NABORS INDUSTRIES LTD - Annual Report: 2010 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

 

Commission File Number 001-32657

NABORS INDUSTRIES LTD.

(Exact name of registrant as specified in its charter)

 

 

(441) 292-1510

(Registrant’s telephone number, including area code)

 

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

 

 

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 þ     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 þ

 

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 þ     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 þ     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.  þ

 

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

The aggregate market value of the 192,800,936 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 30, 2010, of $17.62 per share as reported on the New York Stock Exchange, was $3,397,152,492. 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 24, 2011 was 286,145,675.

 

DOCUMENTS INCORPORATED BY REFERENCE (to the extent indicated herein)

 

Specified portions of the definitive Proxy
Statement to be distributed in connection with our 2011 annual meeting of shareholders (Part III).

 

 

NABORS INDUSTRIES LTD.

Form 10-K Annual Report
For the Year Ended December 31, 2010

Table of Contents

 

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:

 

 

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 natural gas or oil 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 by no means all-inclusive, but is designed to highlight what we believe are important factors to consider. 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. and, where the context requires, includes our subsidiaries. Our subsidiaries include Nabors Industries, Inc., a Delaware corporation (“Nabors Delaware”).

 

 

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 are also a leading provider of offshore platform workover and drilling rigs, and actively market 37 platform, 13 jack-up and three barge rigs in the United States, including the Gulf of Mexico, and multiple international markets.

 

In addition to the foregoing services:

 

 

During the third quarter of 2010, we acquired through a tender offer and merger transaction (the “Superior Merger”), all of the outstanding common stock of Superior Well Services, Inc. (“Superior”). Superior provides 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, to a lesser extent, oil production, and down-hole surveying services. The effects of the Superior Merger and the operating results of Superior from the acquisition date to December 31, 2010 are included in the accompanying audited consolidated financial statements and are reflected in our operating segment, titled “Pressure Pumping.” See Note 7 — Acquisitions and Divestitures in Part II, Item 8. — Financial Statements and Supplementary Data for additional information.

 

Nabors was formed as a Bermuda exempt 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 Mintflower Place, 8 Par-La-Ville Road, Hamilton, HM08, Bermuda, and our phone number there is (441) 292-1510.

 

Our Fleet of Rigs

 

 

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 the larger drilling rigs typically used for the initial drilling job.

 

Land-based drilling rigs are moved between well sites and between geographic areas of operations 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.

 

 

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.

Customers: Types of Drilling Contracts

 

Our customers include major oil and gas companies, national oil and gas companies and independent oil and gas companies. No customer accounted for more than 10% of our consolidated revenues in 2010 or 2009.

 

On land in the U.S. Lower 48 states and Canada, we typically enter into contracts with durations ranging from one to three years. Under these contracts, our rigs are committed to one customer over that term. Most of our recent contracts for newly constructed rigs have three-year terms. Contracts relating to offshore drilling and land drilling in Alaska and international markets generally provide for longer terms, usually from one to five years. Offshore workover projects are often contracted on a single-well basis. We generally are awarded 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, all 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).

 

Well-servicing and Workover 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 oil wells characteristically require more maintenance than flowing wells because of the operation of the mechanical pumping equipment.

 

 

 

Pressure Pumping Services

 

In connection with the Superior Merger, we conduct technical and fluid logistics services. Technical services include technical pumping services, completion, production and rental tool services and down-hole surveying services. Fluid logistics services include those services related to the transportation, storage and disposal of fluids that are used in the drilling, development and production of hydrocarbons. During the period September 10, 2010 through December 31, 2010, approximately 5.5% of revenues from our Pressure Pumping operating segment came from an unconsolidated Nabors affiliate. Our proportionate share of any profits resulting from sales to this affiliate were eliminated in consolidation.

 

Oil and Gas Investments

 

In our Oil and Gas operating segment, we invest in oil and gas exploration, development and production operations in the United States, Canada and Colombia. In addition, in 2006, we entered into an agreement with First Reserve Corporation to form select joint ventures to invest in oil and gas exploration opportunities worldwide. During 2007, three joint ventures were formed for operations in the United States, Canada and Colombia. We hold a 50% ownership interest in the Canadian entity, Stone Mountain Venture Partnership (“SMVP”) and 49.7% ownership interests in the U.S. and Colombia entities, NFR Energy LLC (“NFR Energy”) and Remora Energy International LP (“Remora”), respectively. We account for these investments using the equity method of accounting. Each joint venture pursues development and exploration projects with both existing Nabors customers and other operators in a variety of forms, including operated and non-operated working interests, joint ventures, farm-outs and acquisitions. Our Oil and Gas operating segment includes both wholly owned and joint-venture operations and focuses on the exploration for and the acquisition, development and production of natural gas, oil and natural gas liquids in Alaska, Arkansas, Louisiana, Oklahoma, Mississippi, Montana, North Dakota, Texas, Utah and Wyoming. Outside of the United States, we and our joint ventures own or have interests in the Canadian provinces of Alberta and British Columbia and in Colombia.

 

During 2010, we began actively marketing some of our oil and gas assets in Canada and Colombia, including our ownership interests in SMVP and Remora. Additional information about recent activities for this segment can be found in Part II, Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Part II, Item 8. — Financial Statements and Supplementary Data — Note 21 — Discontinued Operations.

 

Other Services

 

Canrig Drilling Technology Ltd., our drilling technologies and well services subsidiary, manufactures top drives, which are installed on both onshore and offshore drilling rigs. We market our top drives throughout the world. We rent top drives and catwalks, and provide installation, repair and maintenance services to our customers. We also offer rig instrumentation equipment, including proprietary RIGWATCH^tm software and computerized equipment that monitors a rig’s real-time performance. Our directional drilling system, ROCKIT^tm, is experiencing high growth in the marketplace. In addition, we specialize in daily reporting software for drilling operations, making this data available through the internet. We also provide mudlogging services. Canrig Drilling Technology Canada Ltd., one of our Canadian subsidiaries, manufactures catwalks

which are installed on both onshore and offshore drilling rigs. Ryan Energy Technologies, Inc., another one of our subsidiaries, manufactures and sells directional drilling and rig instrumentation equipment and provides data collection services to oil and gas exploration and service companies. Nabors has a 50% ownership interest in Peak Oilfield Service Company, a general partnership with a subsidiary of Cook Inlet Region, Inc., a leading Alaskan native corporation. Peak Oilfield Service Company provides heavy equipment to move drilling rigs, water, other fluids and construction materials, primarily on Alaska’s North Slope and in the Cook Inlet region. The partnership also provides construction and maintenance for ice roads, pads, facilities, equipment, drill sites and pipelines. Nabors also has a 50% membership interest in Alaska Interstate Construction, L.L.C., a general contractor involved in the construction of roads, bridges, dams, drill sites and other facility sites, as well as the provision of mining support in Alaska; the other member of Alaska Interstate Construction, L.L.C. is a subsidiary of Cook Inlet Region, Inc. Revenues are derived from services to companies engaged in mining and public works. Nabors Blue Sky Ltd. leases aircraft used for logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft.

 

Our Employees

 

As of December 31, 2010, Nabors employed approximately 23,412 persons, of whom approximately 2,892 were employed by unconsolidated affiliates. We believe our relationship with our employees is generally good.

 

Some rig employees in 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 that lead 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. Seasonality does not materially impact the remaining portions of our business.

 

Research and Development

 

Research and development constitutes 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, Nabors’ 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 natural gas or oil could have a material impact on the exploration, development and production activities of our customers and could materially affect our financial position, results of operations and cash flows. See Part I, Item 1A. — Risk Factors — Fluctuations in oil and natural gas prices could adversely affect drilling activity and our revenues, cash flows and profitability.

 

Our industry remains competitive. The number of available rigs exceeds demand in many of our markets, resulting in strong price competition. Many rigs can be readily moved from one region to another in response to changes in levels of activity, which may result in an oversupply of rigs in such areas. Many of the total available contracts are currently awarded on a bid basis, which further increases competition based on price. The land drilling, workover and well-servicing market is generally more competitive than the offshore market due to the larger number of rigs and market participants.

From 2005 through most of 2008, demand was strong for drilling services driven by a sustained increase in the level of commodity prices; supply of and demand for land drilling services were largely in balance in the United States and other markets, with demand actually exceeding supply in some of our markets. This resulted in an increase in rates being charged for rigs across our North American, Offshore and International markets. In late 2008, falling oil prices and the declines in natural gas prices forced a curtailment of drilling-related expenditures by many companies and resulted in an oversupply of rigs in the markets where we operate. During 2009 and the first half of 2010, this continued decline in drilling and related activity impacted our key markets.

 

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. 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 Nabors’ 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. Land Well-servicing operating segment, we compete with Basic Energy Services, Inc., Key Energy Services, Inc., Complete Energy Services 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 Pressure Pumping operating segment competes with 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 Canrig Drilling Technology Ltd. subsidiary is one of the three major manufacturers of top drives. Its largest competitors in that market are National Oilwell Varco and Tesco. Its largest competitors in the manufacture of rig instrumentation systems are Pason and National Oilwell Varco’s Totco subsidiary. Mudlogging services are provided by a number of entities that serve the oil and gas industry on a regional basis. In the U.S. Lower 48 states, there are hundreds of rig transportation companies in each of our operating regions. In Alaska, Peak Oilfield Service principally competes with Alaska Petroleum Contractors for road, pad and pipeline maintenance, and is one of many drill site and road construction companies, the largest of which is VECO Corporation, and Alaska Interstate Construction principally competes with large general contractors, including Granite Construction Company and Quality Asphalt Paving on public works projects and Alaska Frontier Constructors and CH2MHill on resource development projects.

 

Our Business Strategy

 

Since 1987, with the installation of our current management team, we have adhered to a consistent strategy aimed at positioning Nabors to grow and prosper in times of good market conditions and to mitigate adverse effects during periods of poor market conditions. We have maintained a financial posture that allows us to capitalize on market weakness and strength by adding to our business base, thereby enhancing our upside potential. The principal elements of our strategy have been to:

 

 

 

We have designed our business strategy to allow us to grow and remain profitable in any market environment. The major developments in our business in recent years illustrate our implementation of this strategy and its continuing success. Beginning in 2005, we took advantage of the robust rig market in the United States and elsewhere to obtain a high volume of contracts for newly constructed rigs. A large portion of these rigs are subject to long-term contracts with creditworthy customers with the most significant impact occurring in our International operations. This will not only expand our operations with the latest state-of-the-art rigs, which should better weather downturns in market activity, but eventually replace the oldest and least capable rigs in our existing fleet. However, this positive trend in the rig market slowed in the fourth quarter of 2008 and throughout 2009 and the first half of 2010, due to the continued steady decline in natural gas and oil prices. As a result of lower commodity prices, many of our customers’ drilling programs were reduced and the demand for additional rigs was substantially reduced. In the latter half of 2010, commodity prices strengthened and our drilling activity improved. Although we expect market conditions to remain challenging during 2011, we believe the deployment of our newer and higher-margin rigs under long-term contracts will enhance our competitive position when market conditions improve.

 

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 many 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 over 550 land drilling rigs, more than 700 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jack-up 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.

 

On January 3, 2006, we completed an acquisition of 1183011 Alberta Ltd., a wholly owned subsidiary of Airborne Energy Solutions Ltd., through the purchase of all common shares outstanding for cash for a total purchase price of Cdn.$41.7 million (U.S. $35.8 million). In addition, we assumed debt, net of working capital, totaling approximately Cdn.$10.0 million (U.S. $8.6 million). On that date, Nabors Blue Sky Ltd. (formerly 1183011 Alberta Ltd.) owned 42 helicopters and fixed-wing aircraft and owned and operated a fleet of heliportable well-service equipment. The purchase price was allocated based on final valuations of the fair value of assets acquired and liabilities assumed as of the acquisition date and resulted in goodwill of approximately U.S. $18.8 million. During 2008 and 2009, the results of our impairment tests of goodwill and intangible assets indicated a permanent impairment to goodwill and to an intangible asset of Nabors Blue Sky Ltd. As such, the goodwill has been fully impaired as of December 31, 2009.

 

On May 31, 2006, we completed an acquisition of Pragma Drilling Equipment Ltd.’s business, which manufactures catwalks, iron roughnecks and other related oilfield equipment, through an asset purchase consisting primarily of intellectual property for a total purchase price of Cdn.$46.1 million (U.S. $41.5 million). The purchase price has been allocated based on final valuations of the fair market value of assets acquired and liabilities assumed as of the acquisition date and resulted in goodwill of approximately U.S. $10.5 million.

 

On August 8, 2007, we sold our Sea Mar business which had previously been included in Other Operating Segments. The assets included 20 offshore supply vessels and related assets, including a right under a vessel

construction contract. The operating results of this business for years ended December 31, 2007 and before are accounted for as discontinued operations.

 

On September 10, 2010, we completed the Superior Merger 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. Superior provides a wide range of wellsite solutions to oil and natural gas companies, primarily technical pumping services and down-hole surveying services. The effects of the Superior Merger and the operating results from the acquisition date to December 31, 2010 are reflected in the accompanying audited consolidated financial statements. Additional information about Superior can be found in Part II, Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Part II, Item 8. — Financial Statements and Supplementary Data — Note 7 — Acquisitions and Divestitures.

 

On December 31, 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. Land Well-servicing 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 $5 million.

 

From time to time, we may sell a subsidiary or group of assets outside of our core markets or business if it is economically advantageous for us to do so. During 2010, we began actively marketing our oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia. These assets include our 49.7% and 50.0% ownership interests in our investments of Remora and SMVP, respectively, which we account for using the equity method of accounting. All of these assets are included in our Oil and Gas operating segment. We determined that the plan of sale criteria in the ASC Topic relating to the Presentation of Financial Statements for Assets Sold or Held for Sale had been met during the third quarter of 2010. Accordingly, the accompanying consolidated statements of income (loss) and accompanying notes to the consolidated financial statements have been updated to retroactively reclassify the operating results of these assets as discontinued operations for all periods presented. See Note 21 — Discontinued Operations for additional discussion in Part II, Item 8. — Financial Statements and Supplementary Data.

 

Environmental Compliance

 

Nabors does not currently anticipate that compliance with currently applicable environmental regulations and controls will significantly change its competitive position, capital spending or earnings during 2011. Nabors believes it is in material compliance with applicable environmental rules and regulations, and the cost of such compliance is not material to the business or financial condition of Nabors. For a more detailed description of the environmental laws and regulations applicable to Nabors’ operations, see Part I, Item 1A. — Risk Factors — Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect Nabors’ results of operations.

 

 

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 facing Nabors. 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.

We have a substantial amount of debt outstanding

 

As of December 31, 2010, we had long-term debt outstanding of approximately $4.4 billion, including $1.4 billion in current maturities, and cash and cash equivalents and investments of $841.5 million, including $40.3 million of long-term investments and other receivables. Long-term investments and other receivables include $32.9 million in oil and gas financing receivables. Our ability to service our debt 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. At December 31, 2010, we had $700 million available under a senior unsecured revolving credit facility; in January 2011, we added another lender to the facility raising the amount available to $750 million. On February 11, 2011, one of our subsidiaries established a credit facility, which we unconditionally guarantee, for approximately US$50 million. If our 0.94% senior exchangeable notes were exchanged before their maturity in May 2011, the required cash payment could have a significant impact on our level of cash and cash equivalents and investments available to meet our other cash obligations. We calculate our leverage in relation to capital (i.e., shareholders’ equity) utilizing two commonly used ratios:

 

 

At December 31, 2010, our gross funded debt to capital ratio was 0.42:1 and our net funded debt to capital ratio was 0.37:1.

 

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. Recent volatility and the effects of recent declines in oil and natural gas prices are likely to continue in the near future, especially given the general contraction in the world’s economy that began during 2008. We believe that any prolonged suppression of oil and natural gas prices could continue to depress the level of exploration and production activity. Lower oil and natural gas prices have also caused some of our customers to seek to terminate, 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 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.

 

Uncertain or negative global economic conditions could continue to adversely affect our results of operations

 

The recent and substantial volatility and extended declines in oil and natural gas prices in response to a weakened global economic environment has adversely affected our results of operations. In addition, economic conditions have resulted in substantial uncertainty in the capital markets and both access to and terms of available financing. During 2009, many of our customers curtailed their drilling programs, which, in many

cases, has resulted in a decrease in demand for drilling rigs and a reduction in dayrates and utilization. Additionally, some customers have terminated drilling contracts prior to the expiration of their terms. A prolonged period of lower oil and natural gas prices could continue to impact our industry and our business, including our future operating results and the ability to recover our assets, including goodwill, at their stated values. In addition, some of our customers could experience an inability to pay suppliers, including us, in the event they are unable to access the capital markets to fund their business operations. Likewise, our suppliers may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. Each of these could adversely affect our operations.

 

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 access to borrowing capacity could be affected by the recent instability in the global financial markets

 

Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by Fitch Ratings, Moody’s Investor Service and Standard & Poor’s and our historical ability to access those markets as needed. A credit downgrade may impact our future ability to access credit markets, which is important for purposes of both meeting our financial obligations and funding capital requirements to finance and grow our businesses.

 

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, 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.

 

Future price declines may result in a writedown of our oil and gas asset carrying values

 

We follow the successful-efforts method of accounting for our consolidated subsidiaries’ oil and gas activities. Under the successful-efforts method, lease acquisition costs and all development costs are capitalized. Our provision for depletion is based on these capitalized costs and is determined on a property-by-property basis using the units-of-production method. Proved property acquisition costs are amortized over total proved reserves. Costs of wells and related equipment and facilities are amortized over the life of proved developed reserves. Proved oil and gas properties are reviewed when circumstances suggest the need for such a review and are written down to their estimated fair value, if required. Unproved properties are reviewed periodically to determine if there has been impairment of the carrying value; any impairment is expensed in that period. The estimated fair value of our proved reserves generally declines when there is a significant and sustained decline in oil and natural gas prices. During 2010, 2009 and 2008, our impairment tests on the wholly owned oil and gas-related assets in our Oil and Gas operating segment resulted in impairment charges of $137.8 million, $48.6 million and $21.5 million, respectively. Any sustained further decline in oil and natural gas prices or reserve quantities could require further writedown of the value of our proved oil and gas properties if the estimated fair value of these properties falls below their net book value.

 

Our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, utilize the full-cost method of accounting for costs related to oil and natural gas properties. Under this method, all of these costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. However, these capitalized costs are subject to a ceiling test which limits the costs to the aggregate of (i) the present value of future net revenues attributable to proved oil and natural gas reserves, discounted at 10%, plus (ii) the lower of cost or market value of unproved properties. The full-cost ceiling was evaluated at December 31, 2010 and 2009 using the 12-month average price, whereas during 2008, the full-cost ceiling was evaluated using year-end prices. During 2010, our unconsolidated oil and gas joint ventures did not record full-cost ceiling test writedowns. During 2009 and 2008, the ventures recorded full-cost ceiling test writedowns of which $237.1 million and $228.3 million, respectively, represented our proportionate share. Any sustained further decline in oil and natural gas prices, or other factors, without other mitigating circumstances, could cause other future writedowns of capitalized costs and asset impairments that could adversely affect our results of operations.

 

Our acquisition of Superior may not be as financially or operationally successful as contemplated

 

In evaluating the acquisition of Superior, we made certain business assumptions and determinations based on our due diligence. However, these assumptions and determinations involve risks and uncertainties that may cause them to be inaccurate. As a result, we may not realize the full benefits that we expect from the acquisition. For example, our assumptions as to future revenue with respect to expanding internationally and achieving synergies in North America by integrating Superior’s pumping services with our drilling and workover offerings may prove to be incorrect. If they are, the financial success of the acquisition may be materially adversely affected.

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

 

We derive a significant portion of our business from global markets, including major operations in Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. These operations are subject to various risks, including the risk of war, civil disturbances and governmental activities 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, such as last year’s currency devaluation in Venezuela. 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.

 

The loss of key executives could reduce our competitiveness and prospects for future success

 

The successful execution of our strategies central to our future success will depend, in part, on a few of our key executive officers. We have entered into employment agreements with our Chairman and Chief Executive Officer, Eugene M. Isenberg and our Deputy Chairman, President and Chief Operating Officer, Anthony G. Petrello, with terms through March 30, 2013. If Mr. Isenberg’s employment is terminated in the event of death or disability, or without cause or in the event of a change in control, a cash payment of $100 million will be made by the Company. If Mr. Petrello’s employment is terminated in the event of death or disability, the Company will make a cash payment of $50 million; or in the event of termination without cause or in the event of a change in control, the Company will make a cash payment based on a formula of three times the average of his base salary and annual bonus paid during the three fiscal years preceding the termination. We do not carry significant amounts of key man insurance. The loss of Mr. Isenberg or Mr. Petrello could have an adverse effect on our financial condition or results of operations.

 

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

 

The drilling of oil and gas wells is subject to various federal, state and local laws, rules and regulations. Our cost of compliance with these laws, rules and regulations may be substantial. For example, federal law imposes on “responsible parties” a variety of regulations related to the prevention of oil spills, and liability for removal costs and natural resource, real or personal property and certain economic damages arising from such spills. Some of these laws may impose strict 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 transportation equipment, we may be deemed to be a responsible party under federal law. In addition, our well-servicing, workover 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. Various state and federal laws govern 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 scope of laws protecting the environment has expanded, particularly outside the United States, and this trend is expected to continue. The violation of environmental laws and regulations 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.

Under the Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or Superfund, and similar state laws and regulations, liability for release of a hazardous substance into the environment can be imposed jointly on the entire group of responsible parties or separately on any one of the responsible parties, without regard to fault or the legality of the original conduct of any party that contributed to the release. Liability under CERCLA may include costs of cleaning up the hazardous substances that have been released into the environment and damages to natural resources.

 

Changes in environmental laws and regulations may also negatively impact the operations of oil and natural gas exploration and production companies, which in turn could have an adverse effect on us. For example, 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 handling, disposal and clean-up requirements. 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, such as the United Nations Framework Convention on Climate Change’s “Kyoto Protocol”, to which the United States is not a party. In addition, the U.S. Environmental Protection Agency (“EPA”) has published findings that emissions of greenhouses gases present an endangerment to public health and the environment, paving the way for regulations that would restrict emissions of greenhouse gases under existing provisions of the Clean Air Act.

 

In October 2009, the EPA enacted rules requiring the reporting of greenhouse gas emissions from large sources and suppliers in the United States. Although we do not believe these rules currently apply to us, the EPA has proposed expanding the rules to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities beginning in 2012 for emissions occurring in 2011. The enactment of such hazardous waste legislation or future or more stringent regulation of greenhouse gases could dramatically increase operating costs for oil and natural gas companies and could reduce the market for our services by making many wells and/or oilfields uneconomical to operate.

 

The U.S. Oil Pollution Act of 1990, as amended, imposes strict liability on responsible parties for removal costs and damages resulting from discharges of oil into U.S. waters. 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.

 

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the demand for fracturing and other services

 

Superior performs 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 March 2010, the EPA announced that it would study the potential adverse impact that fracturing may have on water quality and public health. Legislation has also been introduced in the U.S. Congress and some states that would require the 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. Any new laws regulating fracturing activities could cause operational delays or increased costs in exploration and production, which could adversely affect the demand for fracturing services.

Because our option, warrant and convertible securities holders have a considerable number of common shares available for issuance and resale, significant issuances or resales in the future could adversely affect the market price of our common shares

 

As of February 24, 2011, we had 800,000,000 authorized common shares, of which 315,558,810 shares were outstanding. In addition, 46,780,820 common shares were reserved for issuance pursuant to option and employee benefit plans, and 39,814,194 shares were reserved for issuance upon conversion or repurchase of outstanding senior exchangeable notes. The sale, or availability for sale, of substantial amounts of our common shares in the public market, whether directly by us or resulting from the exercise of warrants or options (and, where applicable, sales pursuant to Rule 144 under the Securities Act) or the conversion into common shares, or repurchase of debentures and notes using common shares, 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 and executive contracts may deter a change of control transaction and decrease the likelihood of a shareholder receiving a change of control premium

 

Our Board of Directors is divided into three classes, with each class serving a staggered three-year term. In addition, the Board of Directors has the authority to issue a significant number of common shares and up to 25,000,000 preferred shares, as well as to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of the preferred shares, in each case without any vote or action by the holders of our common shares. Although we have no current plans to issue preferred shares, our classified Board, as well as its ability to issue preferred shares, may discourage, delay or prevent changes in control of Nabors that are not supported by the Board, thereby preventing some of our shareholders from realizing a premium on their shares. In addition, the requirement in the indenture for our 0.94% senior exchangeable notes due 2011 to pay a make-whole premium in the form of an increase in the exchange rate in certain circumstances could have the effect of making a change in control of Nabors more expensive.

 

We have employment agreements with our Chairman and Chief Executive Officer, Eugene M. Isenberg, and our Deputy Chairman, President and Chief Operating Officer, Anthony G. Petrello. These agreements have change-in-control provisions that could result in significant cash payments to Messrs. Isenberg and Petrello.

 

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.

 

On September 14, 2006, Nabors Drilling International Limited, one of our wholly owned Bermuda subsidiaries (“NDIL”), received a Notice of Assessment (the “Notice”) from Mexico’s federal tax authorities in connection with the audit of NDIL’s Mexico branch for 2003. The Notice proposes to deny depreciation expense deductions relating to drilling rigs operating in Mexico in 2003. The Notice also proposes to deny a deduction for payments made to an affiliated company for the procurement of labor services in Mexico. The amount assessed was approximately $19.8 million (including interest and penalties). Nabors and its tax advisors previously concluded that the deductions were appropriate and more recently that the government’s position lacks merit. NDIL’s Mexico branch took similar deductions for depreciation and labor expenses from 2004 to 2008. On June 30, 2009, the government proposed similar assessments against the Mexico branch of another wholly owned Bermuda subsidiary, Nabors Drilling International II Ltd. (“NDIL II”) for 2006. We anticipate that a similar assessment will eventually be proposed against NDIL for 2004 through 2008 and against NDIL II for 2007 to 2010. We believe that the potential assessments will range from $6 million to

$26 million per year for the period from 2004 to 2009, and in the aggregate, would be approximately $90 million to $95 million. Although we believe that any assessments related to the 2004 to 2010 years lack merit, a reserve has been recorded in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The statute of limitations for NDIL’s 2004 tax year recently expired. Accordingly, during the fourth quarter of 2010, we released $7.4 million from our tax reserves, which represented the reserve recorded for that tax year. If these additional assessments were to be made and we ultimately did not prevail, we would be required to recognize additional tax for the amount in excess of the current reserve.

 

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 reorganization as a Bermuda company. Legislation enacted by the U.S. Congress in 2004 provides that a corporation that reorganized in a foreign jurisdiction on or after March 4, 2003 be treated as a domestic corporation for U.S. federal income tax purposes. Nabors’ reorganization was completed on June 24, 2002. There have 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.

 

Because we cannot predict whether legislation will ultimately be adopted, no assurance can be given that the tax benefits associated with our reorganization will ultimately accrue to the benefit of the Company and its shareholders. It is possible that future changes to the tax laws (including tax treaties) could impact our ability to realize the tax savings recorded to date, as well as future tax savings, resulting from our reorganization.

 

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.

 

Our financial results could be affected by changes in the value of our investment portfolio

 

We invest our excess cash in a variety of investment vehicles, some of which are subject to market fluctuations resulting from a variety of economic factors or factors associated with a particular investment, including without limitation, overall declines in the equity markets, currency and interest rate fluctuations, volatility in the credit markets, exposures related to concentrations of investments in a particular fund or investment, exposures related to hedges of financial positions, and the performance of a particular fund or investment managers. As a result, events or developments that negatively affect the value of our investments could have an adverse effect on our results of operations.

 

We do not currently intend to pay dividends on our common shares

 

We have not paid any cash dividends on our common shares since 1982 and have no current intention to do so. However, we can give no assurance that we will not reevaluate our position on dividends in the future.

 

 

Not applicable.

 

Nabors’ principal executive offices are located in Hamilton, Bermuda. We own or lease executive and administrative office space in Houston, Texas and other areas across the world.

 

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

 

Nabors and its subsidiaries own certain mineral interests in connection with their investing and operating activities. The operations of our Oil and Gas operating segment focus on the exploration for and the acquisition, development and production of natural gas, oil and natural gas liquids in the United States, the Canada provinces of Alberta and British Columbia, and Colombia.

 

Our Oil and Gas operating segment includes our wholly owned oil and gas assets and our unconsolidated oil and gas joint ventures. In December 2008, the SEC revised oil and gas reporting disclosures, which clarified that we should consider our equity-method investments when determining whether we have significant oil and gas activities beginning in 2009. A one-year deferral of the disclosure requirements was allowed if an entity became subject to the requirements because of the change to the definition of significant oil and gas activities. When operating results from our wholly owned oil and gas activities were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we determined that we had significant oil and gas activities under the new definition. Accordingly, we are presenting the information with regard to our oil and gas producing activities as of and for the year ended December 31, 2010.

 

The estimates of net proved oil and gas reserves are based on reserve reports as of December 31, 2010, which were prepared by 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 both our wholly owned assets and our U.S. joint venture’s interests in natural gas and oil properties located in the United States. Netherland, Sewell & Associates, Inc. prepared reports of estimated proved oil reserves for certain oil properties located in Cat Canyon and West Cat Canyon Fields, Santa Barbara County, California. 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. 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 (“Bcf”) at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (“MMBbls”) for oil and natural gas liquids.

 

For our wholly owned properties in the United States, the prices used in our reserve reports were $3.72 per mcf for the 12-month average of natural gas, $36.43 per barrel for natural gas liquids and $61.12 per barrel for oil at December 31, 2010. The prices used in the reserve reports by our unconsolidated U.S. joint venture were $4.53 per mcf for the 12-month average of natural gas, $39.04 per barrel for natural gas liquids and $70.60 per barrel for oil at December 31, 2010. For our wholly owned properties in Canada, the price used in our reserve reports was $2.81 per mcf for the 12-month average of natural gas at December 31, 2010. The 12-month average price for natural gas used in the reserve report by our unconsolidated Canada joint venture was $2.78 per mcf at December 31, 2010. For our wholly owned properties in Colombia, the price used in our reserve reports was $78.21 per barrel for oil at December 31, 2010. The oil price used in the reserve report by our unconsolidated Colombia joint venture was $76.00 per barrel at December 31, 2010.

No major discovery or other favorable or adverse event has occurred since December 31, 2010, that would cause a significant change in the estimated proved reserves as of that date.

 

 

 

 

In the preceding reserve information, consolidated subsidiary and our proportionate interests in our equity company reserves are reported separately. However, we operate our business with the same view of equity company reserves as for reserves from consolidated subsidiaries.

 

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 2010

 

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.

 

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

 

Our Oil and Gas operating segment is managed by and staffed with individuals who have an average of more than 20 years of technical experience in the petroleum industry. 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 personnel at Nabors. After all changes are made, senior management reviews the estimates for final endorsement.

 

Proved Undeveloped Reserves

 

At December 31, 2010, approximately 559 billion cubic feet equivalent (“Bcfe”) of our proved reserves were classified as proved undeveloped, which represented 71.6% of the 780.7 Bcfe reported in proved reserves. This amount is inclusive of both consolidated subsidiaries and equity company reserves. Progress was made in converting proved undeveloped reserves into proved developed reserves in 2010. During 2010, we completed development work in over 12 fields and participated in numerous major project start-ups that resulted in the transfer of approximately 62 Bcfe from proved undeveloped to proved developed reserves. We estimate that 35% of our current proved undeveloped reserves will be developed by year 2012 and all of our current proved undeveloped reserves will be developed by year 2016.

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 the year ended December 31, 2010. 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.

 

 

 

 

Drilling and Other Exploratory and Development Activities

 

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

 

Number of Net Productive and Dry Wells Drilled

 

 

 

 

 

 

 

Present Activities

 

The following table provides the number of wells in the process of drilling as of December 31, 2010.

 

Wells Drilling

 

 

 

 

Oil and Gas Properties, Wells, Operations and Acreage

 

Gross and Net Productive Wells

 

 

 

 

Gross and Net Developed Acreage

 

 

 

 

Gross and Net Undeveloped Acreage

 

 

 

 

Additional information about our properties can be found in Notes 2 — Summary of Significant Accounting Policies, 8 — Property, Plant and Equipment (each, under the caption Property, Plant and Equipment), 16 — Commitments and Contingencies (under the caption Operating Leases), and 24 — Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. — Financial Statements and Supplementary Data. The revenues and property, plant and equipment by geographic area for the years ended December 31, 2010, 2009 and 2008, can be found in Note 22 — Segment Information. 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.

 

 

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. 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 United States Department of Justice relating to its investigation of one of our vendors and compliance with the Foreign Corrupt Practices Act. The inquiry relates to transactions with and involving Panalpina, which provided freight forwarding and customs clearance services to some of our affiliates. To date, the inquiry has 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, has received periodic updates at its regularly scheduled meetings, and the Chairman of the Audit Committee has received updates between meetings as circumstances warrant. The investigation includes 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 United States Department of Justice have been advised of our investigation.

The ultimate outcome of this investigation or the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws cannot be determined at this time.

 

A court 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. We have asserted the lack of legally required notice as a basis for challenging the judgment on appeal to the Algeria Supreme Court. Based upon our understanding of applicable law and precedent, we believe that this challenge will be successful. We do not believe that a loss is probable and have not accrued any amounts related to this matter. However, the ultimate resolution and the timing thereof are uncertain. 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 August 2010, Nabors and its wholly owned subsidiary, Diamond Acquisition Corp. (“Diamond”) were sued in three putative shareholder class actions. Two of the cases were dismissed. The remaining case pending, Jordan Denney, Individually and on Behalf of All Others Similarly Situated v. David E. Wallace, et al., Civil Action No. 10-1154, is pending in the United States District Court for the Western District of Pennsylvania. The suits were brought against Superior, the individual members of its board of directors, certain of Superior’s senior officers, Nabors and Diamond. The complaints alleged that Superior’s officers and directors violated various provisions of the Exchange Act and breached their fiduciary duties in connection with the Superior Merger, and that Nabors and Diamond aided and abetted these violations. The complaints sought injunctive relief, including an injunction against the consummation of the Superior Merger, monetary damages, and attorney’s fees and costs. The claim against Superior and its directors is covered by insurance after a deductible amount. We anticipate settling the claims in the first or second quarter of 2011, and that any settlement will be funded by Superior’s insurers to the extent it exceeds our deductible.

 

 

 

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, 2005 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, 2006 — 2010.

 

 

 

Our common shares are traded on the New York Stock Exchange under the symbol “NBR”. At February 24, 2011, there were approximately 1,573 shareholders of record. We have not paid any cash dividends on our common shares since 1982 and currently have no intentions to do so. However, we can give no assurance that we will not reevaluate our position on dividends in the future.

 

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.

 

 

The following table provides information relating to Nabors’ repurchase of common shares during the three months ended December 31, 2010:

 

 

 

 

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

 

 

See Part I, Item 1A. — Risk Factors — We do not currently intend to pay dividends on our common shares and Part II, Item 5. — I. Market and Share Prices.

III. Shareholder Matters

 

Bermuda has exchange controls which apply to residents in respect of the Bermuda dollar. As an exempt 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).

 

 

 

 

 

 

 

Management Overview

 

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to help the reader understand the results of our 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 many of the major oil and gas markets in the world. Our worldwide fleet of actively marketed rigs consists of over 550 land drilling rigs, more than 700 rigs for land well-servicing and workover work in the United States and Canada, offshore platform rigs, jack-up units, barge rigs and a large component of trucks and fluid hauling vehicles. We invest in oil and gas exploration, development and production activities in the United States, Canada and Colombia.

 

The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, well-servicing and workover operations and pressure pumping, on land and offshore. Our oil and gas exploration, development and production operations are included in our Oil and Gas operating segment. Our operating segments engaged in drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations are aggregated in our Other Operating Segments.

 

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 natural gas or oil, which could have a material impact on exploration, development and production activities, could also materially affect 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. The primary determinant of customer spending is their cash flow and earnings, which (i) in our U.S. Lower 48 Land Drilling and Canadian Drilling operations are largely driven by natural gas prices and (ii) in our Alaskan, International, U.S. Offshore (Gulf of Mexico), Canadian Well-servicing and U.S. Land Well-servicing operations by oil prices. Both natural gas and oil prices impact our customers’ activity levels and spending for our Pressure Pumping operations. Oil and natural gas liquids prices are beginning to be more significant

factors in some of the traditionally natural-gas-driven operating segments. The following table sets forth natural gas and oil price data per Bloomberg for the last three years:

 

 

Beginning in the fourth quarter of 2008, there was a significant reduction in the demand for natural gas and oil that was caused, at least in part, by the significant deterioration of the global economic environment including the extreme volatility in the capital and credit markets. Weaker demand throughout 2009 resulted in sustained lower natural gas and oil prices, which led to a sharp decline in the demand for drilling and workover services. During 2010, these commodity prices strengthened in the latter half of the year and demand for drilling activity improved. Continued fluctuations in the demand for gas and oil, among other factors including supply, could contribute to continued price volatility which may continue to affect demand for our services and could materially affect our future financial results.

 

Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2010 totaled $4.2 billion, representing an increase of $679.9 million, or 19% as compared to the year ended December 31, 2009. Adjusted income derived from operating activities and net income (loss) attributable to Nabors for the year ended December 31, 2010 totaled $655.4 million and $94.7 million ($.33 per diluted share), respectively, representing increases of 55% and 211%, respectively, compared to the year ended December 31, 2009.

 

Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2009 totaled $3.5 billion, representing a decrease of $1.8 billion, or 34% as compared to the year ended December 31, 2008. Adjusted income derived from operating activities and net income (loss) attributable to Nabors for the year ended December 31, 2009 totaled $421.9 million and $(85.5) million ($(.30) per diluted share), respectively, representing decreases of 62% and 118%, respectively, compared to the year ended December 31, 2008.

 

During 2010, operating results improved as compared to 2009 primarily due to the incremental revenue and positive operating results from our Pressure Pumping operating segment and increased drilling activity in 2010 in our U.S. Lower 48 Land Drilling and Canada Well-servicing operations relating to increased drilling activity in oil and the liquids-oil shale plays. Our U.S. Well-servicing business also improved with continuing strong crude oil prices, which have led to increased activity. However, our operating results and activity levels continued to be negatively impacted in our U.S. Offshore operations in response to uncertainty in the regulatory environment; our Alaskan operations due to key customers’ spending constraints; and elsewhere with less activity in Saudi Arabia and Mexico, two of our key markets. There was also improvement in our operating results for 2010 because there were no full-cost ceiling adjustments recorded by our U.S. oil and gas joint venture.

 

Our U.S. Offshore operations were improving during the first half of 2010 until the Gulf of Mexico explosion and oil spill occurred mid-year, which resulted in temporary suspension of offshore drilling and further delays in our customers’ ability to obtain permits, which has limited the use of our assets. Specifically, operating results have been impacted because our customers have suspended most of their operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. Although the previously issued U.S. deepwater drilling moratorium has been lifted, it is uncertain whether our customers’ ability to obtain government permits will improve in the near term. Our Alaska operating segment has been negatively impacted because the largest operator in the area has curtailed and suspended drilling operations, creating a surplus of rigs in the market and causing price competition. We expect that these conditions will persist and continue to adversely impact our Alaska operating results through 2011. We expect our International results to remain flat in 2011 as the increase of land rig activity is expected to be essentially offset by contract renewals on our jack-up rigs at significantly lower average dayrates.

During 2010, we recorded impairments and other charges of $260.9 million. We recognized goodwill and long-lived asset impairments of approximately $10.7 million and $27.4 million, respectively, to assets in our U.S. Offshore operating segment, primarily driven by current market conditions in the Gulf of Mexico. Additionally, we recognized long-lived asset impairments of $7.5 million to our aircraft and some drilling equipment in Canada and recorded impairments of $23.2 million relating to asset retirements across our U.S. Lower 48 Land, U.S. Well-servicing and U.S. Offshore Contract Drilling segments. Our Oil and Gas operating segment recorded impairments of $54.3 million relating to an oil and gas financing receivable and $137.8 million under application of the successful-efforts method of accounting for our wholly owned oil and gas-related assets.

 

During 2009 and 2008, our operating results were negatively impacted as a result of charges arising from oil and gas full-cost ceiling test writedowns and other impairments. Earnings (losses) from unconsolidated affiliates includes $(189.3) million and $(207.3) million, respectively, for the years ended December 31, 2009 and 2008, representing our proportionate share of a full-cost ceiling test writedown from our unconsolidated U.S. oil and gas joint venture which utilizes the full-cost method of accounting. During 2009, our joint venture used a 12-month average price in the ceiling test calculation as required by the revised SEC rules whereas during 2008, the ceiling test calculation used the single-day, year-end commodity price that, at December 31, 2008, was near its low point for that year. The full-cost ceiling test writedowns are included in our Oil and Gas operating segment results.

 

During 2009, impairments and other charges of $331.0 million included recognition of other-than-temporary impairments of $54.3 million relating to our available-for-sale securities, and impairments of $64.2 million to long-lived assets that were retired from our U.S. Offshore, Alaska, Canada and International contract drilling segments. We also recognized a goodwill impairment of $14.7 million relating to Nabors Blue Sky Ltd., one of our Canadian subsidiaries, which eliminated the remaining goodwill balance relating to remote aircraft operations in Canada. Additionally, we recorded impairment charges of $48.6 million to our wholly owned assets in our Oil and Gas operating segment under application of the successful-efforts method of accounting for some of our oil and gas-related assets and $149.1 million relating to an oil and gas financing receivable during the year ended December 31, 2009.

 

During 2008, impairments and other charges of $176.1 million included goodwill and intangible asset impairments totaling $154.6 million recorded by our Canada Well-servicing and Drilling operating segment and Nabors Blue Sky Ltd. We recognized these goodwill and intangible asset impairments to reduce the carrying value of these assets to their estimated fair value. We consider these writedowns necessary because of the duration of the industry downturn in Canada and the lack of certainty regarding eventual recovery. We also recorded impairment charges of $21.5 million to our wholly owned assets in our Oil and Gas operating segment for some of our oil and gas-related assets during the year ended December 31, 2008.

 

Our operating results for 2011 are still expected to increase from levels realized during 2010, despite a moderating outlook of lower commodity prices during 2011 and the related impact on drilling and well-servicing activity and dayrates. The major factors that support our expectations of an improved year are:

 

 

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