our investment. The operating losses of CJES for the period noted above are primarily due to reduced activity levels resulting from the extended downturn in oil prices.

 

Interest expense

 

Interest expense for 2016 was $185.4 million, representing a marginal increase of $3.4 million, or 2%, compared to 2015. During 2016, we curtailed spending on major projects, which resulted in a reduction in the amount of capitalized interest recognized during the period of approximately $13.8 million. The reduction in capitalized interest for the year was partially offset by the benefit of lower interest expense incurred on our 6.15% and 9.25% senior notes of approximately $9.1 million. The average amounts outstanding under these senior notes were lower throughout 2016 due to the repurchases made in 2015 and early 2016 of approximately $10.8 million and $131.0 million, respectively.

 

Other, net

 

Other, net for 2016 was $37.5 million of expense, which was primarily comprised of net losses on sales and disposals of assets of approximately $14.8 million, legal and professional fees primarily incurred in connection with preserving our interests in CJES of $12.9 million, foreign currency exchange losses of $5.7 million and increases to litigation reserves of $3.9 million. These losses were partially offset by the gain on debt buybacks of $6.7 million.

 

Other, net for 2015 was $39.2 million of income, which was primarily comprised of a net gain of $47.1 million related to the Merger, inclusive of a $102.2 million gross gain offset by transaction costs and post-closing adjustment, and net gains on sales and disposals of assets of approximately $2.3 million. These gains were partially offset by increases to litigation reserves of $8.2 million and foreign currency exchange losses of $0.4 million.

 

Income tax rate

 

Our worldwide effective tax rate during 2016 was 15.6% compared to 22.9% during 2015. The change was attributable to the effect of the geographic mix of pre-tax earnings (losses), including greater losses in high-tax jurisdictions. The tax effect of impairments and our share of the net loss of CJES also contributed to the change.

 

Discontinued operations

 

Our discontinued operations during 2016 and 2015 consisted of our historical wholly owned oil and gas businesses. Income (loss) from discontinued operations during 2016 was a loss of $18.4 million compared to $42.8 during 2015. Our net loss during 2016 was primarily due to a $15.4 million impairment charge due to the deterioration of economic conditions in the dry gas market in western Canada. Similarly, during 2015 we recognized impairment

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charges of $51.0 million on our oil and gas properties in western Canada as well as a $3.1 million impairment charge for a note receivable remaining from the sale of one of our former Canada subsidiaries that provided logistics services.

 

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 2—Summary of Significant Accounting Policies in Part II, Item 8.—Financial Statements and Supplementary Data. Additional information relating to discontinued operations is provided in Note 4—Assets Held for Sale and Discontinued Operations in Part II, Item 8.—Financial Statements and Supplementary Data.

 

Comparison of the years ended December 31, 2015 and 2014

 

Operating revenues in 2015 totaled $3.9 billion, representing a decrease of $2.9 billion, or 43%, over 2014. The decrease in revenues was due in part to ceasing to consolidate the revenues associated with our Completion & Production Services business as a result of the Merger, which accounted for $1.9 billion, or 64%, of the overall decrease. Also contributing to the decline in revenues was the decrease in activity and reduced dayrates within our U.S. and Canada Drilling operating segments resulting from the overall decline in oil prices throughout 2015. These decreases were partially offset by an increase in revenue in our International drilling operating segment.

 

Net loss from continuing operations totaled $329.5 million for 2015 ($1.14 per diluted share) compared to a net loss from continuing operations of $669.3 million ($2.28 per diluted share) in 2014. Included in our net loss for 2015 was approximately $369.0 million in impairments and other charges. These charges resulted from the impact of the industry downturn on our business activity and future outlook as the continuation of depressed oil prices led to considerable reductions in capital spending by some of our customers and diminished demand for our drilling services. These charges were primarily comprised of $140.1 million related to tangible assets and equipment and $180.6 million related to an other-than-temporary impairment on our equity method investment in CJES. During 2014, our net loss was primarily driven by approximately $1.03 billion in impairments and other charges. 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. These charges 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. Additional information relating to impairments and other charges is provided in Note 3—Impairments and Other Charges in Part II, Item 8.—Financial Statements and Supplementary Data.

 

General and administrative expenses in 2015 totaled $324.3 million, representing a decrease of $175.7 million, or 35% over 2014. Over half of the decrease, approximately $98.5 million, was due to the fact that we ceased consolidating the expenses from our Completion & Production Services business as a result of the Merger. The remainder of the decrease was attributable to a reduction in workforce and general cost-reduction efforts across the remaining operating units and our corporate offices.

 

Research and engineering expenses in 2015 totaled $41.3 million, representing a decrease of $8.4 million, or 17%, over 2014. The decrease was primarily attributable to a reduction in workforce and general cost-reduction efforts across the various operating units.

 

Depreciation and amortization expense in 2015 was $970.5 million, representing a decrease of $174.6 million, or 15%, over 2014. The decrease was primarily due to the fact that we ceased consolidating the expenses from our Completion & Production Services business as a result of the Merger, which accounted for $170.7 million, or 98% of the decrease. The remainder of the decrease was due to the impairment and retirement of rigs and rig components during the fourth quarter of 2014, which more than offset the incremental depreciation attributed to newly constructed rigs, rig upgrades and other capital expenditures made during 2014.

 

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Segment Results of Operations

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

Increase/(Decrease)

 

 

 

2015

 

2014

 

2015 to 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

 

    

    

 

    

    

 

    

    

    

 

Operating revenues

 

 

$

1,256,989

 

$

2,159,968

 

$

(902,979)

 

(42)

%

Adjusted operating income (loss)

 

 

$

87,051

 

$

370,173

 

$

(283,122)

 

(76)

%

Average rigs working (1)

 

 

 

120.0

 

 

212.5

 

 

(92.5)

 

(44)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

$

137,494

 

$

335,192

 

$

(197,698)

 

(59)

%

Adjusted operating income (loss)

 

 

$

(7,029)

 

$

52,468

 

$

(59,497)

 

n/m

(2)

Average rigs working (1)

 

 

 

16.7

 

 

34.1

 

 

(17.4)

 

(51)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

International

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

$

1,862,393

 

$

1,624,259

 

$

238,134

 

15

%

Adjusted operating income (loss)

 

 

$

308,262

 

$

243,975

 

$

64,287

 

26

%

Average rigs working (1)

 

 

 

124.0

 

 

127.1

 

 

(3.1)

 

(2)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rig Services

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

$

391,066

 

$

692,908

 

$

(301,842)

 

(44)

%

Adjusted operating income (loss)

 

 

$

(12,641)

 

$

53,374

 

$

(66,015)

 

n/m

(2)

 

(1)

Represents 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 average rigs working. International average rigs working includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates, which totaled 2.5 years in 2014. Beginning May 24, 2015, Nabors Arabia’s operations have been consolidated.

 

(2)

The number is so large that it is not meaningful.


 

U.S.

 

Operating results decreased from 2014 to 2015 primarily due to a decline in drilling activity in the lower 48 states, reflected by a 44% reduction in average rigs working during 2015 compared to the prior period. This decrease was primarily driven by lower oil prices beginning in the fourth quarter of 2014 and diminished demand as customers released rigs and delayed drilling projects in response to the significant drop in oil prices. The decline in revenue in the lower 48 states was partially offset by a decrease in operating and general and administrative costs for this segment due to cost reduction efforts.

 

Canada

 

Operating results decreased from 2014 to 2015 primarily due to a decline in drilling rig activity and dayrates. These declines were the direct result of lower industry activity and pricing pressure from customers resulting from the decline in oil and gas prices. The lower activity is evidenced by a 51% reduction in average rigs working during 2015 compared to the prior period. The Canadian dollar weakened in 2015 compared to 2014 by approximately 19% against the U.S. dollar year-over-year. This also negatively impacted margins, as both revenues and expenses are denominated in Canadian dollars.

 

International

 

Operating results increased from 2014 to 2015 primarily as a result of an increase in rig count coupled with the incremental revenue associated with our acquisition of the remaining equity interest in Nabors Arabia in the second quarter of 2015. Our International operations also benefitted from the incremental margins associated with deployments of several newly constructed rigs throughout 2014. These increases were partially offset by a decrease in average rigs working in Mexico, Papua New Guinea and Bahrain.

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Rig Services

 

Operating results decreased from 2014 to 2015 primarily due to a broad-based decline in revenue-producing activities, including top drives and catwalk sales and the continued decline in financial results in our directional drilling businesses due to intense competition and the low price of oil. The decline in revenue was partially offset by a decrease in operating and general and administrative costs for this segment due to cost-reduction efforts.

 

Other Financial Information

 

Earnings (losses) from unconsolidated affiliates

 

Earnings (losses) from unconsolidated affiliates represents our share of the net income (loss), as adjusted for our basis differences, of our equity method investments, primarily composed of our investment in CJES. We accounted for our interest in CJES on a one-quarter lag. As a result, the year ended December 31, 2015 includes our share of the net income (loss) of CJES from the closing of the Merger until September 30, 2015, resulting in a loss of $81.3 million. The operating losses of CJES for the period noted above are primarily due to reduced activity levels driven by lower customer demand resulting from lower oil prices coupled with further pricing concessions required by the highly competitive environment.

 

Interest expense

 

Interest expense for 2015 was $181.9 million, which was relatively flat compared to 2014. Our average outstanding debt balances during 2015 were lower than those in the corresponding 2014 period, primarily due to the repayment of a portion of our outstanding debt using cash consideration received in connection with the Merger. In addition, due to the downturn in the oil and gas markets, we have curtailed spending on major projects, which resulted in a reduction in the amount of capitalized interest recognized during the period.

 

Other, net

 

The amount of other, net for 2015 was $39.2 million of income, which was primarily comprised of a net gain of $47.1 million related to the Merger, inclusive of a $102.2 million gross gain offset by transaction costs and post-closing adjustment, and net gains on sales and disposals of assets of approximately $2.3 million. These gains were partially offset by increases to litigation reserves of $8.2 million and foreign currency exchange losses of $0.4 million.

 

The amount of other, net for 2014 was $31.4 million of expense, which was primarily comprised of transaction costs related to the Merger with CJES, including professional fees and other costs incurred to reorganize the business in contemplation of the Merger, of $22.3 million. Also contributing to the change were increases to litigation reserves of $8.9 million, losses on debt buybacks of $5.6 million and 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.

 

Income tax rate

 

Our worldwide effective tax rate during 2015 was 22.9% compared to (10.4)% during 2014. The change was primarily attributable to the tax effect of the geographic mix of pre-tax earnings (losses), including greater losses in higher-tax jurisdictions. The tax effect of impairments and internal restructuring also contributed to the change.

 

Discontinued Operations

 

Our discontinued operations during 2015 and 2014 consisted of our historical wholly owned oil and gas businesses. Income (loss) from discontinued operations during 2015 was a loss of $42.8 million compared to negligible income during 2014. The net loss during 2015 was primarily related to a $51.0 million impairment charge due to the deterioration of economic conditions in the dry gas market in western Canada as well as a $3.1 million impairment charge for a note receivable remaining from the sale of one of our former Canada subsidiaries that provided logistics services.

 

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 2—Summary of

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Significant Accounting Policies in Part II, Item 8.—Financial Statements and Supplementary Data. Additional information relating to discontinued operations is provided in Note 4—Assets Held for Sale and Discontinued Operations in Part II, Item 8.—Financial Statements and Supplementary Data.

 

Liquidity and Capital Resources

 

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, 2016, we had cash and short-term investments of $295.2 million and working capital of $333.9 million. As of December 31, 2015, we had cash and short-term investments of $274.6 million and working capital of $469.4 million. At December 31, 2016, we had no borrowings outstanding under our $2.25 billion revolving credit facility and commercial paper program.

 

In December 2016, Nabors Delaware completed an offering of $600 million aggregate principal amount of 5.50% senior unsecured notes due January 15, 2023, which are fully and unconditionally guaranteed by us. The proceeds from this offering were used to prepay the $162.5 million due in 2018 under our unsecured term loan and all amounts then outstanding under our $2.25 billion revolving credit facility and commercial paper program, or $392.1 million. The remaining proceeds were allocated for general corporate purposes, including to repay and repurchase debt.

 

In January 2017, Nabors Delaware issued $575 million in aggregate principal amount of its 0.75% exchangeable senior unsecured notes due 2024, which are fully and unconditionally guaranteed by Nabors. The exchangeable notes are exchangeable, under certain conditions, at an initial exchange rate of 39.75 common shares of the Company per $1,000 principal amount of notes (equivalent to an initial exchange price of approximately $25.16 per common share). Upon any exchange, Nabors Delaware will settle its exchange obligation in cash, common shares of the Company, or a combination of cash and common shares, at our election. In connection with the pricing of the notes, we entered into privately negotiated capped call transactions which are expected to reduce potential dilution to common shares and/or offset potential cash payments required to be made in excess of the principal amount upon any exchange of notes. Such reduction and/or offset is subject to a cap representing a price per share of $31.45, an approximately 75.0% premium over our share price of $17.97 as of the date of the transaction. The net proceeds from the offering of the exchangeable notes were used to prepay the remaining balance of our unsecured term loan originally scheduled to mature in 2020, as well as to pay approximately $40.3 million for the cost of the capped call transactions. Any remaining net proceeds from the offering were allocated for general corporate purposes, including to repurchase or repay other indebtedness.

 

We had 15 letter-of-credit facilities with various banks as of December 31, 2016. Availability under these facilities as of December 31, 2016 was as follows:

 

 

 

 

 

 

 

    

December 31,

 

 

 

2016

 

 

 

(In thousands)

 

Credit available

 

$

758,906

 

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

 

 

150,424

 

Remaining availability

 

$

608,482

 

 

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. See Part 1A.—Risk Factors—A downgrade in our credit rating could negatively impact our cost of and ability to access capital markets or other financing sources.

 

Our gross debt to capital ratio was 0.52:1 as of December 31, 2016 and 0.46:1 as of December 31, 2015, respectively. Our net debt to capital of ratio was 0.50:1 as December 31, 2016 and 0.44:1 as of December 31, 2015. The

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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 3.4:1 as of December 31, 2016 and 6.2:1 as of December 31, 2015. The interest coverage ratio is a trailing 12-month quotient of the sum of (x) operating revenues, direct costs, general administrative expenses and research and engineering expenses 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. None of the above ratios give effect to the issuance of the exchangeable notes in January 2017 discussed above.

 

We are a holding company and therefore 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 flows from our operating subsidiaries. There can be no assurance that our operating subsidiaries will generate sufficient net income to pay us dividends or sufficient cash flows to make payments of interest and principal to us. See Part I., Item 1A.—Risk Factors—As a holding company, we depend on our operating subsidiaries and investments to meet our financial obligations.

 

Our current cash and investments, projected cash flows from operations 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.

 

Future Cash Requirements

 

We expect capital expenditures over the next 12 months to be less than $0.6 billion. Purchase commitments outstanding at December 31, 2016 totaled approximately $215.5 million, primarily for rig-related enhancements, new construction and equipment, as well as sustaining capital expenditures, other operating expenses and purchases of inventory. We can reduce planned expenditures if necessary or increase them if market conditions and new business opportunities warrant it. The level of our outstanding purchase commitments and our expected level of capital expenditures over the next 12 months represent a number of capital programs that are currently underway or planned. We believe these programs will result in the enhancement of a significant number of rigs in our existing Lower 48 fleet. When the programs are completed, we expect to have a larger fleet of high-specification land rigs deployed in the Lower 48. We believe the capabilities of these high-specification rigs will meet or exceed requirements from customers.

 

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.

 

On August 25, 2015, our Board authorized a share repurchase program (the “program”) under which we may repurchase, from time to time, up to $400 million of our common shares by various means, including in the open market or in privately negotiated transactions. This authorization does not have an expiration date and does not obligate us to repurchase any of our common shares. Through December 31, 2016, we repurchased 10.9 million of our common shares for an aggregate purchase price of approximately $101.3 million under this program. As of December 31, 2016, the remaining amount authorized under the program that may be used to purchase shares was $298.7 million. The repurchased shares, which are held by our subsidiaries, are registered and tradable subject to applicable securities law limitations and have the same voting and other rights as other outstanding shares. As of December 31, 2016, our subsidiaries held 49.7 million of our common shares.

 

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.

 

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See our discussion of guarantees issued by Nabors that could have a potential impact on our financial position, results of operations or cash flows in future periods included below under “Off-Balance Sheet Arrangements (Including Guarantees)”.

 

The following table summarizes our contractual cash obligations as of December 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Payments due by Period

 

 

    

Total

    

< 1 Year

    

1-3 Years

    

3-5 Years

    

Thereafter

 

 

 

(In thousands)

 

Contractual cash obligations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Principal

 

$

3,608,723

 

$

 —

 

$

1,132,248

(2)  

$

1,529,175

(3)  

$

947,300

(4)

Interest

 

 

797,058

 

 

192,065

 

 

316,219