Nabors Industries 10K 2014 Annual report

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

FORM 10-K


(Mark One)
ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number 001-32657

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


Bermuda (State or Other Jurisdiction of Incorporation or Organization)		980363970 (I.R.S. Employer Identification No.)
Crown House Second Floor 4 Par-la-Ville Road Hamilton, HM08 Bermuda (Address of principal executive offices)		N/A (Zip Code)

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

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

Title of each class		Name of each exchange on which registered

Common shares, $.001 par value per share		New York Stock Exchange

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

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý NO o

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large Accelerated Filer ý		Accelerated Filer o		Non-accelerated Filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o

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

The aggregate market value of the 276,503,079 common shares held by non-affiliates of the registrant outstanding as of the last business day of our most recently completed second fiscal quarter, June 30, 2014, based on the closing price of our common shares as of such date of $29.37 per share as reported on the New York Stock Exchange, was $8,120,895,430. Common shares held by each officer and director and by each person who owns 5% or more of the outstanding common shares have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

The number of common shares outstanding as of February 26, 2015 was 329,376,998.

DOCUMENTS INCORPORATED BY REFERENCE

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

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

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PART I
Item 1.	Business	5
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	20
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	24
PART II
Item 5.	Market Price of and Dividends on the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	27
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	141
Item 9A.	Controls and Procedures	141
Item 9B.	Other Information	143
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	144
Item 11.	Executive Compensation	144
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	144
Item 13.	Certain Relationships and Related Transactions and Director Independence	146
Item 14.	Principal Accounting Fees and Services	147
PART IV
Item 15.	Exhibits, Financial Statement Schedules	148

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

FORWARD-LOOKING STATEMENTS

We often discuss expectations regarding our future markets, demand for our products and services, and our performance in our annual, quarterly and current reports, press releases, and other written and oral statements. Statements relating to matters that are not historical facts are "forward-looking statements" within the meaning of the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Exchange Act. These "forward-looking statements" are based on an analysis of currently available competitive, financial and economic data and our operating plans. They are inherently uncertain and investors should recognize that events and actual results could turn out to be significantly different from our expectations. By way of illustration, when used in this document, words such as "anticipate," "believe," "expect," "plan," "intend," "estimate," "project," "will," "should," "could," "may," "predict" and similar expressions are intended to identify forward-looking statements.

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

•: fluctuations in worldwide prices of and demand for oil and natural gas;
•: fluctuations in levels of oil and natural gas exploration and development activities;
•: fluctuations in the demand for our services;
•: the existence of competitors, technological changes and developments in the oilfield services industry;
•: our ability to complete, and realize the expected benefits of, strategic transactions, including the proposed transaction with C&J Energy Services, Inc.;
•: the existence of operating risks inherent in the oilfield services industry;
•: the possibility of changes in tax and other laws and regulations;
•: the possibility of political instability, war or acts of terrorism; and
•: general economic conditions including the capital and credit markets.

Our businesses depend to a large degree on the level of spending by oil and gas companies for exploration, development and production activities. Therefore, a sustained increase or decrease in the price of oil or natural gas that has a material impact on exploration, development or production activities could also materially affect our financial position, results of operations and cash flows.

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The above description of risks and uncertainties is not all-inclusive, but highlights certain factors that we believe are important for your consideration. For a more detailed description of risk factors, please refer to Part I, Item 1A.—Risk Factors.

Unless the context requires otherwise, references in this report to "we," "us," "our," "the Company," or "Nabors" mean Nabors Industries Ltd., together with our subsidiaries where the context requires, including Nabors Industries, Inc., a Delaware corporation ("Nabors Delaware"), our wholly owned subsidiary.

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PART I

ITEM 1. BUSINESS

Overview

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

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

•: 466 actively marketed rigs for land-based drilling operations in the United States, Canada and over 20 other countries throughout the world;
•: 445 actively marketed rigs for land well-servicing and workover services in the United States and 98 actively marketed rigs for land well-servicing and workover services in Canada;
•: 42 actively marketed rigs for offshore drilling operations in the United States and multiple international markets; and
•: approximately 800,000 hydraulic horsepower for hydraulic fracturing, cementing, nitrogen and acid pressure pumping services in key basins throughout the United States.

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

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

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

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

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

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

Drilling & Rig Services

General

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

U.S. Drilling

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

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

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

Canada Drilling

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

International Drilling

We operate 138 land-based drilling rigs in more than 20 countries as of December 31, 2014. We also operate 19 platforms and 6 jack-up rigs in the international offshore drilling markets. We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets 5 rigs in addition to the rigs we lease to the joint venture. Many of our rigs in our international drilling markets were designed to address the challenges inherent in specific drilling applications such as those required in the desert, remote/environmentally sensitive locations and the various shale plays. We continue to upgrade and deploy high-specification desert rigs specifically for gas drilling in the Middle East.

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

Rig Services

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

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

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

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

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

Drilling Contracts

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

Our drilling contracts are typically daywork contracts. A daywork contract generally provides for a basic rate per day when drilling (the dayrate for our providing a rig and crew) and for lower rates when the rig is moving between drilling locations, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. In addition, daywork contracts may provide for a lump-sum fee for the mobilization and demobilization of the rig, which in most cases approximates our anticipated costs. A daywork contract differs from a footage contract (in which the drilling contractor is paid on the basis of a rate per foot drilled) and a turnkey contract (in which the drilling contractor is paid for drilling a well to a specified depth for a fixed price). See Part 1A.—Risk Factors—Our drilling contracts may in certain instances be renegotiated or terminated without an early termination payment.

Completion & Production Services

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

Completion Services

We provide a wide range of wellsite solutions to oil and natural gas companies, consisting primarily of technical pumping services, including hydraulic fracturing, a process sometimes used in the completion of oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and oil production, and down-hole surveying services. The completion process may involve selectively perforating the well casing at the depth of discrete producing zones, stimulating and testing these zones and installing down-hole equipment. The completion process may take a few days to several weeks. Our Completion Services operations contributed 18% of our Operating revenues for the year ended December 31, 2014.

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Production Services

We operate a fleet of 543 land workover and well-servicing rigs in the U.S. and Canada as of December 31, 2014, which are utilized to perform well maintenance and workover services during the production phase of an oil or natural gas well. Well maintenance services are generally performed on a call-out basis and can usually be completed within 48 hours. The services include the repair and replacement of pumps, sucker rods, tubing and other mechanical apparatuses at the wellsite that are used to pump or lift hydrocarbons from producing wells. We also utilize our well service rigs to perform plugging services for wells in which the oil and natural gas has been depleted or further production has become uneconomical. Workover services can be utilized to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks, or convert a depleted well to an injection well for secondary or enhanced recovery projects. Workovers are typically carried out with a rig that includes standard drilling accessories such as rotary drilling equipment, pumps and tanks for drilling fluids, blowout preventers and other specialized equipment for servicing rigs. We also provide equipment, including fluid service trucks, frac tanks and salt water disposal wells, to supply, store, remove and dispose of specialized fluids utilized in the completion and workover operations used in daily operations for producing wells.

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

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

Our Customers

Our customers include major, national and independent oil and gas companies. No customer accounted for more than 10% of our consolidated revenues in 2014.

Our Employees

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

Seasonality

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

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Research and Development

Research and development continues to be an important part of our overall business. The effective use of technology is critical to maintaining our competitive position within the drilling industry. We expect to continue developing technology internally and acquiring technology through strategic acquisitions.

Industry/Competitive Conditions

To a large degree, our businesses depend on the level of capital spending by oil and gas companies for exploration, development and production activities. During recent months, there has been substantial volatility in oil prices due to increases in global oil production with stagnant demand. For example, within the past year, oil prices have been as high as $107 per barrel and have recently been as low as $44 per barrel in 2015. Currently, based on the average crude oil price in January 2015, prices have declined approximately 49% from the average of the preceding twelve months and the decline has caused a reduction in the level of capital spending by oil companies. A prolonged period of these lower oil prices could continue to depress the level of exploration, development and production activities and result in a corresponding decline in the demand for our services and/or a reduction in dayrates and utilization, which could have an adverse effect on our financial position, results of operations and cash flows. See Part I, Item 1A.—Risk Factors—Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows and profitability.

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

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

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

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

Our Business Strategy

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

•: leveraging our existing global infrastructure and operating reputation to capitalize on growth opportunities;
•: achieving superior operational and health, safety and environmental performance;
•: continuing to develop our existing portfolio of value-added services to our customers;
•: enhancing our technology position and advancing drilling technology both on the rig and downhole; and
•: achieving returns above our cost of capital.

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

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

Acquisitions and Divestitures

We have grown from a land drilling business centered in the U.S. lower 48 states, Canada and Alaska to an international business with operations on land and offshore in most of the major oil and gas markets in the world. At the beginning of 1990, our fleet consisted of 44 actively marketed land drilling rigs in Canada, Alaska and in various international markets. Today, our worldwide fleet of actively marketed rigs consists of 466 land drilling rigs, 543 rigs for land well-servicing and workover work in the United States and Canada, 36 offshore platform rigs, 7 jackup units and a large component of trucks and fluid hauling vehicles. This growth was fueled in part by strategic acquisitions. Although we continue to examine opportunities, including acquisitions, divestitures and other strategic transactions, there can be no assurance that such opportunities will continue to be available, that the pricing will be economical or that we will be successful in making such acquisitions in the future.

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

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

Acquisitions

In January 2013, we purchased the business of Navigate Energy Services, Inc. ("NES") for a total cash price of approximately $37.5 million. This acquisition expanded our technology and development capability for drilling and measurement tools and services, and is included in our Rig Services operating segment.

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

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

Divestitures

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

In 2013, we sold the assets of one of our former Canadian subsidiaries that provided logistics services for proceeds of $9.3 million. In addition, we sold Peak Oilfield Service Company ("Peak"), one of our businesses in Alaska, for gross cash proceeds of $135.5 million. We also sold some of our oil and gas assets and received proceeds of approximately $90.0 million.

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

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

Environmental Compliance

We do not anticipate that compliance with currently applicable environmental regulations and controls will significantly change our competitive position, capital spending or earnings during 2015. We believe we are in material compliance with applicable environmental rules and regulations and that the cost of such compliance is not material to our business or financial condition. For a more detailed description of the environmental laws and regulations applicable to our operations, see Part I, Item 1A.—Risk Factors—Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect our results of operations.

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ITEM 1A. RISK FACTORS

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

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

Risks Related to the Business

Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows and profitability

Our operations depend on the level of spending by oil and gas companies for exploration, development and production activities. Both short-term and long-term trends in oil and natural gas prices affect these levels. Oil and natural gas prices, as well as the level of drilling, exploration and production activity, can be highly volatile. For example, within the past year, oil prices have been as high as $107 per barrel and have recently been as low as $44 per barrel in 2015. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, affect both the demand for, and the supply of, oil and natural gas. Weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, and other factors beyond our control may also affect the supply of and demand for oil and natural gas. A prolonged period of lower oil and natural gas prices could depress the level of drilling, exploration and production activity and result in a corresponding decline in the demand for our services and/or a reduction in dayrates and utilization, which could have an adverse effect on our revenues, cash flows and profitability. Lower oil and natural gas prices have caused some of our customers to terminate, seek to renegotiate or fail to honor our drilling contracts and affected the fair market value of our rig fleet, which in turn has resulted in impairments of our assets. For the year ended December 31, 2014, we recorded impairment charges of approximately $1.0 billion, reflecting the effect of the recent decline in oil prices on our assets. If there is a prolonged period of lower oil and natural gas prices, it could adversely impact our cash forecast models used to determine whether the carrying value of our long-lived assets exceed our future cash flows, which could result in future impairment to our long-lived assets. A prolonged period of lower oil and natural gas prices could also affect our ability to retain skilled rig personnel and affect our ability to access capital to finance and grow our business. There can be no assurances as to the future level of demand for our services or future conditions in the oil and natural gas and oilfield services industries.

We operate in a highly competitive industry with excess drilling capacity, which may adversely affect our results of operations

The oilfield services industry is very competitive. Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Most rigs and drilling-related equipment can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of such rigs and drilling-related equipment in certain areas, and accordingly, significant price competition. In addition, in recent years, the ability to deliver rigs with new technology and features has become an important factor in determining job awards. Our customers are increasingly demanding the services of newer, higher specification drilling rigs, which requires continued technological developments and increased capital expenditures, and our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements for equipment. As a result of these and other competitive factors, we may be unable to maintain or increase our market share, utilization

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

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

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

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

Our operations are subject to many hazards inherent in the drilling, workover and well-servicing and pressure pumping industries, including blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental and natural resources damage and damage to the property of others. Our offshore operations involve the additional hazards of marine operations including capsizing, grounding, collision, damage from hurricanes and heavy weather or sea conditions and unsound ocean bottom conditions. Our operations are also subject to risks of war, civil disturbances or other political events.

Accidents may occur, we may be unable to obtain desired contractual indemnities, and our insurance may prove inadequate in certain cases. The occurrence of an event not fully insured or indemnified against, or the failure or inability of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not be available to cover any or all of these risks. Even if available, insurance may be inadequate or insurance premiums or other costs may increase significantly in the future making insurance prohibitively expensive. We expect to continue facing upward pressure in our insurance renewals; our premiums and deductibles may be higher, and some insurance coverage may either be unavailable or more expensive than it has been in the past. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention. We may choose to increase the levels of deductibles (and thus assume a greater degree of risk) from time to time in order to minimize our overall costs.

The profitability of our operations could be adversely affected by war, civil disturbance, terrorist activity or other political or economic instability, fluctuation in currency exchange rates and local import and export controls

We derive a significant portion of our business from global markets, including major operations in Canada, South America, Mexico, the Middle East, the Far East, the South Pacific, Russia and Africa. These operations are subject to various risks, including war, civil disturbances, political or economic instability, terrorist activity and governmental actions that may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. In some countries, our operations may be subject to the additional risk of fluctuating currency values and exchange controls. We are subject to various laws and regulations that govern the

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operation and taxation of our business and the import and export of our equipment from country to country, the imposition, application and interpretation of which can prove to be uncertain.

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

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

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

As of December 31, 2014, we had approximately $4.4 billion in outstanding debt. We also have various financial commitments, such as leases, firm transportation and processing, contracts and purchase commitments. Our ability to service our debt and other financial obligations depends in large part upon the level of cash flows generated by our subsidiaries' operations, our ability to monetize and/or divest non-core assets, availability under our unsecured revolving credit facility and our ability to access the capital markets.

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

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

The loss of key executives or inability to attract and retain experienced technical personnel could reduce our competitiveness and harm prospects for future success

The successful execution of our business strategies will depend, in part, on the continued service of certain key executive officers. We have employment agreements with some of our key personnel within the company. We do not carry significant amounts of key man insurance. In addition, our operations depend, in part, on our ability to attract and retain experienced technical professionals. Competition for such professionals is intense. The loss of key executive officers and/or our inability to retain or attract experienced technical personnel, could reduce our competitiveness and harm prospects for future success, which may adversely affect our business, financial condition and results of operations.

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

Drilling of oil and gas wells is subject to various laws, rules and regulations in the jurisdictions where we operate. Our cost of compliance with these laws may be substantial. For example, the U.S. Environmental Protection Agency ("EPA") has promulgated rules requiring the reporting of greenhouse gas emissions applicable to certain offshore oil and natural gas production and onshore oil and natural

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gas production, processing, transmission, storage and distribution facilities. In addition, U.S. federal law strictly regulates the prevention of oil spills and the release of hazardous substances, and imposes liability for removal costs and natural resource, real or personal property and certain economic damages arising from any spills. Some of these laws may impose strict and/or joint and several liability for clean-up costs and damages without regard to the conduct of the parties. As an owner and operator of onshore and offshore rigs and other equipment, we may be deemed to be a responsible party under federal law. In addition, our completion and production services operations routinely involve the handling of significant amounts of materials, some of which are classified as solid or hazardous wastes or hazardous substances. We are subject to various laws governing the containment and disposal of hazardous substances, oilfield waste and other waste materials, the use of underground storage tanks and the use of underground injection wells. We employ personnel responsible for monitoring environmental compliance and arranging for remedial actions that may be required from time to time and also use consultants to advise on and assist with our environmental compliance efforts. Liabilities are recorded when the need for environmental assessments and/or remedial efforts become known or probable and the cost can be reasonably estimated.

Changes in environmental laws may also negatively impact the operations of oil and natural gas exploration and production companies, which in turn could have an adverse effect on us. For example, legislation has been proposed from time to time in the U.S. Congress that would reclassify some oil and natural gas production wastes as hazardous wastes under the Resources Conservation and Recovery Act, which would make the reclassified wastes subject to more stringent and costly handling, disposal and clean-up requirements. In addition, the Outer Continental Shelf Lands Act provides the federal government with broad discretion in regulating the leasing of offshore oil and gas production sites. Legislators and regulators in the United States and other jurisdictions where we operate also focus increasingly on restricting the emission of carbon dioxide, methane and other greenhouse gases that may contribute to warming of the Earth's atmosphere, and other climatic changes. The U.S. Congress has considered legislation designed to reduce emission of greenhouse gases, and some states in which we operate have passed legislation or adopted initiatives, such as the Regional Greenhouse Gas Initiative in the northeastern United States and the Western Regional Climate Action Initiative, which establish greenhouse gas inventories and/or cap-and-trade programs. Some international initiatives have also been adopted, which could result in increased costs of operations in covered jurisdictions. In addition, the EPA has published findings that emissions of greenhouse gases present an endangerment to public health and the environment, paving the way for further regulations that could restrict emissions of greenhouse gases under existing provisions of the Clean Air Act. The EPA has already issued rules requiring monitoring and reporting of greenhouse gas emissions from oil and natural gas systems. Future or more stringent regulation could dramatically increase operating costs for oil and natural gas companies and could reduce the market for our services by making wells and/or oilfields uneconomical to operate.

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

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

Operations in our Completion Services operating segment include hydraulic fracturing, a process sometimes used in the completion of oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. Hydraulic fracturing activities are currently exempt under the Safe Drinking Water Act ("SDWA"), except for such activities that use diesel fuel, for which the EPA has asserted federal regulatory authority over and issued permitting guidance on in February 2014. In 2012, the EPA promulgated new rules establishing new air emission controls for oil and gas production and natural gas processing operations. More recently, in May 2014, the EPA issued an advanced notice of proposed rulemaking regarding the agency's intent to develop regulations under the Toxic Substances and Control Act related to the disclosure of chemicals used in hydraulic fracturing. The EPA is also conducting a study of the potential environmental impacts from hydraulic fracturing on drinking water resources and developing rules on effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities, both which are expected for publication in early 2015. In addition, the federal Bureau of Land Management has proposed new requirements on hydraulic fracturing conducted on federal lands, including the disclosure of chemical additives used. In 2011, the U.S. Department of Energy released a report on hydraulic fracturing, recommending the implementation of a variety of measures to reduce the environmental impacts from shale-gas production. In addition, there has been public opposition to hydraulic fracturing. As a result, there have been legislative initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. From time to time, legislation has also been introduced in the U.S. Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require the disclosure of chemicals used in the hydraulic fracturing process. In addition, various states and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements and temporary or permanent bans. For example, Texas has adopted legislation that requires the public disclosure of information regarding the substances used in the hydraulic fracturing process, and, on December 17, 2014, the State of New York announced a ban on hydraulic fracturing due to public health and environmental concerns identified in its several years study. In addition, municipalities in Colorado and several other states have adopted or are in the process of adopting ordinances restricting or prohibiting hydraulic fracturing within their jurisdictions. New or further changes in laws and regulations imposing reporting obligations on, or otherwise banning or limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, cause operational delays, increase costs of regulatory compliance or in exploration and production, which could adversely affect our business and the demand for fracturing services.

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

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

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

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

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

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

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

•: Classifying our Board of Directors ("Board") so that all the directors could not be replaced at a single meeting;
•: Authorizing the Board to issue a significant number of common shares and up to 25,000,000 preferred shares, as well as to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of the preferred shares, in each case without any vote or action by the holders of our common shares;
•: Adopting a shareholder rights plan that limits the number of shares of our common stock a potential acquiror can purchase without either securing the approval of our Board or having their voting interest severely diluted. The plan is scheduled to expire in July 2016 unless it is extended;
•: Limiting the ability of our shareholders to call or bring business before special meetings;
•: Prohibiting our shareholders from taking action by written consent in lieu of a meeting unless the consent is signed by all the shareholders then entitled to vote;
•: Requiring advance notice of shareholder proposals for business to be conducted at general meetings and for nomination of candidates for election to our Board; and
•: Reserving to our Board the ability to determine the number of directors comprising the full Board and to fill vacancies or newly created seats on the Board.

At the request of shareholders, we declassified the Board, which makes it easier for another party to acquire control of the Company. The remaining provisions designed to avoid a coercive takeover may not be fully effective so that a party may still be able to acquire the Company without paying what the Board considers to be fair value, including a control premium. Conversely, such provisions could discourage a would-be acquiror and thus reduce the likelihood that shareholders would receive a premium for their shares in a takeover.

We may have additional tax liabilities

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

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

Legal proceedings could affect our financial condition and results of operations

We are subject to legal proceedings and governmental investigations from time to time that include employment, tort, intellectual property and other claims, and purported class action and shareholder derivative actions. We are also subject to complaints and allegations from former, current or prospective employees from time to time, alleging violations of employment-related laws. Lawsuits or claims could result in decisions against us that could have an adverse effect on our financial condition or results of operations.

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

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

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

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

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

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

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

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

Our business is subject to cybersecurity risks

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

Risks Related to the Merger

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

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

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

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

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

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ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

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

Many of the international drilling rigs and some of the Alaska rigs in our fleet are supported by mobile camps which house the drilling crews and a significant inventory of spare parts and supplies. In addition, we own various trucks, forklifts, cranes, earth-moving and other construction and transportation equipment, which are used to support our operations. We also own or lease a number of facilities and storage yards used in support of operations in each of our geographic markets.

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

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

The estimates of net proved oil and gas reserves as of December 31, 2012 were based on reserve reports prepared by independent petroleum engineers. AJM Deloitte prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Canada. Cawley, Gillespie & Associates, Inc. prepared reports of estimated proved oil reserves for our wholly owned assets located in the Eagle Ford Shale, Texas. DeGolyer and MacNaughton Corp. prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Alaska.

Summary of Oil and Gas Reserves

The table below summarizes the proved reserves in each geographic area and by product type for our wholly owned subsidiaries for the applicable reporting period presented. We report proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Estimates of volumes of proved reserves of natural gas at year end are expressed in billions of cubic feet of natural gas ("Bcf") at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels ("MMBbls") for oil and natural gas liquids.

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Reserve Category

	Proved Developed				Undeveloped				Total

	Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)
As of December 31, 2012:
Consolidated subsidiaries
United States		1.1		0.4		14.3		0.7		15.4		1.1
Canada		—		7.7		—		—		—		7.7
Colombia		—		—		—		—		—		—

Total consolidated(1)		1.1		8.1		14.3		0.7		15.4		8.8

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

Oil and Gas Production, Production Prices and Production Costs

Oil and Gas Production

The table below summarizes production by final product sold, average production sales price and average production cost, each by geographic area for 2012. Production costs are costs to operate and maintain our wells and related equipment and include the cost of labor, well-service and repair, location maintenance, power and fuel, transportation, cost of product, property taxes and production-related general and administrative costs.

	United States					Canada				Colombia					Total

	Liquids (MMBbls)		Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)
For the year ended December 31, 2012:
Oil and natural gas liquids production
Consolidated subsidiaries		0.268		0.938			—		2.00		0.003			—		0.271		2.938

Equity companies(1)		0.545		19.01			—		—		—			—		0.545		19.010
Average production sales prices:
Consolidated subsidiaries	$	76.74	$	3.04		$	—	$	2.36	$	130.04		$	—	$	77.33	$	2.58

Equity companies(1)	$	53.94	$	2.70		$	—	$	—	$	—		$	—	$	53.94	$	2.70
Average production costs ($/boe):
Consolidated subsidiaries			$	3.52/Mcfe	(2)			$	2.91/Mcfe	$	31.75/Boe	(3)

Equity companies(1)			$	1.47/Mcfe				$	—	$	—

(1): Represents our proportionate interests in our equity companies for the applicable period.
(2): Reflects the thousand cubic feet ("Mcf") equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or natural gas liquids, or "Mcfe".
(3): Reflects the barrel of oil equivalent or "Boe".

Drilling and Other Exploratory and Development Activities

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

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Number of Net Productive and Exploratory Wells Drilled



For the year ended December 31, 2012:
Consolidated subsidiaries
United States	2.40	—	6.50	—
Colombia	1.15	—	—	—

Total consolidated	3.55	—	6.50	—

Equity companies(1)
United States	1.49	—	3.48	—

Total equity companies	1.49	—	3.48	—

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

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

Our revenues and property, plant and equipment by geographic area can be found in Note 23—Segment Information in Part II, Item 8.—Financial Statements and Supplementary Data. Information about our rig fleet is included under the caption Overview in Part I, Item 1.—Business.

ITEM 3. LEGAL PROCEEDINGS

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

In 2009, the Court of Ouargla entered a judgment of approximately $16.4 million (at December 31, 2014 exchange rates) against us relating to alleged customs infractions in Algeria. We believe we did not receive proper notice of the judicial proceedings, and that the amount of the judgment was excessive in any case. We asserted the lack of legally required notice as a basis for challenging the judgment on appeal to the Algeria Supreme Court. In May 2012, that court reversed the lower court and remanded the case to the Ouargla Court of Appeals for treatment consistent with the Supreme Court's ruling. In January 2013, the Ouargla Court of Appeals reinstated the judgment. We have again lodged an appeal to the Algeria Supreme Court, asserting the same challenges as before. Based upon our understanding of applicable law and precedent, we continue to believe that we

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will prevail. Although the appeal remains ongoing at this time, the Hassi Messaoud customs office recently initiated efforts to collect the judgment prior to the Supreme Court's decision in the case. As a result, we paid approximately $3.1 million and posted security of approximately $1.33 million to suspend those collection efforts and to enter into a formal negotiations process with the customs authority. We have recorded a reserve in the amount of the posted security. Algerian Customs have recently demanded 50% of the total fine as a final settlement which would require an additional payment of approximately $4.425 million. We have elected to await the ruling from the Supreme Court. The matter was heard on February 26, 2015, and a decision will be issued on March 26, 2015. If we are ultimately required to pay a fine or judgment related to this matter, the resulting loss could be up to $12.0 million in excess of amounts accrued.

In March 2011, the Court of Ouargla entered a judgment of approximately $32.2 million (at December 31, 2014 exchange rates) against us relating to alleged violations of Algeria's foreign currency exchange controls, which require that goods and services provided locally be invoiced and paid in local currency. The case relates to certain foreign currency payments made to us by CEPSA, a Spanish operator, for wells drilled in 2006. Approximately $7.5 million of the total contract amount was paid offshore in foreign currency, and approximately $3.2 million was paid in local currency. The judgment includes fines and penalties of approximately four times the amount at issue. We have appealed the ruling based on our understanding that the law in question applies only to resident entities incorporated under Algerian law. An intermediate court of appeals upheld the lower court's ruling, and we appealed the matter to the Algeria Supreme Court. On September 25, 2014, the Supreme Court of Algeria overturned the verdict against us, and the case will now be reheard by the Court of Appeal Ouargla in light of the Algeria Supreme Court's opinion. The rehearing has been set for March 8, 2015. While our payments were consistent with our historical operations in the country, and, we believe, those of other multinational corporations there, as well as interpretations of the law by the Central Bank of Algeria, the ultimate resolution of this matter could result in a loss of up to $24.2 million in excess of amounts accrued.

In March 2012, Nabors Global Holdings II Limited ("NGH2L") signed a contract with ERG Resources, LLC ("ERG") relating to the sale of all of the Class A shares of NGH2L's wholly owned subsidiary, Ramshorn International Limited, an oil and gas exploration company. When ERG failed to meet its closing obligations, NGH2L terminated the transaction on March 19, 2012 and, as contemplated in the agreement, retained ERG's $3.0 million escrow deposit. ERG filed suit the following day in the 61st Judicial District Court of Harris County, Texas, in a case styled ERG Resources, LLC v. Nabors Global Holdings II Limited, Ramshorn International Limited, and Parex Resources, Inc.; Cause No. 2012-16446, seeking injunctive relief to halt any sale of the shares to a third party, specifically naming as defendant Parex Resources, Inc. ("Parex"). The lawsuit also seeks monetary damages of up to $750.0 million based on an alleged breach of contract by NGH2L and alleged tortious interference with contractual relations by Parex. Nabors successfully defeated ERG's effort to obtain a temporary restraining order from the Texas court on March 20, 2012. Nabors completed the sale of Ramshorn's Class A shares to a Parex affiliate in April 2012, which mooted ERG's application for a temporary injunction. The lawsuit is staid, pending further court actions including appeals of the jurisdictional decisions. ERG retains its causes of action for monetary damages, but Nabors believes the claims are foreclosed by the terms of the agreement and are without factual or legal merit. Although we are vigorously defending the lawsuit, its ultimate outcome cannot be determined at this time.

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

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Market Information.

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

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

		Share Price

Calendar Year		High		Low
2013	First Quarter	$	18.24	$	14.35
	Second Quarter	$	17.35	$	14.34
	Third Quarter	$	16.72	$	14.50
	Fourth Quarter	$	18.33	$	15.32
2014	First Quarter	$	25.06	$	16.43
	Second Quarter	$	29.90	$	23.36
	Third Quarter	$	30.24	$	22.51
	Fourth Quarter	$	23.08	$	9.91

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Holders.

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

Dividends.

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

In 2013, our Board approved the payment of cash dividends on our common stock. Dividends in the amount of $0.04 per share were paid in March, June, September and December of 2013 and March and June of 2014. The dividend was increased to $0.06 per share in July 2014 by our Board, and this new amount was paid in September and December 2014. There were no dividends paid in 2012. The declaration and payment of future dividends will be at the discretion of the Board and will depend, among other things, on future earnings, general financial condition and liquidity, success in business activities, capital requirements, and general business conditions.

Issuer Purchases of Equity Securities.

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

Period (In thousands, except per share amounts)		Average Price Paid per Share(1)

October 1 - October 31	2	$	21.51	—	—
November 1 - November 30	7	$	17.85	—	—
December 1 - December 31	< 1	$	11.97	—	—

(1): Shares were withheld from employees and directors to satisfy certain tax withholding obligations due in connection with grants of stock under our 2003 Employee Stock Plan and 2013 Stock Plan. The 2003 Employee Stock Plan, 2013 Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-employee Directors and 1996 Employee Stock Plan provide for the withholding of shares to satisfy tax obligations, but do not specify a maximum number of shares that can be withheld for this purpose. These shares were purchased in the open market.
(2): We do not have a current share repurchase program authorized by the Board.

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

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

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Performance Graph

The following graph illustrates comparisons of five-year cumulative total returns among Nabors, the S&P 500 Index and the Dow Jones Oil Equipment and Services Index. Total return assumes $100 invested on December 31, 2009 in shares of Nabors, the S&P 500 Index, and the Dow Jones Oil Equipment and Services Index. It also assumes reinvestment of dividends and is calculated at the end of each calendar year, presented in the table below.



Nabors Industries Ltd.	107	79	66	78	61
S&P Index	115	117	136	180	205
Dow Jones Oil Equipment and Services Index	127	112	112	144	119

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

Related Shareholder Matters

Bermuda has exchange controls which apply to residents in respect of the Bermuda dollar. As an exempted company, Nabors is considered to be nonresident for such controls; consequently, there are no Bermuda governmental restrictions on our ability to make transfers and carry out transactions in all other currencies, including currency of the United States.

There is no reciprocal tax treaty between Bermuda and the United States regarding withholding taxes. Under existing Bermuda law there is no Bermuda income or withholding tax on dividends paid by Nabors to its shareholders. Furthermore, no Bermuda tax is levied on the sale or transfer (including by gift and/or on the death of the shareholder) of Nabors common shares (other than by shareholders resident in Bermuda).

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ITEM 6. SELECTED FINANCIAL DATA

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

	Year Ended December 31,

Operating Data(1)(2)	2014			2013			2012			2011			2010
	(In thousands, except per share amounts and ratio data)
Revenues and other income:
Operating revenues	$	6,804,197		$	6,152,015		$	6,843,051		$	6,013,480		$	4,134,483
Earnings (losses) from unconsolidated affiliates		(6,301	)		39			(288,718	)		85,448			58,641
Investment income		11,831			96,577			63,137			19,939			7,263

Total revenues and other income		6,809,727			6,248,631			6,617,470			6,118,867			4,200,387

Costs and other deductions:
Direct costs		4,505,064			3,981,828			4,367,106			3,738,506			2,397,061
General and administrative expenses		549,734			525,330			527,953			487,808			338,720
Depreciation and amortization		1,145,100			1,086,677			1,039,923			918,122			760,962
Interest expense		177,948			223,418			251,904			256,632			272,712
Losses (gains) on sales and disposals of long-lived assets and other expense (income), net		9,073			37,977			(136,636	)		4,474			45,334
Impairments and other charges		1,027,423			287,241			290,260			198,072			61,292

Total costs and other deductions		7,414,342			6,142,471			6,340,510			5,603,614			3,876,081

Income (loss) from continuing operations before income taxes		(604,615	)		106,160			276,960			515,253			324,306
Income tax expense (benefit)		62,666			(55,181	)		40,986			165,083			49,190
Subsidiary preferred stock dividend		1,984			3,000			3,000			3,000			750

Income (loss) from continuing operations, net of tax		(669,265	)		158,341			232,974			347,170			274,366
Income (loss) from discontinued operations, net of tax		21			(11,179	)		(67,526	)		(97,601	)		(161,090	)

Net income (loss)		(669,244	)		147,162			165,448			249,569			113,276
Less: Net (income) loss attributable to noncontrolling interest		(1,415	)		(7,180	)		(621	)		(1,045	)		(85	)

Net income (loss) attributable to Nabors	$	(670,659	)	$	139,982		$	164,827		$	248,524		$	113,191

Earnings (losses) per share:
Basic from continuing operations	$	(2.28	)	$	0.51		$	0.80		$	1.21		$	0.96
Basic from discontinued operations		—			(0.04	)		(0.23	)		(0.34	)		(0.56	)

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

Diluted from continuing operations	$	(2.28	)	$	0.51		$	0.79		$	1.18		$	0.95
Diluted from discontinued operations		—			(0.04	)		(0.23	)		(0.33	)		(0.56	)

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

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	Year Ended December 31,

Operating Data(1)(2)	2014		2013		2012		2011		2010
	(In thousands, except per share amounts and ratio data)
Weighted-average number of common shares outstanding:
Basic		290,694		294,182		289,965		287,118		285,145
Diluted		290,694		296,592		292,323		292,484		289,996
Capital expenditures and acquisitions of businesses(3)	$	1,923,779	$	1,365,994	$	1,433,586	$	2,247,735	$	1,878,063
Interest coverage ratio(4)		9.8:1		7.4:1		7.7:1		7.0:1		5.2:1

	As of December 31,

Balance Sheet Data(1)(2)	2014		2013		2012		2011		2010
	(In thousands, except per share amounts and ratio data)
Cash, cash equivalents and short-term investments	$	536,169	$	507,133	$	778,204	$	539,489	$	801,190
Working capital		1,174,399		1,442,406		2,000,475		1,285,752		458,550
Property, plant and equipment, net		8,599,125		8,597,813		8,712,088		8,629,946		7,815,419
Total assets		11,879,942		12,159,811		12,656,022		12,899,538		11,605,166
Long-term debt		4,348,859		3,904,117		4,379,336		4,348,490		3,064,126
Shareholders' equity		4,908,619		5,969,086		5,944,929		5,587,022		5,322,524
Debt to capital ratio:
Gross(5)		0.47:1		0.40:1		0.42:1		0.45:1		0.45:1
Net(6)		0.44:1		0.36:1		0.38:1		0.42:1		0.41:1

(1): All periods present the operating activities of most of our wholly owned oil and gas businesses, our previously held equity interests in oil and gas joint ventures in Canada and Colombia, aircraft logistics operations and construction services as discontinued operations.
(2): Our acquisitions' results of operations and financial position have been included beginning on the respective dates of acquisition and include 2TD (October 2014), KVS (October 2013), Navigate Energy Services, Inc. (January 2013), Peak (July 2011), Stone Mountain Venture Partnership (June 2011), Energy Contractors (December 2010) and Superior Well Services, Inc. (September 2010).
(3): Represents capital expenditures and the total purchase price of acquisitions.
(4): The interest coverage ratio is a trailing 12-month quotient of the sum of (x) operating revenues and earnings (losses) from unconsolidated affiliates, direct costs and general and administrative expensesless earnings (losses) from the U.S. unconsolidated oil and gas joint venturedivided 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 debtplus 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 debtminus the sum of cash and cash equivalents and short-term investments. Net capital is the sum of net debtplus 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

Drilling & Rig Services

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

Completion & Production Services

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

Outlook

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

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

	Year Ended December 31,						Increase/(Decrease)

	2014		2013		2012		2014 to 2013					2013 to 2012
Commodity prices:
Average Henry Hub natural gas spot price ($/mcf)	$	4.35	$	3.72	$	2.75	$	0.63		17	%	$	0.97	35	%
Average West Texas intermediate crude oil spot price ($/barrel)	$	93.03	$	98.02	$	94.10	$	(4.99	)	(5	)%	$	3.92	4	%

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

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

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

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

Financial Results

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

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

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

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

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

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

During 2012, our income (loss) from continuing operations was negatively impacted by impairments and other charges, including full-cost ceiling test writedowns from Sabine totaling $283.4 million, representing our proportionate share of the writedowns, a $75.0 million impairment of an intangible asset related to the Superior trade name, a provision for the retirement of long-lived assets totaling $138.7 million in multiple operating segments, a $50.4 million impairment of some coil-tubing rigs and a goodwill impairment totaling $26.3 million. Partially offsetting these charges were $160.0 million of asset gains, primarily relating to selling our interest in Sabine at the end of 2012. Excluding these items, our operating results improved as a result of increased demand for our services and products due to increased drilling activity in oil- and liquids-rich shale plays and increased well-servicing activity in the U.S. and Canada. This increase in activity has more than offset the drop in demand from gas-related plays.

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

	Year Ended December 31,									Increase/(Decrease)

	2014			2013			2012			2014 to 2013					2013 to 2012
	(In thousands, except percentages and rig activity)
Reportable segments:
Operating revenues and Earnings (losses) from unconsolidated affiliates
Drilling & Rig Services:
U.S.	$	2,159,968		$	1,914,786		$	2,276,808		$	245,182		13	%	$	(362,022	)	(16	)%
Canada		335,192			361,676			429,411			(26,484	)	(7	)%		(67,735	)	(16	)%
International		1,623,102			1,464,264			1,265,060			158,838		11	%		199,204		16	%
Rig Services(2)		687,302			516,004			688,310			171,298		33	%		(172,306	)	(25	)%

Subtotal Drilling & Rig Services(3)		4,805,564			4,256,730			4,659,589			548,834		13	%		(402,859	)	(9	)%
Completion & Production Services:
Completion Services		1,218,361			1,074,713			1,462,767			143,648		13	%		(388,054	)	(27	)%
Production Services		1,033,538			1,009,214			1,000,873			24,324		2	%		8,341		1	%

Subtotal Completion & Production Services(4)		2,251,899			2,083,927			2,463,640			167,972		8	%		(379,713	)	(15	)%
Other reconciling items(5)(7)		(259,567	)		(188,603	)		(568,896	)		(70,964	)	(38	)%		380,293		67	%

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

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	Year Ended December 31,									Increase/(Decrease)

	2014			2013			2012			2014 to 2013					2013 to 2012
	(In thousands, except percentages and rig activity)
Adjusted income (loss) derived from operating activities(1)(6)
Drilling & Rig Services:
U.S.	$	370,173		$	315,496		$	509,894		$	54,677		17	%	$	(194,398	)	(38	)%
Canada		52,468			61,193			91,360			(8,725	)	(14	)%		(30,167	)	(33	)%
International		242,818			177,833			91,226			64,985		37	%		86,607		95	%
Rig Services(2)		47,768			(3,918	)		67,366			51,686		n/m	(8)		(71,284	)	(106	)%

Subtotal Drilling & Rig Services(3)		713,227			550,604			759,846			162,623		30	%		(209,242	)	(28	)%
Completion & Production Services:
Completion Services		(15,078	)		51,722			188,518			(66,800	)	(129	)%		(136,796	)	(73	)%
Production Services		93,414			102,130			108,835			(8,716	)	(9	)%		(6,705	)	(6	)%

Subtotal Completion & Production Services(4)		78,336			153,852			297,353			(75,516	)	(49	)%		(143,501	)	(48	)%
Other reconciling items(7)		(193,565	)		(146,237	)		(148,649	)		(47,328	)	(32	)%		2,412		2	%

Total adjusted income (loss) derived from operating activities	$	597,998		$	558,219		$	908,550		$	39,779		7	%	$	(350,331	)	(39	)%

U.S. oil and gas joint venture earnings (losses)		—			—			(289,199	)		—		—			289,199		100	%
Interest expense		(177,948	)		(223,418	)		(251,904	)		45,470		20	%		28,486		11	%
Investment income (loss)		11,831			96,577			63,137			(84,746	)	(88	)%		33,440		53	%
Gains (losses) on sales and disposals of long-lived assets and other income (expense), net		(9,073	)		(37,977	)		136,636			28,904		76	%		(174,613	)	(128	)%
Impairments and other charges		(1,027,423	)		(287,241	)		(290,260	)		(740,182	)	(258	)%		3,019		1	%

Income (loss) from continuing operations before income taxes		(604,615	)		106,160			276,960			(710,775	)	(670	)%		(170,800	)	(62	)%
Income tax expense (benefit)		62,666			(55,181	)		40,986			117,847		214	%		(96,167	)	(235	)%
Subsidiary preferred stock dividend		1,984			3,000			3,000			(1,016	)	(34	)%		—		—

Income (loss) from continuing operations, net of tax		(669,265	)		158,341			232,974			(827,606	)	(523	)%		(74,633	)	(32	)%
Income (loss) from discontinued operations, net of tax		21			(11,179	)		(67,526	)		11,200		100	%		56,347		83	%

Net income (loss)		(669,244	)		147,162			165,448			(816,406	)	(555	)%		(18,286	)	(11	)%
Less: Net (income) loss attributable to noncontrolling interest		(1,415	)		(7,180	)		(621	)		5,765		80	%		(6,559	)	n/m	(8)

Net income (loss) attributable to Nabors	$	(670,659	)	$	139,982		$	164,827		$	(810,641	)	(579	)%	$	(24,845	)	(15	)%

Rig activity:
Rig years:(9)
U.S.		212.5			195.0			219.1			17.5		9	%		(24.1	)	(11	)%
Canada		34.1			29.9			34.8			4.2		14	%		(4.9	)	(14	)%
International(10)		127.1			124.2			119.3			2.9		2	%		4.9		4	%

Total rig years		373.7			349.1			373.2			24.6		7	%		(24.1	)	(6	)%

Rig hours:(11)
Production Services		809,438			865,939			853,373			(56,501	)	(7	)%		12,566		1	%
Canada Production Services		139,938			152,747			181,185			(12,809	)	(8	)%		(28,438	)	(16	)%

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

(1): All periods present the operating activities of most of our wholly owned oil and gas businesses, our previously held equity interests in oil and gas joint ventures in Canada and Colombia, aircraft logistics operations and construction services as discontinued operations.
(2): Includes our other services comprised of our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software services.
(3): Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of ($6.8) million and ($0.4) million for the years ended December 31, 2014 and 2013, respectively.
(4): Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $0.5 million, $0.4 million, and $0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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(5): Represents the elimination of inter-segment transactions and earnings (losses), net from the U.S. unconsolidated oil and gas joint venture, accounted for using the equity method until sold in December 2012, of ($289.2) million for the year ended December 31, 2012.
(6): Adjusted income (loss) derived from operating activities is computed by subtracting the sum of direct costs, general and administrative expenses, depreciation and amortization from the sum of Operating revenues and Earnings (losses) from unconsolidated affiliates. Adjusted income (loss) derived from operating activities is a non-GAAP measure and should not be used in isolation as a substitute for the amounts reported in accordance with GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income (loss) derived from operating activities, because it believes that these financial measures accurately reflect our ongoing profitability. A reconciliation of this non-GAAP measure to income (loss) from continuing operations before income taxes, which is a GAAP measure, is provided in the above table.
(7): Represents the elimination of inter-segment transactions and unallocated corporate expenses.
(8): Number is so large that it is not meaningful.
(9): Excludes well-servicing rigs, which are measured in rig hours. Includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates. Rig years represent a measure of the number of equivalent rigs operating during a given period. For example, one rig operating 182.5 days during a 365-day period represents 0.5 rig years.
(10): International rig years include our equivalent percentage ownership of rigs owned by unconsolidated affiliates, which totaled 2.5 years in 2014, 2013 and 2012.
(11): Rig hours represents the number of hours that our well-servicing rig fleet operated during the year.

Segment Results of Operations

Drilling & Rig Services

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

	Years Ended December 31,							Increase/(Decrease)

	2014		2013			2012		2014 to 2013					2013 to 2012
	(In thousands, except percentages and rig activity)
U.S.
Revenues	$	2,159,968	$	1,914,786		$	2,276,808	$	245,182		13	%	$	(362,022	)	(16	)%
Adjusted income	$	370,173	$	315,496		$	509,894	$	54,677		17	%	$	(194,398	)	(38	)%
Rig years		212.5		195.0			219.1		17.5		9	%		(24.1	)	(11	)%
Canada
Revenues	$	335,192	$	361,676		$	429,411	$	(26,484	)	(7	)%	$	(67,735	)	(16	)%
Adjusted income	$	52,468	$	61,193		$	91,360	$	(8,725	)	(14	)%	$	(30,167	)	(33	)%
Rig years		34.1		29.9			34.8		4.2		14	%		(4.9	)	(14	)%
International
Revenues	$	1,623,102	$	1,464,264		$	1,265,060	$	158,838		11	%	$	199,204		16	%
Adjusted income	$	242,818	$	177,833		$	91,226	$	64,985		37	%	$	86,607		95	%
Rig years		127.1		124.2			119.3		2.9		2	%		4.9		4	%
Rig Services
Revenues	$	687,302	$	516,004		$	688,310	$	171,298		33	%	$	(172,306	)	(25	)%
Adjusted income (loss)	$	47,768	$	(3,918	)	$	67,366	$	51,686		n/m	(1)	$	(71,284	)	(106	)%

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

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U.S.

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

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

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

Canada

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

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

International

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

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

Rig Services

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

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

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Completion & Production Services

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

	Year Ended December 31,							Increase/(Decrease)

	2014			2013		2012		2014 to 2013					2013 to 2012
	(In thousands, except percentages and rig activity)
Completion Services
Revenues	$	1,218,361		$	1,074,713	$	1,462,767	$	143,648		13	%	$	(388,054	)	(27	)%
Adjusted income	$	(15,078	)	$	51,722	$	188,518	$	(66,800	)	(129	)%	$	(136,796	)	(73	)%
Production Services
Revenues	$	1,033,538		$	1,009,214	$	1,000,873	$	24,324		2	%	$	8,341		1	%
Adjusted income	$	93,414		$	102,130	$	108,835	$	(8,716	)	(9	)%	$	(6,705	)	(6	)%
Rig hours
U.S.		809,438			865,939		853,373		(56,501	)	(7	)%		12,566		1	%
Canada		139,938			152,747		181,185		(12,809	)	(8	)%		(28,438	)	(16	)%

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

Completion Services

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

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

Production Services

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

Operating results were essentially flat to slightly down from 2012 to 2013 due to higher depreciation and other costs associated with our rig and truck fleet, as a result of capital invested over the past few years to increase those fleets. This was partially offset by the increase in revenue associated with our acquisition of KVS. Additionally, our U.S. markets have had higher utilization and increases in rig and truck fleets as well as frac tank counts, despite continued pricing challenges.

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OTHER FINANCIAL INFORMATION

	Year Ended December 31,									Increase/(Decrease)

	2014			2013			2012			2014 to 2013					2013 to 2012
	(In thousands, except percentages)
General and administrative expenses	$	549,734		$	525,330		$	527,953		$	24,404		5	%	$	(2,623	)	(0	)%
As a percentage of operating revenue		8.1	%		8.5	%		8.1	%		(0.5	)%	(5.3	)%		0.5	%	6.0	%
Depreciation and amortization		1,145,100			1,086,677			1,039,923			58,423		5	%		46,754		4	%
Interest expense		177,948			223,418			251,904			(45,470	)	(20	)%		(28,486	)	(11	)%
Investment income		11,831			96,577			63,137			(84,746	)	(88	)%		33,440		53	%
Losses (gains) on sales and disposals of long-lived assets and other expense (income), net		9,073			37,977			(136,636	)		(28,904	)	(76	)%		174,613		128	%

General and administrative expenses

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

General and administrative expenses decreased slightly from 2012 to 2013 primarily as a result of lower activities and cost-reduction efforts across all business units. As a percentage of operating revenues, general and administrative expenses are comparable for each period relative to fluctuations in activity levels.

Depreciation and amortization

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

Interest expense

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

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

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Investment income

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

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

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

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

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

The amount of gains (losses) on sales and disposals of long-lived assets and other income (expense), net for 2013 was a net loss of $38.0 million, which was primarily comprised of (i) net losses on sales and disposals of assets of approximately $13.6 million, (ii) increases to litigation reserves of $11.7 million, (iii) foreign currency exchange losses of $6.2 million and (iv) losses on debt buybacks of $3.8 million.

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

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Impairments and Other Charges

	Year Ended December 31,						Increase/(Decrease)

	2014		2013		2012		2014 to 2013					2013 to 2012
	(In thousands, except percentages)
Tangible Assets & Equipment:
Provision for retirement of assets	$	393,962	$	14,044	$	138,666	$	379,918		n/m	(1)	$	(124,622	)	(90	)%
Impairment of long-lived assets		217,627		20,000		50,355		197,627		n/m	(1)		(30,355	)	(60	)%

Subtotal		611,589		34,044		189,021		577,545		n/m	(1)		(154,977	)	(82	)%
Goodwill & Intangible Assets:
Goodwill impairments		356,605		—		26,279		356,605		100	%		(26,279	)	(100	)%
Intangible asset impairment		29,942		—		74,960		29,942		100	%		(74,960	)	(100	)%

Subtotal		386,547		—		101,239		386,547		100	%		(101,239	)	(100	)%
Other Charges:
Transaction costs		22,313		—		—		22,313		100	%		—		—
Other-than-temporary impairment on equity security		6,974		—		—		6,974		100	%		—		—
Loss on tendered notes		—		208,197		—		(208,197	)	(100	)%		208,197		100	%
Termination of employment contract		—		45,000		—		(45,000	)	(100	)%		45,000		100	%

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

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

For the year ended December 31, 2014

Tangible Assets and Equipment

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

	Provision for Retirements		Tangible Asset Impairments		Total

Drilling & Rig Services:
U.S.	$	271,141	$	137,000	$	408,141
Canada		24,211		10,176		34,387
International		56,472		70,451		126,923
Rig Services		42,138		—		42,138

Total	$	393,962	$	217,627	$	611,589

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

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

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

Goodwill and Intangible Assets

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

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

Transaction costs

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

Other-than-temporary impairment

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

For the years ended December 31, 2013 and 2012

Provision for retirement of long-lived assets

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

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

Additionally in 2012, we recorded similar provisions for retirement of long-lived assets of $49.4 million in our Completion & Production Services business line. During 2012, we streamlined our operations and retired some non-core assets.

Impairments of long-lived assets

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

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

Goodwill impairments

During 2012, we recognized the impairment of goodwill associated with our operations in the U.S. and International drilling operations. The impairments were deemed necessary due to the prolonged uncertainty of utilization of some of our rigs as a result of changes in our customers' plans for future drilling operations in the Gulf of Mexico and our international markets.

There were no goodwill impairments in 2013.

Intangible asset impairment

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

There were no intangible asset impairments in 2013.

Loss on tendered notes

During 2013, we recognized a loss related to the extinguishment of debt in connection with the tender offer for our 9.25% senior notes. See Note 13—Debt for additional discussion. In 2013, we completed a cash tender offer for these notes and repurchased $785.4 million aggregate principal amount. We paid the holders an aggregate of approximately $1.0 billion in cash, reflecting principal and accrued and unpaid interest and prepayment premium and recognized a loss as part of the debt extinguishment.

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Provision for termination of employment contract

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

Income tax rate

	Year Ended December 31,									Increase/(Decrease)

	2014			2013			2012			2014 to 2013					2013 to 2012
Effective income tax rate from continuing operations		(10.4	)%		(52.0	)%		14.8	%		(42	)%	(80	)%		(67	)%	(451	)%

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

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

Assets Held-for-Sale

	As of December 31,

	2014		2013
	(In thousands)
Oil and Gas	$	146,467	$	239,936
Other Rig Services		—		3,328

	$	146,467	$	243,264

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

Oil and Gas Properties

We have contracts with pipeline companies to pay specified fees based on committed volumes for gas transport and processing. In December 2013, we entered into agreements to restructure these contracts, assigning a portion of the obligation to third parties and reducing our future payment commitments. At December 31, 2014, our undiscounted contractual commitments for these contracts approximated $84.6 million, and we had liabilities of $40.2 million, $19.6 million of which were classified as current and are included in accrued liabilities.

At December 31, 2013, our undiscounted contractual commitments for these contracts approximated $171.2 million, and we had liabilities of $113.6 million, $64.4 million of which were classified as current and are included in accrued liabilities.

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

Discontinued Operations

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

	Year Ended December 31,								Increase/(Decrease)

	2014		2013			2012			2014 to 2013					2013 to 2012
	(In thousands, except percentages)
Operating revenues
Oil and Gas	$	13,143	$	25,327		$	27,363		$	(12,184	)	(48	)%	$	(2,036	)	(7	)%
Rig Services	$	—	$	127,154		$	172,335		$	(127,154	)	(100	)%	$	(45,181	)	(26	)%
Income (loss) from discontinued operations:
Oil and Gas	$	21	$	(27,396)	(1)		(66,033)	(2)	$	27,417		100	%	$	38,637		59	%
Rig Services	$	—	$	16,217	(3)		(1,493)	(4)	$	(16,217	)	(100	)%	$	17,710		n/m	(5)

Oil and Gas

(1): Includes impairments during 2013 of $61.5 million to write down the carrying value of some of our wholly owned oil and gas-centered assets, partially offset by a gain related to our restructure of our future pipeline obligations.
(2): Includes adjustments during 2012 to increase our pipeline contractual commitments by $128.1 million and other gains and losses related to the sale of our wholly owned oil and gas-centered assets.

Rig Services

(3): Includes a gain recognized from the sale of Peak, one of our businesses in Alaska, for which we received cash proceeds of $135.5 million.
(4): Includes $7.8 million of impairment (a Level 3 measurement) in 2012 to our aircraft and logistics assets as a result of the continued downturn in the oil and gas industry in Canada.
(5): Number is so large that it is not meaningful.

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

Additional discussion of our policy pertaining to the calculations of our annual impairment tests, including any impairment of goodwill, is set forth in Critical Accounting Estimates below in this section and in Note 3—Summary of Significant Accounting Policies in Part II, Item 8.—Financial Statements and Supplementary Data. Additional information relating to discontinued operations is provided in Note 5—Assets Held for Sale and Discontinued Operations and our Schedule of Supplemental

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Information on Oil and Gas Exploration and Production Activities in Part II, Item 8.—Financial Statements and Supplementary Data. A further protraction of lower commodity prices or an inability to sell these assets in a timely manner could result in recognition of future impairment charges.

Liquidity and Capital Resources

Cash Flows

Our cash flows depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Sustained increases or decreases in the price of oil or natural gas could have a material impact on these activities, and could also materially affect our cash flows. Certain sources and uses of cash, such as the level of discretionary capital expenditures or acquisitions, purchases and sales of investments, issuances and repurchases of debt and of our common shares are within our control and are adjusted as necessary based on market conditions. We discuss our 2014 and 2013 cash flows below.

Operating Activities. Net cash provided by operating activities totaled $1.8 billion during 2014, compared to net cash provided by operating activities of $1.4 billion during 2013. Net cash provided by operating activities ("operating cash flows") is our primary source of capital and liquidity. Factors affecting changes in operating cash flows are largely the same as those that impact net earnings, with the exception of non-cash expenses such as depreciation and amortization, depletion, impairments, share-based compensation, deferred income taxes and our proportionate share of earnings or losses from unconsolidated affiliates. Net income (loss) adjusted for non-cash components was approximately $1.3 billion and $1.4 billion in 2014 and 2013, respectively. Additionally, changes in working capital items such as collection of receivables can be a significant component of operating cash flows. Changes in working capital items provided $487.8 million and $2.9 million, respectively, in cash flows during 2014 and 2013, respectively.

Investing Activities. Net cash used for investing activities totaled $1.7 billion during 2014 compared to net cash used for investing activities of $815.5 million in 2013. Our primary use of cash for investing activities is for capital expenditures related to rig-related enhancements, new construction and equipment, as well as sustaining capital expenditures. During 2014 and 2013, we used cash for capital expenditures totaling $1.8 billion and $1.2 billion, respectively.

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

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

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

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

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

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Future Cash Requirements

We expect capital expenditures over the next 12 months to approximate $1.0—$1.2 billion. Purchase commitments outstanding at December 31, 2014 totaled approximately $1.1 billion, primarily for rig-related enhancements, new construction and equipment, as well as sustaining capital expenditures, other operating expenses and purchases of inventory. This amount could change significantly based on market conditions and new business opportunities. The level of our outstanding purchase commitments and our expected level of capital expenditures over the next 12 months reflect a number of capital programs that are currently underway or planned. These programs will result in an expansion in the number of land drilling and offshore rigs and the amount of well-servicing equipment and technology assets that we own and operate. We have the ability to reduce the planned expenditures if necessary or increase them if market conditions and new business opportunities warrant it. In light of the recent decline in crude oil prices, we have already undertaken many cost cutting initiatives in an effort to minimize the negative impact to our business. We have undertaken efforts to reduce capital expenditures, operating costs and administrative expenses. Since the last downturn in 2009, we have strengthened our financial flexibility by streamlining operations, shedding non-core businesses and reducing net debt and interest expense.

We have historically completed a number of acquisitions and will continue to evaluate opportunities to acquire assets or businesses to enhance our operations. Several of our previous acquisitions were funded through issuances of debt or our common shares. Future acquisitions may be funded using existing cash or by issuing debt or additional shares of our stock. Such capital expenditures and acquisitions will depend on our view of market conditions and other factors.

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

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

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

	Payments due by Period

	Total		< 1 Year		1 - 3 Years			3 - 5 Years			Thereafter
	(In thousands)
Contractual cash obligations:
Long-term debt:(1)
Principal	$	4,357,098	$	—	$	1,333,119	(2)	$	1,273,979	(3)	$	1,750,000	(4)
Interest		985,488		192,009		375,911			246,328			171,240
Operating leases(5)		96,364		22,740		23,508			10,107			40,009
Purchase commitments(6)		1,062,283		1,042,490		19,793			—			—
Employment contracts(5)		19,114		6,887		10,727			1,500			—
Pension funding obligations		886		886		—			—			—
Transportation and processing contracts(5)(7)		84,580		21,938		21,743			16,815			24,084

The table above excludes liabilities for uncertain tax positions totaling $56.5 million as of December 31, 2014 because we are unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the uncertain tax positions can be found in Note 14—Income Taxes in Part II, Item 8.—Financial Statements and Supplementary Data.

(1): See Note 13—Debt in Part II, Item 8.—Financial Statements and Supplementary Data
(2): Represents Nabors Delaware's aggregate 2.35% senior notes due September 2016, commercial paper and amounts drawn on our revolving credit facility, which expires November 2017.
(3): Represents Nabors Delaware's aggregate 6.15% senior notes due February 2018 and 9.25% senior notes due January 2019.
(4): Represents Nabors Delaware's aggregate 5.0% senior notes due September 2020, 4.625% senior notes due September 2021 and 5.10% senior notes due September 2023.
(5): See Note 19—Commitments and Contingencies in Part II, Item 8.—Financial Statements and Supplementary Data.
(6): Purchase commitments include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including fixed or minimum quantities to be purchased; fixed, minimum or variable pricing provisions; and the approximate timing of the transaction.
(7): We have contracts with pipeline companies to pay specified fees based on committed volumes for gas transport and processing, as calculated on a monthly basis. See Notes 5—Assets Held for Sale and Discontinued Operations and 19—Commitments and Contingencies in Part II, Item 8.—Financial Statements and Supplementary Data.

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

Financial Condition and Sources of Liquidity

Our primary sources of liquidity are cash and investments, availability under our revolving credit facility, our commercial paper program, and cash generated from operations. As of December 31, 2014, we had cash and short-term investments of $536.2 million and working capital of $1.2 billion. As of

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

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

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

	December 31, 2014

	(In thousands)
Credit available	$	650,204
Less: Letters of credit outstanding, inclusive of financial and performance guarantees		326,650

Remaining availability	$	323,554

Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by the major credit rating agencies in the United States and our historical ability to access these markets as needed. While there can be no assurances that we will be able to access these markets in the future, we believe that we will be able to access capital markets or otherwise obtain financing in order to satisfy any payment obligation that might arise upon exchange or purchase of our notes and that any cash payment due, in addition to our other cash obligations, would not ultimately have a material adverse impact on our liquidity or financial position. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.

Our gross debt to capital ratio was 0.47:1 as of December 31, 2014 and 0.40:1 as of December 31, 2013, respectively. Our net debt to capital ratio was 0.44:1 as of December 31, 2014 and 0.36:1 as of December 31, 2013. The gross debt to capital ratio is calculated by dividing (x) total debt by (y) total capital. Total capital is defined as total debtplus shareholders' equity. Net debt is total debtminus the sum of cash and cash equivalents and short-term investments. Neither the gross debt to capital ratio nor the net debt to capital ratio is a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.

Our interest coverage ratio was 9.8:1 as of December 31, 2014 and 7.4:1 as of December 31, 2013. The interest coverage ratio is a trailing 12-month quotient of the sum of (x) operating revenues and earnings (losses) from unconsolidated affiliates, direct costs and general administrative expensesless earnings (losses) from the U.S. unconsolidated oil and gas joint venturedivided by (y) interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.

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

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Off-Balance Sheet Arrangements (Including Guarantees)

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

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

	Maximum Amount

	2015		2016		2017		Thereafter		Total
	(In thousands)
Financial standby letters of credit and other financial surety instruments	$	191,015		75		18		—	$	191,108

Critical Accounting Estimates

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

•: it requires assumptions to be made that were uncertain at the time the estimate was made; and
•: changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated financial position or results of operations.

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

Financial Instruments. Fair value is the price that would be received upon a sale of an asset or paid upon a transfer of a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market-corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best information available. Accordingly, we employ valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The use of unobservable inputs is intended to allow for fair value determinations in situations where there is little, if any, market activity for the asset or liability at the measurement date. We are able to classify fair

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value balances utilizing a fair-value hierarchy based on the observability of those inputs. Under the fair-value hierarchy:

•: Level 1 measurements include unadjusted quoted market prices for identical assets or liabilities in an active market;
•: Level 2 measurements include quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and
•: Level 3 measurements include those that are unobservable and of a highly subjective nature.

Depreciation of Property, Plant and Equipment. The drilling, workover and well-servicing and pressure pumping industries are very capital intensive. Property, plant and equipment represented 72% of our total assets as of December 31, 2014, and depreciation and amortization constituted 15% of our total costs and other deductions in 2014.

Depreciation for our primary operating assets, drilling and workover rigs, is calculated based on the units-of-production method. For each day a rig is operating, we depreciate it over an approximate 4,927-day period, with the exception of our jackup rigs which are depreciated over an 8,030-day period, after provision for salvage value. For each day a rig asset is not operating, it is depreciated over an assumed depreciable life of 20 years, with the exception of our jackup rigs, where a 30-year depreciable life is typically used, after provision for salvage value.

Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, aircraft equipment, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings—10 to 30 years; well-servicing rigs—3 to 15 years; marine transportation and supply vessels—10 to 25 years; aircraft equipment—5 to 20 years; oilfield hauling and mobile equipment and other machinery and equipment—3 to 10 years).

These depreciation periods and the salvage values of our property, plant and equipment were determined through an analysis of the useful lives of our assets and based on our experience with the salvage values of these assets. Periodically, we review our depreciation periods and salvage values for reasonableness given current conditions. Depreciation of property, plant and equipment is therefore based upon estimates of the useful lives and salvage value of those assets. Estimation of these items requires significant management judgment. Accordingly, management believes that accounting estimates related to depreciation expense recorded on property, plant and equipment are critical.

There have been no factors related to the performance of our portfolio of assets, changes in technology or other factors indicating that these estimates do not continue to be appropriate. Accordingly, for the years ended December 31, 2014, 2013 and 2012, no significant changes have been made to the depreciation rates applied to property, plant and equipment, the underlying assumptions related to estimates of depreciation, or the methodology applied. However, certain events could occur that would materially affect our estimates and assumptions related to depreciation. Unforeseen changes in operations or technology could substantially alter management's assumptions regarding our ability to realize the return on our investment in operating assets and therefore affect the useful lives and salvage values of our assets.

Impairment of Long-Lived Assets. As discussed above, the drilling, workover and well-servicing and pressure pumping industry is very capital intensive. We review our assets for impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the sum of estimated future cash flows, on an undiscounted basis, is less than the carrying amount of the long-lived asset.

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Impairment charges are recorded using discounted cash flows, which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could result in future impairments. As the determination of whether impairment charges should be recorded on our long-lived assets is subject to significant management judgment, and an impairment of these assets could result in a material charge on our consolidated statements of income (loss), management believes that accounting estimates related to impairment of long-lived assets are critical.

Assumptions made in the determination of future cash flows are made with the involvement of management personnel at the operational level where the most specific knowledge of market conditions and other operating factors exists. For 2014, 2013 and 2012, no significant changes have been made to the methodology utilized to determine future cash flows.

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

Impairment of Goodwill and Intangible Assets. We review goodwill and intangible assets with indefinite lives for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount of such goodwill and intangible assets exceed their fair value. We perform our impairment tests for goodwill for all of our reporting units within our operating segments. Our Drilling & Rig Services business line consists of U.S., Canada, International and Rig Services operating segments. Our Rig Services operating segment includes Canrig Drilling Technology Ltd. and Ryan Directional Services Inc. Our Completion & Production Services business line consists of Completion & Production Services operating segments. The impairment test involves comparing the estimated fair value of the reporting unit to its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, a second step is required to measure the goodwill impairment loss. This second step compares the implied fair value of the reporting unit's goodwill to the carrying amount of that goodwill. If the carrying amount of the reporting unit's goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess.

The fair values calculated in these impairment tests are determined using discounted cash flow models involving assumptions based on our utilization of rigs or other oil and gas service equipment, revenues and earnings from affiliates, as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. Our discounted cash flow projections for each reporting unit were based on financial forecasts. The future cash flows were discounted to present value using discount rates that are determined to be appropriate for each reporting unit. Terminal values for each reporting unit were calculated using a Gordon Growth methodology with a long-term growth rate of 3%. We believe the fair value estimated for purposes of these tests represent a Level 3 fair value measurement.

A significantly prolonged period of lower oil and natural gas prices or changes in laws and regulations could continue to adversely affect the demand for and prices of our services, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our estimate of our future operating results.

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

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

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

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

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

Litigation and Self-Insurance Reserves. Our operations are subject to many hazards inherent in the drilling, workover and well-servicing and pressure pumping industries, including blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental and natural resources damage and damage to the property of others. Our offshore operations are also subject to the hazards of marine operations including capsizing, grounding, collision and other damage from hurricanes and heavy weather or sea conditions and unsound ocean bottom conditions. Our operations are subject to risks of war or acts of terrorism, civil disturbances and other political events.

Accidents may occur, we may be unable to obtain desired contractual indemnities, and our insurance may prove inadequate in certain cases. There is no assurance that our insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention.

Based on the risks discussed above, it is necessary for us to estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Reserves related to self-insurance are based on the facts and circumstances specific to the claims and our past experience with similar claims. The actual outcome of self-insured claims could differ significantly from estimated amounts. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions for workers' compensation, employers' liability, general liability and automobile liability claims. These accruals are based on certain assumptions developed utilizing historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and reported claims. These loss estimates and accruals recorded in our financial statements for claims have historically been reasonable in light of the actual amount of claims paid.

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Because the determination of our liability for self-insured claims is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, and because such liabilities could be material in nature, management believes that accounting estimates related to self-insurance reserves are critical.

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

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

The determination of the fair value of assets and liabilities is based on the market for the assets and the settlement value of the liabilities. These estimates are made by management based on our experience with similar assets and liabilities. During 2014, 2013 and 2012, no significant changes were made to the methodology utilized to value assets acquired or liabilities assumed. Our estimates of the fair values of assets acquired and liabilities assumed have proved to be reliable in the past.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

At various times, we utilize local currency borrowings (foreign-currency-denominated debt), the payment structure of customer contracts and foreign exchange contracts to selectively hedge our exposure to exchange rate fluctuations in connection with monetary assets, liabilities, cash flows and commitments denominated in certain foreign currencies. A foreign exchange contract is a foreign currency transaction, defined as an agreement to exchange different currencies at a given future date and at a specified rate. A hypothetical 10% decrease in the value of all our foreign currencies relative to the U.S. dollar as of December 31, 2014 would result in a $12.2 million decrease in the fair value of our net monetary assets denominated in currencies other than U.S. dollars.

Credit Risk. Our financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash equivalents, short-term and long-term investments and accounts receivable. Cash equivalents such as deposits and temporary cash investments are held by major banks or investment firms. Our short-term and long-term investments are managed within established guidelines that limit the amounts that may be invested with any one issuer and provide guidance as to issuer credit quality. We believe that the credit risk in our cash and investment portfolio is minimized as a result of the mix of our investments. In addition, our trade receivables are with a variety of U.S., international and foreign-country national oil and gas companies. Management considers this credit risk to be limited due to the financial resources of these companies. We perform ongoing credit evaluations of our customers, and we generally do not require material collateral. We do occasionally require prepayment of amounts from customers whose creditworthiness is in question prior to providing services to them. We maintain reserves for potential credit losses, and these losses historically have been within management's expectations.

Interest Rate, and Marketable and Non-marketable Security Price Risk. Our financial instruments that are potentially sensitive to changes in interest rates include our 2.35%, 5.10%, 6.15%, 9.25%, 5.0% and 4.625% senior notes, our investments in debt securities (including corporate and mortgage-CMO debt securities) and our investments in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages), which are classified as long-term investments.

We may utilize derivative financial instruments that are intended to manage our exposure to interest rate risks. We account for derivative financial instruments under the Derivatives Topic of the ASC. The use of derivative financial instruments could expose us to further credit risk and market risk. Credit risk in this context is the failure of counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty would owe us, which can create credit risk for us. When the fair value of a derivative contract is negative, we would owe the counterparty, and therefore, we would not be exposed to credit risk. We attempt to minimize credit risk in derivative instruments by entering into transactions with major financial institutions that have a significant asset base. Market risk related to derivatives is the adverse effect on the value of a financial instrument that results from changes in interest rates. We try to manage market risk associated with

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interest-rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that we undertake.

Fair Value of Financial Instruments. The fair value of our fixed rate long-term debt, revolving credit facility, commercial paper and subsidiary preferred stock is estimated based on quoted market prices or prices quoted from third-party financial institutions. The carrying and fair values of these liabilities were as follows:

	December 31,

	2014							2013
	Effective Interest Rate			Carrying Value		Fair Value		Effective Interest Rate			Carrying Value		Fair Value
	(In thousands)
2.35% senior notes due September 2016		2.56	%	$	349,887	$	346,980		2.56	%	$	349,820	$	354,694
6.15% senior notes due February 2018		6.42	%		930,693		991,920		6.42	%		969,928		1,097,480
9.25% senior notes due January 2019		9.33	%		339,607		403,531		9.33	%		339,607		428,733
5.00% senior notes due September 2020		5.20	%		698,253		687,953		5.20	%		697,947		731,955
4.625% senior notes due September 2021		4.75	%		698,388		661,619		4.75	%		698,148		709,793
5.10% senior notes due September 2023		5.26	%		348,893		332,759		5.26	%		348,765		349,731
Subsidiary preferred stock		0.00	%		—		—		4.00	%		69,188		69,000
Revolving credit facility		3.47	%		450,000		450,000		2.28	%		170,000		170,000
Commercial paper		0.59	%		533,119		533,119		0.45	%		329,844		329,844
Other		0.00	%		6,209		6,209		0.00	%		10,243		10,243

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

The fair values of our cash equivalents, trade receivables and trade payables approximate their carrying values due to the short-term nature of these instruments. Our cash, cash equivalents,

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

	December 31,

	2014					2013
	Fair Value		Interest Rates	Weighted- Average Life (Years)		Fair Value		Interest Rates	Weighted- Average Life (Years)
	(In thousands, except rates)
Cash and cash equivalents	$	501,149	0.01 - 0.25%		—	$	389,915	0 - .25%		—
Short-term investments:
Trading equity securities		—	—		—		—	—		—
Available-for-sale equity securities		35,002	—		—		96,942	—		—
Available-for-sale debt securities:
Commercial paper and CDs		—	—		—		—	—		—
Corporate debt securities		—	0.0 - 0.0%		—		19,388	10.0 - 11.52%		6.2
Mortgage-backed debt securities		—	0.00%		—		210	2.39%		11.8
Mortgage-CMO debt securities		18	2.39 - 2.73%		5.6		20	2.41 - 2.58%		4.9
Asset-backed debt securities		—	0.0 - 0.0%		—		658	0.67 - 4.81%		4.8

Total available-for-sale debt securities		18					20,276

Total available-for-sale securities		35,020					117,218

Total short-term investments		35,020					117,218
Long-term investments		2,806	N/A				3,236	N/A

Total cash, cash equivalents, short-term and long-term investments	$	538,975				$	510,369

Our investments in debt securities listed in the above table and a portion of our long-term investments are sensitive to changes in interest rates. Additionally, our investment portfolio of debt and equity securities, which are carried at fair value, exposes us to price risk. A hypothetical 10% decrease in the market prices for all securities as of December 31, 2014 would decrease the fair value of our available-for-sale securities by $3.5 million.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX



Report of Independent Registered Public Accounting Firm		56
Consolidated Balance Sheets as of December 31, 2014 and 2013		58
Consolidated Statements of Income (Loss) for the Years Ended December 31, 2014, 2013 and 2012		59
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2014, 2013 and 2012		60
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012		61
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2014, 2013 and 2012		62
Notes to Consolidated Financial Statements		63

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Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss), comprehensive income (loss), changes in equity, and cash flows present fairly, in all material respects, the financial position of Nabors Industries Ltd. and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established inInternal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the accounting for income taxes existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2014 consolidated financial statements, and our opinion regarding the effectiveness of the Company's internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in management's report referred to above. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 2, 2015

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,

	2014			2013
	(In thousands, except per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	501,149		$	389,915
Short-term investments		35,020			117,218
Assets held for sale		146,467			243,264
Accounts receivable, net		1,517,503			1,399,543
Inventory		230,067			209,793
Deferred income taxes		118,230			121,316
Other current assets		193,438			272,781

Total current assets		2,741,874			2,753,830
Long-term investments		2,806			3,236
Property, plant and equipment, net		8,599,125			8,597,813
Goodwill		173,928			512,964
Investment in unconsolidated affiliates		58,251			64,260
Other long-term assets		303,958			227,708

Total assets	$	11,879,942		$	12,159,811

LIABILITIES AND EQUITY
Current liabilities:
Current debt	$	6,190		$	10,185
Trade accounts payable		780,060			545,512
Accrued liabilities		728,004			697,093
Income taxes payable		53,221			58,634

Total current liabilities		1,567,475			1,311,424
Long-term debt		4,348,859			3,904,117
Other long-term liabilities		601,816			377,744
Deferred income taxes		443,003			516,161

Total liabilities		6,961,153			6,109,446
Commitments and contingencies (Note 19)
Subsidiary preferred stock (Note 16)		—			69,188
Equity:
Shareholders' equity:
Common shares, par value $0.001 per share:
Authorized common shares 800,000; issued 328,196 and 323,711, respectively		328			324
Capital in excess of par value		2,452,261			2,392,585
Accumulated other comprehensive income		77,522			216,140
Retained earnings		3,573,172			4,304,664
Less: treasury shares, at cost, 38,788 and 28,414 common shares, respectively		(1,194,664	)		(944,627	)

Total shareholders' equity		4,908,619			5,969,086
Noncontrolling interest		10,170			12,091

Total equity		4,918,789			5,981,177

Total liabilities and equity	$	11,879,942		$	12,159,811

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

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

	Year Ended December 31,

	2014			2013			2012
	(In thousands, except per share amounts)
Revenues and other income:
Operating revenues	$	6,804,197		$	6,152,015		$	6,843,051
Earnings (losses) from unconsolidated affiliates		(6,301	)		39			(288,718	)
Investment income (loss)		11,831			96,577			63,137

Total revenues and other income		6,809,727			6,248,631			6,617,470
Costs and other deductions:
Direct costs		4,505,064			3,981,828			4,367,106
General and administrative expenses		549,734			525,330			527,953
Depreciation and amortization		1,145,100			1,086,677			1,039,923
Interest expense		177,948			223,418			251,904
Losses (gains) on sales and disposals of long-lived assets and other expense (income), net		9,073			37,977			(136,636	)
Impairments and other charges		1,027,423			287,241			290,260

Total costs and other deductions		7,414,342			6,142,471			6,340,510
Income (loss) from continuing operations before income taxes		(604,615	)		106,160			276,960
Income tax expense (benefit):
Current		302,313			39,865			142,994
Deferred		(239,647	)		(95,046	)		(102,008	)

Total income tax expense (benefit)		62,666			(55,181	)		40,986
Subsidiary preferred stock dividend		1,984			3,000			3,000

Income (loss) from continuing operations, net of tax		(669,265	)		158,341			232,974
Income (loss) from discontinued operations, net of tax		21			(11,179	)		(67,526	)

Net income (loss)		(669,244	)		147,162			165,448
Less: Net (income) loss attributable to noncontrolling interest		(1,415	)		(7,180	)		(621	)

Net income (loss) attributable to Nabors	$	(670,659	)	$	139,982		$	164,827

Earnings (losses) per share:
Basic from continuing operations	$	(2.28	)	$	0.51		$	0.80
Basic from discontinued operations		—			(0.04	)		(0.23	)

Total Basic	$	(2.28	)	$	0.47		$	0.57

Diluted from continuing operations	$	(2.28	)	$	0.51		$	0.79
Diluted from discontinued operations		—			(0.04	)		(0.23	)

Total Diluted	$	(2.28	)	$	0.47		$	0.56

Weighted-average number of common shares outstanding:
Basic		290,694			294,182			289,965
Diluted		290,694			296,592			292,323

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

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Net income (loss) attributable to Nabors	$	(670,659	)	$	139,982		$	164,827
Other comprehensive income (loss), before tax:
Translation adjustment attributable to Nabors		(79,059	)		(65,447	)		21,073
Unrealized gains/(losses) on marketable securities:
Unrealized gains/(losses) on marketable securities		(59,932	)		23,007			98,138
Less: reclassification adjustment for (gains)/losses included in net income (loss)		2,337			(88,158	)		(13,405	)

Unrealized gains/(losses) on marketable securities		(57,595	)		(65,151	)		84,733
Pension plan		(5,050	)		5,916			(324	)
Unrealized gains/(losses) on cash flow hedges		612			613			702

Other comprehensive income (loss), before tax		(141,092	)		(124,069	)		106,184
Income tax expense (benefit) related to items of other comprehensive income (loss)		(2,474	)		(66	)		(4,147	)

Other comprehensive income (loss), net of tax		(138,618	)		(124,003	)		110,331

Comprehensive income (loss) attributable to Nabors		(809,277	)		15,979			275,158
Net income (loss) attributable to noncontrolling interest		1,415			7,180			621
Translation adjustment attributable to noncontrolling interest		(1,017	)		(932	)		311

Comprehensive income (loss) attributable to noncontrolling interest		398			6,248			932

Comprehensive income (loss)	$	(808,879	)	$	22,227		$	276,090

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

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(669,244	)	$	147,162		$	165,448
Adjustments to net income (loss):
Depreciation and amortization		1,145,328			1,099,741			1,055,757
Accretion, depletion and other exploratory expenses		2,981			22,270			2,573
Deferred income tax expense (benefit)		(240,195	)		(103,277	)		(131,742	)
Deferred financing costs amortization		4,231			4,255			4,294
Discount amortization on long-term debt		3,131			2,137			1,908
Impairments and other charges		650,199			53,905			311,541
Losses on debt extinguishment		5,576			211,981			—
Losses (gains) on long-lived assets, net		353,110			18,060			(51,585	)
Losses (gains) on investments, net		(5,580	)		(91,480	)		(56,925	)
Share-based compensation		37,190			53,255			18,312
Foreign currency transaction losses (gains), net		1,021			6,225			4,819
Equity in (earnings) losses of unconsolidated affiliates, net of dividends		7,102			800			299,717
Other		(762	)		(9,730	)		1,241
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(126,883	)		(44,561	)		200,537
Inventory		(65,398	)		39,412			14,447
Other current assets		118,162			(6,943	)		(42,743	)
Other long-term assets		(30,475	)		42,298			(38,468	)
Trade accounts payable and accrued liabilities		267,907			113,550			(224,795	)
Income taxes payable		(57,113	)		(31,752	)		(1,488	)
Other long-term liabilities		381,623			(109,085	)		29,857

Net cash provided by operating activities		1,781,911			1,418,223			1,562,705
Cash flows from investing activities:
Purchases of investments		(319	)		—			(949	)
Sales and maturities of investments		23,992			164,510			31,944
Proceeds from sale of unconsolidated affiliates		750			12,640			159,529
Cash paid for acquisition of businesses, net		(72,534	)		(116,971	)		—
Investment in unconsolidated affiliates		(2,365	)		(5,967	)		(1,325	)
Capital expenditures		(1,821,315	)		(1,178,205	)		(1,518,628	)
Proceeds from sales of assets and insurance claims		156,761			308,538			149,801
Other		(1,879	)		(13	)		—

Net cash used for investing activities		(1,716,909	)		(815,468	)		(1,179,628	)
Cash flows from financing activities:
Increase (decrease) in cash overdrafts		(6,151	)		(4,421	)		1,612
Proceeds from issuance of long-term debt		—			698,753			—
Debt issuance costs		—			(4,500	)		(3,433	)
Proceeds from revolving credit facilities		465,000			—			710,000
Proceeds from (payments for) issuance of common shares		30,263			5,383			(3,625	)
Repurchase of common shares		(250,037	)		—			—
Purchase of preferred stock		(70,875	)		—			—
Reduction in long-term debt		—			(994,181	)		(276,258	)
Dividends to shareholders		(59,145	)		(47,168	)		—
Proceeds from (payment for) commercial paper, net		203,275			329,844			—
Reduction in revolving credit facilities		(230,932	)		(720,000	)		(680,000	)
Other		(11,550	)		6,704			(2,423	)

Net cash (used for) provided by financing activities		69,848			(729,586	)		(254,127	)
Effect of exchange rate changes on cash and cash equivalents		(23,616	)		(8,176	)		(2,603	)

Net increase (decrease) in cash and cash equivalents		111,234			(135,007	)		126,347
Cash and cash equivalents, beginning of period		389,915			524,922			398,575

Cash and cash equivalents, end of period	$	501,149		$	389,915		$	524,922

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

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NABORS INDUSTRIES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Common Shares

	Common Shares				Capital in Excess of Par Value			Accumulated Other Comprehensive Income
(In thousands)	Shares		Par Value		Capital in Excess of Par Value			Accumulated Other Comprehensive Income			Retained Earnings			Treasury Shares			Non- controlling Interest			Total Equity
As of December 31, 2011 (As previously reported)		317,042	$	317	$	2,287,743		$	321,264		$	3,955,571		$	(977,873	)	$	13,402		$	5,600,424
Revision (Note 2)									(91,452	)		91,452									—

As of December 31, 2011 (Revised)		317,042		317		2,287,743			229,812			4,047,023			(977,873	)		13,402			5,600,424
Net income (loss)												164,827						621			165,448
Other comprehensive income (loss), net of tax									110,331									311			110,642
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options		1,152		1		(3,626	)														(3,625	)
Capital contribution from forgiveness of liability, net of tax						62,734															62,734
Issuance of treasury shares, net of tax						(25,496	)								33,246						7,750
Share-based compensation						18,312															18,312
Other		619		1		(2,423	)											(2,146	)		(4,568	)

As of December 31, 2012		318,813		319		2,337,244			340,143			4,211,850			(944,627	)		12,188			5,957,117
Net income (loss)												139,982						7,180			147,162
Dividends to shareholders												(47,168	)								(47,168	)
Other comprehensive income (loss), net of tax									(124,003	)								(932	)		(124,935	)
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options		577		1		5,382															5,383
Share-based compensation						53,255															53,255
Other		4,321		4		(3,296	)											(6,345	)		(9,637	)

As of December 31, 2013		323,711	$	324	$	2,392,585		$	216,140		$	4,304,664		$	(944,627	)	$	12,091		$	5,981,177
Net income (loss)												(670,659	)					1,415			(669,244	)
Dividends to shareholders												(59,145	)								(59,145	)
Redemption of subsidiary preferred stock												(1,688	)								(1,688	)
Repurchase of treasury shares															(250,037	)					(250,037	)
Other comprehensive income (loss), net of tax									(138,618	)								(1,017	)		(139,635	)
Issuance of common shares for stock options exercised, net of surrender of unexercised stock options		3,036		3		30,260															30,263
Share-based compensation						37,157															37,157
Other		1,449		1		(7,741	)											(2,319	)		(10,059	)

As of December 31, 2014		328,196	$	328	$	2,452,261		$	77,522		$	3,573,172		$	(1,194,664	)	$	10,170		$	4,918,789

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

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Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 Nature of Operations

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

The majority of our business is conducted through two business lines:

Drilling & Rig Services

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

Completion & Production Services

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

The consolidated financial statements and related footnotes are presented in accordance with GAAP.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2 Revision of Prior Period Financial Statements

During the first quarter of 2014, we determined that we had incorrectly applied certain aspects of Accounting Standards Codification ("ASC") 830—Foreign Currency Matters with respect to the recording of foreign currency gains or losses on certain intercompany transactions. GAAP requires the recognition of foreign currency gains or losses on U.S. dollar denominated intercompany balances of our subsidiaries that have a functional currency other than the U.S. dollar. The primary years impacted were 2002 and 2009, which is the period over which a series of intercompany loans were outstanding between our Canadian subsidiary, whose functional currency is the Canadian dollar, and other subsidiaries whose functional currencies are the U.S. dollar.

The net effect understated net income for periods before 2009 by approximately $91.5 million, due to foreign currency gains that should have been recorded through net income, rather than through Cumulative Translation Adjustments (a component of Accumulated Other Comprehensive Income). The correction of this error resulted in a revision to increase the beginning Retained Earnings at January 1, 2010 by approximately $91.5 million with the offset being a decrease to Accumulated Other Comprehensive Income, both of which are components of Shareholders' Equity. There was no other material impact to our assets, liabilities, cash flows or profit and loss for any periods presented. We do not consider this revision material to any period.

Note 3 Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of Nabors, as well as all majority owned and non-majority owned subsidiaries required to be consolidated under GAAP. All significant intercompany accounts and transactions are eliminated in consolidation.

Investments in operating entities where we have the ability to exert significant influence, but where we do not control operating and financial policies, are accounted for using the equity method. Our share of the net income (loss) of these entities is recorded as earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss). The investments in these entities are included in investment in unconsolidated affiliates in our consolidated balance sheets.

Cash and Cash Equivalents

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

Investments

Short-term investments

Short-term investments consist of equity securities, corporate debt securities, mortgage-backed debt securities and asset-backed debt securities. Securities classified as available-for-sale are stated at fair value. Unrealized holding gains and temporary losses for available-for-sale securities are excluded from earnings and, until realized, are presented in the statement of other comprehensive income (loss). Unrealized holding losses are included in earnings during the period for which the loss is determined to be other-than-temporary.

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Note 3 Summary of Significant Accounting Policies (Continued)

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

Long-term investments and other receivables

We have investments in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages). These investments are non-marketable and do not have published fair values. The fair value of these investments approximates their carrying value and totaled $2.8 million and $3.2 million as of December 31, 2014 and 2013, respectively.

Inventory

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

	December 31,

	2014		2013
	(In thousands)
Raw materials	$	133,797	$	128,606
Work-in-progress		39,617		26,762
Finished goods		56,653		54,425

	$	230,067	$	209,793

Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We provide for the depreciation of our drilling and workover rigs using the units-of-production method. For each day a rig is operating, we depreciate it over an approximate 4,927-day period, with the exception of our jackup rigs which are depreciated over an 8,030-day period, after provision for salvage value. For each day a rig asset is not operating, it is depreciated over an assumed depreciable life of 20 years, with the exception of our jackup rigs, where a 30-year depreciable life is used, after provision for salvage value.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3 Summary of Significant Accounting Policies (Continued)

We review our assets for impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the sum of estimated future cash flows, on an undiscounted basis, is less than the carrying amount of the long-lived asset. Impairment charges are recorded using discounted cash flows which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry.

Significant and unanticipated changes to the assumptions could result in future impairments. A significantly prolonged period of lower oil and natural gas prices could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges. As the determination of whether impairment charges should be recorded on our long-lived assets is subject to significant management judgment, and an impairment of these assets could result in a material charge on our consolidated statements of income (loss), management believes that accounting estimates related to impairment of long-lived assets are critical.

Goodwill

We initially assess goodwill for impairment based on qualitative factors to determine whether to perform the two-step annual goodwill impairment test, a Level 3 fair value measurement. After qualitative assessment, step one of the impairment test compares the estimated fair value of the reporting unit to its carrying amount. If the carrying amount exceeds the fair value, a second step is required to measure the goodwill impairment loss. The second step compares the implied fair value of the reporting unit's goodwill to its carrying amount. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to the excess.

The fair values calculated in these impairment tests were determined using discounted cash flow models involving assumptions based on our utilization of rigs or other oil and gas service equipment, revenues and earnings from affiliates, as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. Our discounted cash flow projections for each reporting unit were based on financial forecasts. The future cash flows were discounted to present value using discount rates determined to be appropriate for each reporting unit. Terminal values for each reporting unit were calculated using a Gordon Growth methodology with a long-term growth rate of 3%.

Our estimated fair values of our reporting units incorporate judgment and the use of estimates by management. Potential factors requiring assessment include a further or sustained decline in our stock price, declines in oil and natural gas prices, a variance in results of operations from forecasts, and additional transactions in the oil and gas industry. Another factor in determining whether impairment has occurred is the relationship between our market capitalization and our book value. As part of our annual review, we compared the sum of our reporting units' estimated fair value, which included the estimated fair value of non-operating assets and liabilities, less debt, to our market capitalization and assessed the reasonableness of our estimated fair value. Any of the above-mentioned factors may cause us to re-evaluate goodwill during any quarter throughout the year.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3 Summary of Significant Accounting Policies (Continued)

The change in the carrying amount of goodwill for our business lines for the years ended December 31, 2013 and 2014 was as follows:

	Balance at December 31, 2012		Acquisitions and Purchase Price Adjustments			Disposals and Impairments			Cumulative Translation Adjustment			Balance at December 31, 2013

	(In thousands)
Drilling & Rig Services:
U.S.	$	50,149	$	—		$	—		$	—		$	50,149
Rig Services		32,113		15,828	(1)		(9,631)	(2)		(1,049	)		37,261

Subtotal Drilling & Rig Services		82,262		15,828			(9,631	)		(1,049	)		87,410
Completion & Production Services
Completion		334,992		—			—			—			334,992
Production		55,072		35,490	(3)		—			—			90,562

Subtotal Completion & Production
Services		390,064		35,490			—			—			425,554

Total	$	472,326	$	51,318		$	(9,631	)	$	(1,049	)	$	512,964

	Balance at December 31, 2013		Acquisitions and Purchase Price Adjustments			Disposals and Impairments			Cumulative Translation Adjustment			Balance at December 31, 2014

	(In thousands)
Drilling & Rig Services:
U.S.	$	50,149	$	—		$	—		$	—		$	50,149
Rig Services		37,261		17,268	(4)		(21,613)	(5)		(1,249	)		31,667

Subtotal Drilling & Rig Services		87,410		17,268			(21,613	)		(1,249	)		81,816
Completion & Production Services
Completion		334,992		—			(334,992)	(5)		—			—
Production		90,562		1,550			—			—			92,112

Subtotal Completion & Production
Services		425,554		1,550			(334,992	)		—			92,112

Total	$	512,964	$	18,818		$	(356,605	)	$	(1,249	)	$	173,928

(1): Represents the goodwill recorded in connection with our acquisition of NES. See Note 6—Acquisitions for additional discussion.
(2): Represents the removal of goodwill in connection with our sale of Peak and the logistic assets from one of our Canada subsidiaries.
(3): Represents the goodwill recorded in connection with our acquisition of KVS. See Note 6—Acquisitions for additional discussion.

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Note 3 Summary of Significant Accounting Policies (Continued)

(4): Represents the goodwill recorded in connection with our acquisition of 2TD. See Note 6—Acquisitions for additional discussion.
(5): Represents the goodwill impairment associated with our acquisitions of NES and Superior in prior years. These impairment charges were deemed necessary due to the continued deterioration of oil prices. See Note 4—Impairments and Other Charges.

Goodwill for the consolidated company, totaling approximately $75.6 million, is expected to be deductible for tax purposes.

Litigation and Insurance Reserves

We estimate our reserves related to litigation and insurance based on the facts and circumstances specific to the litigation and insurance claims and our past experience with similar claims. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions. See Note 19—Commitments and Contingencies regarding self-insurance accruals. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can reasonably be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ from our estimates. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure.

Revenue Recognition

We recognize revenues and costs on daywork contracts daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. We defer revenue related to mobilization periods and recognize the revenue over the term of the related drilling contract. Costs incurred related to a mobilization period for which a contract is secured are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. We defer recognition of revenue on amounts received from customers for prepayment of services until those services are provided.

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

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

We recognize, as operating revenue, proceeds from business interruption insurance claims in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements in excess of the carrying value of damaged assets are recognized in losses (gains) on sales

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Note 3 Summary of Significant Accounting Policies (Continued)

and disposals of long-lived assets and other expense (income), net in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements that are expected to be less than the carrying value of damaged assets are recognized at the time the loss is incurred and recorded in losses (gains) on sales and disposals of long-lived assets and other expense (income), net.

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

Income Taxes

We are a Bermuda exempted company and are not subject to income taxes in Bermuda. Income taxes have been provided based on the tax laws and rates in effect in the countries where we operate and earn income. The income taxes in these jurisdictions vary substantially. Our worldwide effective tax rate for financial statement purposes will continue to fluctuate from year to year due to the change in the geographic mix of pre-tax earnings.

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

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

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

Foreign Currency Translation

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

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and

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Note 3 Summary of Significant Accounting Policies (Continued)

the amounts of revenues and expenses recognized during the reporting period. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:

•: depreciation of property, plant and equipment;
•: impairment of long-lived assets;
•: impairment of goodwill and intangible assets;
•: income taxes;
•: litigation and self-insurance reserves; and
•: fair value of assets acquired and liabilities assumed.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board ("FASB") issued an Accounting Standards Update ("ASU") relating to the reporting of discontinued operations and the disclosures related to disposals of components of an entity. The core principles address the question around whether the disposal represents a strategic shift, if the operations and cash flows can be clearly distinguished and continuing involvement will no longer preclude a disposal from being presented as discontinued operations. These changes are effective for interim and annual periods that begin after December 15, 2014. Early application is permitted. We are currently evaluating the impact this will have on our consolidated financial statements.

In May 2014, the FASB issued an ASU relating to the revenue recognition from contracts with customers that creates a common revenue standard for GAAP and IFRS. The core principle will require recognition of revenue to represent the transfer of promised goods or services to customers in an amount that reflects the consideration, including costs incurred, to which the entity expects to be entitled in exchange for those goods or services. These changes are effective for interim and annual periods that begin after December 15, 2016. Early application is not permitted. We are currently evaluating the impact this will have on our consolidated financial statements.

In June 2014, the FASB issued an ASU relating to the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The core principle will require the reporting entity to apply existing guidance in Topic 718-Compensation-Stock Compensation relating to awards with performance conditions that affect vesting to account for such awards. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. These changes are effective for interim and annual periods that begin after December 15, 2015. Early application is permitted. We are currently evaluating the impact this will have on our consolidated financial statements.

In February 2015, the FASB issued an ASU relating to consolidation, which eliminates the presumption that a general partner should consolidate a limited partnership. It also modifies the evaluation of whether limited partnerships are variable interest entities or voting interest entities and adds requirements that limited partnerships must meet to qualify as voting interest entities. This

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Note 3 Summary of Significant Accounting Policies (Continued)

guidance is effective for public companies for fiscal years beginning after December 15, 2015. We are currently evaluating the impact this will have on our consolidated financial statements.

Note 4 Impairments and Other Charges

The components of impairments and other charges are provided below:

	Year Ended December 31,

	2014		2013		2012
	(In thousands)
Tangible Assets & Equipment:
Provision for retirement of assets	$	393,962	$	14,044	$	138,666
Impairment of long-lived assets		217,627		20,000		50,355

Subtotal		611,589		34,044		189,021
Goodwill & Intangible Assets:
Goodwill impairments		356,605		—		26,279
Intangible asset impairment		29,942		—		74,960

Subtotal		386,547		—		101,239
Other Charges:
Transaction costs		22,313		—		—
Other-than-temporary impairment on equity security		6,974		—		—
Loss on tendered notes		—		208,197		—
Termination of employment contract		—		45,000		—

Total	$	1,027,423	$	287,241	$	290,260

For the year ended December 31, 2014

During the latter part of 2014, oil prices fell sharply and have remained depressed into 2015. As a result of the reduced price of oil, we have experienced a decline in the demand for drilling and completion services as customers have begun reducing or curtailing their capital spending and drilling activities. The reduction in demand for drilling services, coupled with the increased supply of newly built high specification rigs in the drilling market, has led to a highly competitive market for all rigs, including high specification rigs. This has accelerated the under-utilization of our legacy rig fleet (non AC rigs). We have also experienced downward pricing pressure for our services.

Due to the aforementioned factors, we recorded impairments and retirement provisions of approximately $1 billion during 2014, as detailed in the table above. The impairments and retirement provision 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4 Impairments and Other Charges (Continued)

Tangible Assets and Equipment

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

	Provision for Retirements		Tangible Asset Impairments		Total

Drilling & Rig Services:
U.S.	$	271,141	$	137,000	$	408,141
Canada		24,211		10,176		34,387
International		56,472		70,451		126,923
Rig Services		42,138		—		42,138

Total	$	393,962	$	217,627	$	611,589

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

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

Goodwill and Intangible Assets

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4 Impairments and Other Charges (Continued)

adversely affect demand for our services and lead to further goodwill impairment charges for other operating units in the future.

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

Transaction costs

Other-than-temporary impairment

For the years ended December 31, 2013 and 2012

Provision for retirement of long-lived assets

Impairments of long-lived assets

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Note 4 Impairments and Other Charges (Continued)

undiscounted basis, was less than the carrying amount of these assets. The estimated fair values of these assets were calculated using discounted cash flow models involving assumptions based on our utilization of the assets, revenues and direct costs, capital expenditures and working capital requirements. We believe the fair value estimated for purposes of these tests represents a Level 3 fair value measurement. In 2013, we suspended our coil-tubing operations in the United States. A prolonged period of slow economic recovery could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges for other reporting units due to the potential impact on our estimate of our future operating results.

Goodwill impairments

There were no goodwill impairments in 2013.

Intangible asset impairment

There were no intangible asset impairments in 2013.

Loss on tendered notes

Provision for termination of employment contract

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Note 5 Assets Held for Sale and Discontinued Operations

Assets Held for Sale

Assets held for sale included the following:

	As of December 31,

	2014		2013
	(In thousands)
Oil and Gas	$	146,467	$	239,936
Rig Services		—		3,328

	$	146,467	$	243,264

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

Oil and Gas Properties

The carrying value of our assets held for sale represents the lower of carrying value or fair value less costs to sell. We continue to market these properties at prices that are reasonable compared to current fair value. Also, we have deferred tax liabilities of approximately $2.3 million, which are included in long-term deferred income taxes in our consolidated balance sheet, associated with our oil and gas operations in Canada.

The amounts at each balance sheet date represented our best estimate of the fair value of the excess capacity of the pipeline commitments calculated using a discounted cash flow model, when considering our disposal plan, current production levels, natural gas prices and expected utilization of the pipeline over the remaining contractual term. Decreases in actual production or natural gas prices could result in future charges related to excess pipeline commitments.

Discontinued Operations

The operating results from the assets discussed above for all periods presented are retroactively presented and accounted for as discontinued operations in the accompanying audited consolidated statements of income (loss) and the respective accompanying notes to the consolidated financial

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

	Year Ended December 31,

	2014			2013			2012
	(In thousands, except percentages)
Operating revenues
Oil and Gas	$	13,143		$	25,327		$	27,363
Rig Services	$	—		$	127,154		$	172,335
Income (loss) from Oil & Gas discontinued operations:
Income (loss) from discontinued operations	$	(1,840	)	$	(17,371	)	$	(3,958	)
Less: Impairment charges or other (gains) and losses on sale of wholly owned assets		(1,313	)		24,087	(1)		106,096	(2)
Less: Income tax expense (benefit)		(548	)		(14,062	)		(44,021	)

Income (loss) from Oil and Gas discontinued operations, net of tax	$	21		$	(27,396	)	$	(66,033	)

Income (loss) from Rig Services discontinued operations:
Income (loss) from discontinued operations	$	—		$	17,680		$	9,846
Less: Impairment charges or other (gains) and losses on sale of wholly owned assets		—			(4,368	)(3)		9,087	(4)
Less: Income tax expense (benefit)		—			5,831			2,252

Income (loss) from Rig Services discontinued operations, net of tax	$	—		$	16,217		$	(1,493	)

Income (loss) from discontinued operations, net of tax	$	21		$	(11,179	)	$	(67,526	)

Oil and Gas

(1)

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

(2)

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

In 2013, we sold some of our wholly owned oil and gas assets and received proceeds of $90.0 million.

In 2012, we sold our remaining wholly owned oil and gas business in Colombia and sold additional wholly owned assets in the United States. In December 2012, we sold our 49.7% ownership interest in the U.S. unconsolidated oil and gas joint venture, to the remaining equity owners. During 2012, we received cumulative gross cash proceeds of $254.5 million from sales of oil and gas assets.

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Note 5 Assets Held for Sale and Discontinued Operations (Continued)

Rig Services

(3): Represents the gains recognized from our sale of our logistics services and construction services. In April 2013, we sold the assets of one of our former Canadian subsidiaries that provided logistic services for proceeds of $9.3 million. In October 2013, we sold Peak, one of our businesses in Alaska, for which we received cash proceeds of $135.5 million.
(4): Includes $7.8 million respectively, of impairment (a Level 3 measurement) in 2012 to our aircraft and logistics assets as a result of the continued downturn in the oil and gas industry in Canada.

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

Additional discussion of our policy pertaining to the calculations of our annual impairment tests, including any impairment to goodwill, is set forth in Note 3—Summary of Significant Accounting Policies. A further protraction of lower commodity prices or an inability to sell these assets in a timely manner could result in recognition of future impairment charges.

Note 6 Acquisitions

2014 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 segment. Under the terms of the transaction, we paid an initial amount of $40.3 million for the purchase of the shares. We may also be required to make future payments of up to an additional $40.0 million, contingent on the achievement of various milestone objectives. As part of our preliminary purchase price allocation, we have recorded intangible assets of $47.7 million (in process research and development), goodwill of $17.3 million and contingent consideration of $24.7 million. The proforma effect on revenue and net income have been determined to be immaterial to our financial statements.

2013 Acquisitions

In January 2013, we purchased the business of NES for a total cash price of approximately $37.5 million. NES operates primarily in Texas, Louisiana and North Dakota as a provider of drift-while-drilling and measure-while-drilling services and technology. Their business was focused on directional drilling by oil and gas exploration and development companies. This acquisition expands our technology and development capability for drilling and measurement tools and services, and is included

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Note 6 Acquisitions (Continued)

in our Rig Services operating segment. The purchase price was allocated to the net tangible and intangible assets acquired based on their fair value. The excess of the purchase price over the fair values of the assets acquired was recorded as goodwill in the amount of $15.8 million.

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

Note 7 Cash and Cash Equivalents and Short-term Investments

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

	As of December 31,

	2014		2013
	(In thousands)
Cash and cash equivalents	$	501,149	$	389,915

Short-term investments:
Available-for-sale equity securities	$	35,002	$	96,942
Available-for-sale debt securities		18		20,276

Total short-term investments	$	35,020	$	117,218

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

	As of December 31,

	2014							2013
	Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses
	(In thousands)
Cash and cash equivalents	$	501,149	$	—	$	—		$	389,915	$	—	$	—
Short-term investments:
Available-for-sale equity securities		35,002		14,648		—			96,942		68,395		—
Available-for-sale debt securities:
Corporate debt securities		—		—		—			19,388		4,122		—
Mortgage-backed debt securities		—		—		—			210		11		—
Mortgage-CMO debt securities		18		—		(1	)		20		—		(2	)
Asset-backed debt securities		—		—		—			658		2		(54	)

Total available-for-sale debt securities		18		—		(1	)		20,276		4,135		(56	)

Total available-for-sale securities		35,020		14,648		(1	)		117,218		72,530		(56	)

Total short-term investments		35,020		14,648		(1	)		117,218		72,530		(56	)

Total cash, cash equivalents and
short-term investments	$	536,169	$	14,648	$	(1	)	$	507,133	$	72,530	$	(56	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7 Cash and Cash Equivalents and Short-term Investments (Continued)

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

	As of December 31, 2014

	Less Than 12 Months				More Than 12 Months
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
	(In thousands)
Available-for-sale equity securities	$	—	$	—	$	—	$	—
Available-for-sale debt securities:
Mortgage-CMO debt securities		—		—		18		1

Total available-for-sale debt securities		—		—		18		1

Total	$	—	$	—	$	18	$	1

The estimated fair values of our corporate, mortgage-backed, mortgage-CMO and asset-backed debt securities at December 31, 2014, classified by time to contractual maturity, are shown below. Expected maturities differ from contractual maturities because the issuers of the securities may have the right to repay obligations without prepayment penalties and we may elect to sell the securities prior to the contractual maturity date.

	Estimated Fair Value As of December 31, 2014

	(In thousands)
Debt securities:
Due in one year or less	$	—
Due after one year through five years		—
Due in more than five years		18

Total debt securities	$	18

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

	Year Ended December 31,

	2014		2013		2012
	(In thousands)
Available-for-sale
Proceeds from sales and maturities	$	22,313	$	107,586	$	24,010
Realized gains (losses), net	$	4,638	$	88,158	$	13,405

Note 8 Fair Value Measurements

Fair value is the price that would be received upon sale of an asset or paid upon transfer of a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market-corroborated, or generally unobservable. We primarily apply

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Note 8 Fair Value Measurements (Continued)

the market approach for recurring fair value measurements and endeavor to utilize the best information available. Accordingly, we employ valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The use of unobservable inputs is intended to allow for fair value determinations in situations where there is little, if any, market activity for the asset or liability at the measurement date. We are able to classify fair value balances utilizing a fair value hierarchy based on the observability of those inputs. Under the fair value hierarchy:

•: Level 1 measurements include unadjusted quoted market prices for identical assets or liabilities in an active market;
•: Level 2 measurements include quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and
•: Level 3 measurements include those that are unobservable and of a subjective nature.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2014. Our debt securities could transfer into or out of a Level 1 or 2 measure depending on the availability of independent and current pricing at the end of each quarter. During 2014, there were no transfers of our financial assets between Level 1 and Level 2 measures. Our financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

	Fair Value as of December 31, 2014

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Short-term investments:
Available-for-sale equity securities from energy industry	$	35,002	$	—	$	—	$	35,002
Available-for-sale debt securities:
Mortgage-CMO debt securities		—		18		—		18

Total short-term investments	$	35,002	$	18	$	—	$	35,020

Nonrecurring Fair Value Measurements

Fair value measurements were applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis, which would consist of measurements primarily to assets held for sale, goodwill, intangible assets and other long-lived assets, assets acquired and liabilities assumed in a business combination and our pipeline contractual commitment.

Fair Value of Financial Instruments

The fair value of our financial instruments has been estimated in accordance with GAAP. The fair value of our long-term debt, revolving credit facility, commercial paper and subsidiary preferred stock is

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Note 8 Fair Value Measurements (Continued)

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

	As of December 31,

	2014							2013
	Effective Interest Rate			Carrying Value		Fair Value		Effective Interest Rate			Carrying Value		Fair Value
	(In thousands, except interest rates)
2.35% senior notes due September 2016		2.56	%	$	349,887	$	346,980		2.56	%	$	349,820	$	354,694
6.15% senior notes due February 2018		6.42	%		930,693		991,920		6.42	%		969,928		1,097,480
9.25% senior notes due January 2019		9.33	%		339,607		403,531		9.33	%		339,607		428,733
5.00% senior notes due September 2020		5.20	%		698,253		687,953		5.20	%		697,947		731,955
4.625% senior notes due September 2021		4.75	%		698,388		661,619		4.75	%		698,148		709,793
5.10% senior notes due September 2023		5.26	%		348,893		332,759		5.26	%		348,765		349,731
Subsidiary preferred stock		0.00	%		—		—		4.00	%		69,188		69,000
Revolving credit facility		3.47	%		450,000		450,000		2.28	%		170,000		170,000
Commercial paper		0.59	%		533,119		533,119		0.45	%		329,844		329,844
Other		0.00	%		6,209		6,209		0.00	%		10,243		10,243

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

The fair values of our cash equivalents, trade receivables and trade payables approximate their carrying values due to the short-term nature of these instruments.

As of December 31, 2014, our short-term investments were carried at fair market value and included $35.0 million in securities classified as available-for-sale. As of December 31, 2013, our short-term investments were carried at fair market value and included $117.2 million in securities classified as available-for-sale.

Note 9 Share-Based Compensation

Total share-based compensation expense, which includes stock options and restricted stock, totaled $37.2 million, $53.3 million and $18.3 million for 2014, 2013 and 2012, respectively. Compensation expense related to awards of restricted stock totaled $35.0 million, $51.1 million and $14.1 million for 2014, 2013 and 2012, respectively, and is included in direct costs and general and administrative expenses in our consolidated statements of income (loss). Share-based compensation expense has been allocated to our various operating segments. See Note 23—Segment Information.

Our restricted stock share-based awards also include two types of performance share awards: the first, based on our performance measured against pre-determined performance metrics and the second, based on market conditions measured against a predetermined peer group. The performance period for the awards granted in 2014 commenced on January 1, 2013 and ended December 31, 2013.

Stock Option Plans

As of December 31, 2014, we had several stock plans under which options to purchase our common shares could be granted to key officers, directors and managerial employees of Nabors and its subsidiaries. Options granted under the plans generally are at prices equal to the fair market value of the shares on the date of the grant. Options granted under the plans generally are exercisable in varying cumulative periodic installments after one year. In the case of certain key executives, options granted may vest immediately on the grant date. Options granted under the plans cannot be exercised

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Note 9 Share-Based Compensation (Continued)

more than ten years from the date of grant. Options to purchase 6.3 million and 7.8 million Nabors common shares remained available for grant as of December 31, 2014 and 2013, respectively. Of the common shares available for grant as of December 31, 2014, approximately 5.0 million of these shares are also available for issuance in the form of restricted shares.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model which uses assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatilities are based on implied volatilities from traded options on Nabors' common shares, historical volatility of Nabors' common shares, and other factors. We use historical data to estimate the expected term of the options and employee terminations within the option-pricing model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of the options represents the period of time that the options granted are expected to be outstanding.

We also consider an estimated forfeiture rate for these option awards, and we recognize compensation cost only for those shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of three to five years. The forfeiture rate is based on historical experience. Estimated forfeitures have been adjusted to reflect actual forfeitures during 2014.

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

Options	Shares			Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value

	(In thousands, except exercise price)
Options outstanding as of December 31, 2013		18,386		$	21.10
Granted		61			17.93
Exercised		(3,036	)		9.97
Surrendered		—			—
Forfeited		(4,107	)		23.16

Options outstanding as of December 31, 2014		11,304		$	23.30	2.81 years	$	12,976

Options exercisable as of December 31, 2014		10,955		$	23.37	2.67 years	$	12,948

Of the options outstanding, 11.0 million were exercisable at the weighted-average exercise price of $23.37 as of December 31, 2014.

During 2014, 2013 and 2012, respectively, we awarded options vesting over periods up to four years to purchase 60,662, 63,368 and 658,061 of our common shares to our employees, executive officers and directors.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 9 Share-Based Compensation (Continued)

The fair value of stock options granted during 2014, 2013 and 2012 was calculated using the Black-Scholes option pricing model and the following weighted-average assumptions:

	Year Ended December 31,

	2014			2013			2012
Weighted average fair value of options granted	$	6.76		$	6.05		$	9.40
Weighted average risk free interest rate		1.37	%		0.79	%		0.63	%
Dividend yield		1.21	%		0.84	%		0	%
Volatility(1)		51.01	%		51.01	%		55.74	%
Expected life		4.0 years			4.0 years			4.0 years

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

A summary of our unvested stock options as of December 31, 2014, and the changes during the year then ended is presented below:

Unvested Stock Options	Outstanding			Weighted-Average Grant-Date Fair Value

	(In thousands, except fair value)
Unvested as of December 31, 2013		549		$	8.88
Granted		61			5.61
Vested		(248	)		8.02
Forfeited		(13	)		4.83

Unvested as of December 31, 2014		349		$	9.08

The total intrinsic value of options exercised during 2014, 2013 and 2012 was $49.1 million, $4.1 million and $23.7 million, respectively. The total fair value of options that vested during the years ended December 31, 2014, 2013 and 2012 was $2.0 million, $4.3 million and $7.9 million, respectively.

As of December 31, 2014, there was $2.0 million of total future compensation cost related to unvested options that are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately one year.

Restricted Stock

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 9 Share-Based Compensation (Continued)

A summary of our restricted stock as of December 31, 2014, and the changes during the year then ended, is presented below:

Restricted stock	Outstanding			Weighted-Average Grant-Date Fair Value

	(In thousands, except fair value)
Unvested as of December 31, 2013		3,764		$	18.26
Granted		1,169			22.80
Vested		(1,270	)		19.45
Forfeited		(181	)		20.23

Unvested as of December 31, 2014		3,482		$	19.25

During 2014, 2013 and 2012, we awarded 1,169,000, 4,493,443 and 944,015 shares of restricted stock, respectively, to our employees and directors. These awards had an aggregate value at their date of grant of $26.7 million, $73.8 million and $19.5 million, respectively, and were scheduled to vest over a period of up to four years. The fair value of restricted stock that vested during 2014, 2013 and 2012 was $28.0 million, $37.5 million and $9.7 million, respectively. The fair value of these awards is based on the closing price of Nabors stock on the date the awards are granted.

As of December 31, 2014, there was $43.1 million of total future compensation cost related to unvested restricted stock awards that are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately one year.

Restricted Stock Based on Performance Conditions

During the first quarter of 2015, we granted 438,307 performance-based restricted stock awards to some of our executives. These awards vest over a period up to three years. The performance awards granted are based upon achievement of specific financial or operational objectives for fiscal year 2014. The number of shares granted was determined by the number of performance goals achieved. Our performance shares based on performance conditions are liability-classified awards, of which our accrued liabilities included $2.5 million at December 31, 2014. The fair value of these awards was estimated at each reporting period during 2014, based on internal metrics and marked to market at December 31, 2014.

During the first quarter of 2014, we granted 362,311 restricted stock performance-based awards for fiscal year 2013 to some of our executives. These awards vest over a period up to three years. The performance awards granted are based upon achievement of specific financial or operational objectives. The number of shares granted was determined by the number of performance goals achieved. Our performance shares based on performance conditions are liability-classified awards, of which our accrued liabilities included $1.8 million at December 31, 2013. The fair value of these awards was estimated at each reporting period during 2013, based on internal metrics and marked to market at December 31, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 9 Share-Based Compensation (Continued)

Restricted Stock Based on Market Conditions

During 2014 and 2013, we granted 395,550 and 353,933 shares of restricted stock, respectively, which are equity classified awards and will vest on our performance compared to our peer group over a three year period. These awards had an aggregate fair value at their date of grant or $4.5 million and $3.7 million, respectively, after consideration of all assumptions.

The grant date fair value of these awards was based on a Monte Carlo model, using the following assumptions:

	Year ended December 31,

	2014			2013
Risk free interest rate		0.80	%		0.41	%
Expected volatility		40.00	%		46.00	%
Closing stock price at grant date	$	18.19		$	16.53
Expected term (in years)		2.97			2.82

The following table sets forth information regarding outstanding restricted stock based on market conditions as of December 31, 2014:

Market based restricted stock	Outstanding		Weighted-Average Grant-Date Fair Value

	(In thousands, except fair value)
Outstanding as of December 31, 2013		354	$	10.42
Granted		395		11.40
Vested		—		—
Forfeited		—		—

Outstanding as of December 31, 2014		749	$	10.94

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10 Property, Plant and Equipment

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

	December 31,

	2014			2013
	(In thousands)
Land	$	63,311		$	63,733
Buildings		165,826			163,962
Drilling, workover and well-servicing rigs, and related equipment		12,792,207			12,818,136
Marine transportation and supply vessels		14,123			14,062
Oilfield hauling and mobile equipment		1,398,032			1,322,798
Other machinery and equipment		185,663			168,465
Oil and gas properties		26,579			—
Construction-in-process(1)		781,374			693,475

	$	15,427,115		$	15,244,631
Less: accumulated depreciation and amortization		(6,827,990	)		(6,646,818	)

	$	8,599,125		$	8,597,813

(1): Relates primarily to amounts capitalized for new or substantially new drilling, workover and well-servicing rigs that were under construction and had not yet been placed in service as of December 31, 2014 or 2013.

Repair and maintenance expense included in direct costs in our consolidated statements of income (loss) totaled $603.4 million, $510.8 million and $563.5 million during 2014, 2013 and 2012, respectively.

Interest costs of $24.4 million, $13.0 million and $19.4 million were capitalized during 2014, 2013 and 2012, respectively.

Note 11 Investments in Unconsolidated Affiliates

Our principal investment in unconsolidated affiliates accounted for using the equity method include drilling and workover operations located in Saudi Arabia (51% ownership). This unconsolidated affiliate is integral to our operations. See Note 18—Related-Party Transactions for additional information. During 2012, we sold our equity interests in unconsolidated oil and gas joint ventures.

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

	December 31,

	2014		2013
	(In thousands)
Current assets	$	470,501	$	442,703
Long-term assets	$	324,234	$	138,222
Current liabilities	$	467,000	$	440,585
Long-term liabilities	$	207,681	$	4,169

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 11 Investments in Unconsolidated Affiliates (Continued)

	Year Ended December 31,

	2014			2013		2012
	(In thousands)
Gross revenues	$	605,179		$	562,101	$	657,362
Gross margin	$	35,370		$	46,446	$	107,035
Net income (loss)	$	(642	)	$	1,088	$	(624,172	)
Nabors' earnings (losses) from unconsolidated affiliates	$	(6,301	)	$	39	$	(288,718	)

Note 12 Financial Instruments and Risk Concentration

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

Foreign Currency Risk

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

Credit Risk

Our financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash equivalents, short-term and long-term investments and accounts receivable. Cash equivalents such as deposits and temporary cash investments are held by major banks or investment firms. Our short-term and long-term investments are managed within established guidelines that limit the amounts that may be invested with any one issuer and provide guidance as to issuer credit quality. We believe that the credit risk in our cash and investment portfolio is minimized as a result of the mix of our investments. In addition, our trade receivables are with a variety of U.S., international and foreign-country national oil and gas companies. Management considers this credit risk to be limited due to the financial resources of these companies. We perform ongoing credit evaluations of our customers, and we generally do not require material collateral. We do occasionally require prepayment of amounts from customers whose creditworthiness is in question prior to providing services to them. We maintain reserves for potential credit losses, and these losses historically have been within management's expectations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 12 Financial Instruments and Risk Concentration (Continued)

Interest Rate and Marketable and Non-marketable Security Price Risk

Our financial instruments that are potentially sensitive to changes in interest rates include our 2.35%, 5.10%, 6.15%, 9.25%, 5.0% and 4.625% senior notes, our investments in debt securities (including corporate, asset-backed, mortgage-backed debt and mortgage-CMO debt securities) and our investments in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages), which are classified as long-term investments.

We may utilize derivative financial instruments that are intended to manage our exposure to interest rate risks. The use of derivative financial instruments could expose us to further credit risk and market risk. Credit risk in this context is the failure of a counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty would owe us, which can create credit risk for us. When the fair value of a derivative contract is negative, we would owe the counterparty, and therefore, we would not be exposed to credit risk. We attempt to minimize credit risk in derivative instruments by entering into transactions with major financial institutions that have a significant asset base. Market risk related to derivatives is the adverse effect on the value of a financial instrument that results from changes in interest rates. We try to manage market risk associated with interest-rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that we undertake.

Note 13 Debt

Debt consisted of the following:

	As of December 31,

	2014		2013
	(In thousands)
2.35% senior notes due September 2016	$	349,887	$	349,820
6.15% senior notes due February 2018		930,693		969,928
9.25% senior notes due January 2019		339,607		339,607
5.00% senior notes due September 2020		698,253		697,947
4.625% senior notes due September 2021		698,388		698,148
5.10% senior notes due September 2023		348,893		348,765
Revolving credit facility		450,000		170,000
Commercial paper		533,119		329,844
Other		6,209		10,243

	$	4,355,049	$	3,914,302
Less: current portion		6,190		10,185

	$	4,348,859	$	3,904,117

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 13 Debt (Continued)

As of December 31, 2014, the maturities of our primary debt for each of the five years after 2014 and thereafter are as follows:

	Paid at Maturity

	(In thousands)
2015	$	—
2016		350,000	(1)
2017		983,119	(2)
2018		934,372	(3)
2019		339,607	(4)
Thereafter		1,750,000	(5)

	$	4,357,098

(1): Represents our 2.35% senior notes due September 2016.
(2): Represents amounts drawn on our revolving credit facility and commercial paper, which expires November 2017.
(3): Represents our 6.15% senior notes due February 2018.
(4): Represents our 9.25% senior notes due January 2019.
(5): Represents our 5.0% senior notes due September 2020, 4.625% senior notes due September 2021 and 5.10% senior notes due September 2023.

2.35% and 5.10% Senior Notes Due September 2016 and September 2023

In September 2013, Nabors Delaware completed a private placement of $700 million aggregate principal amount of senior notes, comprised of $350 million aggregate principal amount of 2.35% senior notes due 2016 and $350 million aggregate principal amount of 5.10% senior notes due 2023. The notes are unsecured and fully and unconditionally guaranteed by us. The notes are subject to registration rights. The notes were sold by the initial purchasers to qualified institutional buyers pursuant to Rule 144A and to certain investors outside of the United States under Regulation S under the Securities Act. The notes pay interest semiannually on March 15 and September 15, beginning on March 15, 2014. The 2.35% senior notes will mature on September 15, 2016, and the 5.10% senior notes will mature on September 15, 2023.

The notes rank equal in right of payment to all of Nabors Delaware's existing and future senior unsubordinated debt. The notes rank senior in right of payment to all of our existing and future senior subordinated and subordinated debt. Our guarantee of the notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The indenture includes covenants customary for transactions of this type that, subject to significant exceptions, limit our subsidiaries' ability to, among other things, incur certain liens or enter into sale and leaseback transactions. In the event of a Change of Control Trigger Event, as defined in the indenture, with respect to a series of the notes, the holders of that series of notes may require Nabors Delaware to purchase all or a portion of each senior note in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at the redemption prices specified in the indenture, plus

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Note 13 Debt (Continued)

accrued and unpaid interest. Nabors Delaware used the proceeds from the issuance of the notes, together with cash on hand, to redeem a portion of its 9.25% senior notes due 2019.

6.15% Senior Notes Due February 2018

In February 2008, Nabors Delaware completed a private placement of $575 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. On July 22, 2008, Nabors Delaware completed an additional private placement under the same indenture of $400 million aggregate principal amount of 6.15% senior notes due 2018, also with registration rights and fully and unconditionally guaranteed by us. These new notes are subject to the same rates, terms and conditions and together will be treated as a single class of debt securities under the indenture (together $975 million 6.15% senior notes due 2018). The issue of notes was resold by the initial purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain investors outside of the United States pursuant to Regulation S under the Securities Act. The notes bear interest at a rate of 6.15% per year, payable semi-annually on February 15 and August 15 and will mature on February 15, 2018.

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

9.25% Senior Notes Due January 2019

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

The notes are unsecured and are junior in right of payment to any of Nabors Delaware's future secured debt. The notes rank equally with any of Nabors Delaware's other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware's future senior subordinated debt. Our guarantee of the notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The notes are subject to redemption by Nabors Delaware, in whole or in part, at any time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes then outstanding to be redeemed;

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Note 13 Debt (Continued)

or (ii) the sum of the present values of the remaining scheduled payments of principal and interest, determined in the manner set forth in the applicable indenture. In the event of a change in control triggering event, as defined in the indenture, the holders of notes may require Nabors Delaware to purchase all or any part of each note in cash equal to 101% of the principal amount plus accrued and unpaid interest, if any, to the date of purchase, except to the extent Nabors Delaware has exercised its right to redeem the notes.

In September 2013, Nabors Delaware commenced a cash tender offer for any and all of its outstanding 9.25% senior notes due 2019, which expired on September 11, 2013. On September 12, 2013, Nabors Delaware accepted for repurchase all of the notes that were validly tendered and not validly withdrawn prior to the expiration of the tender offer, totaling $785.4 million aggregate principal amount of the notes (including $14 million held by a consolidated affiliate). Nabors Delaware paid the holders an aggregate of approximately $1.0 billion in cash, reflecting principal, accrued and unpaid interest and a premium of $211.9 million (including related fees), from the proceeds of the 2.35% senior notes due 2016 and 5.10% senior notes due 2023 issued in September 2013, discussed above, borrowings under its commercial paper program and cash on hand. Following the repurchase, $339.6 million aggregate principal amount of the 9.25% senior notes remains outstanding. The 9.25% senior notes due 2019 have similar rankings, covenants and change of control provisions as Nabors Delaware's other series of senior notes. The premium represents the loss on the debt extinguishment and is included in the impairments and other charges line of our consolidated statement of income (loss) for the year ended December 31, 2013.

5.0% Senior Notes Due September 2020

In September 2010, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 5.0% senior notes due 2020, which are unsecured and fully and unconditionally guaranteed by us. The notes are subject to registration rights. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S. The notes pay interest semi-annually on March 15 and September 15 and will mature on September 15, 2020.

The notes rank equal in right of payment to all of Nabors Delaware's existing and future unsubordinated indebtedness, and senior in right of payment to all of Nabors Delaware's existing and future senior subordinated and subordinated indebtedness. Our guarantee of the notes is unsecured and an unsubordinated obligation and ranks equal in right of payments to all of our unsecured and unsubordinated indebtedness from time to time outstanding. In the event of a change of control triggering event, as defined in the indenture, the holders of the notes may require Nabors Delaware to purchase all or a portion of the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture. Nabors Delaware used a portion of the proceeds to repay the borrowing under a revolving credit facility incurred to fund our acquisition in September 2010.

4.625% Senior Notes Due September 2021

In August 2011, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 4.625% senior notes due 2021, which are unsecured and fully and unconditionally

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Note 13 Debt (Continued)

guaranteed by us. The notes have registration rights. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S. The notes pay interest semi-annually on March 15 and September 15 and will mature on September 15, 2021.

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

5.375% Senior Notes Due August 2012

In August 2012, we paid $282.4 million to holders of Nabors Delaware's 5.375% senior notes, representing principal of $275.0 million and accrued interest of $7.4 million. We used cash on hand and $270 million from revolving credit facilities to pay this obligation.

Commercial Paper Program

In April 2013, Nabors Delaware established a commercial paper program. This program allows for the issuance from time to time of up to an aggregate amount of $1.5 billion in commercial paper with a maturity of no more than 397 days. Our commercial paper borrowings are classified as long-term debt because the borrowings are fully supported by availability under our revolving credit facility, which matures as currently structured in November 2017, more than one year from now. As of December 31, 2014 and 2013, we had approximately $533.1 and $329.8 million, respectively, of commercial paper outstanding; we used the proceeds to reduce borrowings under our revolving credit facility and redeem debt. The weighted average interest rate on borrowings at December 31, 2014 was 0.369%.

Revolving Credit Facility

At December 31, 2014, we had $516.9 million of remaining availability under our $1.5 billion revolving credit facility. The weighted average interest rate on borrowings at December 31, 2014 was 1.47%. The revolving credit facility contains various covenants and restrictive provisions that limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain a net funded indebtedness to total capitalization ratio, as defined in each agreement. We were in compliance with all covenants under the agreement at December 31, 2014. If we fail to perform our obligations under the covenants, the revolving credit commitment could be terminated, and any outstanding borrowings under the facility could be declared immediately due and payable.

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Note 13 Debt (Continued)

Short-Term Borrowings

We had 11 letter-of-credit facilities with various banks as of December 31, 2014. Availability and borrowings under our letter-of-credit facilities are as follows:

	December 31, 2014

	(In thousands)
Credit available	$	650,204
Less: Letters of credit outstanding, inclusive of financial and performance guarantees		326,650

Remaining availability	$	323,554

Note 14 Income Taxes

The following is a reconciliation of our uncertain tax positions:

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Balance as of January 1	$	47,552		$	83,950		$	68,848
Additions based on tax positions related to the current year		167,107	(1)		145			922
Additions for tax positions of prior years		1,744			3,360			16,372	(3)
Reductions for tax positions for prior years		(4,473	)		(30,320	)(2)		(1,174	)
Settlements		(8,223	)		(9,583	)		(1,018	)

Balance as of December 31	$	203,707		$	47,552		$	83,950

(1): Includes $166.0 million related to internal restructuring.
(2): Includes $21.6 million related to settlements in Mexico, Canada and Algeria and $8.7 million due to the expiration of statutes.
(3): Includes an uncertain tax position of $10.4 million related to a Mexico audit assessment.

If the reserves of $203.7 million are not realized, this would favorably impact the worldwide effective tax rate. As of December 31, 2014, 2013 and 2012, we had approximately $16.9 million, $20.6 million and $42.8 million, respectively, of interest and penalties related to uncertain tax positions. During 2014, 2013 and 2012, we accrued and recognized estimated interest and penalties related to uncertain tax positions of approximately $6.1 million, $5.2 million and $2.7 million, respectively. We include potential interest and penalties related to uncertain tax positions within our global operations in the income tax expense (benefit) line item in our consolidated statements of income (loss).

It is reasonably possible that our existing liabilities related to our reserve for uncertain tax positions may increase or decrease in the next twelve months primarily due to the completion of open audits or the expiration of statutes of limitation. However, we cannot reasonably estimate a range of

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Note 14 Income Taxes (Continued)

changes in our existing liabilities due to various uncertainties, such as the unresolved nature of various audits.

We conduct business globally and, as a result, we file numerous income tax returns in the U.S. and non-U.S. jurisdictions. In the normal course of business we are subject to examination by taxing authorities throughout the world.

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

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
United States and Other Jurisdictions
United States	$	(598,121	)	$	(84,032	)	$	193,125
Other jurisdictions		(6,494	)		190,192			83,835

Income (loss) from continuing operations before income taxes	$	(604,615	)	$	106,160		$	276,960

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

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Current:
U.S. federal	$	183,840		$	(16,934	)	$	25,802
Outside the U.S.		109,072			50,866			82,950
State		9,401			5,933			34,242

	$	302,313		$	39,865		$	142,994

Deferred:
U.S. federal	$	(211,119	)	$	(71,251	)	$	(79,193	)
Outside the U.S.		(9,127	)		(10,288	)		(9,484	)
State		(19,401	)		(13,507	)		(13,331	)

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

Income tax expense (benefit)	$	62,666		$	(55,181	)	$	40,986

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Note 14 Income Taxes (Continued)

A reconciliation of our statutory tax rate to our worldwide effective tax rate consists of the following:

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Income tax provision at statutory (Bermuda rate of 0%)	$	—		$	—		$	—
Taxes (benefit) on U.S. and other international earnings (losses) at greater than the Bermuda rate		(83,747	)		(33,277	)		(39,830	)
Increase (decrease) in valuation allowance		(9,934	)		25,592			33,730
Tax reserves and interest		166,347			(39,921	)		26,176
State income taxes (benefit)		(10,000	)		(7,575	)		20,910

Income tax expense (benefit)	$	62,666		$	(55,181	)	$	40,986

Effective tax rate		(10.4	)%		(52.0	)%		14.8	%

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 14 Income Taxes (Continued)

The components of our net deferred taxes consisted of the following:

	December 31,

	2014			2013
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	1,470,407		$	1,658,084
Equity compensation		35,296			32,219
Deferred revenue		23,116			35,689
Tax credit and other attribute carryforwards		116,833			109,294
Insurance loss reserves		6,235			4,645
Accrued Interest		227,572			224,959
Other		143,302			162,678

Subtotal		2,022,761			2,227,568
Valuation allowance		(1,537,507	)		(1,547,441	)

Deferred tax assets:	$	485,254		$	680,127

Deferred tax liabilities:
Depreciation and amortization for tax in excess of book expense	$	760,294		$	967,689
Variable interest investments		4,496			85,979
Other		17,953			17,890

Deferred tax liability	$	782,743		$	1,071,558

Net deferred tax assets (liabilities)	$	(297,489	)	$	(391,431	)

Balance Sheet Summary:
Net current deferred asset	$	118,230		$	121,316
Net noncurrent deferred asset(1)		30,961			6,491
Net current deferred liability(2)		(3,677	)		(3,077	)
Net noncurrent deferred liability		(443,003	)		(516,161	)

Net deferred asset (liability)	$	(297,489	)	$	(391,431	)

(1): This amount is included in other long-term assets.
(2): This amount is included in accrued liabilities.

For U.S. federal income tax purposes, we have net operating loss ("NOL") carryforwards of approximately $214.3 million that, if not utilized, will expire between 2019 and 2031. The NOL carryforwards for alternative minimum tax purposes are approximately $192.0 million. Additionally, we have NOL carryforwards in other jurisdictions of approximately $5.3 billion of which $380.7 million, if not utilized, will expire at various times from 2015 to 2034. We provide a valuation allowance against NOL carryforwards in various tax jurisdictions based on our consideration of existing temporary differences and expected future earning levels in those jurisdictions. We have recorded a deferred tax asset of approximately $1.43 billion as of December 31, 2014 relating to NOL carryforwards that have an indefinite life in several non-U.S. jurisdictions. A valuation allowance of approximately $1.43 billion

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Note 14 Income Taxes (Continued)

has been recognized because we believe it is more likely than not that substantially all of the deferred tax asset will not be realized.

The NOL carryforwards by year of expiration consist of the following:

Year Ended December 31,	Total		U.S. Federal		Non-U.S.

	(In thousands)
2015	$	8,295	$	—	$	8,295
2016		27,847		—		27,847
2017		34,729		—		34,729
2018		48,559		—		48,559
2019		15,997		13,369		2,628
2020		15,115		—		15,115
2021		21,354		—		21,354
2022		1,282		—		1,282
2023		2,965		—		2,965
2024		7,583		—		7,583
2028		8		—		8
2030		99		—		99
2031		242,703		200,912		41,791
2032		75,257		—		75,257
2033		83,601		—		83,601
2034		9,610		—		9,610

Subtotal: expiring NOLs	$	595,004	$	214,281	$	380,723
Non-expiring NOLs		4,898,787		—		4,898,787

Total	$	5,493,791	$	214,281	$	5,279,510

In addition, for state income tax purposes, we have net operating loss carryforwards of approximately $313.0 million that, if not utilized, will expire at various times from 2015 to 2034.

Note 15 Common Shares

No preferred shares have been issued. The preferred stock is issuable in one or more classes or series, full, limited or no voting rights, designations, preferences, special rights, qualifications, limitations and restrictions as may be determined by Nabors Industries Ltd.'s board.

From time to time, treasury shares may be reissued. When shares are reissued, we use the weighted-average-cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from our capital in excess of par value account. No shares have been reissued during 2014, 2013 or 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 15 Common Shares (Continued)

During 2012, our outstanding shares increased by 807,142 shares, respectively, pursuant to a share settlement of stock options exercised by employees. As part of these transactions, these individuals surrendered unexercised vested stock options to the Company with a value of approximately $79.6 million, to satisfy the option exercise price and related income taxes for 2012. During 2013, our outstanding shares increased slightly by 1,284 shares pursuant to share settlements. These transactions also included surrendered unexercised vested stock options of a nominal value.

In 2014, 2013 and 2012, the Compensation Committee of our Board granted restricted stock awards to some of our executive officers, other key employees, and independent directors. We awarded 1,926,861, 4,847,376 and 944,015 restricted shares at an average market price of $19.53, $16.28 and $20.69 to these individuals for 2014, 2013 and 2012, respectively. See Note 8—Share-Based Compensation for a summary of our restricted stock and option awards as of December 31, 2014.

During 2014, 2013 and 2012 our employees and employees' estates exercised vested options to acquire 3.0 million, 0.6 million and 1.1 million of our common shares, respectively. During 2014, 2013 and 2012, we received $30.3 million, $5.4 million and $17.4 million, respectively, relating to exercised vested options. During 2012, we paid $21 million to repurchase surrendered unexercised vested options to satisfy related tax withholdings pursuant to stock option share settlements and exercises by employees.

In 2014, our Board declared cash dividends of $0.04 per outstanding common share, which was paid in March and June. The dividend was increased to $0.06 per share in July 2014 by our Board, and this new amount was paid in September and December 2014. The aggregate amount paid in 2014 for dividends was $59.1 million.

Shareholder Rights Plan

On July 16, 2012, the Board declared the issuance of one preferred share purchase right (a "Right") for each Common Share issued and outstanding on July 27, 2012 (the "Record Date") to the shareholders of record on that date. The Rights are not exercisable until the Distribution Date, as defined below. On July 15, 2013, the Rights expiration was extended to July 16, 2016 (the "Final Expiration Date"); the Final Expiration Date may be extended or the Rights earlier redeemed by the Company.

Each Right entitles the registered holder to purchase from the Company one one-thousandth of a Series A Junior Participating Preferred Share, par value US$0.001 per share (the "Preferred Shares"), of the Company, at a price of $80.00 per one one-thousandth of a Preferred Share (the "Purchase Price"), subject to adjustment.

Until the Distribution Date, the Rights will be evidenced, with respect to any Common Share certificates issued and outstanding as of the Record Date, by such Common Share certificate together with a copy of a summary of rights. The Distribution Date is defined as the earlier to occur of:

(i): 10 days following a public announcement that a person or group of affiliated or associated persons (an "Acquiring Person") has acquired beneficial ownership (including derivative positions) of 10% or more of the issued and outstanding Common Shares (or, in the event an exchange is effected in accordance with Section 24 of the Rights Agreement and the Board determines that a later date is advisable, then such later date that is not more than 20 days after such public announcement); or

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Note 15 Common Shares (Continued)

(ii): 10 business days (or such later date as may be determined by action of the Board prior to such time as any Person becomes an Acquiring Person) following the commencement of, or announcement of an intention to make, a tender offer or exchange offer the consummation of which would result in the beneficial ownership by a person or group of 10% or more of the issued and outstanding Common Shares.

Note 16 Subsidiary Preferred Stock

During 2014, we paid $70.9 million to redeem the 75,000 shares of Series A Preferred Stock outstanding of our subsidiary and paid all dividends due on such shares. The result of the redemption was a loss of $1.688 million, representing the difference between the redemption amount and the carrying value of the subsidiary preferred stock. The loss results in a charge to retained earnings and a reduction to net income used to determine income available for common shareholders in the calculation of basic and diluted earnings per share in the period of transaction. We also paid regular and accrued dividends of $750,000 and $108,750, respectively, and special dividends of $375,000. These dividends were treated as regular dividends, and as such were reflected in earnings in the consolidated statement of income (loss) for the year ended December 31, 2014.

Note 17 Pension, Postretirement and Postemployment Benefits

Pension Plans

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 17 Pension, Postretirement and Postemployment Benefits (Continued)

Summarized information on the Pool Pension Plan is as follows:

	Pension Benefits

	2014			2013
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	26,193		$	29,205
Interest cost		1,219			1,078
Actuarial loss (gain)		5,974			(3,360	)
Benefit payments		(791	)		(730	)

Benefit obligation at end of year(1)	$	32,595		$	26,193

Change in plan assets:
Fair value of plan assets at beginning of year	$	21,384		$	18,780
Actual (loss) returns on plan assets		1,690			2,736
Employer contributions		1,251			598
Benefit payments		(791	)		(730	)

Fair value of plan assets at end of year	$	23,534		$	21,384

Funded status:
Underfunded status at end of year	$	(9,061	)	$	(4,809	)
Amounts recognized in consolidated balance sheets:
Other long-term liabilities	$	(9,061	)	$	(4,809	)

(1): As of December 31, 2014 and 2013, the accumulated benefit obligation was the same as the projected benefit obligation.

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Components of net periodic benefit cost (recognized in our consolidated statements of income (loss)):
Interest cost	$	1,219		$	1,078		$	1,116
Expected return on plan assets		(1,401	)		(1,210	)		(1,086	)
Recognized net actuarial loss		485			1,123			1,034

Net periodic benefit cost	$	303		$	991		$	1,064

Weighted-average assumptions:
Weighted-average discount rates		4.00	%		4.75	%		3.75	%
Expected long-term rate of return on plan assets		6.00	%		6.50	%		6.50	%

For the years ended December 31, 2014, 2013 and 2012, the net actuarial loss amounts included in other comprehensive income (loss) were approximately ($11.8) million, ($6.6) million and ($12.7) million, respectively.

The amount included in other comprehensive income (loss) that is expected to be recognized as a component of net periodic benefit cost during 2015 is approximately $1.1 million.

100

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 17 Pension, Postretirement and Postemployment Benefits (Continued)

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

The following table sets forth, by level within the fair value hierarchy, the investments in the Pool Pension Plan as of December 31, 2014. The investments' fair value measurement level within the fair value hierarchy is classified in its entirety based on the lowest level of input that is significant to the measurement.

	Fair Value as of December 31, 2014

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:(1)
Cash	$	—	$	745	$	—	$	745
Short-term investments:
Available-for-sale equity securities(2)		—		13,056		—		13,056
Available-for-sale debt securities(3)		—		9,733		—		9,733

Total investments		—		22,789		—		22,789

Total	$	—	$	23,534	$	—	$	23,534

(1): Includes investments in collective trust funds that are valued based on the fair value of the underlying investments using quoted prices in active markets or other significant inputs that are deemed observable.
(2): Includes funds that invest primarily in U.S. common stocks and foreign equity securities.
(3): Includes funds that invest primarily in investment grade debt.

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

Our weighted-average asset allocations as of December 31, 2014 and 2013 by asset category are as follows:

	Pension Benefits

	2014			2013
Cash		3	%		3	%
Equity securities		56	%		56	%
Debt securities		41	%		41	%

Total		100	%		100	%

We invest plan assets based on a total return on investment approach, pursuant to which the plan assets include a diversified blend of investments in equity and debt securities toward a goal of maximizing the long-term rate of return without assuming an unreasonable level of investment risk. We

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Note 17 Pension, Postretirement and Postemployment Benefits (Continued)

determine the level of risk based on an analysis of plan liabilities, the extent to which the value of the plan assets satisfies the plan liabilities and our financial condition. Our investment policy includes target allocations approximating 55% investment in equity securities and 45% investment in debt securities. The equity portion of the plan assets represents growth and value stocks of small, medium and large companies. We measure and monitor the investment risk of the plan assets both on a quarterly basis and annually when we assess plan liabilities.

We expect to contribute approximately $0.9 million to the Pool Pension Plan in 2015. This is based on the sum of (1) the minimum contribution for the 2014 plan year that will be made in 2015 and (2) the estimated minimum required quarterly contributions for the 2015 plan year. We made contributions to the Pool Pension Plan in 2014 and 2013 totaling $1.0 million and $0.6 million, respectively.

As of December 31, 2014, we expect that benefits to be paid in each of the next five years after 2014 and in the aggregate for the five years thereafter will be as follows:

	(In thousands)

2015	$	1,286
2016		1,369
2017		1,495
2018		1,603
2019		1,680
2020 - 2024		9,712

	$	17,145

Some of our employees are covered by defined contribution plans. Our contributions to the plans totaled $29.6 million and $23.1 million during 2014 and 2013, respectively. Nabors does not provide post-employment benefits to its employees, except for employees covered under the Pool Pension Plan.

Note 18 Related-Party Transactions

Nabors and certain current and former key employees, including Mr. Petrello, entered into split-dollar life insurance agreements, pursuant to which we pay a portion of the premiums under life insurance policies with respect to these individuals and, in some instances, members of their families. These agreements provide that we are reimbursed for the premium payments upon the occurrence of specified events, including the death of an insured individual. Any recovery of premiums paid by Nabors could be limited to the cash surrender value of the policies under certain circumstances. As such, the values of these policies are recorded at their respective cash surrender values in our consolidated balance sheets. We have made premium payments to date totaling $6.6 million related to these policies. The cash surrender value of these policies of approximately $6.0 million and $5.9 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2014 and 2013, respectively.

Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors under the agreements could be deemed to be prohibited loans by us to these individuals. Consequently, we have paid no premiums related to our agreements with these individuals since the adoption of the Sarbanes-Oxley Act.

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Note 18 Related-Party Transactions (Continued)

In the ordinary course of business, we enter into various rig leases, rig transportation and related oilfield services agreements with our unconsolidated affiliates at market prices. Revenues from business transactions with these affiliated entities totaled $227.5 million, $190.6 million and $164.0 million for 2014, 2013 and 2012, respectively. Expenses from business transactions with these affiliated entities totaled $0.1 million and $0.1 million for 2013 and 2012, respectively. Additionally, we had accounts receivable from these affiliated entities of $80.7 million and $87.1 million as of December 31, 2014 and 2013, respectively. We had accounts payable to these affiliated entities of $40.0 million and $6.4 million as of December 31, 2014 and 2013, respectively, and long-term payables with these affiliated entities of $0.8 million as of each of those dates, which are included in other long-term liabilities.

In the ordinary course of business, we also provide drilling, well-servicing and other services to LINN Operating, Inc. ("LINN"), a company of which Mr. Linn, an independent member of our Board, is a Director. Revenues from business transactions with LINN totaled $1.1 million and $3.2 million during 2014 and 2013, respectively. We had accounts receivable from LINN of $0.2 million as of December 31, 2013.

In addition, Mr. Crane, an independent director, is Chairman and Chief Executive Officer of Crane Capital Group Inc. ("CCG"), an investment company that indirectly owns a majority interest in several operating companies, some of which have provided services to us in the ordinary course of business, including international logistics and electricity. During 2014 and 2013, we made payments for these services of $89.1 million and $39.4 million, respectively. We had accounts payable to these CCG-related companies of $3.9 million and $1.4 million as of December 31, 2014 and 2013, respectively.

Note 19 Commitments and Contingencies

Commitments

Leases

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

The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2014, were as follows:

	(In thousands)

2015	$	22,740
2016		13,533
2017		9,975
2018		4,221
2019		5,866
Thereafter		40,029

	$	96,364

The above amounts do not include property taxes, insurance or normal maintenance that the lessees are required to pay. Rental expense relating to operating leases with terms greater than 30 days

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Note 19 Commitments and Contingencies (Continued)

amounted to $39.2 million, $40.5 million and $35.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Minimum Volume Commitment

We have contracts with pipeline companies to pay specified fees based on committed volumes for gas transport and processing. Our pipeline contractual commitments as of December 31, 2014 were as follows:

	(In thousands)

2015	$	21,938
2016		10,815
2017		10,928
2018		10,780
2019		6,035
Thereafter(1)		24,084

	$	84,580

(1): Final commitment period is for the period ending October 2029. See Note 5—Assets Held for Sale and Discontinued Operations for additional discussion.

Employment Contracts

We have entered into employment contracts with certain of our employees. Our minimum salary and bonus obligations under these contracts as of December 31, 2014 were as follows:

	(In thousands)

2015	$	6,887
2016		6,437
2017		4,290
2018		1,200
2019		300
Thereafter		—

	$	19,114

During the first quarter of 2013, the Compensation Committee authorized a new employment agreement for Mr. Petrello effective January 1, 2013 that significantly restructured his compensation arrangements. This new employment agreement provides for an initial term of five years, with automatic one-year extensions at the end of each term, subject to a 90-day notice of termination provided within the agreement.

•: The new employment agreement provides for an annual cash bonus targeted at base salary, with a cap of twice that amount, based on the achievement of certain financial and operational performance metrics and defined performance criteria.

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•: The new employment agreement provides for long-term equity incentive awards. Mr. Petrello may receive restricted stock that may or may not vest depending upon the Company's performance relative to a Performance Peer Group (as defined) over a three-year period ("TSR Shares"). The agreement provides that the target number of TSR Shares that will vest is valued at 150% of base salary, with a maximum number of TSR Shares valued at twice that amount.
•: The new employment agreement provides for long-term equity incentive awards in the form of restricted stock based upon the achievement of specific financial or operational objectives ("Performance Shares"). Once earned, Performance Shares are then subject to three-year vesting requirements. Performance Shares are targeted at 200% of base salary, with a maximum award of twice that amount, and are also subject to a minimum threshold before any amount can be earned.
•: In the event of Mr. Petrello's Termination Without Cause (including in the event of a change of control), or his death or disability, either he or his estate would be entitled to receive, within 30 days thereafter, 2.99 times the average of his base salary and annual cash bonus during the three fiscal years preceding the termination.

During 2014, Mr. Petrello's annual compensation package pursuant to his employment agreement included $1.7 million in base salary and $1.7 million in cash bonus. The employment agreement also provides a quarterly deferred bonus of $0.3 million to his account under Nabors' executive deferred compensation plan.

Mr. Petrello is also eligible for awards under Nabors' equity plans, may participate in annual long-term incentive programs and pension and welfare plans on the same basis as other executives, and may receive special bonuses from time to time as determined by the Board.

On December 19, 2014, (1) Mr. Petrello's new employment agreement was amended to provide for a reduction of his annual rate of base salary to $1.53 million per year for an interim period commencing January 1, 2015 and ending on June 30, 2015, and (2) Mr. Restrepo's employment agreement was amended to provide for a reduction of his annual rate of base salary to $585,000 per year for an interim period commencing January 1, 2015 and ending on June 30, 2015. The reduction in base salaries of Messrs. Petrello and Restrepo was implemented as part of an initiative to reduce costs in light of the current industry conditions and does not affect the calculation or payment of any ancillary benefits.

Effective March 3, 2014, we entered into an employment agreement with William Restrepo, our Chief Financial Officer. This employment agreement provides for an initial term through December 2017, with automatic one-year extensions at the end of each term, subject to a 365-day notice of termination provided within the agreement. Mr. Restrepo's annual base salary was set at $0.65 million. In addition, the employment agreement provides for an annual bonus targeted at base salary, with a cap of twice that amount, based on the achievement of one or more annual financial and operational performance goals, as determined by the Compensation Committee of our Board.

Mr. Restrepo's employment agreement also provides for long-term equity incentive awards. Mr. Restrepo will receive awards of restricted stock that may or may not vest depending upon the Company's performance relative to a Performance Peer Group (as defined) over a three-year period ("TSR Shares"). The employment agreement provides that the target number of TSR Shares that will vest is valued at 100% of base salary, with a maximum number of TSR Shares valued at twice that

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amount. In addition, the employment agreement provides for long-term equity incentive awards in the form of restricted stock based upon the achievement of specific financial or operational objectives ("Performance Shares"). Once earned, Performance Shares are then subject to three-year vesting requirements. Performance Shares are targeted at 100% of base salary, with a maximum award of twice that amount, and are also subject to a minimum threshold before any amount can be earned.

As an inducement to join the Company and to make him whole for certain foregone amounts at his prior employer, Mr. Restrepo received an award of restricted stock with a grant-date fair value of $4.9 million. The award vests over four years.

Mr. Restrepo's employment agreement provides for severance payments in the event the agreement is terminated, including in connection with a change in control (as defined in the employment agreement), (i) by the Company prior to the expiration date of the agreement for any reason other than for cause, or (ii) by Mr. Restrepo for constructive termination without cause, each as defined in the employment agreement. Mr. Restrepo would have the right to receive within 30 days of a termination without cause or constructive termination without cause, 2.99 times the sum of the average of his base salary and annual bonus during the three fiscal years preceding the termination (or, if employed less than three completed fiscal years, his then-current base salary and target annual bonus would be used for the years not employed).

Mr. Restrepo's employment agreement also provides that, upon death, disability, termination without cause, or constructive termination without cause, he would receive (a) any unvested stock options and restricted stock outstanding (except for TSR Shares), which will immediately and fully vest; (b) any amounts earned, accrued or owing to him but not yet paid (including executive benefits, life insurance, disability benefits and reimbursement of expenses and perquisites); (c) continued participation in medical, dental and life insurance coverage; and (d) certain perquisites and other or additional benefits in accordance with applicable plans and programs of Nabors. In addition, under the employment agreement, any unvested TSR Shares at the time of termination for these reasons will vest at target levels.

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

Contingencies

Income Tax Contingencies

Income tax returns that we file are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries, if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially.

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Note 19 Commitments and Contingencies (Continued)

We have received an assessment from the Mexican federal tax authority in connection with 2007. The assessment was related to the denial of depreciation expense deductions related to drilling rigs. Similar deductions were taken in 2008 - 2010. Although Nabors and its tax advisors believe these deductions continue to be defendable, a partial reserve has been recorded. The total amounts assessed or expected to be assessed range from $30 million to $35 million. The Mexican Supreme Court recently reached an unfavorable decision related to depreciation for another taxpayer. We have not changed our position to defend this issue, as we are confident that we will prevail in court. If we ultimately do not prevail, we would be required to recognize additional tax for any amount in excess of the current reserve.

Self-Insurance

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

We self-insure for certain losses relating to workers' compensation, employers' liability, general liability, automobile liability and property damage. Effective April 1, 2014, some of our workers' compensation claims, employers' liability and marine employers' liability claims are subject to a $3.0 million per-occurrence deductible; additionally, some of our automobile liability claims are subject to a $2.5 million deductible. General liability claims remain subject to a $5.0 million per-occurrence deductible.

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

Political risk insurance is procured for select operations in South America, Africa, the Middle East and Asia. Losses are subject to a $0.25 million deductible, except for Colombia, which is subject to a $0.5 million deductible. There is no assurance that such coverage will adequately protect Nabors against liability from all potential consequences.

As of December 31, 2014 and 2013, our self-insurance accruals totaled $198.1 million and $181.7 million, respectively, and our related insurance recoveries/receivables were $39.9 million and $44.7 million, respectively.

Litigation

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Note 19 Commitments and Contingencies (Continued)

As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ from our estimates. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure. In the opinion of management and based on liability accruals provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our consolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particular reporting period.

In 2009, the Court of Ouargla entered a judgment of approximately $16.4 million (at current exchange rates) against us relating to alleged customs infractions in Algeria. We believe we did not receive proper notice of the judicial proceedings, and that the amount of the judgment was excessive in any case. We asserted the lack of legally required notice as a basis for challenging the judgment on appeal to the Algeria Supreme Court. In May 2012, that court reversed the lower court and remanded the case to the Ouargla Court of Appeals for treatment consistent with the Supreme Court's ruling. In January 2013, the Ouargla Court of Appeals reinstated the judgment. We have again lodged an appeal to the Algeria Supreme Court, asserting the same challenges as before. Based upon our understanding of applicable law and precedent, we continue to believe that we will prevail. Although the appeal remains ongoing at this time, the Hassi Messaoud customs office recently initiated efforts to collect the judgment prior to the Supreme Court's decision in the case. As a result, we paid approximately $3.1 million and posted security of approximately $1.33 million to suspend those collection efforts and to enter into a formal negotiations process with the customs authority. We have recorded a reserve in the amount of the posted security. Algerian Customs have recently demanded 50% of the total fine as a final settlement which would require an additional payment of approximately $4.425 million. We have elected to await the ruling from the Supreme Court. The matter was heard on February 26, 2015, and a decision will be issued on March 26, 2015. If we are ultimately required to pay a fine or judgment related to this matter, the resulting loss could be up to $12.0 million in excess of amounts accrued.

In March 2011, the Court of Ouargla entered a judgment of approximately $32.2 million (at current exchange rates) against us relating to alleged violations of Algeria's foreign currency exchange controls, which require that goods and services provided locally be invoiced and paid in local currency. The case relates to certain foreign currency payments made to us by CEPSA, a Spanish operator, for wells drilled in 2006. Approximately $7.5 million of the total contract amount was paid offshore in foreign currency, and approximately $3.2 million was paid in local currency. The judgment includes fines and penalties of approximately four times the amount at issue. We have appealed the ruling based on our understanding that the law in question applies only to resident entities incorporated under Algerian law. An intermediate court of appeals upheld the lower court's ruling, and we appealed the matter to the Algeria Supreme Court. On September 25, 2014, the Supreme Court of Algeria overturned the verdict against us, and the case will now be reheard by the Court of Appeal Ouargla in light of the Algeria Supreme Court's opinion. The rehearing has been set for March 8, 2015. While our payments were consistent with our historical operations in the country, and, we believe, those of other multinational corporations there, as well as interpretations of the law by the Central Bank of Algeria, the ultimate resolution of this matter could result in a loss of up to $24.2 million in excess of amounts accrued.

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Note 19 Commitments and Contingencies (Continued)

In 2012, Nabors Global Holdings II Limited ("NGH2L") signed a contract with ERG Resources, LLC ("ERG") relating to the sale of all of the Class A shares of NGH2L's wholly owned subsidiary, Ramshorn International Limited, an oil and gas exploration company. When ERG failed to meet its closing obligations, NGH2L terminated the transaction on March 19, 2012 and, as contemplated in the agreement, retained ERG's $3.0 million escrow deposit. ERG filed suit the following day in the 61st Judicial District Court of Harris County, Texas, in a case styled ERG Resources, LLC v. Nabors Global Holdings II Limited, Ramshorn International Limited, and Parex Resources, Inc.; Cause No. 2012-16446, seeking injunctive relief to halt any sale of the shares to a third party, specifically naming as defendant Parex Resources, Inc. ("Parex"). The lawsuit also seeks monetary damages of up to $750.0 million based on an alleged breach of contract by NGH2L and alleged tortious interference with contractual relations by Parex. Nabors successfully defeated ERG's effort to obtain a temporary restraining order from the Texas court on March 20, 2012. Nabors completed the sale of Ramshorn's Class A shares to a Parex affiliate in April 2012, which mooted ERG's application for a temporary injunction. The lawsuit is staid, pending further court actions, including appeals of the jurisdictional decisions. ERG retains its causes of action for monetary damages, but Nabors believes the claims are foreclosed by the terms of the agreement and are without factual or legal merit. Although we are vigorously defending the lawsuit, its ultimate outcome cannot be determined at this time.

On July 30, 2014, Nabors and Red Lion, along with CJES and its board of directors, were sued in a putative shareholder class action filed in the Court of Chancery of the State of Delaware (the "Court of Chancery"). The plaintiff alleges that the members of the CJES board of directors breached their fiduciary duties in connection with the Merger, and that Nabors Red Lion and CJES aided and abetted these alleged breaches. The plaintiff seeks to enjoin the defendants from proceeding with or consummating the Merger and the CJES stockholder meeting for approval of the Merger and, to the extent that the Merger is completed before any relief is granted, to have the Merger rescinded. On November 10, 2014, the plaintiff filed a motion for a preliminary injunction, and, on November 24, 2014, the Court of Chancery entered a bench ruling, followed by a written order on November 25, 2014, that (i) ordered certain members of the CJES board of directors to solicit for a 30 day period alternative proposals to purchase CJES (or a controlling stake in CJES) that are superior to the Merger, and (ii) preliminarily enjoined CJES from holding its stockholder meeting until it complied with the foregoing. CJES complied with the order while it simultaneously pursued an expedited appeal of the Court of Chancery's order to the Supreme Court of the State of Delaware (the "Delaware Supreme Court"). On December 19, 2014, the Delaware Supreme Court overturned the Court of Chancery's judgment and vacated the order.

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Off-Balance Sheet Arrangements (Including Guarantees)

Management believes the likelihood that we would be required to perform or otherwise incur any material losses associated with any of these guarantees is remote. The following table summarizes the total maximum amount of financial guarantees issued by Nabors:

	Maximum Amount

	2015		2016		2017		Thereafter		Total
	(In thousands)
Financial standby letters of credit and other financial surety instruments	$	191,015		75		18		—	$	191,108

Note 20 Earnings (Losses) Per Share

ASC 260, Earnings per Share, requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividends or dividend equivalents as a separate class of securities in calculating earnings (losses) per share. We have granted and expect to continue to grant to employees restricted stock grants that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260. As such, we are required to include these grants in the calculation of our basic earnings (losses) per share and calculate basic earnings (losses) per share using the two-class method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared and participation rights in undistributed earnings.

Basic earnings (losses) per share is computed utilizing the two-class method and is calculated based on the weighted-average number of common shares outstanding during the periods presented.

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Note 20 Earnings (Losses) Per Share (Continued)

Diluted earnings (losses) per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options and unvested restricted stock.

	Year Ended December 31,

	2014			2013			2012
	(In thousands, except per share amounts)
BASIC EPS:
Net income (loss) (numerator):
Income (loss) from continuing operations, net of tax	$	(669,265	)	$	158,341		$	232,974
Less: net (income) loss attributable to noncontrolling interest		(1,415	)		(7,180	)		(621	)
Less: loss on redemption of subsidiary preferred stock		(1,688	)		—			—
Less: (earnings) losses allocated to unvested shareholders		10,595			(1,277	)		—

Numerator for basic earnings per share:
Adjusted income (loss) from continuing operations	$	(661,773	)	$	149,884		$	232,353

Income (loss) from discontinued operations	$	21		$	(11,179	)	$	(67,526	)

Weighted-average number of shares outstanding—basic		290,694			294,182			289,965
Earnings (losses) per share:
Basic from continuing operations	$	(2.28	)	$	0.51		$	0.80
Basic from discontinued operations		—			(0.04	)		(0.23	)

Total Basic	$	(2.28	)	$	0.47		$	0.57

DILUTED EPS:
Income (loss) from continuing operations attributed to common shareholders	$	(661,773	)	$	149,884		$	232,353
Add: effect of reallocating undistributed earnings of unvested shareholders		—			—			—

Adjusted income (loss) from continuing operations attributed to common shareholders	$	(661,773	)	$	149,884		$	232,353

Income (loss) from discontinued operations	$	21		$	(11,179	)	$	(67,526	)

Weighted-average number of shares outstanding—basic		290,694			294,182			289,965
Add: dilutive effect of potential common shares		—			2,410			2,358

Weighted-average number of diluted shares outstanding		290,694			296,592			292,323
Earnings (losses) per share:
Diluted from continuing operations	$	(2.28	)	$	0.51		$	0.79
Diluted from discontinued operations		—			(0.04	)		(0.23	)

Total Diluted	$	(2.28	)	$	0.47		$	0.56

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Note 20 Earnings (Losses) Per Share (Continued)

For all periods presented, the computation of diluted earnings (losses) per Nabors' share excludes outstanding stock options with exercise prices greater than the average market price of Nabors' common shares, because their inclusion would be anti-dilutive and because they are not considered participating securities. The average number of options that were excluded from diluted earnings (losses) per share that would potentially dilute earnings per share in the future was 12,950,249, 11,642,417 and 14,200,915 shares during 2014, 2013 and 2012, respectively. In any period during which the average market price of Nabors' common shares exceeds the exercise prices of these stock options, such stock options will be included in our diluted earnings (losses) per share computation using the if-converted method of accounting. Restricted stock is included in our basic and diluted earnings (losses) per share computation using the two-class method of accounting in all periods because such stock is considered participating securities.

Note 21 Supplemental Balance Sheet, Income Statement and Cash Flow Information

Accrued liabilities include the following:

	December 31,

	2014		2013
	(In thousands)
Accrued compensation	$	177,707	$	172,803
Deferred revenue		298,345		202,918
Other taxes payable		58,445		76,781
Workers' compensation liabilities		37,459		29,459
Interest payable		63,532		64,728
Warranty accrual		5,799		4,653
Litigation reserves		23,681		30,784
Current liability to discontinued operations		19,602		64,404
Professional fees		2,550		2,971
Current deferred tax liability		3,677		3,075
Current liability to acquisition of KVS		22,278		22,033
Other accrued liabilities		14,929		22,484

	$	728,004	$	697,093

Investment income (loss) includes the following:

	Year Ended December 31,

	2014		2013			2012
	(In thousands)
Interest and dividend income	$	6,267	$	5,120		$	7,536
Gains (losses) on investments, net		5,564		91,457	(1)		55,601	(2)

	$	11,831	$	96,577		$	63,137

(1): Includes net gains of $2.5 million from our trading securities and $89.0 million realized gains from short-term and other long-term investments.

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Note 21 Supplemental Balance Sheet, Income Statement and Cash Flow Information (Continued)

(2): Includes net unrealized gains of $41.1 million from our trading securities and $14.5 million realized gains from short-term and other long-term investments.

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

	Year Ended December 31,

	2014			2013		2012
	(In thousands)
Losses (gains) on sales, disposals and involuntary conversions of long-lived assets	$	(8,830	)	$	13,624	$	(147,522	)(1)
Litigation expenses		8,880			11,684		5,382
Foreign currency transaction losses (gains)		1,019			6,219		4,787
Losses on debt buybacks		5,576			3,785		—
Other losses (gains)		2,428			2,665		717

	$	9,073		$	37,977	$	(136,636	)

(1): Includes a $160 million gain from the sale of our equity interest in our U.S. unconsolidated oil and gas joint venture.

The changes in accumulated other comprehensive income (loss), by component, include the following:

	Gains (losses) on cash flow hedges			Unrealized gains (losses) on available- for-sale securities			Defined benefit pension plan items			Foreign currency items			Total

	(In thousands(a))
As of January 1, 2013	$	(2,793	)	$	134,229		$	(7,632	)	$	216,339		$	340,143

Other comprehensive income (loss) before reclassifications		—			22,968			2,950			(65,447	)		(39,529	)
Amounts reclassified from accumulated other comprehensive income (loss)		374			(85,455	)		607			—			(84,474	)

Net other comprehensive income (loss)		374			(62,487	)		3,557			(65,447	)		(124,003	)

As of December 31, 2013	$	(2,419	)	$	71,742		$	(4,075	)	$	150,892		$	216,140

(a): All amounts are net of tax. Amounts in parentheses indicate debits.

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Note 21 Supplemental Balance Sheet, Income Statement and Cash Flow Information (Continued)

	Gains (losses) on cash flow hedges			Unrealized gains (losses) on available- for-sale securities			Defined benefit pension plan items			Foreign currency items			Total

	(In thousands(a))
As of January 1, 2014	$	(2,419	)	$	71,742		$	(4,075	)	$	150,892		$	216,140

Other comprehensive income (loss) before reclassifications		—			(59,991	)		(3,374	)		(79,059	)		(142,424	)
Amounts reclassified from accumulated other comprehensive income (loss)		375			3,245			186			—			3,806

Net other comprehensive income (loss)		375			(56,746	)		(3,188	)		(79,059	)		(138,618	)

As of December 31, 2014	$	(2,044	)	$	14,996		$	(7,263	)	$	71,833		$	77,522

(a): All amounts are net of tax. Amounts in parentheses indicate debits.

The line items that were reclassified to net income include the following:

	Year Ended December 31,

Line item in consolidated statement of income (loss)	2014			2013		2012
	(In thousands)
Investment income (loss)	$	4,635		$	88,158	$	13,405
Impairments and other charges		6,972			—		—
Interest expense		614			613		702
General and administrative expenses(1)		303			991		1,063

Total before tax		(3,254	)		86,554		11,640
Tax expense (benefit)		552			2,080		3,695

Reclassification adjustment for (gains)/losses included in net income (loss)	$	(3,806	)	$	84,474	$	7,945

(1): See Pension Footnote for computations of net periodic pension cost.

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Note 21 Supplemental Balance Sheet, Income Statement and Cash Flow Information (Continued)

Supplemental cash flow information includes the following:

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Cash paid for income taxes	$	166,660		$	100,749		$	85,044

Cash paid for interest, net of capitalized interest	$	164,928		$	239,637		$	250,045

Acquisitions of businesses:
Fair value of assets acquired	$	59,195		$	140,740		$	—
Goodwill		18,818			51,318			—
Liabilities assumed		(2,796	)		(8,232	)		—
Future consideration payments (fair value)		(2,457	)		(64,174	)		—

Cash paid for acquisitions of businesses		72,760			119,652			—
Cash acquired in acquisitions of businesses		(226	)		(2,681	)		—

Cash paid for acquisitions of businesses, net	$	72,534		$	116,971		$	—

Note 22 Unaudited Quarterly Financial Information

	Year Ended December 31, 2014

	Quarter Ended
	March 31			June 30			September 30			December 31
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(1)	$	1,587,173		$	1,616,405		$	1,810,911		$	1,783,407

Income (loss) from continuing operations, net of tax	$	48,977		$	65,729		$	102,430		$	(886,401	)
Income (loss) from discontinued operations, net of tax		1,515			(1,032	)		4,005			(4,467	)
Less: Net (income) loss attributable to noncontrolling interest		(573	)		(253	)		(387	)		(202	)

Net income (loss) attributable to Nabors	$	49,919		$	64,444		$	106,048		$	(891,070	)

Earnings (losses) per share:(2)
Basic from continuing operations	$	0.16		$	0.21		$	0.34		$	(3.06	)
Basic from discontinued operations		0.01			—			0.02			(0.02	)

Total Basic	$	0.17		$	0.21		$	0.36		$	(3.08	)

Diluted from continuing operations	$	0.16		$	0.21		$	0.34		$	(3.06	)
Diluted from discontinued operations		—			—			0.01			(0.02	)

Total Diluted	$	0.16		$	0.21		$	0.35		$	(3.08	)

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Note 22 Unaudited Quarterly Financial Information (Continued)

	Year Ended December 31, 2013

	Quarter Ended
	March 31			June 30			September 30			December 31
	(In thousands, except per share amounts)
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations(3)	$	1,538,373		$	1,459,326		$	1,548,965		$	1,605,390

Income (loss) from continuing operations, net of tax	$	92,207		$	28,128		$	(90,510	)	$	128,516
Income (loss) from discontinued operations, net of tax		7,011			(26,873	)		(14,430	)		23,113
Less: Net (income) loss attributable to noncontrolling interest		(97	)		(5,616	)		(441	)		(1,026	)

Net income (loss) attributable to Nabors	$	99,121		$	(4,361	)	$	(105,381	)	$	150,603

Earnings (losses) per share:(2)
Basic from continuing operations	$	0.31		$	0.08		$	(0.30	)	$	0.43
Basic from discontinued operations		0.03			(0.09	)		(0.05	)		0.07

Total Basic	$	0.34		$	(0.01	)	$	(0.35	)	$	0.50

Diluted from continuing operations	$	0.31		$	0.08		$	(0.30	)	$	0.42
Diluted from discontinued operations		0.02			(0.09	)		(0.05	)		0.08

Total Diluted	$	0.33		$	(0.01	)	$	(0.35	)	$	0.50

(1): Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of ($2.4) million, ($0.6) million, ($2.9) million and ($0.4) million, respectively.
(2): Earnings per share is computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the total computed for the year.
(3): Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $2.9 million, $1.4 million, ($2.6) million and ($1.6) million, respectively.

Note 23 Segment Information

At December 31, 2014, we conducted our operations through two business lines:

•: Drilling & Rig Services

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

•: Completion & Production Services

The accounting policies of the segments are the same as those described in Note 3—Summary of Significant Accounting Policies. Inter-segment sales are recorded at cost or cost plus a profit margin. We evaluate the performance of our segments based on several criteria, including adjusted income (loss) derived from operating activities.

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Note 23 Segment Information (Continued)

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

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates:(1)
Drilling & Rig Services:
U.S.	$	2,159,968		$	1,914,786		$	2,276,808
Canada		335,192			361,676			429,411
International		1,623,102			1,464,264			1,265,060
Rig Services(2)		687,302			516,004			688,310

Subtotal drilling and rig services(3)		4,805,564			4,256,730			4,659,589
Completion & Production Services:
Completion Services		1,218,361			1,074,713			1,462,767
Production Services		1,033,538			1,009,214			1,000,873

Subtotal completion and production services(4)		2,251,899			2,083,927			2,463,640
Other reconciling items(5)		(259,567	)		(188,603	)		(568,896	)

Total	$	6,797,896		$	6,152,054		$	6,554,333

Adjusted income (loss) derived from operating activities:(1)(6)
Drilling & Rig Services:
U.S.		370,173			315,496			509,894
Canada		52,468			61,193			91,360
International		242,818			177,833			91,226
Rig Services(2)		47,768			(3,918	)		67,366

Subtotal drilling and rig services(3)		713,227			550,604			759,846
Completion & Production Services:
Completion Services		(15,078	)		51,722			188,518
Production Services		93,414			102,130			108,835

Subtotal completion and production services(4)		78,336			153,852			297,353
Other reconciling items(7)		(193,565	)		(146,237	)		(148,649	)

Total adjusted income (loss) derived from operating activities		597,998			558,219			908,550

U.S. oil and gas joint venture earnings (losses)		—			—			(289,199	)
Interest expense		(177,948	)		(223,418	)		(251,904	)
Investment income (loss)		11,831			96,577			63,137
Gains (losses) on sales and disposals of long-lived assets and other income (expense), net		(9,073	)		(37,977	)		136,636
Impairments and other charges		(1,027,423	)		(287,241	)		(290,260	)

Income (loss) from continuing operations before income taxes		(604,615	)		106,160			276,960
Income tax expense (benefit)		62,666			(55,181	)		40,986
Subsidiary preferred stock dividend		1,984			3,000			3,000

Income (loss) from continuing operations, net of tax		(669,265	)		158,341			232,974
Income (loss) from discontinued operations, net of tax		21			(11,179	)		(67,526	)

Net income (loss)		(669,244	)		147,162			165,448
Less: Net (income) loss attributable to noncontrolling interest		(1,415	)		(7,180	)		(621	)

Net income (loss) attributable to Nabors	$	(670,659	)	$	139,982		$	164,827

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Note 23 Segment Information (Continued)

	Year Ended December 31,

	2014			2013			2012
	(In thousands)
Depreciation and amortization(1)
Drilling & Rig Services:
U.S.		465,506			440,210			406,740
Canada		55,986			57,796			59,191
International		367,345			346,659			330,388
Rig Services(2)		33,559			32,029			29,617

Subtotal drilling and rig services		922,396			876,694			825,936
Completion & Production Services:
Completion Services		109,917			109,242			112,401
Production Services		114,505			103,502			104,201

Subtotal completion and production services		224,422			212,744			216,602
Other reconciling items(7)		(1,718	)		(2,761	)		(2,615	)

Total depreciation and amortization	$	1,145,100		$	1,086,677		$	1,039,923

	Year Ended December 31,

	2014			2013		2012
	(In thousands)
Capital expenditures and acquisitions of businesses:(9)
Drilling & Rig Services:
U.S.		839,536			644,792		758,555
Canada		49,317			59,386		78,729
International		788,748			248,980		265,249
Rig Services(2)		103,491			70,831		39,923

Subtotal drilling and rig services		1,781,092			1,023,989		1,142,456
Completion & Production Services(8)		156,106			325,449		238,300
Other reconciling items(7)		(13,419	)		16,556		52,830

Total capital expenditures and acquisitions of businesses	$	1,923,779		$	1,365,994	$	1,433,586

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Note 23 Segment Information (Continued)

	Year Ended December 31,

	2014		2013
	(In thousands)
Total assets:
Drilling & Rig Services:
U.S.		4,184,854		4,248,630
Canada		615,269		608,018
International		3,815,051		3,584,339
Rig Services		549,622		474,275

Subtotal drilling and rig services(10)		9,164,796		8,915,262
Completion & Production Services(8)(11)		1,933,387		2,394,865
Other reconciling items(7)(12)		781,759		849,684

Total assets	$	11,879,942	$	12,159,811

(1): All periods present the operating activities of most of our wholly owned oil and gas businesses, our previously held equity interests in oil and gas joint ventures in Canada and Colombia, aircraft logistics operations and construction services as discontinued operations.
(2): Includes our other services comprised of our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software services.
(3): Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of ($6.8) million and ($0.4) million for the years ended December 31, 2014 and 2013, respectively.
(4): Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $0.5 million, $0.4 million and $0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
(5): Represents the elimination of inter-segment transactions and earnings (losses), net from the U.S. unconsolidated oil and gas joint venture, accounted for using the equity method until sold in December 2012, of ($289.2) million for the year ended December 31, 2012.
(6): Adjusted income (loss) derived from operating activities is computed by subtracting the sum of direct costs, general and administrative expenses, depreciation and amortization from the sum of Operating revenues and Earnings (losses) from unconsolidated affiliates. Adjusted income is a non-GAAP measure and should not be used in isolation as a substitute for the amounts reported in accordance with GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income (loss) derived from operating activities, because it believes that these financial measures accurately reflect our ongoing profitability. A reconciliation of this non-GAAP measure to income (loss) from continuing operations before income taxes, which is a GAAP measure, is provided in the above table.
(7): Represents the elimination of inter-segment transactions and unallocated corporate expenses, assets and capital expenditures.
(8): Reflects assets allocated to the line of business to conduct its operations. Further allocation to individual operating segments of Completion & Production Services is not available.

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Note 23 Segment Information (Continued)

(9): Includes the total purchase price of acquisitions.
(10): Includes $48.1 million and $57.0 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2014 and 2013, respectively.
(11): Includes $10.2 million and $7.4 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2014 and 2013, respectively.
(12): Includes assets of $146.5 million and $239.9 million from oil and gas businesses classified as assets held-for-sale as of December 31, 2014 and 2013, respectively.

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

	Year Ended December 31,

	2014		2013		2012
	(In thousands)
Operating revenues and Earnings (losses) from unconsolidated affiliates:
U.S.	$	4,695,977	$	4,146,125	$	4,625,614
Outside the U.S.		2,101,919		2,005,929		1,928,719

	$	6,797,896	$	6,152,054	$	6,554,333

Property, plant and equipment, net:
U.S.	$	5,205,296	$	5,474,746	$	5,179,578
Outside the U.S.		3,393,829		3,123,067		3,532,510

	$	8,599,125	$	8,597,813	$	8,712,088

Goodwill:
U.S.	$	146,310	$	498,149	$	456,463
Outside the U.S.		27,618		14,815		15,863

	$	173,928	$	512,964	$	472,326

Note 24 Condensed Consolidating Financial Information

Nabors has fully and unconditionally guaranteed all of the issued public debt securities of Nabors Delaware. The following condensed consolidating financial information is included so that separate financial statements of Nabors Delaware is not required to be filed with the SEC. The condensed consolidating financial statements present investments in both consolidated and unconsolidated affiliates using the equity method of accounting.

The following condensed consolidating financial information presents condensed consolidating balance sheets as of December 31, 2014 and 2013, and statements of income (loss), statements of other comprehensive income (loss) and the statements of cash flows for the years ended December 31, 2014, 2013 and 2012 of (a) Nabors, parent/guarantor, (b) Nabors Delaware, issuer of public debt securities guaranteed by Nabors, (c) the non-guarantor subsidiaries, (d) consolidating adjustments necessary to consolidate Nabors and its subsidiaries and (e) Nabors on a consolidated basis.

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Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Balance Sheets

	December 31, 2014

	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
	ASSETS
Current assets:
Cash and cash equivalents	$	1,170	$	7		$	499,972		$	—		$	501,149
Short-term investments		—		—			35,020			—			35,020
Assets held for sale		��		—			146,467			—			146,467
Accounts receivable, net		—		—			1,517,503			—			1,517,503
Inventory		—		—			230,067			—			230,067
Deferred income taxes		—		—			118,230			—			118,230
Other current assets		50		5,242			188,146			—			193,438
Short-term intercompany note		—		880,820			—			(880,820	)		—

Total current assets		1,220		886,069			2,735,405			(880,820	)		2,741,874
Long-term investments		—		—			2,806			—			2,806
Property, plant and equipment, net		—		30,330			8,568,795			—			8,599,125
Goodwill		—		—			173,928			—			173,928
Intercompany receivables		136,360		—			1,286,522			(1,422,882	)		—
Investment in unconsolidated affiliates		4,771,413		5,014,743			1,506,939			(11,234,844	)		58,251
Other long-term assets		—		30,298			273,660			—			303,958

Total assets	$	4,908,993	$	5,961,440		$	14,548,055		$	(13,538,546	)	$	11,879,942

		LIABILITIES AND EQUITY
Current liabilities:
Current debt	$	—	$	—		$	6,190		$	—		$	6,190
Trade accounts payable		111		2			779,947			—			780,060
Accrued liabilities		263		64,390			663,351			—			728,004
Income taxes payable		—		—			53,221			—			53,221
Short-term intercompany note		—		—			880,820			(880,820	)		—

Total current liabilities		374		64,392			2,383,529			(880,820	)		1,567,475
Long-term debt		—		4,389,299			(40,440	)		—			4,348,859
Other long-term liabilities		—		35,480			566,336			—			601,816
Deferred income taxes		—		(294,655	)		737,658			—			443,003
Intercompany payable		—		1,422,882			—			(1,422,882	)		—

Total liabilities		374		5,617,398			3,647,083			(2,303,702	)		6,961,153
Subsidiary preferred stock		—		—			—			—			—
Shareholders' equity		4,908,619		344,042			10,890,802			(11,234,844	)		4,908,619
Noncontrolling interest		—		—			10,170			—			10,170

Total equity		4,908,619		344,042			10,900,972			(11,234,844	)		4,918,789

Total liabilities and equity	$	4,908,993	$	5,961,440		$	14,548,055		$	(13,538,546	)	$	11,879,942

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Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Balance Sheets

	December 31, 2013

	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments			Total
	(In thousands)
	ASSETS
Current assets:
Cash and cash equivalents	$	730	$	7,029		$	382,156	$	—		$	389,915
Short-term investments		—		—			117,218		—			117,218
Assets held for sale		—		—			243,264		—			243,264
Accounts receivable, net		27		—			1,399,516		—			1,399,543
Inventory		—		—			209,793		—			209,793
Deferred income taxes		—		—			121,316		—			121,316
Other current assets		50		26,378			246,353		—			272,781

Total current assets		807		33,407			2,719,616		—			2,753,830
Long-term investments		—		—			3,236		—			3,236
Property, plant and equipment, net		—		33,815			8,563,998		—			8,597,813
Goodwill		—		—			512,964		—			512,964
Intercompany receivables		160,136		3,891			1,583,539		(1,747,566	)		—
Investment in unconsolidated affiliates		5,808,606		6,097,337			1,854,111		(13,695,794	)		64,260
Other long-term assets		—		34,487			193,221		—			227,708

Total assets	$	5,969,549	$	6,202,937		$	15,430,685	$	(15,443,360	)	$	12,159,811

		LIABILITIES AND EQUITY
Current liabilities:
Current debt	$	—	$	—		$	10,185	$	—		$	10,185
Trade accounts payable		86		25			545,401		—			545,512
Accrued liabilities		378		65,947			630,768		—			697,093
Income taxes payable		—		—			58,634		—			58,634

Total current liabilities		464		65,972			1,244,988		—			1,311,424
Long-term debt		—		3,904,059			58		—			3,904,117
Other long-term liabilities		—		31,071			346,673		—			377,744
Deferred income taxes		—		(213,233	)		729,394		—			516,161
Intercompany payable		—		1,747,566			—		(1,747,566	)		—

Total liabilities		464		5,535,435			2,321,113		(1,747,566	)		6,109,446
Subsidiary preferred stock		—		—			69,188		—			69,188
Shareholders' equity		5,969,085		667,502			13,028,293		(13,695,794	)		5,969,086
Noncontrolling interest		—		—			12,091		—			12,091

Total equity		5,969,085		667,502			13,040,384		(13,695,794	)		5,981,177

Total liabilities and equity	$	5,969,549	$	6,202,937		$	15,430,685	$	(15,443,360	)	$	12,159,811

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Income (Loss)

	Year Ended December 31, 2014

	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—		$	—		$	6,804,197		$	—		$	6,804,197
Earnings from unconsolidated affiliates		—			—			(6,301	)		—			(6,301	)
Earnings (losses) from consolidated affiliates		(653,124	)		(120,996	)		(250,365	)		1,024,485			—
Investment income (loss)		—			1,869			16,265			(6,303	)		11,831
Intercompany interest income		—			2,415			336			(2,751	)		—

Total revenues and other income		(653,124	)		(116,712	)		6,564,132			1,015,431			6,809,727

Costs and other deductions:
Direct costs		—			—			4,505,064			—			4,505,064
General and administrative expenses		9,531			8,001			532,789			(587	)		549,734
Depreciation and amortization		—			3,608			1,141,492			—			1,145,100
Interest expense		—			198,246			(20,298	)		—			177,948
Losses (gains) on sales and disposals of long-lived assets and other expense (income), net		7,668			(223	)		1,041			587			9,073
Impairments and other charges		—			—			1,027,423			—			1,027,423
Intercompany interest expense		336			—			2,415			(2,751	)		—

Total costs and other deductions		17,535			209,632			7,189,926			(2,751	)		7,414,342

Income from continuing operations before income taxes		(670,659	)		(326,344	)		(625,794	)		1,018,182			(604,615	)
Income tax expense (benefit)		—			(75,979	)		138,645			—			62,666
Subsidiary preferred stock dividend		—			—			1,984			—			1,984

Income (loss) from continuing operations, net of tax		(670,659	)		(250,365	)		(766,423	)		1,018,182			(669,265	)
Income (loss) from discontinued operations, net of tax		—			—			21			—			21

Net income (loss)		(670,659	)		(250,365	)		(766,402	)		1,018,182			(669,244	)
Less: Net (income) loss attributable to noncontrolling interest		—			—			(1,415	)		—			(1,415	)

Net income (loss) attributable to Nabors	$	(670,659	)	$	(250,365	)	$	(767,817	)	$	1,018,182		$	(670,659	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Income (Loss)

	Year Ended December 31, 2013

	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—	$	—		$	6,152,015		$	—		$	6,152,015
Earnings from unconsolidated affiliates		—		—			39			—			39
Earnings (losses) from consolidated affiliates		158,445		191,821			(92,137	)		(258,129	)		—
Investment income (loss)		1		75			101,047			(4,546	)		96,577
Intercompany interest income		—		92			—			(92	)		—

Total revenues and other income		158,446		191,988			6,160,964			(262,767	)		6,248,631

Costs and other deductions:
Direct costs		—		—			3,981,828			—			3,981,828
General and administrative expenses		11,111		796			514,000			(577	)		525,330
Depreciation and amortization		—		3,610			1,083,067			—			1,086,677
Interest expense		—		234,512			(11,094	)		—			223,418
Losses (gains) on sales and disposals of long-lived assets and other expense (income), net		7,353		211,976			(181,929	)		577			37,977
Impairments and other charges		—		—			287,241			—			287,241
Intercompany interest espense		—		—			92			(92	)		—

Total costs and other deductions		18,464		450,894			5,673,205			(92	)		6,142,471

Income from continuing operations before income taxes		139,982		(258,906	)		487,759			(262,675	)		106,160
Income tax expense (benefit)		—		(166,769	)		111,588			—			(55,181	)
Subsidiary preferred stock dividend		—		—			3,000			—			3,000

Income (loss) from continuing operations, net of tax		139,982		(92,137	)		373,171			(262,675	)		158,341
Income (loss) from discontinued operations, net of tax		—		—			(11,179	)		—			(11,179	)

Net income (loss)		139,982		(92,137	)		361,992			(262,675	)		147,162
Less: Net (income) loss attributable to noncontrolling interest		—		—			(7,180	)		—			(7,180	)

Net income (loss) attributable to Nabors	$	139,982	$	(92,137	)	$	354,812		$	(262,675	)	$	139,982

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Income (Loss)

	Year Ended December 31, 2012

	Nabors (Parent/ Guarantor)		Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Revenues and other income:
Operating revenues	$	—	$	—		$	6,843,051		$	—		$	6,843,051
Earnings from unconsolidated affiliates		—		—			(288,718	)		—			(288,718	)
Earnings (losses) from consolidated affiliates		173,199		(99,048	)		(206,413	)		132,262			—
Investment income (loss)		—		43			63,094			—			63,137
Intercompany interest income		—		69,145			—			(69,145	)		—

Total revenues and other income		173,199		(29,860	)		6,411,014			63,117			6,617,470

Costs and other deductions:
Direct costs		—		—			4,367,106			—			4,367,106
General and administrative expenses		7,141		458			521,962			(1,608	)		527,953
Depreciation and amortization		—		3,610			1,036,313			—			1,039,923
Interest expense		—		268,904			(17,000	)		—			251,904
Losses (gains) on sales and disposals of long-lived assets and other expense (income), net		1,231		(2,451	)		(137,024	)		1,608			(136,636	)
Impairments and other charges		—		—			290,260			—			290,260
Intercompany interest expense		—		—			69,145			(69,145	)		—

Total costs and other deductions		8,372		270,521			6,130,762			(69,145	)		6,340,510

Income from continuing operations before income taxes		164,827		(300,381	)		280,252			132,262			276,960
Income tax expense (benefit)		—		(74,493	)		115,479			—			40,986
Subsidiary preferred stock dividend		—		—			3,000			—			3,000

Income (loss) from continuing operations, net of tax		164,827		(225,888	)		161,773			132,262			232,974
Income (loss) from discontinued operations, net of tax		—		—			(67,526	)		—			(67,526	)

Net income (loss)		164,827		(225,888	)		94,247			132,262			165,448
Less: Net (income) loss attributable to noncontrolling interest		—		—			(621	)		—			(621	)

Net income (loss) attributable to Nabors	$	164,827	$	(225,888	)	$	93,626		$	132,262		$	164,827

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Year Ended December 31, 2014

	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Net income (loss) attributable to Nabors	$	(670,659	)	$	(250,365	)	$	(767,817	)	$	1,018,182		$	(670,659	)
Other comprehensive income (loss) before tax
Translation adjustment attributable to Nabors		(79,059	)		1,583			(79,174	)		77,591			(79,059	)
Unrealized gains/(losses) on marketable securities:
Unrealized gains/(losses) on marketable securities		(59,932	)		156			(59,776	)		59,620			(59,932	)
Less: reclassification adjustment for (gains)/losses on marketable securities		(2,337	)		(2,395	)		(58	)		2,453			(2,337	)

Unrealized gains/(losses) on marketable securities		(57,595	)		(2,239	)		(59,834	)		62,073			(57,595	)
Pension plan		(5,050	)		(5,050	)		(10,100	)		15,150			(5,050	)
Unrealized gains/(losses) and amortization of (gains)/losses on cash flow hedges		612			612			612			(1,224	)		612
Other comprehensive income (loss) before tax		(141,092	)		(5,094	)		(148,496	)		153,590			(141,092	)
Income tax expense (benefit) related to items of other comprehensive income (loss)		(2,474	)		(2,474	)		(5,187	)		7,661			(2,474	)

Other comprehensive income (loss), net of tax		(138,618	)		(2,620	)		(143,309	)		145,929			(138,618	)

Comprehensive income (loss) attributable to Nabors		(809,277	)		(252,985	)		(911,126	)		1,164,111			(809,277	)
Net income (loss) attributable to noncontrolling interest		—			—			1,415			—			1,415
Translation adjustment to noncontrolling interest		—			—			(1,017	)		—			(1,017	)

Comprehensive income (loss) attributable to noncontrolling interest		—			—			398			—			398

Comprehensive income (loss)	$	(809,277	)	$	(252,985	)	$	(910,728	)	$	1,164,111		$	(808,879	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Year Ended December 31, 2013

	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Net income (loss) attributable to Nabors	$	139,982		$	(92,137	)	$	354,812		$	(262,675	)	$	139,982
Other comprehensive income (loss) before tax
Translation adjustment attributable to Nabors		(65,447	)		87			(65,357	)		65,270			(65,447	)
Unrealized gains/(losses) on marketable securities:
Unrealized gains/(losses) on marketable securities		23,007			98			23,105			(23,203	)		23,007
Less: reclassification adjustment for (gains)/losses on marketable securities		(88,158	)		(7,114	)		(95,272	)		102,386			(88,158	)

Unrealized gains/(losses) on marketable securities		(65,151	)		(7,016	)		(72,167	)		79,183			(65,151	)
Pension plan		5,916			5,916			11,832			(17,748	)		5,916
Unrealized gains/(losses) on cash flow hedges		613			613			613			(1,226	)		613

Other comprehensive income (loss) before tax		(124,069	)		(400	)		(125,079	)		125,479			(124,069	)
Income tax expense (benefit) related to items of other comprehensive income (loss)		(66	)		(66	)		(370	)		436			(66	)

Other comprehensive income (loss), net of tax		(124,003	)		(334	)		(124,709	)		125,043			(124,003	)

Comprehensive income (loss) attributable to Nabors		15,979			(92,471	)		230,103			(137,632	)		15,979
Net income (loss) attributable to noncontrolling interest		7,180			—			7,180			(7,180	)		7,180
Translation adjustment to noncontrolling interest		(932	)		—			(932	)		932			(932	)

Comprehensive income (loss) attributable to noncontrolling interest		6,248			—			6,248			(6,248	)		6,248

Comprehensive income (loss)	$	22,227		$	(92,471	)	$	236,351		$	(143,880	)	$	22,227

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Year Ended December 31, 2012

	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Net income (loss) attributable to Nabors	$	164,827		$	(225,888	)	$	93,626		$	132,262		$	164,827
Other comprehensive income (loss) before tax
Translation adjustment attributable to Nabors		21,073			(88	)		20,987			(20,899	)		21,073
Unrealized gains/(losses) on marketable securities:
Unrealized gains/(losses) on marketable securities		98,138			133			98,271			(98,404	)		98,138
Less: reclassification adjustment for (gains)/losses on marketable securities		(13,405	)		(11,488	)		(24,893	)		36,381			(13,405	)

Unrealized gains/(losses) on marketable securities		84,733			(11,355	)		73,378			(62,023	)		84,733
Pension plan		(324	)		(324	)		(648	)		972			(324	)
Unrealized gains/(losses) on cash flow hedges		702			702			702			(1,404	)		702

Other comprehensive income (loss) before tax		106,184			(11,065	)		94,419			(83,354	)		106,184
Income tax expense (benefit) related to items of other comprehensive income (loss)		(4,147	)		(4,147	)		(8,533	)		12,680			(4,147	)

Other comprehensive income (loss), net of tax		110,331			(6,918	)		102,952			(96,034	)		110,331

Comprehensive income (loss) attributable to Nabors		275,158			(232,806	)		196,578			36,228			275,158
Net income (loss) attributable to noncontrolling interest		621			—			621			(621	)		621
Translation adjustment to noncontrolling interest		311			—			311			(311	)		311

Comprehensive income (loss) attributable to noncontrolling interest		932			—			932			(932	)		932

Comprehensive income (loss)	$	276,090		$	(232,806	)	$	197,510		$	35,296		$	276,090

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2014

	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Net cash provided by (used for) operating activities	$	26,943		$	(71,982	)	$	1,816,831		$	10,119		$	1,781,911

Cash flows from investing activities:
Purchases of investments		—			—			(319	)		—			(319	)
Sales and maturities of investments		—			—			23,992			—			23,992
Proceeds from sales of assets and insurance claims		—			—			156,761			—			156,761
Cash paid for acquisitions of businesses, net		—			—			(72,534	)		—			(72,534	)
Proceeds from sale of unconsolidated affiliates		—			—			750			—			750
Other Changes in Investing		—			—			(1,879	)		—			(1,879	)
Investments in unconsolidated affiliates		—			—			(2,365	)		—			(2,365	)
Change in intercompany balances		—			(418,315	)		418,315			—			—
Capital expenditures		—			—			(1,821,315	)		—			(1,821,315	)

Net cash provided by (used for) investing activities		—			(418,315	)		(1,298,594	)		—			(1,716,909	)

Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			(6,151	)		—			(6,151	)
Proceeds from revolving credit facilities		—			450,000			15,000			—			465,000
Reduction in revolving credit facilities		—			(170,000	)		(60,932	)		—			(230,932	)
Proceeds (reductions) in commercial paper		—			203,275			—			—			203,275
Redemption of subsidiary Preferred Shares		—			—			(70,875	)		—			(70,875	)
Proceeds from (payments for) issuance of parent common shares to affiliates		16,424			—			—			(16,424	)		—
Treasury stock transactions, net		—			—			(250,037	)		—			(250,037	)
Proceeds from issuance of Parent common shares		30,263			—			—			—			30,263
Proceeds from Intercompany Debt		55,000			—			(55,000	)		—			—
Paydown of Intercompany Debt		(55,000	)		—			55,000			—			—
Cash dividends paid		(65,450	)		—			—			6,305			(59,145	)
Other Changes		(7,740	)		—			(3,810	)		—			(11,550	)

Net cash (used for) provided by financing activities		(26,503	)		483,275			(376,805	)		(10,119	)		69,848
Effect of exchange rate changes on cash and cash equivalents		—			—			(23,616	)		—			(23,616	)

Net increase (decrease) in cash and cash equivalents		440			(7,022	)		117,816			—			111,234
Cash and cash equivalents, beginning of period		730			7,029			382,156			—			389,915

Cash and cash equivalents, end of period	$	1,170		$	7		$	499,972		$	—		$	501,149

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2013

	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Net cash provided by (used for) operating activities	$	16,746		$	(157,952	)	$	1,531,902		$	27,527		$	1,418,223
Cash flows from investing activities:
Purchases of investments		—			—			—			—			—
Sales and maturities of investments		—			—			164,510			—			164,510
Proceeds from sale of unconsolidated affiliates		—			—			12,640			—			12,640
Cash paid for acquisition of businesses, net		—			—			(116,971	)		—			(116,971	)
Investment in unconsolidated affiliates		—			—			(5,967	)		—			(5,967	)
Capital expenditures		—			—			(1,178,205	)		—			(1,178,205	)
Proceeds from sales of assets and insurance claims		—			—			308,538			—			308,538
Cash paid for investments in consolidated affiliates		(100	)		(772,000	)		(1,544,000	)		2,316,100			—
Other		—			—			(13	)		—			(13	)
Changes in intercompany balances		—			748,537			(748,537	)		—			—

Net cash provided by (used for) investing activities		(100	)		(23,463	)		(3,108,005	)		2,316,100			(815,468	)

Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			(4,421	)		—			(4,421	)
Proceeds from issuance of long-term debt		—			698,434			319			—			698,753
Debt issuance costs		—			(4,500	)		—			—			(4,500	)
Proceeds from (payments for) issuance of common shares		37,455			—			—			(32,072	)		5,383
Reduction in long-term debt		—			(994,112	)		(69	)		—			(994,181	)
Dividends to shareholders		(51,713	)		—			—			4,545			(47,168	)
Proceeds (reductions) in commercial paper, net		—			329,844			—			—			329,844
Reduction in revolving credit facilities		—			(720,000	)		—			—			(720,000	)
Proceeds from parent contributions		—			772,000			1,544,100			(2,316,100	)		—
Other		(3,296	)		—			10,000			—			6,704

Net cash (used for) provided by financing activities		(17,554	)		81,666			1,549,929			(2,343,627	)		(729,586	)
Effect of exchange rate changes on cash and cash equivalents		—			—			(8,176	)		—			(8,176	)

Net increase (decrease) in cash and cash equivalents		(908	)		(99,749	)		(34,350	)		—			(135,007	)
Cash and cash equivalents, beginning of period		1,639			106,778			416,505			—			524,922

Cash and cash equivalents, end of period	$	731		$	7,029		$	382,155		$	—		$	389,915

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 24 Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2012

	Nabors (Parent/ Guarantor)			Nabors Delaware (Issuer/ Guarantor)			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Total
	(In thousands)
Net cash provided by (used for) operating activities	$	7,253		$	39,708		$	1,546,250		$	(30,506	)	$	1,562,705
Cash flows from investing activities:
Purchases of investments		—			—			(949	)		—			(949	)
Sales and maturities of investments		—			—			31,944			—			31,944
Proceeds from sale of unconsolidated affiliates		—			—			159,529			—			159,529
Cash paid for acquisition of businesses, net		(35	)		—			—			35			—
Investment in unconsolidated affiliates		—			—			(1,325	)		—			(1,325	)
Capital expenditures		—			—			(1,518,628	)		—			(1,518,628	)
Proceeds from sales of assets and insurance claims		—			—			149,801			—			149,801
Changes in intercompany balances		—			274,482			(274,482	)		—			—

Net cash provided by (used for) investing activities		(35	)		274,482			(1,454,110	)		35			(1,179,628	)

Cash flows from financing activities:
Increase (decrease) in cash overdrafts		—			—			1,612			—			1,612
Debt issuance costs		—			(3,433	)		—			—			(3,433	)
Proceeds from revolving credit facilities		—			710,000			—			—			710,000
Proceeds from (payments for) issuance of common shares		(3,622	)		—			(3	)		—			(3,625	)
Reduction in long-term debt		—			(224,997	)		(51,261	)		—			(276,258	)
Reduction in revolving credit facilities		—			(680,000	)		—			—			(680,000	)
Other		(2,160	)		—			(263	)		—			(2,423	)
Proceeds from parent contributions		—			—			35			(35	)		—
Cash dividends paid		—			(9,003	)		(21,503	)		30,506			—

Net cash (used for) provided by financing activities		(5,782	)		(207,433	)		(71,383	)		30,471			(254,127	)
Effect of exchange rate changes on cash and cash equivalents		—			—			(2,603	)		—			(2,603	)

Net increase (decrease) in cash and cash equivalents		1,436			106,757			18,154			—			126,347
Cash and cash equivalents, beginning of period		203			21			398,351			—			398,575

Cash and cash equivalents, end of period	$	1,639		$	106,778		$	416,505		$	—		$	524,922

Note 25 Subsequent Events

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

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Nabors Industries Ltd. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 25 Subsequent Events (Continued)

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

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

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

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

Results of Operations

Results of operations of oil and gas activities are included in discontinued operations, except those of our former unconsolidated U.S. oil and gas joint venture. Net revenues from production include only the revenues from the production and sale of natural gas, oil, and natural gas liquids. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and

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amortization ("DD&A") allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

	United States			Canada			Colombia			Total

	(In thousands)
Results of Operations
For the year ended December 31, 2012:
Consolidated Subsidiaries
Revenue	$	24,805		$	4,741		$	435		$	29,981
Production costs		8,959			5,842			106			14,907
Exploration expenses		1,245			160			2,343			3,748
Depreciation and depletion		89			2,308			13			2,410
Impairment of oil and gas properties		29,314			127,766			—			157,080
Loss (gain) on disposition		(2,302	)		—			(47,060)	(4)		(49,362	)
Related income tax expense (benefit)		(8,092	)		(32,834	)		—			(40,926	)

Results of producing activities for consolidated subsidiaries	$	(4,408	)	$	(98,501	)	$	45,033		$	(57,876	)

Equity Companies(1)
Revenue	$	80,607		$	—		$	—		$	80,607
Production costs		32,192			—			—			32,192
Depreciation and depletion		39,502			—			—			39,502
Impairment of oil and gas properties		305,151	(3)		—			—			305,151
Realized gain on derivative instrument		—			—			—			—
Related income tax expense (benefit)(2)		—			—			—			—

Results of producing activities for equity subsidiaries	$	(296,238	)	$	—		$	—		$	(296,238	)

Total results of operations	$	(300,646	)	$	(98,501	)	$	45,033		$	(354,114	)

(1): Represents our proportionate share of interests in our equity companies for the applicable year.
(2): Equity companies are pass-through entities for tax purposes.
(3): Includes our proportionate share of full-cost ceiling test writedowns.
(4): Includes our gain on disposition of Colombia properties in April 2012.

Capitalized Cost

Capitalized costs include the cost of properties, equipment and facilities for oil and gas-producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells

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that are in the process of drilling or for active completion, and costs of exploratory wells suspended or waiting for completion.

	United States			Canada			Colombia		Total

	(In thousands)
Capitalized Costs
For the year ended December 31, 2012:
Consolidated Subsidiaries
Property acquisition costs, proved	$	114,427		$	62,048		$	—	$	176,475
Property acquisition costs, unproved		91,219			83,455			—		174,674

Total acquisition costs		205,646			145,503			—		351,149
Accumulated depreciation and amortization		(23,949	)		(29,560	)		—		(53,509	)

Net capitalized costs for consolidated subsidiaries	$	181,697		$	115,943		$	—	$	297,640

Equity Companies(1)

(1): As of December 31, 2012, we had no equity companies with oil and gas assets.

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

Amounts reported as costs incurred include both capitalized costs and costs charged to expense during 2012, for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs include the costs of drilling and equipping successful exploration wells, as well as dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds.

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Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

	United States		Canada		Colombia		Total

	(In thousands)
Costs incurred in property acquisitions, exploration and development activities
For the year ended December 31, 2012:
Consolidated Subsidiaries
Property acquisition costs, proved	$	—	$	—	$	—	$	—
Property acquisition costs, unproved		—		—		—		—
Exploration costs		27,994		190		13,181		41,365
Development costs		64,805		623		—		65,428
Asset retirement costs		89		162		13		264

Total costs incurred for consolidated subsidiaries	$	92,888	$	975	$	13,194	$	107,057

Equity Companies(1)
Property acquisition costs, proved	$	1,420	$	—	$	—	$	1,420
Property acquisition costs, unproved		—		—		—		—
Exploration costs		31,411		—		—		31,411
Development costs		24,355		—		—		24,355
Asset retirement costs		127		—		—		127

Total costs incurred for equity companies	$	57,313	$	—	$	—	$	57,313

(1): Represents our proportionate share of interests in equity companies for the applicable year.

Oil and Gas Reserves

The reserve disclosures that follow reflect estimates of proved reserves for our consolidated subsidiaries and equity companies of natural gas, oil, and natural gas liquids owned at December 31, 2012 and changes in proved reserves during 2012. Our year-end reserve volumes in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserve quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Estimates of volumes of proved reserves of natural gas at year end are expressed in billions of cubic feet of natural gas ("Bcf") at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels ("MMBbls") for oil and natural gas liquids.

For our wholly owned properties in the United States, the prices used in our reserve reports were $2.75 per mcf for the 12-month average of natural gas, $33.74 per barrel for natural gas liquids and $94.71 per barrel for oil at December 31, 2012. For our wholly owned properties in Canada, the price used in our reserve reports was $1.05 per mcf for the 12-month average of natural gas at December 31, 2012.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

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

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

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

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

	United States						Canada					Colombia				Total

Reserves	Liquids (MMBbls)			Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)
Net proved reserves of consolidated subsidiaries
January 1, 2012		1.8			16.9			—		8.2			—		—		1.8			25.1
Revisions		(0.2	)		0.6			—		1.5			—		—		(0.2	)		2.1
Extensions, additions and discoveries		14.8	(1)		0.9			—		—			—		—		14.8			0.9
Production		(0.2	)		(0.8	)		—		(2.0	)		—		—		(0.2	)		(2.8	)
Purchases in place		—			—			—		—			—		—		—			—
Sales in place		(0.8	)		(16.5)	(2)		—		—			—		—		(0.8	)		(16.5	)

December 31, 2012		15.4			1.1			—		7.7			—		—		15.4			8.8

	United States						Canada				Colombia				Total

Reserves	Liquids (MMBbls)			Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)
Proportional interest in proved reserves of equity companies
January 1, 2012		15.9			582.5			—		—		—		—		15.9			582.5
Revisions		(1.5	)		(22.6	)		—		—		—		—		(1.5	)		(22.6	)
Extensions, additions and discoveries		1.4			8.9			—		—		—		—		1.4			8.9
Production		(0.5	)		(19.0	)		—		—		—		—		(0.5	)		(19.0	)
Purchases in place		—			—			—		—		—		—		—			—
Sales in place(3)		(15.3	)		(549.8	)		—		—		—		—		(15.3	)		(549.8	)

December 31, 2012		—			—			—		—		—		—		—			—

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	United States				Canada				Colombia				Total

Reserves	Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)		Liquids (MMBbls)		Natural Gas (Bcf)
Proved Developed Reserves at December 31, 2012
Consolidated subsidiaries		1.1		0.4		—		7.7		—		—		1.1		8.1
Proved Undeveloped Reserves at December 31, 2012
Consolidated subsidiaries		14.3		0.7		—		—		—		—		14.3		0.7

(1): Relates primarily to the discovery of proved undeveloped reserves in our North Slope, Alaska field.
(2): Relates to the divestitures during 2012 of substantially all of our U.S. wholly owned gas properties.
(3): Relates to our sale of Sabine in December 2012, which included 15.1 MMBbls and 531.9 Bcf, respectively, of oil and natural gas.

Standardized Measure of Discounted Future Cash Flows

For the year ended December 31, 2012, the standardized measure of discounted future net cash flow was computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and global, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The 10-percent discount factor is prescribed by GAAP.

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

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estimated reserve volumes or commodity prices could have a material effect on our consolidated financial statements.

	United States			Canada			Colombia		Total

	(In thousands)
Standardized Measure of Discounted Future Cash Flows
For the year ended December 31, 2012:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	1,633,946		$	8,101		$	—	$	1,642,047
Future production costs		(427,971	)		(5,060	)		—		(433,031	)
Future development costs		(402,392	)		(376	)		—		(402,768	)
Future income tax expense(1)		(305,215	)		—			—		(305,215	)

Future net cash inflows		498,368			2,665			—		501,033
Effect of discounting net cash flows at 10%		(218,139	)		(268	)		—		(218,407	)

Discounted future net cash flows	$	280,229		$	2,397		$	—	$	282,626

Total consolidated and equity interests in standardized measure of discounted future net cash flows(2)	$	280,229		$	2,397		$	—	$	282,626

(1): For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.
(2): As of December 31, 2012, we had no equity companies with oil and gas assets.

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

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

	United States			Canada			Colombia		Total

	(In thousands)
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries
Discounted future net cash flows as of January 1, 2012	$	57,302		$	11,011		$	—	$	68,313

Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		454,913			—			—		454,913
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(14,958	)		1,101			—		(13,857	)
Development costs incurred during the year		11,343			623			—		11,966
Net change in prices and production costs		13,174			(11,659	)		—		1,515
Net change in future development costs		1,164			4			—		1,168
Revisions of previous reserve estimates		(894	)		427			—		(467	)
Purchases of reserves		—			—			—		—
Divestiture of reserves		(33,082	)		—			—		(33,082	)
Accretion of discount		5,730			1,101			—		6,831
Other		(25,922	)		(211	)		—		(26,133	)
Net change in income taxes(2)		(188,541	)		—			—		(188,541	)

Total change in the standardized measure for consolidated subsidiaries	$	222,927		$	(8,614	)	$	—	$	214,313

Discounted future net cash flows as of December 31, 2012	$	280,229		$	2,397		$	—	$	282,626

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	United States			Canada		Colombia		Total

	(In thousands)
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Equity Companies(1)
Discounted future net cash flows as of January 1, 2012	$	582,063		$	—	$	—	$	582,063

Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		16,926			—		—		16,926
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(48,432	)		—		—		(48,432	)
Development costs incurred during the year		24,356			—		—		24,356
Net change in prices and production costs		—			—		—		—
Net change in future development costs		—			—		—		—
Revisions of previous reserve estimates		(377,184	)		—		—		(377,184	)
Purchases of reserves		—			—		—		—
Divestiture of reserves(3)		(246,093	)		—		—		(246,093	)
Accretion of discount		58,206			—		—		58,206
Other		(9,842	)		—		—		(9,842	)
Net change in income taxes		—			—		—		—

Total change in the standardized measure for equity companies	$	(582,063	)	$	—	$	—	$	(582,063	)

Discounted future net cash flows as of December 31, 2012	$	—		$	—	$	—	$	—

(1): Represents our proportionate share of interests in equity companies for the applicable year.
(2): For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.
(3): Includes $233 million, representing our divestiture of Sabine in December 2012.

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

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain a set of disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure. We have investments in certain unconsolidated entities that we do not control or manage. Because we do not control or manage these entities, our disclosure controls and procedures with respect to these entities are necessarily more limited than those we maintain with respect to our consolidated subsidiaries.

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The Company's management, with the participation of the Chief Executive Officer and the Chief Financial Officer, has evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that, as of December 31, 2014, the Company's disclosure controls and procedures are not effective due to the material weakness described in "Management's Report on Internal Control Over Financial Reporting."

Management's Report on Internal Control over Financial Reporting

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

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

Management conducted an evaluation of the effectiveness of the Company's internal control over financial reporting based on the criteria set forth in theInternal Control—Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company's internal control over financial reporting was not effective as of December 31, 2014, based on the material weaknesses described in the paragraph below.

We have concluded that, as of December 31, 2014, our controls over the accounting for and disclosures related to a non-routine complex legal entity restructuring in the interim consolidated financial statements did not operate effectively. Specifically, during the operation of a tax control, we failed to detect the use of inaccurate historical tax attributes. Accordingly, we initially did not appropriately record the tax impact related to the third quarter 2014 restructuring of our Completion and Production Services entities in preparation for the pending Merger. This control deficiency resulted in a material overstatement of the tax expense reflected in our initial third quarter 2014 earnings press release issued on October 21, 2014. This error was subsequently identified and corrected in the interim consolidated financial statements before filing our Form 10-Q for the third quarter of 2014. If not remediated, this control deficiency could result in material misstatements of our annual or interim consolidated financial statements that may not be prevented or detected. Accordingly, management has determined that this control deficiency constitutes a material weakness.

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PricewaterhouseCoopers LLP has issued a report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2014, which is included in Part II, Item 8 of this report.

Remedial Actions

We are in the process of remediating the identified deficiency in internal control over financial reporting. However, we have not completed our evaluation and all of the corrective remediation actions that we believe are necessary.

Management believes that significant progress has been made as of the date of this report, in remediating the underlying causes of the material weakness. We have taken, and will continue to take, a number of actions to remediate this material weakness. Among other things, we have:

•: filled the vacant Vice President—Tax position in January 2015;
•: developed and implemented enhanced review and analytical procedures to evaluate the accuracy of tax transactions, which will be performed by the Vice President—Tax each quarter;
•: enhanced the documentation surrounding our estimation and reconciliation of the tax ramifications of non-routine complex legal entity restructuring; and
•: developed procedures for engaging third party tax advisors to assist with our methodology of estimating and reconciling tax entries.

We will continue to develop and implement policies and procedures to improve the overall effectiveness of internal control over financial reporting. Management believes the foregoing efforts will effectively remediate the material weakness. As we continue to evaluate and work to improve our internal control over financial reporting, management may determine to take additional measures to address the control deficiency or determine to modify the remediation plan described above. We cannot assure you, however, when we will remediate the deficiency, nor can we be certain of whether additional actions will be required or the costs of any such actions.

Changes in Internal Control over Financial Reporting

Except for the material weakness remediation efforts, there have not been any changes in the Company's internal control over financial reporting (identified in connection with the evaluation required by paragraph (d) in Rules 13a-15 and 15d-15 under the Exchange Act) during the most recently completed fiscal quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information called for by this item will be contained in the definitive Proxy Statement to be distributed in connection with our 2015 annual general meeting of shareholders under the captions "Election of Directors", "Other Executive Officers", "Meetings of the Board and Committees" and "Section 16(a) Beneficial Ownership Reporting Compliance" and is incorporated into this document by reference.

We have adopted a Code of Business Conduct (the "Code") that applies to all directors, employees, including our principal executive officer and principal financial and accounting officer. The Code satisfies the SEC's definition of a "Code of Ethics" and is posted on our website atwww.nabors.com. We intend to disclose on our website any amendments to the Code and any waivers of the Code that apply to our principal executive officer, principal financial officer, or principal accounting officer.

On June 10, 2014, we filed with the New York Stock Exchange the Annual CEO Certification regarding our compliance with the Exchange's Corporate Governance listing standards as required by Section 303A-12(a) of the Exchange's Listed Company Manual.

ITEM 11. EXECUTIVE COMPENSATION

The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2015 annual general meeting of shareholders under the caption "Executive Compensation" and except as specified in the following sentence, is incorporated into this document by reference. Information in Nabors' 2015 Proxy Statement not deemed to be "soliciting material" or "filed" with the Commission under its rules, including the Compensation Committee Report, is not deemed to be incorporated by reference.

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

We maintain five different equity compensation plans: 1996 Employee Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors, 2003 Employee Stock Plan and 2013 Stock Plan pursuant to which we may grant equity awards to eligible persons. The terms of our equity compensation plans are described more fully below.

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The following table gives information about these equity compensation plans as of December 31, 2014:

Plan category		(b) Weighted- average exercise price of outstanding options, warrants and rights

Equity compensation plans approved by security holders	10,458,624	$	22.7714	4,969,922
Equity compensation plans not approved by security holders	845,192	$	29.8590	1,346,922

Total	11,303,816			6,316,844

(1): The 1996 Employee Stock Plan incorporated an evergreen formula pursuant to which on each January 1, the aggregate number of shares reserved for issuance under the plan were increased by an amount equal to 1.5% of the common shares outstanding on September 30 of the immediately preceding fiscal year. Effective January 1, 2006, no new awards could be granted under this plan, but there are outstanding awards that were granted before this date.
(2): The 2003 Employee Stock Plan provided, commencing on June 1, 2006 and expiring January 1, 2011, on each January 1 for an automatic increase in the number of shares reserved and available for issuance under the Plan by an amount equal to two percent (2%) of the Company's outstanding common shares as of each June 1 or January 1. Effective June 3, 2013, no new awards could be granted under this plan, but there are outstanding awards that were granted before this date.

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

1998 Employee Stock Plan

The plan reserved for issuance up to 35,000,000 common shares of the Company pursuant to the exercise of options granted under the plan. The persons eligible to participate in the plan were employees and consultants of the Company. Options granted to employees were either awards of shares, non-qualified stock options (each, an "NQSO"), incentive stock options (each, an "ISO") or stock appreciation rights (each, an "SAR"). An optionee may reduce the option exercise price by paying the Company in cash, shares, options, or the equivalent, an amount equal to the difference between the exercise price and the reduced exercise price of the option. The administrative committee established performance goals for stock awards in writing and not later than the date required for compliance under Section 162(m) of the IRC, and vesting of these shares was contingent upon the attainment of such performance goals. Stock awards vest over a period determined by the committee. The Plan expired on January 8, 2008 and effective that date, no new awards could be granted even though there are outstanding awards that were granted before this date. The committee could grant

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ISOs of not less than 100% of the fair market value per common share on the date of grant; except that in the event the optionee owns on the date of grant, securities possessing more than 10% of the total combined voting power of all classes of securities of the Company or of any subsidiary of the Company, the price per share must not have been less than 110% of the fair market value per common share on the date of the grant. The option must expire five years from the date it is granted. SARs may be granted in conjunction with all or part of any option granted under the plan, in which case the exercise of the SAR must require the cancellation of a corresponding portion of the option; conversely, the exercise of the option will result in cancellation of a corresponding portion of the SAR. In the case of a NQSO, SARs may be granted either at or after the time of grant of the option. In the case of an ISO, SARs may be granted only at the time of grant of the option. A SAR may also be granted on a stand-alone basis. The term of a SAR must be established by the committee. The exercise price of a SAR cannot be less than 100% of the fair market value per common share on the date of grant. The committee has the authority to make provisions in its award and grant agreements to address vesting and other issues arising in connection with a change of control.

1999 Stock Option Plan for Non-Employee Directors

The plan reserves for issuance up to 3,000,000 common shares of the Company pursuant to the exercise of options granted under the plan. The plan is administered by the Board or a committee appointed by the Board. Eligible directors may not consider or vote on the administration of the plan or serve as a member of the committee. Options may be granted under the plan to non-employee directors of the Company. Options vest and become non-forfeitable on the first anniversary of the option grant if the optionee has continued to serve as a director until that day, unless otherwise provided. In the event of termination of an optionee's service as a director by reason of voluntary retirement, declining to stand for re-election or becoming a full-time employee of the Company or a subsidiary of the Company, all unvested options granted under the plan automatically expire and are not exercisable, and all unexercised options continue to be exercisable until their stated expiration date. In the event of death or disability of an optionee while the optionee is a director, the then-outstanding options of such optionee become exercisable for two years from the date of the death or disability. All unvested options automatically vest and become non-forfeitable as of the date of death or disability and become exercisable for two years from the date of the death of the optionee or until the stated expiration date, whichever is earlier. In the event of the termination of an optionee's service as a director by the Board for cause or the failure of such director to be re-elected, the administrator of the plan in its sole discretion can cancel the then-outstanding options of the optionee, including options that have vested, and those options automatically expire and become non-exercisable on the effective date of the termination.

The remainder of the information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2015 annual general meeting of shareholders under the caption "Share Ownership of Management and Principal Shareholders" and is incorporated into this document by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

(1): Financial Statements

		Page No.

Consolidated Balance Sheets as of December 31, 2014 and 2013			58
Consolidated Statement of Income (Loss) for the Years Ended December 31, 2014, 2013 and 2012			59
Consolidated Statement of Other Comprehensive Income (Loss) for the Years Ended December 31, 2014, 2013 and 2012			60
Consolidated Statement of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012			61
Consolidated Statement of Changes in Equity for the Years Ended December 31, 2014, 2013 and 2012			62

(2): Financial Statement Schedule

		Page No.

Schedule II—Valuation and Qualifying Accounts			157

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

(b) Exhibit Index

See the Exhibit Index for a list of those exhibits filed herewith, which Exhibit Index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 of Regulation S-K.

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SIGNATURES

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


		NABORS INDUSTRIES LTD.
		By:		/s/ ANTHONY G. PETRELLO Anthony G. Petrello Chairman, President and Chief Executive Officer (Principal Executive Officer)
		By:		/s/ WILLIAM RESTREPO William Restrepo Chief Financial Officer
		Date:		March 2, 2015

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

Signature	Title	Date


/s/ ANTHONY G. PETRELLO Anthony G. Petrello	Chairman, President and Chief Executive Officer	March 2, 2015
/s/ WILLIAM RESTREPO William Restrepo	Chief Financial Officer	March 2, 2015
/s/ JAMES R. CRANE James R. Crane	Director	March 2, 2015
/s/ MICHAEL C. LINN Michael C. Linn	Director	March 2, 2015
/s/ JOHN V. LOMBARDI John V. Lombardi	Director	March 2, 2015

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Signature	Title	Date


/s/ JOHN P. KOTTS John P. Kotts	Director	March 2, 2015
/s/ DAG SKATTUM Dag Skattum	Director	March 2, 2015
/s/ JOHN YEARWOOD John Yearwood	Director	March 2, 2015
/s/ W. HOWARD WOLF W. Howard Wolf	Director	March 2, 2015

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Exhibit Index

Exhibit No.			Description

	2.1		Agreement and Plan of Merger among Nabors Industries, Inc., Nabors Acquisition Corp. VIII, Nabors Industries Ltd. and Nabors US Holdings Inc. (incorporated by reference to Annex I to the proxy statement/prospectus included in our Registration Statement on Form S-4 (File No. 333-76198) filed with the SEC on May 10, 2002, as amended).

	2.2		Agreement and Plan of Merger, by and among Nabors Industries Ltd., Diamond Acquisition Corp., and Superior Well Services, Inc., dated as of August 6, 2010 (incorporated by reference to Exhibit 2.1 to our Form 8-K (File No. 001-32657) filed with the SEC on August 9, 2010).

	2.3		Agreement and Plan of Merger, dated as of June 25, 2014, by and among Nabors Industries Ltd., Nabors Red Lion Limited and C&J Energy Services, Inc. (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on July 1, 2014).

	2.4		Separation Agreement, dated as of June 25, 2014, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on July 1, 2014).

	2.5		Amendment No. 1 to the Agreement and Plan of Merger, by and among Nabors Industries Ltd., Nabors Red Lion Limited, C&J Energy Services, Inc., Nabors Merger Co. and CJ Holding Co. (incorporated by reference to Exhibit 10.1 of our Form 8-K (File No. 001-32657) filed with the SEC on February 9, 2015).

	2.6		Amendment No. 1 to the Separation Agreement, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated by reference to Exhibit 10.2 of our Form 8-K (File No. 001-32657) filed with the SEC on February 9, 2015).

	3.1		Memorandum of Association of Nabors Industries Ltd. (incorporated by reference to Annex II to the proxy statement/prospectus included in our Registration Statement on Form S-4 (File No. 333-76198) filed with the SEC on May 10, 2002, as amended).

	3.2		Amended and Restated Bye-Laws of Nabors Industries Ltd. (incorporated by reference to Exhibit 3.2 to our Form 10-Q (File No. 001-32657) filed with the SEC on August 3, 2012).

	4.1		Indenture, dated as of February 20, 2008, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.'s 6.15% Senior Notes due 2018 (including form of 6.15% Senior Note due 2018) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on February 25, 2008).

	4.3		Indenture, dated as of January 12, 2009, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.'s 9.25% Senior Notes due 2019 (including form of 9.25% Senior Note due 2019) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on January 14, 2009).

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		Description

4.4		Indenture, dated as of September 14, 2010, among Nabors Industries, Inc., Nabors Industries Ltd., Wilmington Trust Company, as trustee, and Citibank, N.A. as securities administrator, with respect to Nabors Industries, Inc.'s 5.0% Senior Notes due 2020 (including form of 5.0% Senior Note due 2020) (incorporated by reference to Exhibit 4.2 to our Form 8-K (File No. 001-32657) filed with the SEC on September 15, 2010).

4.5		Tender and Voting Agreement, by and among Nabors Industries Ltd., Diamond Acquisition Corp., and certain stockholders of Superior Well Services, Inc., dated as of August 6, 2010 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-32657) filed with the SEC on August 9, 2010).

4.6		Indenture, dated as of August 23, 2011, among Nabors Industries, Inc., Nabors Industries Ltd., Wilmington Trust, National Association, as trustee and Citibank, N.A. as securities administrator, with respect to Nabors Industries, Inc.'s 4.625% Senior Notes due 2021 (including form of 4.625% Senior Note due 2021) (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-32657) filed with the SEC on August 24, 2011).

4.7		Rights Agreement, dated as of July 16, 2012, between Nabors Industries Ltd. and Computershare Trust Company, N.A., as Rights Agent, including the Form of Certificate of Designations of Series A Junior Participating Preferred Shares, the Form of Right Certificate, and the Summary of Rights to Purchase Preferred Shares, respectively attached thereto as Exhibits A, B and C (incorporated by reference to Exhibit 4.1 to Nabors Industries Ltd.'s Form 8-K (File No. 001-32657) filed with the SEC on July 17, 2012).

4.7	(a)	Amendment No. 1, dated as of April 4, 2013, to the Rights Agreement, dated as of July 16, 2012, between Nabors Industries Ltd. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to Amendment No. 1 to the Registration Statement on Form 8-A (File No. 001-32657) filed with the SEC on April 4, 2013).

4.7	(b)	Amendment No. 2, dated as of July 15, 2013, to the Rights Agreement, dated as of July 16, 2012, between Nabors Industries Ltd. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 4.3 to Amendment No. 2 to the Registration Statement on Form 8-A (File No. 001-32657) filed with the SEC on July 15, 2013).

4.8		Indenture related to the 2.35% Senior Notes due 2016 and 5.10% Senior Notes due 2023, dated as of September 12, 2013, among Nabors Industries, Inc. as Issuer, Nabors Industries Ltd. as Guarantor, Wilmington Trust, National Association as Trustee and Citibank, N.A. as Securities Administrator (including form of 2.35% Senior Note due 2016 and form of 5.10% Senior Note due 2023) (incorporated by reference to Exhibit 4.1 to Nabors Industries Ltd. Form 8-K (File No. 001-32657) filed with the SEC on September 13, 2013).

10.1	(+)	Executive Employment Agreement, by and among Nabors Industries Ltd., Nabors Industries, Inc. and William Restrepo, effective as of March 31, 2014 (incorporated by reference to Exhibit 99.1 to our Form 8-K (File No. 001-32657) filed with the SEC on March 4, 2014).

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		Description

10.1	(a)(+)	First Amendment to Executive Employment Agreement, dated December 19, 2014, among Nabors Industries Ltd., Nabors Industries, Inc. and William Restrepo (incorporated by reference to Exhibit 99.2 to our Form 8-L (File No. 001-32657) filed with the SEC on December 19, 2014).

10.1	(b)(+)	Form of TSR Stock Grant Agreement—William Restrepo, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.1 to the Form 10-Q (File No. 001-32657) filed with the SEC on May 9, 2014).

10.1	(c)(+)	Form of Nabors Industries Ltd. Restricted Stock Agreement—William Restrepo, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.1 to the Form 10-Q (File No. 001-32657) filed with the SEC on May 9, 2014).

10.1	(d)(+)	Form of Nabors Corporate Services, Inc. Restricted Stock Agreement—William Restrepo, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.1 to the Form 10-Q (File No. 001-326571) filed with the SEC on May 9, 2014).

10.2	(+)	Executive Employment Agreement by and among Nabors Industries Ltd., Nabors Industries, Inc. and Anthony G. Petrello, effective as of January 1, 2013 (incorporated by reference to Exhibit 99.1 to our Form 8-K (File No. 001-32657) filed with the SEC on March 11, 2013).

10.2	(a)(+)	First Amendment to Executive Employment Agreement, dated December 19, 2014, among Nabors Industries Ltd., Nabors Industries, Inc. and Anthony G. Petrello (incorporated by reference to Exhibit 99.1 to our Form 8-L (File No. 001-32657) filed with the SEC on December 19, 2014).

10.2	(b)(+)	Termination Agreement, by and among Nabors Industries Ltd., Nabors Industries, Inc. and Anthony G. Petrello effective December 31, 2012 and relating to Mr. Petrello's Employment Agreement, effective as of April 1, 2009 (incorporated by reference to Exhibit 99.2 to Nabors Industries Ltd.'s Form 8-K (File No. 001-32657) filed with the SEC on March 11, 2013).

10.2	(c)(+)	Stock Bonus Agreement, dated as of March 7, 2013 among Nabors Industries Ltd., Nabors Industries, Inc. and Anthony G. Petrello (incorporated by reference to Exhibit 99.3 to Nabors Industries Ltd.'s Form 8-K (File No. 001-32657) filed with the SEC on March 11, 2013).

10.3		Form of Indemnification Agreement entered into between Nabors Industries Ltd. and the directors and executive officers (incorporated by reference to Exhibit 10.28 to our Form 10-K (File No. 000-49887) filed with the SEC on March 31, 2003).

10.4	(+)	Nabors Industries Ltd. 2013 Stock Plan (incorporated by reference to Appendix B of Nabors Industries Ltd.'s Definitive Proxy Statement on Schedule 14A (File No. 001-32657) filed with the SEC on April 30, 2013).

10.4	(a)(+)	Form of Stock Option Agreement—Others, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.8(a) to our Form 10-K (File No. 001-32657) filed with the SEC on March 3, 2014).

10.4	(b)(+)	Form of Restricted Stock Agreement—Others, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.8(b) to our Form 10-K (File No. 001-32657) filed with the SEC on March 3, 2014).

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		Description

10.4	(c)(+)	Form of Restricted Stock Agreement—Directors, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.8(c) to our Form 10-K (File No. 001-32657) filed with the SEC on March 3, 2014).

10.4	(d)(+)	Form of TSR Stock Grant Agreement—Anthony G. Petrello, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.8(d) to our Form 10-K (File No. 001-32657) filed with the SEC on March 3, 2014).

10.4	(e)(+)	Form of Nabors Industries Ltd. Restricted Stock Agreement—Anthony G. Petrello, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.8(e) to our Form 10-K (File No. 001-32657) filed with the SEC on March 3, 2014).

10.4	(f)(+)	Form of Nabors Corporate Services, Inc. Restricted Stock Agreement—Anthony G. Petrello, pursuant to the 2013 Stock Plan (incorporated by reference to Exhibit 10.8(f) to our Form 10-K (File No. 001-32657) filed with the SEC on March 3, 2014).

10.5	(+)	Form of Restricted Stock Award—Isenberg/Petrello (incorporated by reference to Exhibit 10.01 to Nabors Industries Ltd.'s Form 8-K, File No. 000-49887, filed March 2, 2005).

10.5	(a)(+)	Form of Restricted Stock Award—Others (incorporated by reference to Exhibit 10.02 to Nabors Industries Ltd.'s Form 8-K, File No. 000-49887, filed March 2, 2005).

10.5	(b)(+)	Form of Stock Option Agreement—Petrello/Isenberg (incorporated by reference to Exhibit 10.03 to our Form 8-K (File No. 000-49887) filed with the SEC on March 2, 2005).

10.5	(c)(+)	Form of Stock Option Agreement—Others (incorporated by reference to Exhibit 10.04 to our Form 8-K (File No. 000-49887) filed with the SEC on March 2, 2005).

10.6	(+)	2003 Employee Stock Plan (incorporated by reference to Annex D of our Proxy Statement (File No. 000-49887) filed with the SEC on May 8, 2003).

10.6	(a)(+)	First Amendment to 2003 Employee Stock Plan (incorporated by reference to Exhibit 4.1 to our Form 10-Q (File No. 000-49887) filed with the SEC on August 3, 2005).

10.6	(b)(+)	Nabors Industries Ltd. Amended and Restated 2003 Employee Stock Plan (incorporated by reference to Exhibit A of our Proxy Statement (File No. 001-32657) filed with the SEC on May 4, 2006).

10.7	(+)	1996 Employee Stock Plan (incorporated by reference to Nabors Industries, Inc.'s Registration Statement on Form S-8 (File No. 333-11313) filed with the SEC on September 3, 1996).

10.8	(+)	Nabors Industries, Inc. 1997 Executive Officers Incentive Stock Plan (incorporated by reference to Exhibit 10.20 to Nabors Industries, Inc.'s Form 10-K (File No. 1-9245) filed with the SEC on December 29, 1997).

10.9	(+)	Nabors Industries, Inc. 1998 Employee Stock Plan (incorporated by reference to Exhibit 10.19 to Nabors Industries, Inc.'s Form 10-K (File No. 1-9245) filed with the SEC on March 31, 1999).

10.10	(+)	Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.21 to Nabors Industries, Inc.'s Form 10-K (File No. 1-9245) filed with the SEC March 31, 1999).

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		Description

10.10	(a)(+)	Amendment to Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.19 to Nabors Industries Inc.'s Form 10-K (File No. 1-09245) filed with the SEC on March 19, 2002).

10.10	(b)(+)	Amended and Restated 1999 Stock Option Plan for Non-Employee Directors (amended on May 2, 2003) (incorporated by reference to Exhibit 10.29 to our Form 10-Q (File No. 000-49887) filed with the SEC on May 12, 2003).

10.11		Credit Agreement, dated as of November 29, 2012, among Nabors Industries, Inc. as US borrower, Nabors Canada as Canadian borrower, Nabors Industries Ltd. as guarantor, HSBC Bank Canada as Canadian lender, the other lenders party thereto, Mizuho Corporate Bank, Ltd. and HSBC Bank USA, N.A. as documentation agents, HSBC Bank USA, N.A. as syndication agent and Citibank, N.A. as administrative agent for the US lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-32657) filed with the SEC on November 30, 2012).

10.12		Agreement, dated as of April 4, 2013, by and between Nabors Industries Ltd. and PHM Investment (USD) 1 S.à.r.l. (incorporated by reference to Exhibit 10.1 to the Form 8-K (File No. 001-32657) filed with the Commission on April 4, 2013).

10.13		Support Agreement, dated as of June 25, 2014, by and among Nabors Industries Ltd., Nabors Red Lion Limited, Joshua E. Comstock, the Joshua E. Comstock Trust and JRC Investments, LLC (incorporated by reference to Exhibit 10.3 to our Form 8-K (File No. 001-32657) filed with the SEC on July 1, 2014.

10.14		Term Loan Agreement, dated February 6, 2015, among Nabors Industries, Inc., as borrower, Nabors Industries Ltd., as guarantor, the lenders party thereto, HSBC Bank USA, N.A. and Wells Fargo Bank, N.A., as documentation agents, Mizuho Bank, Ltd., as syndication agent and Citibank, N.A, as administrative agent for the lenders (incorporated by reference to Exhibit 10.3 to our Form 8-K (File No. 001-32657) filed with the SEC on February 6, 2015).

12		Computation of Ratios.*

14		Code of Business Conduct (incorporated by reference to Exhibit 14 to our Form 10-K (File No. 000-49887) filed with the SEC on March 15, 2004).
		��
21		Significant Subsidiaries.*

23.1		Consent of Independent Registered Public Accounting Firm—PricewaterhouseCoopers LLP—Houston.*

23.2		Consent of Deloitte LLP.*

23.3		Consent of Cawley, Gillespie & Associates, Inc.*

23.4		Consent of DeGolyer and MacNaughton.*

31.1		Rule 13a-14(a)/15d-14(a) Certification of Anthony G. Petrello, Chairman, President and Chief Executive Officer*

31.2		Rule 13a-14(a)/15d-14(a) Certification of William Restrepo, Chief Financial Officer*

32.1		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Anthony G. Petrello, Chairman, President and Chief Executive Officer and William Restrepo, Chief Financial Officer.*

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Exhibit No.			Description

	101.INS		XBRL Instance Document*

	101.SCH		XBRL Schema Document*

	101.CAL		XBRL Calculation Linkbase Document*

	101.LAB		XBRL Label Linkbase Document*

	101.PRE		XBRL Presentation Linkbase Document*

	101.DEF		XBRL Definition Linkbase Document*

*: Filed herewith.
(+): Management contract or compensatory plan or arrangement.

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SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2014, 2013 and 2012

	Balance at Beginnning of Period								Balance at End of Period

	(In thousands)
2014
Allowance for doubtful accounts	$	27,134	(802	)	(52	)	(2,735	)	$	23,545
Inventory reserve	$	6,801	43,076		—		(4,736	)	$	45,141
Valuation allowance on deferred tax assets	$	1,547,441	—		(9,934	)	—		$	1,537,507
2013
Allowance for doubtful accounts	$	32,847	(1,880	)	(294	)	(3,539	)	$	27,134
Inventory reserve	$	6,645	3,270		(366	)	(2,748	)	$	6,801
Valuation allowance on deferred tax assets	$	1,520,852	—		26,589		—		$	1,547,441
2012
Allowance for doubtful accounts	$	41,703	(5,979	)	179		(3,056	)	$	32,847
Inventory reserve	$	6,984	(3,141	)	9		2,793		$	6,645
Valuation allowance on deferred tax assets	$	1,485,540	—		35,312		—		$	1,520,852

We revised the 2013 inventory reserve amounts for "Charged to Costs and Expenses" and "Balance at End of Period" to correct an error, which management determined is not material. This revision has no impact on the financial statements and related footnote disclosures.

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Readability	8th grade Avg

Nabors Industries (NBR) 10-K2014 FY Annual report

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