10-K 1 a13-2327_110k.htm 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

 

x

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

 

For the fiscal year ended December 31, 2012

 

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

 

980363970

(State or Other Jurisdiction of Incorporation or
Organization)

 

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

 

 

 

Crown House, Second Floor

 

 

4 Par-la-Ville Road

 

 

Hamilton, HM08

 

 

Bermuda

 

N/A

(Address of principal executive offices)

 

(Zip Code)

 

(441) 292-1510

(Registrant’s telephone number, including area code)

 

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

 

 

 

Name of each

Title of each class

 

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 x  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 x

 

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 x  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.  YES x  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. x

 

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 x

 

Accelerated Filer o

 

 

 

Non-accelerated Filer o

 

Smaller Reporting Company o

 

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

 

The aggregate market value of the 275,797,408 common shares, par value $.001 per share, held by non-affiliates of the registrant, based upon the closing price of our common shares as of the last business day of our most recently completed second fiscal quarter, June 29, 2012, of $14.40 per share as reported on the New York Stock Exchange, was $3,971,482,675. Common shares held by each officer and director and by each person who owns 5% or more of the outstanding common shares have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

 

The number of common shares, par value $.001 per share, outstanding as of February 25, 2013 was 291,036,865.

 

DOCUMENTS INCORPORATED BY REFERENCE (to the extent indicated herein)

 

Specified portions of the definitive Proxy

Statement to be distributed in connection with our 2013 Annual General Meeting of Shareholders (Part III).

 

 

 



Table of Contents

 

NABORS INDUSTRIES LTD.

Form 10-K Annual Report

For the Year Ended December 31, 2012

 

Table of Contents

 

 

PART I

 

Item 1.

Business

4

Item 1A.

Risk Factors

11

Item 1B.

Unresolved Staff Comments

15

Item 2.

Properties

15

Item 3.

Legal Proceedings

25

Item 4.

Mine Safety Disclosures

26

 

 

 

 

PART II

 

Item 5.

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

27

Item 6.

Selected Financial Data

30

Item 7.

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

32

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

57

Item 8.

Financial Statements and Supplementary Data

59

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

143

Item 9A.

Controls and Procedures

143

Item 9B.

Other Information

144

 

 

 

 

PART III

 

Item 10.

Directors, Executive Officers and Corporate Governance

145

Item 11.

Executive Compensation

145

Item 12.

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

146

Item 13.

Certain Relationships and Related Transactions and Director Independence

147

Item 14.

Principal Accounting Fees and Services

147

 

 

 

PART IV

Item 15.

Exhibits, Financial Statement Schedules

148

 

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

 

FORWARD-LOOKING STATEMENTS

 

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

 

You should consider the following key factors when evaluating these forward-looking statements:

 

·               fluctuations in worldwide prices of and demand for oil and natural gas;

 

·               fluctuations in levels of oil and natural gas exploration and development activities;

 

·               fluctuations in the demand for our services;

 

·               the existence of competitors, technological changes and developments in the oilfield services industry;

 

·               the existence of operating risks inherent in the oilfield services industry;

 

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

 

·               the possibility of political instability, war or acts of terrorism; and

 

·               general economic conditions including the capital and credit markets.

 

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

 

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

 

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

 

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PART I

 

ITEM 1. BUSINESS

 

Introduction

 

Nabors is the largest land drilling contractor in the world and one of the largest land well-servicing and workover contractors in the United States and Canada:

 

·                  We actively market approximately 474 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada and over 20 other countries throughout the world.

 

·                  We actively market approximately 442 rigs for land well-servicing and workover work in the United States and approximately 106 rigs for land well-servicing and workover work in Canada.

 

We are also a leading provider of offshore platform workover and drilling rigs, and actively market 36 platform, 12 jackup and 4 barge rigs in the United States, including the Gulf of Mexico, and multiple international markets.

 

In addition to the foregoing services:

 

·                  We provide completion and production services, including hydraulic fracturing, cementing, nitrogen and acid pressure pumping services with over 805,000 hydraulic horsepower in key basins throughout the United States and Canada.

 

·                  We offer a wide range of ancillary well-site services, including engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select U.S. and international markets.

 

·                  We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software.

 

·                  We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets nine rigs in addition to the rigs we lease to the joint venture.

 

Nabors was formed as a Bermuda exempted company on December 11, 2001. Through predecessors and acquired entities, Nabors has been continuously operating in the drilling sector since the early 1900s. Our principal executive offices are located at Crown House, 4 Par-la-Ville Road, Second Floor, Hamilton, HM08, Bermuda, and our phone number there is (441) 292-1510.

 

Our Rig Fleet

 

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

 

Special-purpose drilling rigs used to perform workover services consist of a mobile carrier, which includes an engine, drawworks and a mast, together with other standard drilling accessories and specialized equipment for servicing wells. These rigs are specially designed for major repairs and modifications of oil and gas wells, including standard drilling functions.  A well-servicing rig is specially designed for periodic maintenance of oil and gas wells for which service is required to maximize the productive life of the wells.  The primary function of a well-servicing rig is to act as a hoist so that pipe, sucker rods and down-hole equipment can be run into and out of a well, although they also can perform standard drilling functions.  Because of size and cost considerations, these specially designed rigs are used for these operations rather than larger drilling rigs typically used for initial drilling.

 

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Land-based drilling rigs are moved between well sites and among geographic areas using our fleet of cranes, loaders and transport vehicles or those of third-party service providers. Well-servicing rigs are typically self-propelled, while heavier capacity workover rigs are either self-propelled or trailer-mounted and include auxiliary equipment, which is either transported on trailers or moved with trucks.

 

·             Platform Rigs. Platform rigs provide offshore workover, drilling and re-entry services. Our platform rigs have drilling and/or well-servicing or workover equipment and machinery arranged in modular packages that are transported to, and assembled and installed on, fixed offshore platforms owned by the customer. Fixed offshore platforms are steel tower-like structures that either stand on the ocean floor or are moored floating structures. The top portion, or platform, sits above the water level and provides the foundation upon which the platform rig is placed.

 

·             Jackup Rigs. Jackup rigs are mobile, self-elevating drilling and workover platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the hull, which contains the drilling and/or workover equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. The rig legs may operate independently or have a mat attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas. Many of our jackup rigs are of cantilever design — a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over adjacent, fixed platforms.  Our shallow workover jackup rigs are typically limited to a maximum water depth of approximately 125 feet, and some may drill in water depths as shallow as 13 feet.  We also have deeper water jackup rigs capable of drilling at depths between eight feet and 150 to 250 feet. The water depth limit of a particular rig is determined by the length of its legs and by the operating environment. Moving a rig from one drill site to another involves lowering the hull down into the water until it is afloat and then jacking up its legs. The rig is then towed to the new drilling site.

 

·             Inland Barge Rigs. One of Nabors’ barge rigs is a full-size drilling unit. We also own two workover inland barge rigs. These barges are designed to perform plugging and abandonment, well-service or workover services in shallow inland, coastal or offshore waters. Our barge rigs can operate at depths between three and 20 feet.

 

Additional information regarding the geographic markets in which we operate and our business segments can be found in Note 22 — Segment Information in Part II, Item 8. — Financial Statements and Supplementary Data.

 

Types of Drilling Contracts

 

In the U.S. Lower 48 states and Canada, we typically enter into contracts for land-based drilling with durations ranging from one to three years. Under these contracts, our rigs are committed to one customer. Our more recent contracts for newly constructed rigs have multi-year terms. Contracts relating to offshore drilling and land drilling in Alaska and international markets generally have one- to five-year terms. Offshore workover projects are often contracted on a single-well basis. We generally receive drilling contracts through competitive bidding, although we occasionally enter into contracts by direct negotiation. Most of our single-well contracts are subject to termination by the customer on short notice, but some can be firm for a number of wells or a period of time, and may provide for early termination compensation in certain circumstances. Contract terms and rates differ depending on a variety of factors, including competitive conditions, the geographical area, the geological formation to be drilled, the equipment and services to be supplied, the on-site drilling conditions and the anticipated duration of the work to be performed.

 

In recent years, most of our drilling contracts have been daywork contracts. A daywork contract generally provides for a basic rate per day when drilling (the dayrate for our providing a rig and crew) and for lower rates when the rig is moving, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. In addition, daywork contracts may provide for a lump-sum fee for the mobilization and demobilization of the rig, which in most cases approximates our incurred costs. A daywork contract differs from a footage contract (in which the drilling contractor is paid on the basis of a rate per foot drilled) and a turnkey contract (in which the drilling contractor is paid for drilling a well to a specified depth for a fixed price).

 

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Completion Services

 

We provide a wide range of wellsite solutions to oil and natural gas companies, consisting primarily of technical pumping services, including hydraulic fracturing, a process sometimes used in the completion of oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and oil production, and down-hole surveying services.  The completion process may involve selectively perforating the well casing at the depth of discrete producing zones, stimulating and testing these zones and installing down-hole equipment. The completion process may take a few days to several weeks. We are paid an hourly rate and work is generally performed seven days a week, 24 hours a day.

 

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

 

In 2012, approximately 3.3% of revenues from our Completion Services operating segment came from a Nabors consolidated entity and an unconsolidated Nabors affiliate.  Our proportionate share of any profits resulting from sales to affiliates were eliminated in consolidation.

 

U.S. Production Services

 

Although some wells in the United States flow oil to the surface without mechanical assistance, most are in mature production areas that require pumping or some other form of artificial lift. Pumping wells characteristically require more maintenance than flowing wells because of the mechanical pumping equipment.

 

·             Well-servicing/Maintenance Services. We provide maintenance services on the mechanical apparatus used to pump or lift oil from producing wells. These services include, among other activities, repairing and replacing pumps, sucker rods and tubing. They also occasionally include drilling services.  We provide the rigs, equipment and crews for these tasks, which are performed on both oil and natural gas wells, but which are more commonly required on oil wells. Maintenance services typically take less than 48 hours to complete. Rigs generally are provided to customers on a call-out basis. We are paid an hourly rate, and work typically is performed five days a week during daylight hours.

 

·             Workover Services. Producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workovers may be required to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks or convert a depleted well to an injection well for secondary or enhanced recovery projects.  Workovers normally are carried out with a rig that includes standard drilling accessories such as rotary drilling equipment, pumps and tanks for drilling fluids, blowout preventers and other specialized equipment for servicing rigs.  A workover may last anywhere from a few days to several weeks. We are paid a daily rate and work is generally performed seven days a week, 24 hours a day.

 

·             Production and Other Specialized Services. We can also provide other specialized services, including onsite temporary fluid storage; the supply, removal and disposal of specialized fluids used during certain completion and workover operations; and the removal and disposal of salt water that often accompanies the production of oil and natural gas. We also provide plugging services for wells where the oil and natural gas has been depleted or further production has become uneconomical. We are paid an hourly or a per-unit rate, as applicable, for these services.

 

Oil and Gas Investments

 

In 2007, we began investing in oil and gas exploration, development and production operations in the United States, Canada and Colombia.  We had wholly owned operations as well as three unconsolidated joint ventures, which were accounted for by the equity method in these geographic areas.

 

During 2010, we began marketing our oil and gas assets in Canada and Colombia. During the fourth quarter of 2011, we announced our intention to dispose of virtually all of our remaining oil and gas investment portfolio.  We sold some of these assets in 2011 and 2012, and continue marketing others.

 

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

 

Other Services

 

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

 

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

 

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

 

Our Customers

 

Our customers include major, national and independent oil and gas companies. No customer accounted for more than 10% of our consolidated revenues in 2012 or 2011.

 

Our Employees

 

As of December 31, 2012, we employed approximately 27,500 people, of whom approximately 3,000 were employed by unconsolidated affiliates. We believe our relationship with our employees is generally good.

 

Some rig employees in Alaska, Argentina and Australia are represented by collective bargaining units.

 

Seasonality

 

Our Canada and Alaska drilling and workover operations are subject to seasonal variations as a result of weather conditions and generally experience reduced levels of activity and financial results during the second quarter of each year. In addition, our pressure pumping operations located in the Appalachian, Mid-Continent, and Rocky Mountain regions of the United States can be adversely affected by seasonal weather conditions, primarily in the spring, as many municipalities impose weight restrictions on the paved roads leading to our jobsites due to the muddy conditions caused by spring thaws.  Global warming could lengthen these periods of reduced activity, but we cannot currently estimate to what degree.  Our overall financial results reflect the seasonal variations experienced in these operations, but seasonality does not materially impact the remaining portions of our business.

 

Research and Development

 

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

 

Industry/Competitive Conditions

 

To a large degree, our businesses depend on the level of capital spending by oil and gas companies for exploration, development and production activities. A sustained increase or decrease in the price of oil and natural gas could have a material impact on the exploration, development and production activities of our customers and could materially affect our financial position, results of operations and cash flows. See Part I, Item 1A. — Risk Factors — Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows and profitability.

 

Our industry remains competitive. The number of available rigs exceeds demand in many of our markets, resulting in strong price competition. Many rigs can be readily moved from one region to another in response to

 

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changes in levels of activity, which may result in an oversupply of rigs in an area.  Many of the total available contracts are currently awarded on a bid basis, which further increases competition based on price. The land drilling, workover, pressure pumping and well-servicing market is generally more competitive than the offshore market due to the larger number of rigs and market participants.

 

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

 

Certain competitors are present in more than one of our operating regions, although no one competitor operates in all of these areas. In the U.S. Lower 48 states, we compete with Helmerich and Payne, Inc. and Patterson-UTI Energy, Inc., and several hundred other competitors with national, regional or local rig operations. In our U.S. Production Services operating segment, we compete with Basic Energy Services, Inc., Key Energy Services, Inc., Superior Energy Services, Inc. (formerly, Complete Energy Services, Inc.), Forbes Energy Services Ltd. and numerous other competitors having smaller regional or local rig operations. In Canada and U.S. Offshore, we compete with many firms of varying size, several of which have more significant operations in those areas than Nabors. Elsewhere, we compete directly with various contractors at each location where we operate. Our Completion Services operating segment competes with large operators such as Halliburton, Baker Hughes, Weatherford International Ltd., Schlumberger Limited, and FTS International Services LLC as well as smaller companies such as C&J Energy Services, Inc., RPC, Inc. and other small and mid-sized independent contractors, as well as major oilfield services companies with operations outside of the United States. We believe that the market for land drilling, well-servicing and workover and pressure pumping contracts will continue to be competitive for the foreseeable future.

 

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

 

Our Business Strategy

 

Our strategy is to position Nabors to grow and prosper when market conditions are good and to mitigate adverse effects when market conditions are bad. During 2012, we sought to strengthen our balance sheet, which enhances stability, reduces our borrowing costs and allows us to better navigate challenges and capitalize on market opportunities. In addition to the foregoing, the principal elements of our strategy to build shareholder value are to:

 

·                  Leverage our global infrastructure;

 

·                  Achieve superior health, safety and environmental performance;

 

·                  Achieve superior operational performance;

 

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

 

·                  Enhance and leverage our technology position; and

 

·                  Achieve returns well above our cost of capital.

 

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During 2012, we formed two business lines to provide a solid foundation for sustained long-term growth, leveraging the benefits of our size and becoming a more customer-focused organization. We believe the deployment of our newer and higher-margin rigs under long-term contracts will also enhance our competitive position.

 

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

 

·                  Emphasize execution and operational excellence in our core businesses;

 

·                  Impose more stringent investment criteria for new projects;

 

·                  Optimize intra-company synergies and technological advancements; and

 

·                  Monetize nonperforming and nonstrategic assets.

 

Acquisitions and Divestitures

 

We have grown from a land drilling business centered in the U.S. Lower 48 states, Canada and Alaska to an international business with operations on land and offshore in most of the major oil and gas markets in the world. At the beginning of 1990, our fleet consisted of 44 actively marketed land drilling rigs in Canada, Alaska and in various international markets. Today, our worldwide fleet of actively marketed rigs consists of 474 land drilling rigs, 548 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jackup units, barge rigs and a large component of trucks and fluid hauling vehicles. This growth was fueled in part by strategic acquisitions. Although Nabors continues to examine opportunities, there can be no assurance that attractive rigs or other acquisition opportunities will continue to be available, that the pricing will be economical or that we will be successful in making such acquisitions in the future.

 

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

 

Acquisitions

 

In September 2010, we acquired through a tender offer and merger all of the outstanding common stock of Superior Well Services, Inc. (“Superior”) at a cash purchase price of $22.12 per share, or approximately $681.3 million in the aggregate.  The purchase price was allocated to the net tangible and intangible assets acquired and liabilities assumed based on their fair value at the acquisition date.  The excess of the purchase price over such fair values was $335.0 million and was recorded as goodwill.  Our added services include a wide range of wellsite solutions to oil and natural gas companies, primarily technical pumping services and down-hole surveying services. During 2012, we ceased using the Superior trade name, and in May 2012, we renamed the entity Nabors Completion and Production Services (“NCPS”) and we merged our U.S. Production Services.

 

In December 2010, we purchased the business of Energy Contractors LLC (“Energy Contractors”) for a total cash purchase price of $53.4 million.  The assets were comprised of vehicles and rig equipment and are included in our U.S. Production Services operating segment.  The purchase price was allocated to the net tangible and intangible assets acquired based on their preliminary fair value estimates as of December 31, 2010.  The excess of the purchase price over the fair value of the assets acquired was recorded as goodwill in the amount of $4.2 million.

 

In July 2011, we paid $65 million in cash to acquire the remaining 50 percent equity interest of Peak, making it a wholly owned subsidiary.  Previously, we held a 50 percent equity interest with a carrying value of $38.1 million that we had accounted for as an equity method investment.  As a result of the acquisition, we consolidated the assets and liabilities of Peak during the third quarter of 2011 based on their respective fair values. The excess of the estimated fair value of the assets and liabilities over the net carrying value of our previously held equity interest

 

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resulted in a gain of $13.1 million and is reflected in losses (gains) on sales and disposals of long-lived assets and other expense (income) for 2011. The excess of the purchase price over the fair value was $8.0 million and was recorded as goodwill.

 

Divestitures

 

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

 

In 2012, we sold our remaining wholly owned oil and gas business in Colombia and sold additional wholly owned assets in the United States. In December 2012, we sold our 49.7% ownership interest in NFR Energy LLC (“NFR Energy”), the 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 sales of oil and gas assets.

 

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

 

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Environmental Compliance

 

We do not currently anticipate that compliance with currently applicable environmental regulations and controls will significantly change our competitive position, capital spending or earnings during 2013. We believe we are in material compliance with applicable environmental rules and regulations, and the cost of such compliance is not material to our business or financial condition. For a more detailed description of the environmental laws and regulations applicable to our operations, see Part I, Item 1A. — Risk Factors — Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect our results of operations.

 

ITEM 1A.  RISK FACTORS

 

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

 

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

 

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

 

Our operations depend on the level of spending by oil and gas companies for exploration, development and production activities.  Both short-term and long-term trends in oil and natural gas prices affect these levels.  Oil and natural gas prices, as well as the level of drilling, exploration and production activity, can be highly volatile. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, affect both the demand for, and the supply of, oil and natural gas.  Weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, and other factors beyond our control may also affect the supply of and demand for oil and natural gas. Lower oil and natural gas prices have caused some of our customers to terminate, seek to renegotiate or fail to honor our drilling contracts and affected the fair market value of our rig fleet, which in turn has resulted in impairments of our assets.  A sustained or further decline in oil and natural gas prices could adversely impact our cash forecast models used to determine whether the carrying value of our long-lived assets exceed our future cash flows, which could result in future impairment to our long-lived assets. A prolonged period of lower oil and natural gas prices could affect our ability to retain skilled rig personnel and affect our ability to access capital to finance and grow our business. There can be no assurances as to the future level of demand for our services or future conditions in the oil and natural gas and oilfield services industries.

 

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

 

The oilfield services industry is very competitive. Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Many drilling, workover and well-servicing rigs can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of rigs in an area. In many markets where we operate, the number of rigs available for use exceeds the demand for rigs, resulting in price competition. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. The land drilling market generally is more competitive than the offshore drilling market because there are larger numbers of rigs and competitors.

 

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

 

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

 

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grounding, collision, damage from hurricanes and heavy weather or sea conditions and unsound ocean bottom conditions. Our operations are also subject to risks of war, civil disturbances or other political events.

 

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

 

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

 

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

 

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

 

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

 

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

 

As of December 31, 2012, we had long-term debt outstanding of approximately $4.4 billion. We also have various commitments for leases, firm transportation and processing, and purchase commitments. Our ability to service our debt and other obligations depends in large part upon the level of cash flows generated by our subsidiaries’ operations, possible dispositions of non-core assets, availability under our unsecured revolving credit facility and our ability to access the capital markets.

 

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

 

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

 

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

 

The successful execution of the strategies central to our future success will depend, in part, on a few of our key executive officers.  We have an employment agreement with  our Chairman, President and Chief Executive Officer, Anthony G. Petrello, with a term through March 30, 2015, and other key personnel within the company. We do not carry significant amounts of key man insurance.  Our operations depend, in part, on our ability to attract and retain experienced technical professionals. Competition for such professionals is intense. The loss of Mr. Petrello or other key executive officers, or our inability to attract or retain experienced technical personnel, could harm our ability to compete.

 

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

 

Drilling of oil and gas wells is subject to various laws, rules and regulations in the various jurisdictions in where we operate. Our cost of compliance with these laws may be substantial. For example,  the U.S. Environmental Protection Agency (“EPA”) has promulgated rules requiring the reporting of greenhouse gas emissions applicable to certain offshore oil and natural gas production and onshore oil and natural gas production, processing, transmission, storage and distribution facilities beginning in 2012 for emissions occurring in 2011.  In addition, U.S. federal law imposes on “responsible parties” a variety of regulations related to the prevention of oil spills, release of hazardous substances, and liability for removal costs and natural resource, real or personal property and certain economic damages arising from such incidents. Some of these laws may impose strict and/or joint and several liability for these costs and damages without regard to the conduct of the parties.  As an owner and operator of onshore and offshore rigs and 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.

 

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.

 

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. 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. The report could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. Legislation has also been introduced in the U.S. Congress and adopted or introduced in some states requiring disclosure of chemicals used in the fracturing process.  If enacted, the legislation could require fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping requirements and meet plugging and abandonment requirements.  EPA has indicated an intent to regulate wastewater discharges under the Federal Clean Water Act from hydraulic fracturing and other natural gas production.  In 2012, EPA also promulgated new rules establishing new air emission controls for oil and gas production and natural gas processing operations.  These rules require, among other things, controlling emissions through flaring until 2015 and thereafter through reduced emissions completions, as well as imposing new requirements on emissions from tanks and other equipment.   These rules and any other new laws regulating production and completion activities could cause operational delays, increased costs of compliance or increased costs in exploration and production, which could adversely affect our business and the demand for fracturing services.

 

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.   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.

 

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

 

As of February 25, 2013, we had 800,000,000 authorized common shares, of which 319,449,700 shares were outstanding. In addition, 37,726,170 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 deter a change-of-control transaction and decrease the likelihood of a shareholder receiving a change-of-control premium; conversely, those provisions may be insufficient to thwart an attempt to acquire control without paying a control premium

 

The Board of Directors has the authority to issue a significant number of common shares and up to 25,000,000 preferred shares, and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of the preferred shares, without any vote or action by shareholders.  In 2012, the Board of Directors adopted a shareholder rights plan that limits the voting power a person can acquire without either securing the approval of the Board or having their voting interest diluted.  The plan will expire in July 2013 unless it is extended.  Although these provisions are designed to enhance the ability of the Board to negotiate with a potential acquiror to ensure that all shareholders receive fair value in exchange for control of the Company, they may also discourage potential acquirors and thus reduce the possibility of a takeover and therefore the likelihood that shareholders would receive a premium for their shares.

 

Conversely, we declassified our Board in 2012, which makes it easier for another party to acquire control of the Company.  If the shareholder rights plan is not extended beyond July 2013, the ability of the Board to maximize value for all shareholders in a change-of-control transaction may be further diminished.

 

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We may have additional tax liabilities

 

We are subject to income taxes in the United States and numerous other jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly audited by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than what is reflected in income tax provisions and accruals. An audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows in the period or periods challenged.  It is also possible that future changes to tax laws (including tax treaties) could impact our ability to realize the tax savings recorded to date.

 

Proposed tax legislation could mitigate or eliminate the benefits of our 2002 reorganization as a Bermuda company

 

Various bills have been introduced in the U.S. Congress that could reduce or eliminate the tax benefits associated with our 2002 reorganization as a Bermuda company. There has been and we expect that there may continue to be legislation proposed by the U.S. Congress from time to time which, if enacted, could limit or eliminate the tax benefits associated with our reorganization. No assurance can be given that the tax benefits associated with our reorganization will continue to accrue to the benefit of the Company and its shareholders.

 

Legal proceedings could affect our financial condition and results of operations

 

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

 

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

 

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

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

Not applicable.

 

ITEM 2. PROPERTIES

 

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

 

Many of the international drilling rigs and some of the Alaska rigs in our fleet are supported by mobile camps which house the drilling crews and a significant inventory of spare parts and supplies. In addition, we own various

 

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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.

 

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.

 

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

 

The estimates of net proved oil and gas reserves as of December 31, 2010 were based on reserve reports prepared by the following independent petroleum engineers.  AJM Petroleum Consultants prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Canada. Miller and Lents, Ltd. prepared reports of estimated proved oil and gas reserves for our wholly owned assets and interests in oil and natural gas properties located in the United States; Netherland, Sewell & Associates, Inc., prepared reports of estimated proved oil reserves for certain properties located in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California; and Lonquist & Co., LLC prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Colombia.

 

Summary of Oil and Gas Reserves

 

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

 

For our wholly owned properties in the lower 48 states, the prices used in the reserve reports were $2.75 per thousand cubic feet of natural gas (“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 Alaska, the price used in our reserve report was $110.56 per barrel for oil at December 31, 2012. For our wholly owned properties in Canada, the price used in our reserve report was $1.05 per mcf for the 12-month average of natural gas at December 31, 2012.

 

No major discovery or other favorable or adverse event has occurred since December 31, 2012 that would cause a significant change in the estimated proved reserves as of that date.

 

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Reserves

 

 

 

Liquids

 

Natural Gas

 

Reserve category

 

(MMBbls)

 

(Bcf)

 

As of December 31, 2012:

 

 

 

 

 

Proved

 

 

 

 

 

Developed

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

United States

 

1.1

 

0.4

 

Canada

 

 

7.7

 

Colombia

 

 

 

Total consolidated

 

1.1

 

8.1

 

Equity Company (1)

 

 

 

 

 

United States

 

 

 

Total equity company

 

 

 

Total developed

 

1.1

 

8.1

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

United States

 

14.3

 

0.7

 

Canada

 

 

 

Colombia

 

 

 

Total consolidated

 

14.3

 

0.7

 

Equity Company (1)

 

 

 

 

 

United States

 

 

 

Total equity company

 

 

 

Total undeveloped

 

14.3

 

0.7

 

Total proved

 

15.4

 

8.8

 

 

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Table of Contents

 

 

 

Reserves

 

 

 

Liquids

 

Natural Gas

 

Reserve category

 

(MMBbls)

 

(Bcf)

 

As of December 31, 2011:

 

 

 

 

 

Proved

 

 

 

 

 

Developed

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

United States

 

0.9

 

13.6

 

Canada

 

 

8.2

 

Colombia

 

 

 

Total consolidated

 

0.9

 

21.8

 

Equity Companies (1)

 

 

 

 

 

United States

 

6.3

 

256.4

 

Canada

 

 

 

Colombia

 

 

 

Total equity companies

 

6.3

 

256.4

 

Total developed

 

7.2

 

278.2

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

United States

 

0.9

 

3.3

 

Canada

 

 

 

Colombia

 

 

 

Total consolidated

 

0.9

 

3.3

 

Equity Companies (1)

 

 

 

 

 

United States

 

9.6

 

326.1

 

Canada

 

 

 

Colombia

 

 

 

Total equity companies

 

9.6

 

326.1

 

Total undeveloped

 

10.5

 

329.4

 

Total proved

 

17.7

 

607.6

 

 

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Reserves

 

 

 

Liquids

 

Natural Gas

 

Reserve category

 

(MMBbls)

 

(Bcf)

 

As of December 31, 2010:

 

 

 

 

 

Proved

 

 

 

 

 

Developed

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

United States

 

2.7

 

17.1

 

Canada

 

 

5.5

 

Colombia

 

1.6

 

 

Total consolidated

 

4.3

 

22.6

 

Equity Companies (1)

 

 

 

 

 

United States

 

3.0

 

147.1

 

Canada

 

 

5.2

 

Colombia

 

0.5

 

 

Total equity companies

 

3.5

 

152.3

 

Total developed

 

7.8

 

174.9

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

United States

 

18.5

 

2.7

 

Canada

 

 

 

Colombia

 

0.4

 

 

Total consolidated

 

18.9

 

2.7

 

Equity Companies (1)

 

 

 

 

 

United States

 

4.9

 

405.7

 

Canada

 

 

 

Colombia

 

1.4

 

 

Total equity companies

 

6.3

 

405.7

 

Total undeveloped

 

25.2

 

408.4

 

Total proved

 

33.0

 

583.3

 

 


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

 

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines.  Furthermore, we record proved reserves only for projects that have received significant funding commitments by management made toward the development of the reserves.  Although we are reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and natural gas price levels.

 

Technologies Used in Establishing Proved Reserves Additions in 2012

 

Proved reserves were based on estimates generated through the integration of available and appropriate data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

 

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 2-D and 3-D seismic data, calibrated with available well control. Where applicable, surface geological information was also utilized. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software and commercially available data analysis packages.

 

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In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

 

Internal Controls over Proved Reserves

 

We maintain computerized records of our reserve estimates and production data. Appropriate controls, including limitations on access and updating capabilities, are in place to ensure data integrity. We engage qualified third-party reservoir engineers and perform reviews to ensure reserve estimations include all properties owned and are based on correct working and net revenue interests.  Key components of the reserve estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to reserve estimates unless these changes have been thoroughly reviewed and evaluated by authorized company personnel. After all changes are made, senior management reviews the estimates for final endorsement.

 

Proved Undeveloped Reserves

 

Our total estimated PUD reserves of approximately 86 billion cubic feet equivalent (“Bcfe”) as of December 31, 2012 decreased by 306 Bcfe from the 392 Bcfe of PUD reserves estimated at the end of 2011.  During the year, we sold NFR Energy, which reported 384 Bcfe of PUD reserves at the end of 2011.  Also during the year, we converted 72 Bcfe on the North Slope, Alaska.  At December 31, 2012, our PUD reserves represented 85% of the 101 Bcfe reported in proved reserves.

 

During 2012, approximately $6.8 million was spent on projects associated with reserves that were carried as PUD reserves at the end of 2011.  We completed development work that resulted in the transfer of approximately 0.6 Bcfe from proved undeveloped to proved developed reserves during 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 and 2011. Production costs are costs to operate and maintain our wells and related equipment and include the cost of labor, well-service and repair, location maintenance, power and fuel, transportation, cost of product, property taxes and production-related general and administrative costs.

 

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United States

 

Canada

 

Colombia

 

Total

 

 

 

Liquids

 

Natural
Gas

 

Liquids

 

Natural
Gas

 

Liquids

 

Natural
Gas

 

Liquids

 

Natural
Gas

 

 

 

(MMBbls)

 

(Bcf)

 

(MMBbls)

 

(Bcf)

 

(MMBbls)

 

(Bcf)

 

(MMBbls)

 

(Bcf)

 

As of December 31, 2012:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas liquids production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

0.268

 

0.938

 

 

2.00

 

0.003

 

 

0.271

 

2.938

 

Equity companies (1)

 

0.545

 

19.01

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

$

76.74

 

$

3.04

 

$

 

$

2.36

 

$

130.04

 

$

 

$

77.33

 

$

2.58

 

Equity companies (1)

 

$

53.94

 

$

2.70

 

$

 

$

 

$

 

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production costs ($/bce):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

 

 

$

3.52/Mcfe

(2)

 

 

$

2.91/Mcfe

 

$

31.75/Boe

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

$

1.47/Mcfe

 

 

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas liquids production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

0.140

 

2.944

 

 

2.117

 

0.111

 

0.011

 

0.251

 

5.072

 

Equity companies (1)

 

0.409

 

18.634

 

 

0.380

 

0.316

 

 

0.725

 

19.014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

$

88.94

 

$

4.09

 

$

 

$

3.33

 

$

111.57

 

$

5.00

 

$

98.91

 

$

3.77

 

Equity companies (1)

 

$

58.16

 

$

4.03

 

$

 

$

3.48

 

$

84.47

 

$

 

$

69.63

 

$

4.02

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production costs ($/bce):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

 

 

$

3.35/Mcfe

(2)

 

 

$

12.96/Mcfe

 

$

32.98/Boe

(2)

 

 

 

 

 

 

Equity companies (1)

 

 

 

$

1.32/Mcfe

 

 

 

$

11.99/Mcfe

 

$

33.49/Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2010:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas liquids production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

0.073

 

3.533

 

 

3.058

 

0.230

 

 

0.303

 

6.591

 

Equity companies (1)

 

0.249

 

12.338

 

 

1.535

 

0.273

 

 

0.522

 

13.873

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

$

63.77

 

$

4.19

 

$

 

$

3.69

 

$

72.25

 

$

 

$

70.19

 

$

2.71

 

Equity companies (1)

 

$

74.86

 

$

4.43

 

$

 

$

3.93

 

$

73.90

 

$

 

$

58.59

 

$

4.11

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production costs ($/bce):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 

 

 

$

2.14/Mcfe

 

 

 

$

2.60/Mcfe

 

$

34.42/Boe

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

$

1.33/Mcfe

 

 

 

$

5.89/Mcfe

 

$

33.60/Boe

 

 

 

 

 

 

 

 


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

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

 

Drilling and Other Exploratory and Development Activities

 

During 2012, 2011 and 2010, our drilling program focused on proven and emerging oil and natural gas basins in the United States.  Our drilling program included development activities with properties located in the United States, Canada and Colombia that are being actively marketed. The following tables provide the number of oil and gas wells completed during 2012, 2011 and 2010.

 

21



Table of Contents

 

Number of Net Productive and Exploratory Wells Drilled

 

 

 

Net Productive Exploratory

 

Net Dry Exploratory

 

 

 

Wells Drilled

 

Wells Drilled

 

For the year ended December 31, 2012:

 

 

 

 

 

Consolidated subsidiaries

 

 

 

 

 

United States

 

2.40

 

 

Canada

 

 

 

Colombia

 

1.15

 

 

Total consolidated

 

3.55

 

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

 

 

United States

 

1.49

 

 

Canada

 

 

 

Colombia

 

 

 

Total equity companies

 

1.49

 

 

 

 

 

 

 

 

For the year ended December 31, 2011:

 

 

 

 

 

Consolidated subsidiaries

 

 

 

 

 

United States

 

5.14

 

3.63

 

Canada

 

3.00

 

4.00

 

Colombia

 

 

 

Total consolidated

 

8.14

 

7.63

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

 

 

United States

 

 

 

Canada

 

 

 

Colombia

 

 

 

Total equity companies

 

 

 

 

 

 

 

 

 

For the year ended December 31, 2010:

 

 

 

 

 

Consolidated subsidiaries

 

 

 

 

 

United States

 

1.90

 

 

Canada

 

 

 

Colombia

 

4.20

 

 

Total consolidated

 

6.10

 

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

 

 

United States

 

0.90

 

 

Canada

 

 

 

Colombia

 

3.30

 

2.10

 

Total equity companies

 

4.20

 

2.10

 

 


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

 

22



Table of Contents

 

 

 

Net Productive Development

 

Net Dry Development

 

 

 

Wells Drilled

 

Wells Drilled

 

For the year ended December 31, 2012:

 

 

 

 

 

Consolidated subsidiaries

 

 

 

 

 

United States

 

6.50

 

 

Canada

 

 

 

Colombia

 

 

 

Total consolidated

 

6.50

 

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

 

 

United States

 

3.48

 

 

Canada

 

 

 

Colombia

 

 

 

Total equity companies

 

3.48

 

 

 

 

 

 

 

 

For the year ended December 31, 2011:

 

 

 

 

 

Consolidated subsidiaries

 

 

 

 

 

United States

 

2.04

 

3.28

 

Canada

 

 

 

Colombia

 

2.00

 

1.40

 

Total consolidated

 

4.04

 

4.68

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

 

 

United States

 

10.45

 

 

Canada

 

 

 

Colombia

 

 

 

Total equity companies

 

10.45

 

 

 

 

 

 

 

 

For the year ended December 31, 2010:

 

 

 

 

 

Consolidated subsidiaries

 

 

 

 

 

United States

 

1.20

 

0.10

 

Canada

 

 

 

Colombia

 

 

 

Total consolidated

 

1.20

 

0.10

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

 

 

United States

 

9.50

 

 

Canada

 

 

 

Colombia

 

1.60

 

 

Total equity companies

 

11.10

 

 

 


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

 

Present Activities

 

The following table provides the number of wells in the process of drilling as of December 31, 2012.

 

Wells Drilled

 

 

 

United States

 

Canada

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Consolidated subsidiaries

 

4.00

 

1.53

 

 

 

4.00

 

1.53

 

Equity companies (1)

 

 

 

 

 

 

 

 


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

 

23



Table of Contents

 

Oil and Gas Properties, Wells, Operations and Acreage

 

Gross and Net Productive Wells

 

 

 

For the year ended

 

 

 

December 31, 2012

 

 

 

Gross

 

Net

 

 

 

 

 

 

 

Consolidated subsidiaries

 

 

 

 

 

United States

 

63

 

28

 

Canada

 

7

 

7

 

Colombia

 

 

 

Total consolidated

 

70

 

35

 

 

 

 

 

 

 

Equity companies (1)

 

 

 

 

 

United States

 

 

 

Canada

 

 

 

Colombia

 

 

 

Total equity companies

 

 

 

 


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

 

Gross and Net Developed Acreage

 

 

 

United States

 

Canada

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Consolidated subsidiaries

 

60,950

 

29,649

 

9,764

 

7,334

 

70,714

 

36,983

 

Equity companies (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 


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

 

Gross and Net Undeveloped Acreage

 

 

 

United States

 

Canada

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Consolidated subsidiaries

 

175,013

 

93,496

 

56,085

 

35,176

 

231,098

 

128,672

 

Equity companies (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 


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

 

24



Table of Contents

 

Lease Expirations of Net Acreage

 

 

 

United States

 

Canada

 

 

 

2013

 

2014

 

2015

 

2013

 

2014

 

2015

 

Consolidated subsidiaries (1)

 

4,754

 

14,836

 

17,966

 

12,244

 

 

417

 

Equity companies (2)

 

 

 

 

 

 

 

 


(1)                                 The carrying value of leases at December 31, 2012 was approximately $114 million.

(2)                                 No equity companies existed at December 31, 2012.

 

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

 

Additional information about our properties can be found in Notes 2 — Summary of Significant Accounting Policies, 18 — Commitments and Contingencies (under the caption Leases) 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.  The revenues and property, plant and equipment by geographic area for 2012, 2011 and 2010 can be found in Note 22 — Segment Information in Part I, Item 8. — Financial Statements and Supplementary Data. A description of our rig fleet is included under the caption Introduction in Part I, Item 1. — Business.

 

Management believes that our existing equipment and facilities are adequate to support our current level of operations as well as an expansion of drilling operations in those geographical areas where we may expand.

 

ITEM 3. LEGAL PROCEEDINGS

 

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

 

On July 5, 2007, we received an inquiry from the U.S. Department of Justice relating to its investigation of one of our vendors and compliance with the Foreign Corrupt Practices Act.  The inquiry related to transactions with and involving Panalpina, which provided freight forwarding and customs clearance services to some of our affiliates.  The inquiry focused on transactions in Kazakhstan, Saudi Arabia, Algeria and Nigeria.  The Audit Committee of our Board of Directors engaged outside counsel to review some of our transactions with this vendor, received periodic updates at its regularly scheduled meetings, and the Chairman of the Audit Committee received updates between meetings as circumstances warranted.  The investigation included a review of certain amounts paid to and by Panalpina in connection with obtaining permits for the temporary importation of equipment and clearance of goods and materials through customs.  Both the SEC and the Department of Justice have been advised of our investigation.  In April 2012, the SEC advised us that it concluded its review of this matter and did not intend to recommend any enforcement action against us.  In February 2013, the Department of Justice likewise advised us that it concluded its inquiry, also without recommending any enforcement action against us.

 

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Table of Contents

 

In 2009, the Court of Ouargla (in Algeria) entered a judgment of approximately $19.7 million against us related to alleged customs infractions in 2009.  We believe we did not receive proper notice of the judicial proceedings, and that the amount of the judgment is excessive 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.  We do not believe that a loss is probable and have not accrued any amounts related to this matter. If we are ultimately required to pay a fine or judgment related to this matter, the amount of the loss could range from approximately $140,000 to $19.7 million.

 

In March 2011, the Court of Ouargla entered a judgment of approximately $39.1 million 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, and is not payable pending appeal. We have appealed the ruling based on our understanding that the law in question applies only to resident entities incorporated under Algerian law. An intermediate court of appeals has upheld the lower court’s ruling, and we have appealed the matter to the Algeria Supreme Court.  While our payments were consistent with our historical operations in the country, and, we believe, those of other multinational corporations there, 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 $31.1 million in excess of amounts accrued.

 

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

 

On March 9, 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 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 $100 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.  On March 23, 2012, ERG filed and obtained an ex parte stay from the Supreme Court of Bermuda (Commercial Court), in a case styled as ERG Resources LLC v. Nabors Global Holdings II Limited, Case No. 2012: No. 110.  Nabors challenged the stay and, following a series of oral hearings on the matter, the Bermuda court discharged the stay by a ruling dated April 5, 2012.  Nabors completed the sale of Ramshorn’s Class A shares to a Parex affiliate on April 12, 2012, which mooted ERG’s application for a temporary injunction that was scheduled for hearing by the Texas court on April 13, 2012.  ERG retains its causes of action for monetary damages, but Nabors believes the claims are foreclosed by the terms of the agreement and are without factual or legal merit.  Although we are vigorously defending the lawsuit, its ultimate outcome cannot be determined at this time.

 

ITEM 4.  MINE SAFETY DISCLOSURES

 

Not applicable.

 

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Table of Contents

 

PART II

 

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

 

STOCK PERFORMANCE GRAPH

 

The following graph illustrates comparisons of five-year cumulative total returns among Nabors, the S&P 500 Index and the Dow Jones Oil Equipment and Services Index. Total return assumes $100 invested on December 31, 2007 in shares of Nabors, the S&P 500 Index, and the Dow Jones Oil Equipment and Services Index. It also assumes reinvestment of dividends and is calculated at the end of each calendar year, December 31, 2008 - 2012.

 

 

 

 

2008

 

2009

 

2010

 

2011

 

2012

 

Nabors Industries Ltd.

 

44

 

80

 

86

 

63

 

53

 

S&P 500 Index

 

63

 

80

 

92

 

94

 

109

 

Dow Jones Oil Equipment and Services Index

 

41

 

67

 

86

 

75

 

75

 

 

27



Table of Contents

 

Market and Share Prices

 

Our common shares are traded on the New York Stock Exchange under the symbol “NBR”. At February 25, 2013, there were approximately 1,525 shareholders of record.

 

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

 

2011

First quarter

 

30.70

 

21.50

 

 

Second quarter

 

32.47

 

22.43

 

 

Third quarter

 

27.63

 

12.26

 

 

Fourth quarter

 

20.69

 

11.05

 

2012

First quarter

 

22.73

 

16.36

 

 

Second quarter

 

17.84

 

12.40

 

 

Third quarter

 

16.83

 

12.77

 

 

Fourth quarter

 

15.50

 

12.75

 

 

The following table provides information relating to Nabors’ repurchase of common shares during the three months ended December 31, 2012:

 

Period
(In thousands, except per share amounts)

 

Total
Number of
Shares
Purchased
(1)

 

Average
Price
Paid per
Share (1)

 

Total Number
of Shares
Purchased as
Part of Publicly
Announced
Program

 

Approximate
Dollar Value of
Shares that May
Yet Be
Purchased
Under the
Program (2)

 

October 1 – October 31

 

2

 

$

14.01

 

 

 

November 1 – November 30

 

1

 

$

13.71

 

 

 

December 1 – December 31

 

2

 

$

14.67

 

 

 

 


(1)  Shares were withheld from employees and directors to satisfy certain tax withholding obligations due in connection with grants of stock under our 2003 Employee Stock Plan and option exercises from our 1996 Employee Stock Plan. The 2003 Employee Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-employee Directors and 1996 Employee Stock Plan provide for the withholding of shares to satisfy tax obligations, but do not specify a maximum number of shares that can be withheld for this purpose.  These shares were not purchased as part of a publicly announced program to purchase common shares.

 

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

 

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

 

Dividend Policy

 

We have not paid any cash dividends on our common shares since 1982. On February 22, 2013, our Board of Directors declared a cash dividend of $0.04 per share to the holders of our common shares as of March 11, 2013 to be paid on March 28, 2013.  The Board’s current intention is to pay cash dividends on a quarterly basis in the future.  However, the amounts and timing of future dividends are subject to approval by the Board and will depend on future business conditions, financial conditions, results of operations and other factors.

 

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Table of Contents

 

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).

 

29



Table of Contents

 

ITEM 6. SELECTED FINANCIAL DATA

Operating Data (1)(2)

 

 

 

Year Ended December 31,

 

 

 

2012

 

2011

 

2010

 

2009

 

2008

 

 

 

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

 

Revenues and other income:

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

6,989,573

 

$

6,060,351

 

$

4,134,483

 

$

3,662,220

 

$

5,394,225

 

Earnings (losses) from unconsolidated affiliates

 

(301,320

)

56,647

 

33,267

 

(155,432

)

(192,548

)

Investment income (loss)

 

63,137

 

19,940

 

7,263

 

25,522

 

21,383

 

Total revenues and other income

 

6,751,390

 

6,136,938

 

4,175,013

 

3,532,310

 

5,223,060

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and other deductions:

 

 

 

 

 

 

 

 

 

 

 

Direct costs

 

4,483,320

 

3,775,964

 

2,400,519

 

1,981,504

 

3,063,257

 

General and administrative expenses

 

532,568

 

489,892

 

338,720

 

421,492

 

473,885

 

Depreciation and amortization

 

1,055,517

 

924,094

 

760,962

 

663,958

 

609,155

 

Interest expense

 

251,552

 

256,633

 

272,712

 

266,047

 

196,726

 

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

 

(136,510

)

4,514

 

47,238

 

11,982

 

15,143

 

Impairments and other charges

 

290,260

 

198,072

 

61,292

 

118,543

 

145,447

 

Total costs and other deductions

 

6,476,707

 

5,649,169

 

3,881,443

 

3,463,526

 

4,503,613

 

Income (loss) from continuing operations before income taxes

 

274,683

 

487,769

 

293,570

 

68,784

 

719,447

 

Income tax expense (benefit)

 

32,628

 

142,605

 

36,950

 

(63,937

)

200,186

 

Subsidiary preferred stock dividend

 

3,000

 

3,000

 

750

 

 

 

Income (loss) from continuing operations, net of tax

 

239,055

 

342,164

 

255,870

 

132,721

 

519,261

 

Income (loss) from discontinued operations, net of tax

 

(74,400

)

(97,440

)

(161,090

)

(218,609

)

(39,597

)

Net income (loss)

 

164,655

 

244,724

 

94,780

 

(85,888

)

479,664

 

Less: Net (income) loss attributable to noncontrolling interest

 

(621

)

(1,045

)

(85

)

342

 

(3,927

)

Net income (loss) attributable to Nabors

 

$

164,034

 

$

243,679

 

$

94,695

 

$

(85,546

)

$

475,737

 

Earnings (losses) per share:

 

 

 

 

 

 

 

 

 

 

 

Basic from continuing operations

 

$

0.82

 

$

1.19

 

$

0.90

 

$

0.47

 

$

1.83

 

Basic from discontinued operations

 

(0.25

)

(0.34

)

(0.57

)

(0.77

)

(0.14

)

Total Basic

 

$

0.57

 

$

0.85

 

$

0.33

 

$

(0.30

)

$

1.69

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted from continuing operations

 

$

0.82

 

$

1.17

 

$

0.88

 

$

0.46

 

$

1.79

 

Diluted from discontinued operations

 

(0.26

)

(0.34

)

(0.55

)

(0.76

)

(0.14

)

Total Diluted

 

$

0.56

 

$

0.83

 

$

0.33

 

$

(0.30

)

$

1.65

 

Weighted-average number of common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

289,965

 

287,118

 

285,145

 

283,326

 

281,622

 

Diluted

 

292,323

 

292,484

 

289,996

 

286,502

 

288,236

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures and acquisitions of businesses (3)

 

$

1,433,586

 

$

2,247,735

 

$

1,878,063

 

$

990,287

 

$

1,578,241

 

Interest coverage ratio (4)

 

7.9:1

 

7.2:1

 

5.2:1

 

4.9:1

 

9.5:1

 

 

30



Table of Contents

 

Balance Sheet Data (1)(2)

 

 

 

Year Ended December 31,

 

 

 

2012

 

2011

 

2010

 

2009

 

2008

 

 

 

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

 

Cash, cash equivalents and short-term investments

 

$

778,204

 

$

539,489

 

$

801,190

 

$

1,090,851

 

$

586,111

 

Working capital

 

2,000,475

 

1,285,752

 

458,550

 

1,568,042

 

1,037,734

 

Property, plant and equipment, net

 

8,712,088

 

8,629,946

 

7,815,419

 

7,646,050

 

7,331,959

 

Total assets

 

12,656,022

 

12,912,140

 

11,646,569

 

10,644,690

 

10,517,899

 

Long-term debt

 

4,379,336

 

4,348,490

 

3,064,126

 

3,940,605

 

3,600,533

 

Shareholders’ equity

 

5,944,929

 

5,587,815

 

5,328,162

 

5,167,656

 

4,904,106

 

Debt to capital ratio:

 

 

 

 

 

 

 

 

 

 

 

Gross (5)

 

0.42:1

 

0.45:1

 

0.45:1

 

0.43:1

 

0.44:1

 

Net (6)

 

0.38:1

 

0.42:1

 

0.41:1

 

0.36:1

 

0.40:1

 

 


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

 

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

 

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

 

(4)      The interest coverage ratio is a trailing 12-month quotient of the sum of (x) operating revenues and earnings (losses) from unconsolidated affiliates, direct costs and general administrative expenses less our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated oil and gas joint ventures (in years applicable) divided by (y) interest expense.  The interest coverage ratio is not a measure of operating performance or liquidity defined by accounting principles generally accepted in the United States of America (“GAAP”) and may not be comparable to similarly titled measures presented by other companies.

 

(5)      The gross debt to capital ratio is calculated by dividing (x) total debt by (y) total capital. Total capital is defined as total debt plus shareholders’ equity.  The gross debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.

 

(6)      The net debt to capital ratio is calculated by dividing (x) net debt by (y) net capital. Net debt is total debt minus the sum of cash and cash equivalents and short-term investments. Net capital is the sum of net debt plus shareholders’ equity.  The net debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.

 

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Table of Contents

 

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

 

Management Overview

 

This section is intended to help you understand our results of operations and our financial condition. This information is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the accompanying notes thereto.

 

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. Our worldwide fleet of actively marketed rigs consists of 474 land drilling rigs, 548 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jackup units, barge rigs and a large component of trucks and fluid hauling vehicles. We have investments in oil and gas exploration, development and production activities in the United States and Canada, but are marketing to dispose of our oil and gas portfolio in an expeditious and prudent manner.

 

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

 

·                  Our Drilling & Rig Services business line includes our drilling operations for oil and natural gas wells, on land and offshore, and companies engaged in drilling technology, top drive manufacturing, directional drilling, construction services, and rig instrumentation and software. This business line, consisting of six operating segments, includes U.S. Lower 48 Land Drilling, U.S. Offshore, Alaska, Canada, and International operations. Our U.S. Lower 48 Land Drilling and International operating segments also represent reportable segments based on quantitative thresholds. In addition, our Other Rig Services operating segment combines Canrig Drilling Technology Ltd., Peak Oilfield Services and Ryan Directional Services, Inc. The latter operating segment does not meet the criteria for disclosure, individually or in the aggregate, as a reportable segment.

 

·                  Our Completion & Production Services business line includes our well-servicing, fluid logistics, workover operations and our pressure pumping services. This business line, consisting of two operating segments, includes U.S. Production Services and Completion Services, and represents reportable segments.

 

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

 

The magnitude of customer spending on new and existing wells is the primary driver of our business. Our customers’ spending is determined principally by their internally generated cash flow and to a lesser extent by joint venture arrangements and funding from the capital markets. In our Drilling & Rig Services business line, operations have traditionally been driven by natural gas prices, but the majority of current activity is driven by the price of oil and natural gas liquids from unconventional reservoirs (shales). In our Completion & Production Services business line, operations are primarily driven by oil prices.

 

During 2012, domestic ongoing weak natural gas prices, combined with a general decline in natural gas liquids and a mid-year sharp, but temporary, drop in crude oil prices, resulted in a second-half contraction in customer spending.  This led to a curtailment of drilling-related expenditures by many companies and an oversupply of rigs in the markets where we operate.  We believe gas and liquids prices are likely to remain weak through 2013.  Crude oil pricing has been more resilient, but remains volatile and potentially vulnerable, which keeps our customers’ forward-spending plans in check for the near-term.  Projections of stable crude oil pricing at today’s level and  improving liquids pricing later in the year, if realized, should lead to increased domestic drilling activity later in 2013.  Nonetheless, it is also likely that continuing additions of new rig capacity and improving rig efficiency will result in a continued oversupply of rigs for most, if not all, of the year.

 

Our international markets have been much slower to respond to the improving oil prices of the last two years and continue to be dampened by cost issues in several markets which should abate as the year progresses.  This abatement, combined with a general tightening of the rig supply-demand balance, leading to improving rates, and the deployment of several large projects and other rigs returning to work should improve international results in 2013.

 

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

 

 

 

Year Ended December 31,

 

Increase/(Decrease)

 

 

 

2012

 

2011

 

2010

 

2012 to 2011

 

2011 to 2010

 

Commodity prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Henry Hub natural gas spot price ($/thousand cubic feet (“mcf”))

 

$

2.75

 

$

4.00

 

$

4.37

 

$

(1.25

)

(31

)%

$

(0.37

)

(8

)%

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

 

$

94.10

 

$

95.05

 

$

79.51

 

$

(0.95

)

(1

)%

$

15.54

 

20

%

 

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Table of Contents

 

Operating revenues and Earnings (losses) from unconsolidated affiliates in 2012 totaled $6.7 billion, representing an increase of $571.3 million, or 9%, over 2011.  Adjusted income derived from operating activities in 2012 totaled $918.6 million, representing an increase of 6% compared to 2011, while net income (loss) from continuing operations in 2012 totaled $239.1 million ($0.82 per diluted share), representing a decrease of 30% compared to 2011.

 

Operating revenues and Earnings (losses) from unconsolidated affiliates for 2011 totaled $6.1 billion, representing an increase of $1.9 billion, or 47%, over 2010.  Adjusted income derived from operating activities and net income (loss) from continuing operations for 2011 totaled $867.4 million and $342.2 million ($1.17 per diluted share), respectively, representing increases of 34% over 2010 for both financial measures.

 

During 2012, our income (loss) from continuing operations was negatively impacted by impairments and other charges, including full-cost ceiling test writedowns from NFR Energy totalling $310.0 million, representing our proportionate share of the writedowns, a $75.0 million impairment of an intangible asset related to the Superior trade name, a provision for the retirement of long-lived assets totaling $138.7 million in multiple operating segments, a $50.4 million impairment of some coil-tubing rigs and a goodwill impairment totaling $26.3 million. Partially offsetting these charges were $160 million of asset gains, primarily relating to selling our interest in NFR Energy at the end of 2012. Excluding these items, our operating results improved as a result of increased demand for our services and products due to increased drilling activity in oil- and liquids-rich shale plays and increased well-servicing activity in the U.S. and Canada. This increase in activity has more than offset the drop in demand from gas-related plays.

 

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

 

Our income from continuing operations during 2011 was negatively impacted by $198.1 million in impairments and other charges, $100 million of which related to a provision for a contingent liability that existed on December 31, 2011 for a potential termination payment to our former Chief Executive Officer, which was not paid. See Note 3 for further discussion. The remaining $98.1 million was comprised of a provision for retirement of long-lived assets recorded by multiple operating segments.  This related to the decommissioning and retirement of assets previously utilized in our U.S. Lower 48 Land Drilling, International and U.S. Production Services operations and the amounts are reflected in the Impairments and other charges line in our consolidated statements of income (loss).

 

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Table of Contents

 

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

 

 

 

Year Ended December 31,

 

Increase/(Decrease)

 

 

 

2012

 

2011

 

2010

 

2012 to 2011

 

2011 to 2010

 

 

 

(In thousands, except percentages and rig activity)

 

Reportable segments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilling & Rig Services:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Lower 48 Land Drilling

 

$

1,860,357

 

$

1,698,620

 

$

1,294,853

 

$

161,737

 

10

%

$

403,767

 

31

%

U.S. Offshore

 

268,986

 

170,727

 

123,761

 

98,259

 

58

%

46,966

 

38

%

Alaska

 

147,465

 

129,894

 

179,218

 

17,571

 

14

%

(49,324

)

(28

)%

Canada

 

572,616

 

574,754

 

389,229

 

(2,138

)

 

185,525

 

48

%

International

 

1,265,060

 

1,104,461

 

1,093,608

 

160,599

 

15

%

10,853

 

1

%

Other Rig Services (2)

 

839,533

 

674,206

 

427,154

 

165,327

 

25

%

247,052

 

58

%

Subtotal Drilling & Rig Services (3)

 

4,954,017

 

4,352,662

 

 

3,507,823

 

601,355

 

14

%

 

844,839

 

24

%

Completion & Production Services:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Production Services

 

857,668

 

701,223

 

444,665

 

156,445

 

22

%

256,558

 

58

%

Completion Services

 

1,462,767

 

1,237,306

 

321,295

 

225,461

 

18

%

916,011

 

285

%

Subtotal Completion & Production Services (4)

 

2,320,435