ITEM 1.
BUSINESS
Introduction
Nabors is the largest land drilling contractor in the world and one of the largest land well-servicing and workover contractors in the United States and Canada:
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We actively market approximately 550 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa.
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We actively market approximately 555 rigs for land well-servicing and workover work in the United States and approximately 172 rigs for land well-servicing and workover work in Canada.
We are also a leading provider of offshore platform workover and drilling rigs, and actively market 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:
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We offer a wide range of ancillary well-site services, including hydraulic fracturing, engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select United States and international markets.
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We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software.
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We invest in oil and gas exploration, development and production activities in the United States, Canada and Colombia through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests.
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We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets nine rigs in addition to the rigs we lease to the joint venture.
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We also provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft.
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
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Land Rigs. A land-based drilling rig generally consists of engines, a drawworks, a mast (or derrick), pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string and
related equipment. The engines power the different pieces of equipment, including a rotary table or top drive that turns the drill string, causing the drill bit to bore through the subsurface rock layers. Rock cuttings are carried to the surface by the circulating drilling fluid. The intended well depth, bore hole diameter and drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job.
Special-purpose drilling rigs used to perform workover services consist of a mobile carrier, which includes an engine, drawworks and a mast, together with other standard drilling accessories and specialized equipment for servicing wells. These rigs are specially designed for major repairs and modifications of oil and gas wells, including standard drilling functions. A well-servicing rig is specially designed for periodic maintenance of oil and gas wells for which service is required to maximize the productive life of the wells. The primary function of a well-servicing rig is to act as a hoist so that pipe, sucker rods and down-hole equipment can be run into and out of a well, although they also can perform standard drilling functions. Because of size and cost considerations, these specially designed rigs are used for these operations rather than 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.
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Platform Rigs. Platform rigs provide offshore workover, drilling and re-entry services. Our platform rigs have drilling and/or well-servicing or workover equipment and machinery arranged in modular packages that are transported to, and assembled and installed on, fixed offshore platforms owned by the customer. Fixed offshore platforms are steel tower-like structures that either stand on the ocean floor or are moored floating structures. The top portion, or platform, sits above the water level and provides the foundation upon which the platform rig is placed.
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Jack-up Rigs. Jack-up rigs are mobile, self-elevating drilling and workover platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the hull, which contains the drilling and/or workover equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. The rig legs may operate independently or have a mat attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas. Many of our jack-up rigs are of cantilever design - a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over adjacent, fixed platforms. Nabors’ shallow workover jack-up rigs generally are subject to a maximum water depth of approximately 125 feet, while some of our jack-up rigs may drill in water depths as shallow as 13 feet. Nabors also has deeper water jack-up rigs that are capable of drilling at depths between eight feet and 150 to 250 feet. The water depth limit of a particular rig is determined by the length of its legs and by the operating environment. Moving a rig from one drill site to another involves lowering the hull down into the water until it is afloat and then jacking up its legs with the hull floating. The rig is then towed to the new drilling site.
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Inland Barge Rigs. One of Nabors’ barge rigs is a full-size drilling unit. We also own two workover inland barge rigs. These barges are designed to perform plugging and abandonment, well-service or workover services in shallow inland, coastal or offshore waters. Our barge rigs can operate at depths between three and 20 feet.
Additional information regarding the geographic markets in which we operate and our business segments can be found in Note 22 - Segment Information in Part II, Item 8. - Financial Statements and Supplementary Data.
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.
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Well-servicing/Maintenance Services. We provide maintenance services on the mechanical apparatus used to pump or lift oil from producing wells. These services include, among other activities, repairing and replacing pumps, sucker rods and tubing. They also occasionally include drilling services. We provide the rigs, equipment and crews for these tasks, which are performed on both oil and natural gas wells, but which are more commonly required on oil wells. Maintenance services typically take less than 48 hours to complete. Rigs generally are provided to customers on a call-out basis. We are paid an hourly rate and work typically is performed five days a week during daylight hours.
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Workover Services. Producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workovers may be required to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks or convert a depleted well to an injection well for secondary or enhanced recovery projects. Workovers normally are carried out with a rig that includes standard drilling accessories such as rotary drilling equipment, mud pumps, mud tanks and blowout preventers plus other specialized equipment for servicing rigs. A workover may last anywhere from a few days to several weeks. We are paid a daily rate and work is generally performed seven days a week, 24 hours a day.
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Completion Services. The kinds of activities necessary to carry out a workover operation are essentially the same as those required to “complete” a well when it is first drilled. The completion process may involve selectively perforating the well casing at the depth of discrete producing zones, stimulating and testing these zones and installing down-hole equipment. The completion process may
take a few days to several weeks. We are paid an hourly rate and work is generally performed seven days a week, 24 hours a day.
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Production and Other Specialized Services. We also can provide other specialized services, including onsite temporary fluid storage; the supply, removal and disposal of specialized fluids used during certain completion and workover operations; and the removal and disposal of salt water that often accompanies the production of oil and natural gas. We also provide plugging services for wells from which the oil and natural gas has been depleted or further production has become uneconomical. We are paid an hourly or a per-unit rate, as applicable, for these services.
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 RIGWATCHtm
software and computerized equipment that monitors a rig’s real-time performance. Our directional drilling system, ROCKITtm,
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.
Item 1A. - Risk Factors - Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect Nabors’ results of operations.
ITEM 1A.
RISK FACTORS
In addition to the other information set forth elsewhere in this report, the following factors should be carefully considered when evaluating Nabors. The risks described below are not the only ones 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:
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Gross funded debt to capital, which is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portions of long-term debt and (3) long-term debt; and
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Net funded debt to capital, which is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables.
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.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
ITEM 2.
PROPERTIES
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.
(1)
Represents our proportionate interests in our equity companies.
(2)
During 2010, we purchased a 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County California for $25 million. At December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls. Workovers on approximately 273 productive wells began in late 2010, and 22 wells were producing as of December 31, 2010. The price used in our reserve report was $65.641 per barrel for oil at December 31, 2010.
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
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.
(1)
Represents our proportionate interests in our equity companies.
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
(1)
Represents our proportionate interests in our equity companies.
(1)
Represents our proportionate interests in our equity companies.
Present Activities
The following table provides the number of wells in the process of drilling as of December 31, 2010.
Wells Drilling
(1)
Represents our proportionate interests in our equity companies.
Oil and Gas Properties, Wells, Operations and Acreage
Gross and Net Productive Wells
(1)
Represents our proportionate interests in our equity companies.
Gross and Net Developed Acreage
(1)
Represents our proportionate interests in our equity companies.
Gross and Net Undeveloped Acreage
(1)
Represents our proportionate interests in our equity companies.
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.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
Nabors and its subsidiaries are defendants or otherwise involved in a number of lawsuits in the ordinary course of business. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ from our estimates. 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.
ITEM 4.
ITEM 4.
(REMOVED AND RESERVED)
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
STOCK PERFORMANCE GRAPH
The following graph illustrates comparisons of five-year cumulative total returns among Nabors, the S&P 500 Index and the Dow Jones Oil Equipment and Services Index. Total return assumes $100 invested on December 31, 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.
I.
Market and Share Prices
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:
(1)
Shares were withheld from employees and directors to satisfy certain tax withholding obligations due in connection with grants of stock under our 2003 Employee Stock Plan and option exercises from our 1996 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and our 1998 Employee Stock Plan. The 2003 Employee Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and 1996 Employee Stock Plan provide for the withholding of shares to satisfy tax obligations, but do not specify a maximum number of shares that can be withheld for this purpose. These shares were not purchased as part of a publicly announced program to purchase common shares.
(2)
In July 2006 our Board of Directors authorized a share repurchase program under which we may repurchase up to $500 million of our common shares in the open market or in privately negotiated transactions. Through December 31, 2010, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2010, we had the capacity to repurchase up to an additional $35.5 million of our common shares under the July 2006 share repurchase program.
See Part III, Item 12. for a description of securities authorized for issuance under equity compensation plans.
II.
Dividend Policy
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).
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
(1)
All periods present the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia and the Sea Mar business as discontinued operations.
(2)
Our acquisitions’ results of operations and financial position have been included beginning on the respective dates of acquisition and include Superior (September 2010), Energy Contractors (December 2010), Pragma Drilling Equipment Ltd. assets (May 2006), and 1183011 Alberta Ltd. (January 2006).
(3)
Represents capital expenditures and the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.
(4)
The interest coverage ratio is a trailing 12-month quotient of the sum of income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, subsidiary preferred stock dividends, depreciation and amortization, depletion expense, impairments and other charges, income tax expense (benefit) and our proportionate share of full-cost ceiling test writedowns from our unconsolidated oil and gas joint ventures less investment income (loss) divided by cash interest
expense plus subsidiary preferred stock dividends. This ratio is a method for calculating the amount of operating cash flows available to cover interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
(5)
The December 31, 2008 and 2007 amounts include $1.9 million and $53.1 million, respectively, in cash proceeds receivable from brokers from the sale of certain long-term investments that are included in other current assets. Additionally, the December 31, 2010, 2009 and 2008 amounts include $32.9 million, $92.5 million and $224.2 million, respectively, in oil and gas financing receivables that are included in long-term investments and other receivables.
(6)
The gross funded debt to capital ratio is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portion of long-term debt and (3) long-term debt. Capital is defined as shareholders’ equity. The gross funded debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
(7)
The net funded debt to capital ratio is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables. The net funded debt to capital ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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:
•
An expected incremental increase from ancillary well-site services, primarily technical pumping services and down-hole surveying services, resulting from our acquisition in the third quarter of 2010, and
•
The anticipated positive impact on our overall level of drilling and well-servicing activity and margins resulting from our new and upgraded rigs added to our fleet over the past five years, which we expect will enhance our competitive position as market conditions improve.
The following tables set forth certain information with respect to our reportable segments and rig activity:
(1)
All information present the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia as discontinued operations.
(2)
These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore.
(3)
Includes operating results of the Superior Merger after September 10, 2010.
(4)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $6.9 million, $9.7 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(5)
Represents our oil and gas exploration, development and production operations. Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(189.3) million and $(207.3) million for the years ended December 31, 2009 and 2008, respectively.
(6)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $18.7 million, $(182.6) million and $(204.1) million for the years ended December 31, 2010, 2009 and 2008, respectively. Additional information is provided in Note 24 - Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. - Financial Statements and Supplementary Data.
(7)
Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations.
(8)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $7.7 million, $17.5 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(9)
Represents the elimination of inter-segment transactions.
(10)
Adjusted income (loss) derived from operating activities is computed by subtracting direct costs, general and administrative expenses, depreciation and amortization, and depletion expense from “Operating revenues” and then adding “Earnings (losses) from unconsolidated affiliates.” These amounts should not be used as a substitute for those amounts reported under GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income (loss) derived from operating activities, because it believes that these financial measures are an accurate reflection of our ongoing profitability. A reconciliation of this non-GAAP measure to income (loss) from continuing operations before income taxes, which is a GAAP measure, is provided within the above table.
(11)
Represents the elimination of inter-segment transactions and unallocated corporate expenses.
(12)
Represents impairments and other charges recorded during the years ended December 31, 2010, 2009 and 2008, respectively.
(13)
Excludes well-servicing rigs, which are measured in rig hours. Includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates. Rig years represent a measure of the number of equivalent rigs operating during a given period. For example, one rig operating 182.5 days during a 365-day period represents 0.5 rig years.
(14)
International rig years include our equivalent percentage ownership of rigs owned by unconsolidated affiliates which totaled 2.2 years, 2.5 years and 3.5 years during the years ended December 31, 2010, 2009 and 2008, respectively.
(15)
Rig hours represents the number of hours that our well-servicing rig fleet operated during the year.
Segment Results of Operations
Contract Drilling
Our Contract Drilling operating segments contain one or more of the following operations: drilling, workover and well-servicing and pressure pumping, on land and offshore.
U.S. Lower 48 Land Drilling. The results of operations for this reportable segment are as follows:
Operating revenues increased from 2009 to 2010 primarily due to higher average dayrates and utilization. The increase was partially offset by the decrease in early contract termination revenue. Operating revenues related to early contract termination during 2010 included $23.2 million as compared to $108.5 million in 2009.
Adjusted income derived from operating activities decreased from 2009 to 2010 due to an increase in operating costs associated with the increased drilling activity. Operating results continued to be negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.
Operating results decreased from 2008 to 2009 primarily due to a decline in drilling activity, driven by lower natural gas prices beginning in the fourth quarter of 2008 and diminished demand as customers released rigs and delayed drilling projects in response to the significant drop in natural gas prices and the tightening of the credit markets.
U.S. Land Well-servicing. The results of operations for this reportable segment are as follows:
Operating results increased from 2009 to 2010 primarily due to an increase in rig utilization driven by higher oil prices. The increase in operating results also reflects lower general and administrative costs and depreciation expense.
Operating results decreased from 2008 to 2009 primarily due to lower rig utilization and price erosion, driven by lower customer demand for our services due to relatively lower oil prices caused by the
U.S. economic recession and reduced end product demand. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.
Pressure Pumping. The results of operations for this reportable segment were as follows:
Operating results reflecting our acquisition of Superior are presented above for the period September 10, 2010 through December 31, 2010. See Note 7 - Acquisitions and Divestitures in Part II, Item 8. - Financial Statements and Supplementary Data.
U.S. Offshore. The results of operations for this reportable segment are as follows:
The decrease in operating results from 2009 to 2010 primarily resulted from receiving standby rates and lower utilization for the MODS®
rigs, SuperSundownertm
platform rigs and Sundowner®
platform rigs. Drilling activities significantly declined as our customers suspended their operations in the Gulf of Mexico, largely as a result of their inability to procure government permits.
The decrease in operating results from 2008 to 2009 primarily resulted from lower average dayrates and utilization for the SuperSundownertm
platform rigs, workover jack-up rigs, barge drilling and workover rigs, and Sundowner®
platform rigs, partially offset by higher utilization of our MODS®
rigs inclusive of a significant term contract for a MODS®
rig deployed in January 2009.
Alaska. The results of operations for this reportable segment are as follows:
The decrease in operating results from 2009 to 2010 was primarily due to lower average dayrates and drilling activity. While drilling activity levels decreased significantly during 2010, operating results decreased only slightly due to an acceleration of deferred revenues from a significant terminating contract.
The increase in operating results from 2008 to 2009 was primarily due to increases in average dayrates and drilling activity. Although drilling activity levels decreased slightly during 2009, operating results reflect the higher average margins as a result of the addition of some high specification rig work. The increase during 2009 was partially offset by higher operating costs and increased depreciation expense as well as increased labor and repair and maintenance costs in 2009 as compared to 2008.
Canada. The results of operations for this reportable segment are as follows:
Operating results increased from 2009 to 2010 primarily as a result of an overall increase in drilling and well-servicing activity, which offset the decline in average drilling dayrates and well-servicing hourly rates. The increased drilling activity in Western Canada is the result of renewed interest in oil exploration supported by sustained improved oil prices. The well-servicing hourly rate decreased during 2010 as a result of customer discounts to maintain market share. Our operating results were also positively impacted during 2010 by cost reduction efforts, mainly in general and administrative expenses.
Operating results decreased from 2008 to 2009 primarily as a result of an overall decrease in drilling and well-servicing activity due to lower natural gas prices driving a significant decline of customer demand for drilling and well-servicing operations. Our operating results for 2009 were further negatively impacted by the economic uncertainty in the Canadian drilling market and financial market instability. The Canadian dollar began 2009 in a weak position versus the U.S. dollar, during a period of time when drilling and well-servicing activity was typically at its seasonal peak, which also had an overall negative impact on operating results. These decreases in operating results were partially offset by cost reductions in direct costs, general and administrative expenses and depreciation.
International. The results of operations for this reportable segment are as follows:
The decrease in operating results from 2009 to 2010 resulted primarily from year-over-year decreases in average dayrates and lower utilization of rigs in Saudi Arabia, Mexico, Kazakhstan, and Oman, driven by changes in our customers’ drilling programs and longer lead times for formalization of project requirements in our key markets. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.
The decrease in operating results from 2008 to 2009 resulted primarily from year-over-year decreases in average dayrates and lower utilization of rigs in Mexico, Libya, Argentina and Colombia, driven by weakening customer demand for drilling services stemming from the drop in oil prices in the fourth quarter of 2008 which continued throughout 2009. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years. These decreases were partially offset by higher average dayrates from two jack-up rigs deployed in Saudi Arabia, increases in average dayrates for our new and incremental rigs added and deployed during 2008 and a start-up floating, drilling, production, storage and offloading vessel off the coast of the Republic of the Congo.
Oil and Gas. The results of operations for this reportable segment are as follows:
Our operating results increased from 2009 to 2010 primarily because our unconsolidated U.S. oil and gas joint venture recorded a full-cost ceiling test writedown during 2009, of which our proportionate share totaled $189.3 million. Our proportionate share of the full-cost ceiling writedowns recorded by our other unconsolidated oil and gas joint ventures, SMVP and Remora, have been reclassified to discontinued operations. These writedowns resulted from the application of the full-cost method of accounting for costs related to oil and natural gas properties. The full-cost ceiling test limits the carrying value of the capitalized cost of the properties to the present value of future net revenues attributable to proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or market value of unproved properties. The full-cost ceiling test was evaluated using the 12-month average commodity price as required by the revised SEC rules. Operating results for our U.S. oil and gas joint venture, excluding the full-cost ceiling test writedown, improved from 2009 to 2010.
Our operating results decreased from 2008 to 2009 primarily as a result of the full-cost ceiling test writedown recorded during 2009 discussed above. Operating results further decreased from 2008 to 2009 due to declines in natural gas prices and production volumes. Additionally, operating results for 2008 included a $12.3 million gain recorded on the sale of leasehold interests.
Additional information is provided in Notes 21 - Discontinued Operations and 24 - Supplemental Information on Oil and Gas Exploration and Production Activities in Part II, Item 8. - Financial Statements and Supplementary Data.
Other Operating Segments
These operations include our drilling technology and top-drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations. The results of operations for these operating segments are as follows:
The increase in operating results from 2009 to 2010 primarily resulted from higher demand in the United States and Canada drilling markets for rig instrumentation and data collection services from oil and gas exploration companies and higher third-party rental and rigwatch units, which generate higher margins, partially offset by a continued decline in customer demand for our construction and logistics services in Alaska.
The decreases in operating results from 2008 to 2009 primarily resulted from (i) lower demand in the U.S. and Canada drilling markets for rig instrumentation and data collection services from oil and gas exploration companies, (ii) decreases in customer demand for our construction and logistics services in Alaska and (iii) decreased capital equipment unit volumes and lower service and rental activity as a result of the slowdown in the oil and gas industry.
Discontinued Operations
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 also 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, we reclassified these wholly owned oil and gas assets from our property, plant and equipment, net, as well as our investment balances for Remora and SMVP from investments in unconsolidated affiliates to assets held for sale in our consolidated balance sheet at September 30, 2010.
The operating results from these assets for all periods presented are retroactively presented and accounted for as discontinued operations in the accompanying audited consolidated statements of income (loss). Our condensed statements of income (loss) from discontinued operations for the years ended December 31, 2010, 2009 and 2008 were as follows:
(1)
Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million and $21.0 million, for the years ended December 31, 2009 and 2008, respectively.
OTHER FINANCIAL INFORMATION
General and administrative expenses
General and administrative expenses decreased from 2009 to 2010 and from 2008 to 2009 primarily as a result of significant decreases in wage-related expenses and other cost-reduction efforts across all business units. The decrease during 2009 was partially offset by share-based compensation expense, which included $72.1 million of compensation expense related to previously granted restricted stock and option awards held by Messrs. Isenberg and Petrello that was unrecognized as of April 1, 2009. The recognition of this expense resulted from provisions of their respective new employment agreements that effectively eliminated the risk of forfeiture of such awards. There is no remaining unrecognized expense related to their outstanding restricted stock and option awards. Excluding the share-based compensation expense related to the previous awards held by Messrs. Isenberg and Petrello, general and administrative expenses for 2009 and 2010 are substantially below 2008 levels, indicating that the cost-reduction efforts and actions across all business units beginning in late 2008 have had a favorable impact on our operating results.
Depreciation and amortization, and depletion expense
Depreciation and amortization expense. Depreciation and amortization expense increased from 2009 to 2010 and from 2008 to 2009 primarily as a result of projects completed in recent years under our expanded capital expenditure program that commenced in early 2005.
Depletion expense. Depletion expense increased from 2009 to 2010 as a result of increased units-of-production depletion. Depletion expense decreased from 2008 to 2009 primarily as a result of decreased natural gas production volumes during each year.
Interest expense
Interest expense increased from 2009 to 2010 as a result of the interest expense related to our September 2010 issuance of 5.0% senior notes due September 2020. The increase was partially offset by a reduction to interest expense resulting from our repurchases of approximately $1.2 billion par value of 0.94% senior exchangeable notes during 2009 and 2010.
Interest expense increased from 2008 to 2009 as a result of the interest expense related to our January 2009 issuance of 9.25% senior notes due January 2019. The increase was partially offset by a reduction to interest expense due to our repurchases of approximately $1.1 billion par value of 0.94% senior exchangeable notes during 2008 and 2009.
Investment income (loss)
Investment income during 2010 was $7.6 million compared to $25.6 million during the prior year. Investment income in 2010 included interest and dividend income of $7.2 million from our cash, other short-term and long-term investments and $4.9 million from gains on sales of short-term and long-term investments, partially offset by net unrealized losses of $4.4 million from our trading securities.
Investment income during 2009 was $25.6 million compared to $21.4 million during 2008. Investment income in 2009 included net unrealized gains of $9.8 million from our trading securities and interest and dividend income of $15.9 million from our cash, other short-term and long-term investments.
Investment income during 2008 was $21.4 million and included net unrealized gains of $8.5 million from our trading securities and interest and dividend income of $40.5 million from our short-term and long-term investments, partially offset by losses of $27.4 million from our actively managed funds classified as long-term investments.
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net
The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2010 represents a net loss of $47.1 million and includes: (i) foreign currency exchange losses of approximately $17.9 million, (ii) litigation expenses of $6.4 million, (iii) net losses on sales and retirements of long-lived assets of approximately $6.6 million, (iv) acquisition-related costs of $7.0 million and (v) losses of $7.0 million recognized on purchases of our 0.94% senior exchangeable notes due 2011.
The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2009 represents a net loss of $12.6 million and includes: (i) foreign currency exchange losses of approximately $8.4 million, (ii) litigation expenses of $11.5 million and (iii) net losses on sales and retirements of long-lived assets of approximately $5.9 million. These losses were partially offset by pre-tax gains of $11.5 million recognized on purchases of $964.8 million par value of our 0.94% senior exchangeable notes due 2011.
The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2008 represents a net loss of $15.8 million and includes: (i) losses on derivative instruments of approximately $14.6 million, including a $9.9 million loss on a three-month written put option and a $4.7 million loss on the fair value of our range-cap-and-floor derivative, (ii) losses on retirements on long-lived assets of approximately $13.2 million, inclusive of involuntary conversion losses on long-lived assets of approximately $12.0 million, net of insurance recoveries, related to damage sustained from Hurricanes Gustav and Ike during 2008 and (iii) litigation expenses of $3.5 million. These losses were partially offset by a $12.2 million pre-tax gain recognized on our purchase of $100 million par value of 0.94% senior exchangeable notes due 2011.
Impairments and Other Charges
Impairments of Oil and Gas Assets
In 2010, we recognized impairments of $192.2 million related to our oil and gas assets. Of this total, $137.8 million represents writedowns to the carrying value of some acreage in the United States, which we do not have future plans to develop due to the sustained low natural gas prices, and certain exploratory wells in Colombia, which we have determined will be uneconomical to develop in the foreseeable future.
The remaining $54.3 million relates to an impairment of a financing receivable as a result of the continued commodity price deterioration in the Barnett Shale area of north central Texas. We determined that this impairment was necessary using estimates and assumptions based on estimated cash flows for proved and probable reserves and current natural gas prices. We believe the estimates used provide a reasonable estimate of current fair value. We determined that this represented a Level 3 fair value measurement. As of December 31, 2010, the carrying value of this oil and gas financing receivable, which is included in long-term investments, has been reduced to $20.1 million. A further protraction or continued period of lower commodity prices could result in recognition of future impairment charges.
In 2009, we recorded impairments totaling $197.7 million to some of our wholly owned oil and gas assets. We recognized an impairment of $149.1 million to a financing receivable as a result of commodity price deterioration and the lower price environment last longer than expected. The prolonged period of lower prices significantly reduced demand for future gas production and development in the Barnett Shale area of north central Texas and influenced our decision not to expend capital to develop on some of the undeveloped acreage. The impairment, which represented a Level 3 fair value measurement, was determined using discounted cash flow models involving assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices. Additionally, our annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $48.6 million to writedown the carrying value of some acreage that we do not have future plans to develop.
In 2008, our annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $21.5 million primarily due to the significant decline in oil and natural gas prices at the end of 2008. Additional discussion of our policy pertaining to the calculation of our annual impairment tests is set forth below in “Oil and Gas Properties” and in Note 2 - Summary of Significant Accounting Policies in Part II, Item 8. - Financial Statements and Supplementary Data.
Impairments of Long-Lived Assets
In 2010, we recognized impairments of $58.0 million in multiple operating segments. These impairments included $23.2 million related to the retirement of certain rig components, comprised of engines, top-drive units, building modules and other equipment that has become obsolete or inoperable in each of these operating segments in our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing and U.S. Offshore Contract Drilling segment. The impairment charges were determined to be necessary as a result of the continued lower commodity price environment and its related impact on drilling and well-servicing activity and our dayrates. A prolonged period of legislative uncertainty in our U.S. Offshore operations, or continued period of lower natural gas and oil prices and its potential impact on our utilization and dayrates could result in the recognition of future impairment charges to additional assets if future cash flow estimates, based upon information then available to management, indicate that the carrying value of those assets may not be recoverable.
The remaining $34.8 million in impairment charges recorded during 2010 include $27.3 million related to the impairment of some jack-up rigs in our U.S. Offshore operating segment and $7.5 million to our aircraft and some drilling equipment in Nabors Blue Sky Ltd. These impairment charges stemmed from our annual impairment tests on long-lived assets, which determined that the sum of the estimated future cash flows, on an undiscounted basis, was less than the carrying amount of these assets. The estimated fair values of these assets were calculated using discounted cash flow models involving assumptions based on our utilization of the assets, revenues as well as direct costs, capital expenditures and working capital requirements. The impairment charge relating to our U.S. Offshore segment was deemed necessary due to the economic conditions for drilling in the Gulf of Mexico, as discussed below. The impairment charge relating to Nabors Blue Sky Ltd. was deemed necessary due to the continued duration of the downturn in the oil and gas industry in Canada, which has resulted in diminished demand for the remote access services provided by this subsidiary’s aircraft fleet.
In 2009, we recognized impairments of $64.2 million related to retirements of certain assets in our U.S. Offshore, Alaska, Canada and International Contract Drilling segments, which reduced their aggregate carrying value to their estimated aggregate salvage value. The retirements included inactive workover jack-up
rigs in our U.S. Offshore and International operations, the structural frames of some incomplete coiled tubing rigs in our Canada operations and miscellaneous rig components in our Alaska operations. The impairment charges resulted from the continued deterioration and longer-than-expected downturn in the demand for oil and gas drilling activities.
Goodwill Impairments
In 2010, we recognized an impairment of approximately $10.7 million relating to our goodwill balance of our U.S. Offshore operating segment. The impairment charge stemmed from our annual impairment test on goodwill, which compared the estimated fair value of each of our reporting units to its carrying value. The estimated fair value of our U.S. Offshore segment was determined using discounted cash flow models involving assumptions based on our utilization of rigs and revenues as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. We determined that the fair value estimated for purposes of this test represented a Level 3 fair value measurement. The impairment charge was deemed necessary due to the uncertainty of utilization of some of our rigs as a result of changes in our customers’ plans for future drilling operations in the Gulf of Mexico. Many of our customers have suspended drilling operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. Although the 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. A significantly prolonged period of lower oil and natural gas prices or changes in laws and regulations could adversely affect the demand for and prices of our services, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our estimate of our future operating results. See Critical Accounting Policies below and Note 2 - Summary of Significant Accounting Policies (included under the caption “Goodwill”) in Part II, Item 8. - Financial Statements and Supplementary Data.
In 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd., one of our Canadian subsidiaries who provides access to remote drilling sites by helicopters and fixed-wing aircraft. The impairment charges resulted from our annual impairment tests on goodwill which compared the estimated fair value of each of our reporting units to its carrying value. The estimated fair value of these business units was determined using discounted cash flow models involving assumptions based on our utilization of rigs or aircraft, revenues and earnings from affiliates, as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. We determined that the fair value estimated for purposes of this test represented a Level 3 fair value measurement. The impairment charges were deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn led to reduced capital spending by some of our customers and diminished demand for our drilling services and for immediate access to remote drilling sites.
In 2008, we impaired the entire goodwill balance of $145.4 million of our Canada Well-servicing and Drilling operating segment and recorded an impairment of $4.6 million to Nabors Blue Sky Ltd. This impairment was also deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn led to reduced capital spending by some of our customers and diminished demand for our drilling services and for immediate access to remote drilling sites.
Other than Temporary Impairments on Debt and Equity Securities
In 2009, we recorded other-than-temporary impairments to our available-for-sale securities totaling $54.3 million. Of this, $35.6 million was related to an investment in a corporate bond that was downgraded to non-investment grade level by Standard and Poor’s and Moody’s Investors Service during the year. Our determination that the impairment was other-than-temporary was based on a variety of factors, including the length of time and extent to which the market value had been less than cost, the financial condition of the issuer of the security, and the credit ratings and recent reorganization of the issuer.
The remaining $18.7 million related to an equity security of a public company whose operations are driven in large measure by the price of oil and in which we invested approximately $46 million during the
second and third quarters of 2008. During late 2008, demand for oil and gas began to diminish significantly as part of the general deterioration of the global economic environment, causing a broad decline in value of nearly all oil and gas-related equity securities. Because the trading price per share of this security remained below our cost basis for an extended period of time, we determined the investment was other than temporarily impaired and it was appropriate to write down its carrying value to its estimated fair value.
Income tax rate
Our effective income tax rate for 2010 and 2009 reflects the disparity between losses in our U.S. operations (attributable primarily to impairments) and income in our other operations primarily in lower tax jurisdictions. Because the U.S. income tax rate is higher than that of other jurisdictions, the tax benefit from our U.S. losses was not proportionately reduced by the tax expense from our other operations. During 2010 and 2009, the result was a net tax benefit. In 2009, that benefit represented a significant percentage of our consolidated loss from continuing operations before income taxes. Because of the manner in which that number was derived, we do not believe it presents a meaningful basis for comparing our 2009 effective income tax rate to either the 2010 or 2008 effective income tax rate.
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. One of the most volatile factors in this determination is the relative proportion of our income or loss being recognized in high- versus low-tax jurisdictions. In the ordinary course of our business, there are many transactions and calculations for which the ultimate tax determination is uncertain. We are regularly audited by tax authorities. Although we believe our tax estimates are reasonable, the final outcome of tax audits and any related litigation could be materially different than what is reflected in our income tax provisions and accruals. The results of an audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows.
Various bills have been introduced in Congress that could reduce or eliminate the tax benefits associated with our reorganization as a Bermuda company. Legislation enacted by 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 June 24, 2002. There have been and we expect that there may continue to be legislation proposed by 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.
Liquidity and Capital Resources
Cash Flows
Our cash flows depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Sustained increases or decreases in the price of natural gas or oil could have a material impact on these activities, and could also materially affect our cash flows. Certain sources and uses of cash, such as the level of discretionary capital expenditures, purchases and sales of investments, issuances and repurchases of debt and of our common shares are within our control and are adjusted as necessary based on market conditions. The following is a discussion of our cash flows for the years ended December 31, 2010 and 2009.
Operating Activities. Net cash provided by operating activities totaled $1.1 billion during 2010 compared to net cash provided by operating activities of $1.6 billion during 2009. Net cash provided by
operating activities (“operating cash flows”) is our primary source of capital and liquidity. Factors affecting changes in operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as depreciation and amortization, depletion, impairments, share-based compensation, deferred income taxes and our proportionate share of earnings or losses from unconsolidated affiliates. Net income (loss) adjusted for non-cash components was approximately $1.3 billion and $1.1 billion for the years ended December 31, 2010 and 2009, respectively. Additionally, changes in working capital items such as collection of receivables can be a significant component of operating cash flows. Changes in working capital items used $202.4 million in cash flows for the year ended December 31, 2010 and provided $471.9 million in cash flows for the year ended December 31, 2009.
Investing Activities. Net cash used for investing activities totaled $1.7 billion during 2010 compared to net cash used for investing activities of $1.2 billion during 2009. During 2010, we used cash of $680.2 million and $53.4 million, respectively, to acquire Superior (net of the cash acquired) and the assets of Energy Contractors. During 2010 and 2009, we used cash primarily for capital expenditures totaling $930.3 million and $1.1 billion, respectively, and investments in unconsolidated affiliates totaling $40.9 million and $125.1 million, respectively. During 2009, we derived cash from sales of investments, net of purchases, totaling $24.4 million.
Financing Activities. Net cash provided by financing activities totaled $280.3 million during 2010 compared to net cash used for financing activities of $19.4 million during 2009. During 2010, cash was provided from the receipt of $682.3 million in proceeds, net of debt issuance costs, from the September 2010 issuance of 5.0% senior notes due 2020. During 2010, we used cash to purchase $273.9 million of our 0.94% senior exchangeable notes due 2011 and to repay $124.0 million of Superior’s revolving credit facility and second lien notes.
During 2009, cash was derived from the receipt of $1.1 billion in proceeds, net of debt issuance costs, from the January 2009 issuance of 9.25% senior notes due 2019, and cash totaling $862.6 million was used to purchase $964.8 million par value of 0.94% senior exchangeable notes due 2011 and $225.2 million was used to redeem the 4.875% senior notes. During 2010 and 2009, cash was provided by our receipt of proceeds totaling $8.2 million and $11.2 million, respectively, from the exercise by our employees of options to acquire our common shares.
Future Cash Requirements
As of December 31, 2010, we had long-term debt, including current maturities, of $4.4 billion and cash 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.
As of December 31, 2010, the current portion of our long-term debt included $1.4 billion par value of Nabors Delaware’s 0.94% senior exchangeable notes that mature in May 2011. We continue to assess our ability to meet this obligation, along with our other operating and capital requirements and other potential opportunities. We expect to do so through a combination of cash on hand, future operating cash flows, possible dispositions of non-core assets, availability under our unsecured revolving credit facility and our ability to access the capital markets, if required. 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. There are a number of factors that could negatively impact our plans, including our ability to access the financial markets at competitive rates if the financial markets are limited or restricted, a decline in oil and natural gas prices, a decline in demand for our services or market perceptions of us and our industry.
The senior exchangeable notes would require us upon exchange to pay note holders cash up to the principal amount of the notes and our common shares for any amount by which the exchange value of the notes exceeds their principal amount. The notes can only be exchanged:
(i) if our share price exceeds $59.57 (approximately) for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter; or
(ii) during the five business days immediately following any ten consecutive trading day period in which the per note trading price for each day of that period is less than 95% of the product of (a) the sale price of our common shares and (b) the then applicable exchange rate for the notes; or
(iii) upon the occurrence of specified corporate transactions.
On February 24, 2011, the closing market price for our common stock was $27.65 per share. If any of the foregoing conditions were met and the notes were exchanged at a price equal to 100% of their principal amount before maturity, 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. However, management believes that if the price of our shares exceeded $59.57 for the required period of time, note holders would be unlikely to exchange them as it would be more beneficial to sell the notes to other investors on the open market. Nevertheless, there can be no assurance that the holders would not exchange the notes.
We expect capital expenditures over the next 12 months to approximate $1.3-1.7 billion. We had outstanding purchase commitments of approximately $754.6 million at December 31, 2010, primarily for rig-related enhancements, construction and sustaining capital expenditures and other operating expenses. We can reduce the planned expenditures if necessary, or increase them if market conditions and new business opportunities warrant it.
We have historically completed a number of acquisitions and will continue to evaluate opportunities to acquire assets or businesses to enhance our operations. Several of our previous acquisitions were funded through issuances of our common shares. Future acquisitions may be paid for using existing cash or issuing debt or Nabors shares. Such capital expenditures and acquisitions will depend on our view of market conditions and other factors.
See our discussion of guarantees issued by Nabors that could have a potential impact on our financial position, results of operations or cash flows in future periods included below under Off-Balance Sheet Arrangements (Including Guarantees).
The following table summarizes our contractual cash obligations as of December 31, 2010:
The table above excludes liabilities for unrecognized tax benefits totaling $124.1 million as of December 31, 2010 because we are unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in Note 12 - Income Taxes in Part II, Item 8. - Financial Statements and Supplementary Data.
(1) See Note 11 - Debt in Part II, Item 8. - Financial Statements and Supplementary Data.
(2)
Includes the remaining portion of Nabors Delaware’s 0.94% senior exchangeable notes due May 2011.
(3) Includes Nabors Delaware’s 5.375% senior notes due August 2012.
(4)
Represents Nabors Delaware’s aggregate 6.15% senior notes due February 2018, 9.25% senior notes due January 2019 and 5.0% senior notes due September 2020.
(5)
See Note 17 - Commitments and Contingencies in Part II, Item 8. - Financial Statements and Supplementary Data.
(6)
Purchase commitments include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including fixed or minimum quantities to be purchased; fixed, minimum or variable pricing provisions; and the approximate timing of the transaction.
(7)
We have contracts with a pipeline company to pay specified fees based on committed volumes for gas transport and processing, as calculated on a monthly basis. Due to low natural gas prices and our decision to delay drilling, our current available production flowing to pipelines and processing plants does not meet the daily committed volumes required under the contracts. The amounts set forth in the table above reflect the aggregate fees payable under these contracts.
We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, both in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In July 2006 our Board of Directors authorized a share repurchase program under which we may repurchase up to $500 million of our common shares in the open market or in privately negotiated transactions. Through December 31, 2010, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2010, we had the capacity to repurchase up to an additional $35.5 million of our common shares under the July 2006 share repurchase program.
See Note 17 - Commitments and Contingencies in Part II, Item 8. - Financial Statements and Supplementary Data for discussion of commitments and contingencies relating to (i) new employment agreements, effective April 1, 2009, that could result in significant cash payments of $100 million and $50 million to Messrs. Isenberg and Petrello, respectively, by the Company if their employment is terminated in the event of death or disability or cash payments of $100 million to Mr. Isenberg and a cash payment of approximately $34 million to Mr. Petrello, respectively, by the Company if their employment is terminated without cause or in the event of a change in control and (ii) off-balance sheet arrangements (including guarantees).
Financial Condition and Sources of Liquidity
Our primary sources of liquidity are cash and cash equivalents, short-term and long-term investments and cash generated from operations. As of December 31, 2010, we had cash and investments of $841.5 million (including $40.3 million of long-term investments and other receivables, inclusive of $32.9 million in oil and gas financing receivables) and working capital of $458.6 million. Oil and gas financing receivables are classified as long-term investments. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment. This compares to cash and investments of $1.2 billion (including $100.9 million of long-term investments and other receivables, inclusive of $92.5 million in oil and gas financing receivables) and working capital of $1.6 billion as of December 31, 2009.
Our gross funded debt to capital ratio was 0.42:1 as of December 31, 2010 and 0.41:1 as of December 31, 2009. Our net funded debt to capital ratio was 0.37:1 as of December 31, 2010 and 0.33:1 as of December 31, 2009.
The gross funded debt to capital ratio is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portion of long-term debt and (3) long-term debt. Capital is shareholders’ equity.
The net funded debt to capital ratio is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables. Both of these ratios are used to calculate a company’s leverage in relation to its capital. Neither ratio measures operating performance or liquidity as defined by GAAP and, therefore, may not be comparable to similarly titled measures presented by other companies.
Our interest coverage ratio was 7.0:1 as of December 31, 2010 and 6.3:1 as of December 31, 2009. The interest coverage ratio is a trailing 12-month quotient of the sum of income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, subsidiary preferred stock dividends, depreciation and amortization, depletion expense, impairments and other charges, income tax expense (benefit) and our proportionate share of writedowns from our unconsolidated oil and gas joint ventures less investment income (loss) divided by cash interest expense plus subsidiary preferred stock dividends. This ratio is a method for calculating the amount of operating cash flows available to cover cash interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.
During the third quarter of 2010, we and Nabors Delaware entered into a credit agreement under which the lenders committed to provide up to $700 million under an unsecured revolving credit facility (the “Revolving Credit Facility”) or the (“Facility”). The Facility also provides Nabors Delaware the option to add other lenders and increase the aggregate principal amount of commitments to $850 million by adding new lenders to the Facility or by asking existing lenders under the Facility to increase their commitments (in each case with the consent of the new lenders or the increasing lenders). In January 2011, Nabors Delaware added a new lender to the Facility and increased the total commitments under the Facility to $750 million. We fully and unconditionally guarantee the obligations under the Revolving Credit Facility, which matures in four years.
Borrowings under the Revolving Credit Facility bear interest, at Nabors Delaware’s option, at either (x) the “Base Rate” (as defined below) plus the applicable interest margin, calculated on the basis of the actual number of days elapsed in a year of 365 days and payable quarterly in arrears or (y) interest periods of one, two, three or six months at an annual rate equal to the LIBOR for the corresponding deposits of U.S. dollars, plus the applicable interest margin, payable on the last days of the relevant interest periods (but in any event at least every three months). The “Base Rate” is defined, for any day, as a fluctuating rate per annum equal to the highest of (i) the Federal Funds Rate, as published by the Federal Reserve Bank of New York, plus 1/2 of 1%, (ii) the prime commercial lending rate of UBS AG, as established from time to time at its Stamford Branch and (iii) LIBOR for an interest period of one month beginning on such day plus 1%.
On September 10, 2010, we completed the Superior Merger, pursuant to which we acquired all of the issued and outstanding shares of Superior’s common stock, at a price per share equal to $22.12 for a cash purchase price of approximately $681.3 million. We paid this amount using cash on hand and proceeds from the Revolving Credit Facility. Nabors Delaware repaid the borrowing under the Revolving Credit Facility using cash on hand and proceeds from the senior notes issued on September 14, 2010, as discussed below.
On September 14, 2010, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 5.0% senior notes due 2020, which are unsecured and are fully and unconditionally guaranteed by us. The senior notes have registration rights and will mature on September 15, 2020. Nabors Delaware used a portion of the proceeds to repay the borrowing of $600 million under the Revolving Credit Facility incurred to fund the acquisition of Superior. We and Nabors Delaware are using the remaining proceeds for general corporate purposes.
On January 20, 2011, in accordance with the registration rights agreement entered into in connection with the issuance of the 5.0% senior notes, Nabors Delaware commenced an exchange offer for the notes pursuant to a registration statement on Form S-4, which was declared effective by the SEC on January 19, 2011. The exchange offer expired on February 23, 2011 and closed on February 28, 2011.
On December 31, 2010, we purchased the business of Energy Contractors for a total cash purchase price of $53.4 million. We paid this amount using cash on hand.
We had five letter-of-credit facilities with various banks as of December 31, 2010. Availability under our letter-of-credit facilities as of December 31, 2010 was as follows:
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 Investors Service and Standard & Poor’s and our historical ability to access those markets as needed. While there can be no assurances that we will be able to access these markets in the future, we believe that we will be able to access capital markets or otherwise obtain financing in order to satisfy any payment obligation that might arise upon exchange or purchase of our notes and that any cash payment due, in addition to our other cash obligations, would not ultimately have a material adverse impact on our liquidity or financial position. A credit downgrade may impact our ability to access credit markets.
Our current cash and investments, projected cash flows from operations, possible dispositions of non-core assets and our Facility are expected to adequately finance our purchase commitments, our scheduled debt service requirements, and all other expected cash requirements for the next twelve months.
See our discussion of the impact of changes in market conditions on our derivative financial instruments under Item 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. This risk arises primarily as a result of potential changes in the fair market value of financial instruments due to adverse fluctuations in foreign currency exchange rates, credit risk, interest rates, and marketable and non-marketable security prices as discussed below.
Foreign Currency Risk. We operate in a number of international areas and are involved in transactions denominated in currencies other than U.S. dollars, which exposes us to foreign exchange rate risk and foreign currency devaluation risk. The most significant exposures arise in connection with our operations in Venezuela and Canada, which usually are substantially unhedged.
At various times, we utilize local currency borrowings (foreign currency-denominated debt), the payment structure of customer contracts and foreign exchange contracts to selectively hedge our exposure to exchange rate fluctuations in connection with monetary assets, liabilities, cash flows and commitments denominated in certain foreign currencies. A foreign exchange contract is a foreign currency transaction, defined as an agreement to exchange different currencies at a given future date and at a specified rate. A hypothetical 10% decrease in the value of all our foreign currencies relative to the U.S. dollar as of December 31, 2010 would result in a $12.2 million decrease in the fair value of our net monetary assets denominated in currencies other than U.S. dollars.
Credit Risk. Our financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash equivalents, short-term and long-term investments, oil and gas financing receivables, accounts receivable and our range-cap-and-floor derivative instrument. Cash equivalents such as deposits and temporary cash investments are held by major banks or investment firms. Our short-term and long-term investments are managed within established guidelines which limit the amounts that may be invested with any one issuer and provide guidance as to issuer credit quality. We believe that the credit risk in our cash and investment portfolio is minimized as a result of the mix of our investments. In addition, our trade receivables are with a variety of U.S., international and foreign-country national oil and gas companies. Management considers this credit risk to be limited due to the financial resources of these companies. We perform ongoing credit evaluations of our customers and we generally do not require material collateral. We do occasionally require prepayment of amounts from customers whose creditworthiness is in question prior to providing services to them. We maintain reserves for potential credit losses, and these losses historically have been within management’s expectations.
Interest Rate, and Marketable and Non-marketable Security Price Risk. Our financial instruments that are potentially sensitive to changes in interest rates include the 0.94% senior exchangeable notes, our 5.375%, 6.15%, 9.25% and 5.0% senior notes, our range-cap-and-floor derivative instrument, our investments in debt securities (including corporate, asset-backed, mortgage-backed debt and mortgage-CMO debt securities) and our investments in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages), which are classified as long-term investments.
We may utilize derivative financial instruments that are intended to manage our exposure to interest rate risks. We account for derivative financial instruments under the Derivatives Topic of the ASC. The use of derivative financial instruments could expose us to further credit risk and market risk. Credit risk in this context is the failure of a counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty would owe us, which can create credit risk for us. When the fair value of a derivative contract is negative, we would owe the counterparty, and therefore, we would not be exposed to credit risk. We attempt to minimize credit risk in derivative instruments by entering into transactions with major financial institutions that have a significant asset base. Market risk related to derivatives is the adverse effect on the value of a financial instrument that results from changes in interest rates. We try to manage market risk associated with interest-rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that we undertake.
On October 21, 2002, we entered into an interest rate swap transaction with a third-party financial institution to hedge our exposure to changes in the fair value of $200 million of our fixed rate 5.375% senior
notes due 2012, which has been designated as a fair value hedge. Additionally on that date, we purchased a LIBOR range-cap and sold a LIBOR floor, in the form of a cashless collar, with the same third-party financial institution with the intention of mitigating and managing our exposure to changes in the three-month U.S. dollar LIBOR rate. This transaction does not qualify for hedge accounting treatment and any change in the cumulative fair value of this transaction is reflected as a gain or loss in our consolidated statements of income (loss). In June 2004, we unwound $100 million of the $200 million range-cap-and-floor derivative instrument. During the fourth quarter of 2005, we unwound the interest rate swap resulting in a loss of $2.7 million, which has been deferred and will be recognized as an increase to interest expense over the remaining life of our 5.375% senior notes due 2012. During the year ended December 31, 2005, we recorded interest savings of $2.7 million related to our interest rate swap agreement accounted for as a fair value hedge, which served to reduce interest expense.
The fair value of our range-cap-and-floor transaction is recorded as a derivative liability and included in other long-term liabilities. It totaled approximately $3.4 million and $3.3 million as of December 31, 2010 and 2009, respectively. During 2010, 2009 and 2008, we recorded gains (losses) of approximately $(.1) million, $1.4 million and $(4.7) million, respectively, related to this derivative instrument; these amounts are included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss).
A hypothetical 10% adverse shift in quoted interest rates as of December 31, 2010 would decrease the fair value of our range-cap-and-floor derivative instrument by approximately $.1 million.
In September 2008 we entered into a three-month written put option for one million of our common shares with a strike price of $25 per share. We settled this contract during the fourth quarter of 2008 and paid cash of $22.6 million, net of the premium received, and recognized a loss of $9.9 million which is included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss).
Fair Value of Financial Instruments. We estimate the fair value of our financial instruments in accordance with the provisions of the Fair Value Measurements and Disclosures Topic of the ASC. The fair value of our fixed rate long-term debt is estimated based on quoted market prices or prices quoted from third-party financial institutions. The fair value of the subsidiary preferred stock was estimated based on the allocation of the purchase price. See Note 7 - Acquisitions and Divestitures in Part II, Item 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Nabors Industries Ltd.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss), changes in equity and cash flows present fairly, in all material respects, the financial position of Nabors Industries Ltd. and its subsidiaries (the Company) at December 31, 2010 and December 31, 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which their oil and gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and gas costs as of December 31, 2009.
As described in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, management has excluded Superior Well Services, Inc. (“Superior”) from its assessment of internal control over financial reporting as of December 31, 2010 because Superior was acquired by the Company in a purchase business combination during 2010. We have also excluded Superior from our audit of internal control over financial reporting. Superior is a wholly-owned subsidiary whose total assets and total revenues represent 10 and 8 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2010.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2011
NABORS INDUSTRIES LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
NABORS INDUSTRIES LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
The details of credit-related impairments to investments for the year ended December 31, 2009 is presented below:
(1)
Included in Impairments and other charges (Note 3)
The accompanying notes are an integral part of these consolidated financial statements.
NABORS INDUSTRIES LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
NABORS INDUSTRIES LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
NABORS INDUSTRIES LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - (Continued)
The accompanying notes are an integral part of these consolidated financial statements.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1
Nature of Operations
Nabors is the largest land drilling contractor in the world and one of the largest land well-servicing and workover contractors in the United States and Canada:
•
We actively market approximately 550 land drilling rigs for oil and gas land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa.
•
We actively market approximately 555 rigs for land well-servicing and workover work in the United States and approximately 172 rigs for land workover and well-servicing work in 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:
•
We offer a wide range of ancillary well-site services, including hydraulic fracturing, engineering, transportation and disposal, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select United States and international markets.
•
We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software.
•
We invest in oil and gas exploration, development and production activities in the United States, Canada and Colombia through both our wholly owned subsidiaries and our oil and gas joint ventures in which we hold 49-50% ownership interests.
•
We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets nine rigs in addition to the rigs we lease to the joint venture.
•
We also provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft.
The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, well-servicing, fluid logistics and workover operations, 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.
On September 10, 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 downhole 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 for additional information.
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 also include our 49.7% and 50.0% ownership interests in our investments of Remora Energy International LP (“Remora”) and Stone Mountain Venture Partnership
Nabors Industries Ltd. and Subsidiaries
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(“SMVP”), respectively, which we account for using the equity method of accounting. 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 certain 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.
The consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications have been made to prior periods to conform to the current period presentation, with no effect on our consolidated financial position, results of operations or cash flows.
Note 2
Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of Nabors, as well as all majority owned and non-majority owned subsidiaries required to be consolidated under GAAP. Our consolidated financial statements exclude majority owned entities for which we do not have either (1) the ability to control the operating and financial decisions and policies of that entity or (2) a controlling financial interest in a variable interest entity. All significant intercompany accounts and transactions are eliminated in consolidation.
Investments in operating entities where we have the ability to exert significant influence, but where we do not control operating and financial policies, are accounted for using the equity method. Our share of the net income (loss) of these entities is recorded as earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss), and our investment in these entities is included as a single amount in our consolidated balance sheets. Investments in unconsolidated affiliates accounted for using the equity method totaled $265.8 million and $305.7 million and investments in unconsolidated affiliates accounted for using the cost method totaled $1.9 million and $.9 million as of December 31, 2010 and 2009, respectively. At December 31, 2010, assets held for sale include investments in unconsolidated affiliates accounted for using the equity method totaling $79.5 million. See Note 21 - Discontinued Operations for additional information.
Similarly, we have investments in offshore funds, which are classified as long-term investments and are accounted for using the equity method of accounting based on our ownership interest in each fund.
Cash and Cash Equivalents
Cash and cash equivalents include demand deposits and various other short-term investments with original maturities of three months or less.
Investments
Short-term investments
Short-term investments consist of equity securities, certificates of deposit, corporate debt securities, mortgage-backed debt securities and asset-backed debt securities. Securities classified as available-for-sale or trading are stated at fair value. Unrealized holding gains and temporary losses for available-for-sale securities are excluded from earnings and, until realized, are reported net of taxes in a separate component of equity. Unrealized holding losses are included in earnings during the period for which the loss is determined to be other-than-temporary. Gains and losses from changes in the market value of securities classified as trading are reported in earnings currently.
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In computing realized gains and losses on the sale of equity securities, the specific-identification method is used. In accordance with this method, the cost of the equity securities sold is determined using the specific cost of the security when originally purchased.
Long-term investments and other receivables
Our oil and gas financing receivables are classified as long-term investments. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment. We have also invested in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages). These investments are non-marketable and do not have published fair values. We account for these funds under the equity method of accounting based on our percentage ownership interest and recognize gains or losses as investment income (loss), currently based on changes in the net asset value of our investment during the current period.
Inventory
Inventory is stated at the lower of cost or market. Cost is determined using the first-in, first-out method and includes the cost of materials, labor and manufacturing overhead. Inventory was comprised of approximately $81.3 million in raw materials, $23.6 million in work-in-progress and $53.9 million in finished goods at December 31, 2010.
Property, Plant and Equipment
Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We provide for the depreciation of our drilling and workover rigs using the units-of-production method. For each day a rig is operating, we depreciate it over an approximate 4,900-day period, with the exception of our jack-up rigs which are depreciated over an 8,030-day period, after provision for salvage value. For each day a rig asset is not operating, it is depreciated over an assumed depreciable life of 20 years, with the exception of our jack-up rigs, where a 30-year depreciable life is used, after provision for salvage value.
Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, aircraft equipment, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings - 10 to 30 years; well-servicing rigs - 3 to 15 years; marine transportation and supply vessels - 10 to 25 years; aircraft equipment - 5 to 20 years; oilfield hauling and mobile equipment and other machinery and equipment - 3 to 10 years). Amortization of capitalized leases is included in depreciation and amortization expense. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations.
We review our assets for impairment when events or changes in circumstances indicate that the carrying amounts of property, plant and equipment may not be recoverable. An impairment loss is recorded in the period in which it is determined that the sum of estimated future cash flows, on an undiscounted basis, is less than the carrying amount of the long-lived asset. Impairment charges are recorded using discounted cash flows which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could result in future impairments. A significantly prolonged period of lower oil and natural gas prices could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges. As the determination of whether impairment charges
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should be recorded on our long-lived assets is subject to significant management judgment and an impairment of these assets could result in a material charge on our consolidated statements of income (loss), management believes that accounting estimates related to impairment of long-lived assets are critical.
Oil and Gas Properties
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. Estimated fair value of proved and unproved properties includes the estimated present value of all reasonably expected future production, prices and costs. 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 to determine if there has been impairment of the carrying value and when circumstances suggest an impairment has occurred, are written down to their estimated fair value in that period. We consider the fair value estimates a Level 3 fair value measurement. 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 assets of our Oil and Gas operating segment resulted in impairment charges of $137.8 million, $48.6 million and $21.5 million, respectively. As further discussed below in Recent Accounting Pronouncements, we adopted new guidance relating to the manner in which our oil and gas reserves are estimated as of December 31, 2009.
Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. Other exploratory costs are expensed as incurred.
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 such 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 pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or market value of unproved properties. As further discussed below in Recent Accounting Pronouncements and in relation to the full-cost ceiling test, our unconsolidated oil and gas joint ventures changed the manner in which their oil and gas reserves are estimated and the manner in which they calculate the ceiling limit on capitalized oil and gas costs as of December 31, 2009. Under the new guidance, future revenues for purposes of the ceiling test are valued using a 12-month average price, adjusted for the impact of derivatives accounted for as cash flow hedges as prescribed by the Securities and Exchange Commission (“SEC”) rules. No full-cost ceiling test writedowns were recorded by our unconsolidated oil and gas joint ventures during 2010. During 2009, our proportionate share of those ventures’ full-cost ceiling test writedowns was $237.1 million.
During 2008, our unconsolidated oil and gas joint ventures evaluated the full-cost ceiling using then-current prices for oil and natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges. As a result, our proportionate share of those ventures’ full-cost ceiling test writedowns was $228.3 million.
A significantly prolonged period of lower oil and natural gas prices or a reduction to the estimation of reserve quantities could continue to result in future impairment charges to our oil and gas properties.
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Oil and Gas Reserves
Evaluations of oil and gas reserves are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment. Oil and gas reserves include both proved and unproved reserves. Consistent with the definitions provided by the SEC, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, known reservoirs, and under existing economic conditions. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.
Estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process involving rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. 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 long-term oil and gas price levels.
Goodwill
Goodwill represents the cost in excess of fair value of the net assets of companies acquired. We review goodwill and intangible assets with indefinite lives for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit exceeds its fair value. A significantly prolonged period of lower oil and natural gas prices could continue to adversely affect the demand for and prices of our services, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our estimate of our future operating results. See Note 3 - Impairments and Other Charges for discussion of goodwill impairments.
The change in the carrying amount of goodwill for our various Contract Drilling segments and our Other Operating Segments for the years ended December 31, 2010 and 2009 was as follows:
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(1)
Represents goodwill impairment associated with Nabors Blue Sky Ltd., a Canadian subsidiary, included in our Other Operating segment. The impairment charges to Nabors Blue Sky were deemed necessary due to the continued deterioration of the downturn in the oil and gas industry in Canada which has led to diminished demand for immediate heliportable access to remote drilling sites. As of December 31, 2009, Nabors Blue Sky Ltd. has no recorded goodwill.
(2)
Represents the preliminary calculations of goodwill recorded in connection with our acquisition of Energy Contractors LLC (“Energy Contractors”). See Note 7 - Acquisitions and Divestitures for additional discussion.
(3)
Represents the goodwill recorded in connection with our acquisition of Superior. See Note 7 - Acquisitions and Divestitures for additional discussion.
(4)
Represents goodwill impairment associated with our U.S. Offshore operating segment. The impairment charge was deemed necessary due to the uncertainty of utilization of some of our rigs as a result of changes in our customers’ plans for future drilling operations in the Gulf of Mexico. See Note 3 - Impairments and other charges for additional information.
Our Oil and Gas segment does not have any goodwill. Goodwill for the consolidated company, totaling approximately $6.5 million, is expected to be deductible for tax purposes.
Derivative Financial Instruments
We record derivative financial instruments (including certain derivative instruments embedded in other contracts) in our consolidated balance sheets at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Any change in fair value of derivative financial instruments that are speculative in nature and do not qualify for hedge accounting treatment is also recognized
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immediately in earnings. Proceeds received upon termination of derivative financial instruments qualifying as fair value hedges are deferred and amortized into income over the remaining life of the hedged item using the effective interest rate method.
Litigation and Insurance Reserves
We estimate our reserves related to litigation and insurance based on the facts and circumstances specific to the litigation and insurance claims and our past experience with similar claims. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions. See Note 17 - Commitments and Contingencies regarding self-insurance accruals. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can 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.
Revenue Recognition
We recognize revenues and costs on daywork contracts daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. We defer revenue related to mobilization periods and recognize the revenue over the term of the related drilling contract. Costs incurred related to a mobilization period for which a contract is secured are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. We defer recognition of revenue on amounts received from customers for prepayment of services until those services are provided.
We recognize revenue for top drives and instrumentation systems we manufacture when the earnings process is complete. This generally occurs when products have been shipped, title and risk of loss have been transferred, collectibility is probable, and pricing is fixed and determinable.
In connection with the performance of our cementing services, we recognize product and service revenue when the products are delivered or services are provided to the customer and collectibility is reasonably assured. Product sale prices are determined by published price lists provided to our customers.
We recognize, as operating revenue, proceeds from business interruption insurance claims in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements in excess of the carrying value of damaged assets are recognized in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements that are expected to be less than the carrying value of damaged assets are recognized at the time the loss is incurred and recorded in losses (gains) on sales and retirements of long-lived assets and other expense (income), net.
We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.
We recognize revenue on our interests in oil and gas properties as production occurs and title passes. We also recognize, as operating revenues, gains on sales of our interests in oil and gas properties when title passes and on our earnings associated with production contracts when realized. We apply the entitlement method of accounting for natural gas revenue. Under this method, revenues are recognized based on our revenue interest of production from our properties in which sales are disproportionately allocated to owners because of marketing or other contractual arrangements. Accordingly, revenue is not recognized for deliveries in excess of our net revenue interest, while revenue is recognized for any under delivered volumes. Production imbalances
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are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. Production volume is monitored to minimize these natural gas imbalances.
Share-Based Compensation
We record compensation expense for all share-based awards granted. The amount of compensation expense recognized is based on the grant-date fair value. Note 6 - Share-Based Compensation for additional discussion.
Income Taxes
We are a Bermuda exempt company and are not subject to income taxes in Bermuda. Consequently, income taxes have been provided based on the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income taxes in these jurisdictions vary substantially. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year because our operations are conducted in different taxing jurisdictions.
We recognize increases to our tax reserves for uncertain tax positions along with interest and penalties as an increase to other long-term liabilities.
For U.S. and other jurisdictional income tax purposes, we have net operating and other loss carryforwards that we are required to assess quarterly for potential valuation allowances. We consider the sufficiency of existing temporary differences and expected future earnings levels in determining the amount, if any, of valuation allowance required against such carryforwards and against deferred tax assets.
We do not provide for U.S. or global income or withholding taxes on unremitted earnings of all U.S. and certain foreign entities, as these earnings are considered permanently reinvested. Unremitted earnings, represented by tax basis accumulated earnings and profits, totaled approximately $7.0 million, $105.0 million and $537.7 million as of December 31, 2010, 2009 and 2008, respectively. It is not practicable to estimate the amount of deferred income taxes associated with these unremitted earnings.
Nabors realizes an income tax benefit associated with certain awards issued under our stock plans. We recognize the benefits related to tax deductions up to the amount of the compensation expense recorded for the award in the consolidated statements of income (loss). Any excess tax benefit (i.e., tax deduction in excess of compensation expense) is reflected as an increase in capital in excess of par. Any shortfall is recorded as a reduction to capital in excess of par to the extent of our aggregate accumulated pool of windfall benefits, beyond which the shortfall would be recognized in the consolidated statements of income (loss).
Foreign Currency Translation
For certain of our foreign subsidiaries, such as those in Canada and Argentina, the local currency is the functional currency, and therefore translation gains or losses associated with foreign-denominated monetary accounts are accumulated in a separate section of the consolidated statements of changes in equity. For our other international subsidiaries, the U.S. dollar is the functional currency, and therefore local currency transaction gains and losses, arising from remeasurement of payables and receivables denominated in local currency, are included in our consolidated statements of income (loss).
Cash Flows
We treat the redemption price, including accrued original issue discount, on our convertible debt instruments as a financing activity for purposes of reporting cash flows in our consolidated statements of cash flows.
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Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:
•
financial instruments;
•
depreciation and amortization of property, plant and equipment;
•
impairment of long-lived assets;
•
impairment of goodwill and intangible assets;
•
impairment of oil and gas properties;
•
valuation of oil and gas reserves;
•
income taxes;
•
litigation and self-insurance reserves;
•
fair value of assets acquired and liabilities assumed; and
•
share-based compensation.
Recent Accounting Pronouncements
In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revises some of the oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act and the Securities Exchange Act of 1934 (the “Exchange Act”), as well as Industry Guide 2. Effective December 31, 2009, the FASB issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. Additionally, this new accounting standard requires that entities use 12-month average natural gas and oil prices when calculating the quantities of proved reserves and performing the full-cost ceiling test calculation. The new standard also clarified that an entity’s equity-method investments must be considered in determining whether it has significant oil and gas activities. The disclosure requirements are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. The FASB provided a one-year deferral of the disclosure requirements if an entity became subject to the requirements because of a change to the definition of significant oil and gas activities. When operating results from our wholly owned oil and gas activities are considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we have significant oil and gas activities under the new definition. Our oil and gas disclosures are provided in Note 24 - Supplementary Information on Oil and Gas Exploration and Production Activities.
Effective January 1, 2010, we adopted the revised provisions relating to consolidation of variable interest entities within the Consolidations Topic of the ASC. The revised provisions replaced the quantitative approach to identify a variable interest entity with a qualitative approach that focuses on an entity’s control and ability to direct the variable interest entity’s activities. The application of these provisions did not have a material impact on our consolidated financial statements.
The FASB issued new guidance relating to revenue recognition for contractual arrangements with multiple revenue-generating activities. The ASC Topic for revenue recognition includes identification of a unit of
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accounting and how arrangement consideration should be allocated to separate the units of accounting, when applicable. The new guidance, including expanded disclosures, will apply to us for contracts entered into after June 15, 2010. We are evaluating the impact this guidance may have on future contracts. Historically, we have not entered into contractual agreements with multiple revenue-generating activities.
Note 3
Impairments and Other Charges
The following table provides the components of impairments and other charges recorded during the years ended December 31, 2010, 2009 and 2008:
Impairments of Oil and Gas Assets
In 2010, we recognized impairments of $192.2 million related to our wholly owned oil and gas assets. Of this total, $137.8 million represents writedowns to the carrying value of some acreage in the United States, which we do not have future plans to develop due to the sustained low natural gas prices, and certain exploratory wells in Colombia, which we have determined will be uneconomical to develop in the foreseeable future.
The remaining $54.3 million relates to an impairment of a financing receivable as a result of the continued commodity price deterioration in the Barnett Shale area of north central Texas. We determined that this impairment was necessary using estimates and assumptions based on estimated cash flows for proved and probable reserves and current natural gas prices. We believe the estimates used provide a reasonable estimate of current fair value. We determined that this represented a Level 3 fair value measurement. As of December 31, 2010, the carrying value of this oil and gas financing receivable, which is included in long-term investments, has been reduced to $20.1 million. A further protraction or continued period of lower commodity prices could result in recognition of future impairment charges.
In 2009, we recorded impairments totaling $197.7 million to some of our wholly owned oil and gas assets. We recognized an impairment of $149.1 million to a financing receivable as a result of commodity price deterioration and the lower price environment last longer than expected. The prolonged period of lower prices significantly reduced demand for future gas production and development in the Barnett Shale area of north central Texas and influenced our decision not to expend capital to develop on some of the undeveloped acreage. The impairment, which represented a Level 3 fair value measurement, was determined using discounted cash flow models involving assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices. Additionally, our annual
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impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $48.6 million to writedown the carrying value of some acreage that we do not have future plans to develop.
In 2008, our annual impairment tests on our U.S. wholly owned oil and gas properties resulted in impairment charges of $21.5 million primarily due to the significant decline in oil and natural gas prices at the end of 2008. Additional discussion of our policy pertaining to the calculation of our annual impairment tests is set forth in “Oil and Gas Properties” in Note 2 - Summary of Significant Accounting Policies.
Impairments of Long-Lived Assets
In 2010, we recognized impairments of $58.0 million in multiple operating segments. These impairments included $23.2 million related to the retirement of certain rig components, comprised of engines, top-drive units, building modules and other equipment that has become obsolete or inoperable in each of these operating segments in our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing and U.S. Offshore Contract Drilling segment. The impairment charges were determined to be necessary as a result of the continued lower commodity price environment and its related impact on drilling and well-servicing activity and our dayrates. A prolonged period of legislative uncertainty in our U.S. Offshore operations, or continued period of and lower natural gas and oil prices and its potential impact on our utilization and dayrates could result in the recognition of future impairment charges to additional assets if future cash flow estimates, based upon information then available to management, indicate that the carrying value of those assets may not be recoverable.
The remaining $34.8 million in impairment charges recorded during 2010 include $27.3 million related to the impairment of some jack-up rigs in our U.S. Offshore operating segment and $7.5 million to our aircraft and some drilling equipment in Nabors Blue Sky Ltd. These impairment charges stemmed from our annual impairment tests on long-lived assets, which determined that the sum of the estimated future cash flows, on an undiscounted basis, was less than the carrying amount of these assets. The estimated fair values of these assets were calculated using discounted cash flow models involving assumptions based on our utilization of the assets, revenues as well as direct costs, capital expenditures and working capital requirements. The impairment charge relating to our U.S. Offshore segment was deemed necessary due to the economic conditions for drilling in the Gulf of Mexico, as discussed below. The impairment charge relating to Nabors Blue Sky Ltd. was deemed necessary due to the continued duration of the downturn in the oil and gas industry in Canada, which has resulted in diminished demand for the remote access services provided by this subsidiary’s aircraft fleet.
In 2009, we recognized impairments of $64.2 million related to retirements of certain assets in our U.S. Offshore, Alaska, Canada and International Contract Drilling segments, which reduced their aggregate carrying value to their estimated aggregate salvage value. The retirements included inactive workover jack-up rigs in our U.S. Offshore and International operations, the structural frames of some incomplete coiled tubing rigs in our Canada operations and miscellaneous rig components in our Alaska operations. The impairment charges resulted from the continued deterioration and longer than expected downturn in the demand for oil and gas drilling activities.
Goodwill Impairments
In 2010, we recognized an impairment of approximately $10.7 million relating to our goodwill balance of our U.S. Offshore operating segment. The impairment charge stemmed from our annual impairment test on goodwill, which compared the estimated fair value of each of our reporting units to its carrying value. The estimated fair value of our U.S. Offshore segment was determined using discounted cash flow models involving assumptions based on our utilization of rigs and revenues as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. We determined that the fair value estimated for purposes of this test represented a Level 3 fair value measurement. The impairment charge was deemed necessary due to the uncertainty of utilization of some of
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our rigs as a result of changes in our customers’ plans for future drilling operations in the Gulf of Mexico. Many of our customers have suspended drilling operations in the Gulf of Mexico, largely as a result of their inability to obtain government permits. Although the 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. A significantly prolonged period of lower oil and natural gas prices or changes in laws and regulations could adversely affect the demand for and prices of our services, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our estimate of our future operating results. See Note 2 - Summary of Significant Accounting Policies (included under the caption “Goodwill”) for amounts of goodwill related to each of our reporting units.
In 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd., one of our Canadian subsidiaries who provides access to remote drilling sites by helicopters and fixed-wing aircraft. The impairment charges resulted from our annual impairment tests on goodwill which compared the estimated fair value of each of our reporting units to its carrying value. The estimated fair value of these business units was determined using discounted cash flow models involving assumptions based on our utilization of rigs or aircraft, revenues and earnings from affiliates, as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. We determined that the fair value estimated for purposes of this test represented a Level 3 fair value measurement. The impairment charges were deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn led to reduced capital spending by some of our customers and diminished demand for our drilling services and for immediate access to remote drilling sites.
In 2008, we impaired the entire goodwill balance of $145.4 million of our Canada Well-servicing and Drilling operating segment and recorded an impairment of $4.6 million to Nabors Blue Sky Ltd. This impairment was also deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn led to reduced capital spending by some of our customers and diminished demand for our drilling services and for immediate access to remote drilling sites.
Other than Temporary Impairments on Debt and Equity Securities
In 2009, we recorded other-than-temporary impairments to our available-for-sale securities totaling $54.3 million. Of this, $35.6 million was related to an investment in a corporate bond that was downgraded to non-investment grade level by Standard and Poor’s and Moody’s Investors Service during the year. Our determination that the impairment was other-than-temporary was based on a variety of factors, including the length of time and extent to which the market value had been less than cost, the financial condition of the issuer of the security, and the credit ratings and recent reorganization of the issuer.
The remaining $18.7 million related to an equity security of a public company whose operations are driven in large measure by the price of oil and in which we invested approximately $46 million during the second and third quarters of 2008. During late 2008, demand for oil and gas began to diminish significantly as part of the general deterioration of the global economic environment, causing a broad decline in value of nearly all oil and gas-related equity securities. Because the trading price per share of this security remained below our cost basis for an extended period of time, we determined the investment was other than temporarily impaired and it was appropriate to write down its carrying value to its estimated fair value.
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Note 4
Cash and Cash Equivalents and Investments
Our cash and cash equivalents, short-term and long-term investments and other receivables consisted of the following:
Certain information related to our cash and cash equivalents and short-term investments follows:
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Certain information related to the gross unrealized losses of our cash and cash equivalents and short-term investments follows:
(1)
Our unrealized losses on available-for-sale debt securities held for more than one year are comprised of various types of securities. Each of these securities have a rating ranging from “A” to “AAA” from Standard & Poor’s and ranging from “A2” to “Aaa” from Moody’s Investors Service and is considered of high credit quality. In each case, we do not intend to sell these investments, and it is less likely than not that we will be required to sell them to satisfy our own cash flow and working capital requirements. We believe that we will be able to collect all amounts due according to the contractual terms of each investment and, therefore, do not consider the decline in value of these investments to be other-than-temporary at December 31, 2010.
The estimated fair values of our corporate, mortgage-backed, mortgage-CMO and asset-backed debt securities at December 31, 2010, classified by time to contractual maturity, are shown below. Expected maturities differ from contractual maturities because the issuers of the securities may have the right to repay obligations without prepayment penalties and we may elect to sell the securities prior to the contractual maturity date.
Certain information regarding our debt and equity securities is presented below:
(1)
Includes other-than-temporary impairments of $18.7 million related to an equity security and a $35.6 million credit-related impairment to a corporate debt security.
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Note 5
Fair Value Measurements
As defined in the ASC, fair value is the price that would be received upon sale of an asset or paid upon transfer of a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market-corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best information available. Accordingly, we employ valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The use of unobservable inputs is intended to allow for fair value determinations in situations where there is little, if any, market activity for the asset or liability at the measurement date. We are able to classify fair value balances utilizing a fair value hierarchy based on the observability of those inputs. Under the fair value hierarchy
•
Level 1 measurements include unadjusted quoted market prices for identical assets or liabilities in an active market;
•
Level 2 measurements include quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and
•
Level 3 measurements include those that are unobservable and of a subjective measure.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2010. Our financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
Recurring Fair Value Measurements
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Nonrecurring Fair Value Measurements
Fair value measurements were applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis, which consists primarily of goodwill, oil and gas financing receivables, intangible assets and other long-lived assets, assets acquired and liabilities assumed in a business combination, and asset retirement obligations. Refer to Note 3 - Impairments and Other Charges for additional discussion.
Fair Value of Financial Instruments
The fair value of our financial instruments has been estimated in accordance with GAAP. The fair value of our fixed rate long-term debt is estimated based on quoted market prices or prices quoted from third-party financial institutions. The fair value of our subsidiary preferred stock was estimated based on the allocation of the purchase price. The carrying and fair values of these liabilities were as follows:
(1)
Includes $.7 million and $1.1 million as of December 31, 2010 and 2009, respectively, related to the unamortized loss on the interest rate swap that was unwound during the fourth quarter of 2005.
The fair values of our cash equivalents, trade receivables and trade payables approximate their carrying values due to the short-term nature of these instruments.
As of December 31, 2010, our short-term investments were carried at fair market value and included $139.9 million and $19.6 million in securities classified as available-for-sale and trading, respectively. As of December 31, 2009, our short-term investments were carried at fair market value and included $139.0 million and $24.0 million in securities classified as available-for-sale and trading, respectively. The carrying values of our long-term investments that are accounted for using the equity method of accounting approximate fair value. The fair value of these long-term investments totaled $7.4 million and $8.3 million as of December 31, 2010 and 2009, respectively. The carrying value of our oil and gas financing receivables included in long-term investments approximate fair value. The carrying value of our oil and gas financing receivables totaled $32.9 million and $92.5 million as of December 31, 2010 and 2009, respectively. Income and gains associated with our oil and gas financing receivables are recognized as operating revenues.
Note 6
Share-Based Compensation
Total share-based compensation expense, which includes both stock options and restricted stock, totaled $13.7 million, $106.7 million and $45.4 million for the years ended December 31, 2010, 2009 and 2008,
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respectively. Compensation expense related to awards of restricted stock totaled $10.5 million, $88.9 million and $44.6 million for the years ended December 31, 2010, 2009 and 2008, respectively, and is included in direct costs and general and administrative expenses in our consolidated statements of income (loss). Share-based compensation expense has been allocated to our various operating segments. See Note 22 - Segment Information. Total share-based compensation expense for 2009 includes the recognition of $72.1 million of compensation expense related to previously granted restricted stock and option awards held by Messrs. Isenberg and Petrello that was unrecognized as of April 1, 2009. The recognition of this expense resulted from provisions of their respective new employment agreements which effectively eliminated the risk of forfeiture of such awards. See Note 17 - Commitments and Contingencies for additional information.
The cash flows resulting from tax deductions in excess of the compensation cost recognized for share-based awards (excess tax benefits) are classified as financing cash flows. The actual tax benefit realized from share-based awards during the years ended December 31, 2010, 2009 and 2008 was $.1 million, $.3 million and $7.6 million, respectively.
Stock Option Plans
As of December 31, 2010, we had several stock plans under which options to purchase our common shares could be granted to key officers, directors and managerial employees of Nabors and its subsidiaries. Options granted under the plans generally are at prices equal to the fair market value of the shares on the date of the grant. Options granted under the plans generally are exercisable in varying cumulative periodic installments after one year. In the case of certain key executives, options granted under the plans are subject to accelerated vesting related to targeted common share prices, or may vest immediately on the grant date. Options granted under the plans cannot be exercised more than ten years from the date of grant. Options to purchase 17.3 million and 12.0 million Nabors common shares remained available for grant as of December 31, 2010 and 2009, respectively. Of the common shares available for grant as of December 31, 2010, approximately 17.3 million of these shares are also available for issuance in the form of restricted shares.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model which uses assumptions for the risk-free interest rate, volatility, dividend yield and the expected term of the options. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for a period equal to the expected term of the option. Expected volatilities are based on implied volatilities from traded options on Nabors’ common shares, historical volatility of Nabors’ common shares, and other factors. We do not assume any dividend yield, since we do not pay dividends. We use historical data to estimate the expected term of the options and employee terminations within the option-pricing model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of the options represents the period of time that the options granted are expected to be outstanding.
We also consider an estimated forfeiture rate for these option awards, and we recognize compensation cost only for those shares that are expected to vest, on a straight-line basis over the requisite service period of the award, which is generally the vesting term of three to five years. The forfeiture rate is based on historical experience. Estimated forfeitures have been adjusted to reflect actual forfeitures during 2010.
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Stock option transactions under our various stock-based employee compensation plans are presented below:
(1)
Represents unexercised vested stock options, which were surrendered by key officers and directors, to satisfy the option exercise price and related income taxes. See related discussion at Note 13 - Common Shares.
Of the options outstanding, 24.9 million, 27.2 million and 25.9 million were exercisable at weighted-average exercise prices of $20.19, $21.04 and $21.99, as of December 31, 2010, 2009 and 2008, respectively.
During the years ended December 31, 2010 and 2009, respectively, we awarded options vesting over periods up to four years to purchase 32,115 and 10,015,883 of our common shares to our employees, executive officers and directors. There were no options granted during the year ended December 31, 2008. During February 2009, this included options to purchase 3,000,000 and 1,698,427 shares, with grant date fair values of $8.8 million and $5.0 million, granted to Messrs. Isenberg and Petrello, respectively, and in September 2009, an option to purchase 1,726 shares, with a grant date fair value of $.01 million, to Mr. Petrello in lieu of certain portions of their cash compensation.
The fair value of stock options granted during 2010 and 2009 was calculated using the Black-Scholes option pricing model and the following weighted-average assumptions:
(1)
Expected volatilities are based on implied volatilities from publicly traded options to purchase Nabors’ common shares, historical volatility of Nabors’ common shares and other factors.
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A summary of our unvested stock options as of December 31, 2010, and the changes during the year then ended is presented below:
The total intrinsic value of options exercised during the years ended December 31, 2010, 2009 and 2008 was $6.9 million, $19.7 million and $43.6 million, respectively. The total fair value of options that vested during the years ended December 31, 2010, 2009 and 2008 was $5.6 million, $10.8 million and $4.3 million, respectively.
As of December 31, 2010, there was $6.2 million of total future compensation cost related to unvested options which are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately one year.
Restricted Stock and Restricted Stock Units
Our stock plans allow grants of restricted stock. Restricted stock is issued on the grant date, but cannot be sold or transferred. Restricted stock vests in varying periodic installments ranging from three to five years.
A summary of our restricted stock as of December 31, 2010, and the changes during the year then ended, is presented below:
During 2010 and 2009, we awarded 538,496 and 85,000 shares of restricted stock, respectively, to our employees and directors. These awards had an aggregate value at their date of grant of $11.9 million and $1.0 million, respectively, and were scheduled to vest over a period of up to four years. The fair value of restricted stock that vested during the years ended December 31, 2010, 2009 and 2008 was $26.7 million, $23.9 million and $39.6 million, respectively.
As of December 31, 2010, there was $15.0 million of total future compensation cost related to unvested restricted stock awards which are expected to vest. That cost is expected to be recognized over a weighted-average period of approximately one year.
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Note 7
Acquisitions and Divestitures
Acquisitions
On September 10, 2010, we completed the Superior Merger, and we acquired all of the issued and outstanding shares of Superior’s common stock at a price per share equal to $22.12, for a cash purchase price of approximately $681.3 million. The purchase price for Superior was allocated to the net tangible and intangible assets acquired and liabilities assumed based on fair value. The excess of the purchase price over such fair values was recorded as goodwill.
As part of the Superior Merger, we recognized $7.0 million of acquisition-related transaction costs in losses (gains) on sales and retirements of long-lived assets and other expense (income) for the year ended December 31, 2010. The acquisition-related transaction costs consisted primarily of investment banking fees and legal and accounting costs. The Superior Merger enhances our well-servicing, including the addition of hydraulic fracturing to our services, and workover capacity work throughout the Appalachian, Mid-Continent, Rocky Mountain, Southeast and Southwest regions of the United States.
The following table provides the allocation of the purchase price as of the acquisition date. This allocation was based on the significant use of estimates and on information that was available to management at the time these consolidated financial statements were prepared.
Intangible assets
We identified other intangible assets associated with fracturing and fluid logistics services, including trade name, technology, employment contracts and non-compete agreements and customer relationships. The amortization of the intangible assets is calculated on a straight-line basis, which estimates the consumption of
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economic benefits. The following table summarizes the intangible assets recognized at the acquisition date, the monthly amortization expense as well as their estimated useful lives:
Goodwill
Goodwill of $335.0 million arising from the Superior Merger consists largely of the expected synergies and economies of scale from combining the operations of Nabors and Superior. We have allocated the goodwill to our Pressure Pumping operating segment. See Note 2 - Summary of Significant Account Policies for additional information.
Long-term debt
Long-term debt included a secured revolving credit facility, which had approximately $44.8 million outstanding at the acquisition date. As of December 31, 2010, all amounts outstanding under the credit facility had been repaid. See Note 11 - Debt for additional information.
Long-term debt also included second lien notes, which had an aggregate principal amount of $80 million outstanding at the acquisition date. We exercised our right to redeem these notes and, on October 25, 2010, paid $80.4 million to repurchase all outstanding notes and related accrued interest.
Pro Forma Impact of the Superior Merger
The following unaudited supplemental pro forma results present consolidated information as if the Superior Merger had been completed as of January 1, 2009. The pro forma results include: (i) the amortization associated with an estimate of the acquired intangible assets, (ii) interest expense associated with debt used to fund the acquisition, (iii) the impact of certain fair value adjustments, including additional depreciation expense for adjustments to property, plant and equipment and reduction to interest expense for adjustments to debt, and (iv) costs directly related to acquiring Superior. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the acquisition and related borrowings had been consummated as of January 1, 2009; nor are they indicative of future results.
Superior’s operating results for the period September 10, 2010 through December 31, 2010 are reflected in our operating segment titled Pressure Pumping in our segment footnote. See Note 22 - Segment Information for additional discussion.
On December 31, 2010, we purchased the business of Energy Contractors for a total cash purchase price of $53.4 million. The assets were comprised of vehicles and rig equipment and have been included in our
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U.S. 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 values of the assets acquired was recorded as goodwill in the amount of $5.0 million.
Divestitures
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 some of our oil and gas assets. See Note 21 - Discontinued Operations for additional discussion.
Note 8
Property, Plant and Equipment
The major components of our property, plant and equipment are as follows:
(1)
Relates to amounts capitalized for new or substantially new drilling, workover and well-servicing rigs that were under construction and had not yet been placed in service as of December 31, 2010 or 2009.
(2)
Includes suspended wells that have capitalized costs for more than one year as of December 31, 2010. Suspended wells include the following:
•
On the north slope of Alaska, three wells, including two drilled in 2007 and one drilled in 2008, were suspended with total capitalized costs of $13.7 million and $5.9 million, respectively for each year. Further drilling is needed over the area to determine if the discovery holds sufficient quantities of reserves to justify future investment of infrastructure. During 2010, we drilled two wells in this area, and another well is planned to spud in March 2011.
•
In the Cotton Valley in Bossier County, Louisiana, five wells were suspended in the Sentell field. Total capitalized costs of $2.6 million and $3.6 million relate to three wells drilled in 2008 and two wells drilled in 2009, respectively for each year. The wells are suspended pending negotiation of a pipeline right-of-way.
•
In the Fayetteville Shale in Conway County, Arkansas, two wells, drilled in 2008 with total capitalized costs of $11.2 million, are suspended pending the outcome of drilling in the area by other operators.
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•
In Reeves County, Texas, five wells, drilled in 2009, have total capitalized costs of $3.0 million. Of the five, one well is producing and the remaining four are suspended and wait on hydraulic fracturing.
•
In the Middle Magdalena basin of Colombia, two wells were suspended. The Guariquies #1 and Morpho #1 wells were drilled in 2005 and 2009 with total capitalized costs of $1.5 million and $4.3 million, respectively. The Guariquies #1 is expected to be turned to production in May 2011, and the Morpho #1 was turned to production in January 2011. An offset to Morpho #1 was drilled in 2010.
•
In the Horn River Basin of British Columbia, Canada, one well was drilled in 2009 and was waiting on hydraulic fracturing as of December 31, 2010. Total capitalized costs were $12.5 million. This well is part of the Canadian oil and gas assets that are classified as held-for-sale at December 31, 2010. When completed, this well will be produced into the wholly owned compression and pipeline facility along with two other wells that were drilled in 2009 that are currently producing.
Assets held under capital leases totaled $.9 million as of December 31, 2010, and are included in our property, plant and equipment within the oilfield hauling and mobile equipment asset component. Amortization of assets recorded under capital leases is reported in depreciation and amortization expense.
Repair and maintenance expense included in direct costs in our consolidated statements of income (loss) totaled $390.2 million, $282.1 million and $476.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Interest costs of $12.4 million, $29.9 million and $29.8 million were capitalized during the years ended December 31, 2010, 2009 and 2008, respectively.
Note 9
Investments in Unconsolidated Affiliates
Our principal investments in unconsolidated affiliates accounted for using the equity method include a construction and logistics operation in Alaska (50% ownership), drilling and workover operations located in Saudi Arabia (51% ownership) and oil and gas exploration, development and production joint ventures in the United States and Colombia (49.7% ownership) and Canada (50% ownership). These unconsolidated affiliates are integral to our operations in those locations. During 2008, our unconsolidated U.S. oil and gas joint venture was deemed a significant subsidiary. See Part IV - Item 15. Exhibits, Financial Statement Schedules for Schedule III - Financial Statements and Notes for NFR Energy LLC (“NFR Energy”) and see Note 16 - Related-Party Transactions for a discussion of transactions with all of these related parties.
As of December 31, 2010 and 2009, our consolidated balance sheets reflect our investments in unconsolidated affiliates accounted for using the equity method totaled $265.8 million and $305.7 million, respectively, and our investments in unconsolidated affiliates accounted for using the cost method totaled $1.9 million and $.9 million, respectively. Assets held for sale include investments in unconsolidated affiliates accounted for using the equity method totaling $79.5 million at December 31, 2010.
Combined condensed financial data for investments in unconsolidated affiliates, including assets classified as held for sale, is summarized as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Nabors’ earnings (losses) from unconsolidated affiliates included in discontinued operations, net of tax was $(10.6) million, $(59.2) million, and $(37.3) million, respectively, for the years ended December 31, 2010, 2009 and 2008.
Cumulative undistributed (losses) earnings of our unconsolidated affiliates included in our retained earnings as of December 31, 2010 and 2009 totaled approximately $(373.9) million and $(387.5) million, respectively. Our Earnings (losses) from unconsolidated affiliates line in our consolidated statements of income (loss) for the years ended December 31, 2009 and 2008 include our proportionate share of full-cost ceiling test writedowns of $189.3 million and $207.3 million, respectively, from our unconsolidated U.S. oil and gas joint venture. These writedowns are included in our Oil and Gas operating segment results. Our proportionate share of full-cost ceiling test writedowns of $47.8 million and $21.0 million recorded for the years ended December 31, 2009 and 2008, respectively, by our other unconsolidated oil and gas joint ventures, SMVP and Remora, are reflected in discontinued operations. See Note 21 - Discontinued Operations for additional information.
Note 10
Financial Instruments and Risk Concentration
We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. These risks arise primarily as a result of potential changes in the fair market value of financial instruments that would result from adverse fluctuations in foreign currency exchange rates, credit risk, interest rates, and marketable and non-marketable security prices as discussed below.
Foreign Currency Risk
We operate in a number of international areas and are involved in transactions denominated in currencies other than U.S. dollars, which exposes us to foreign exchange rate risk or foreign currency devaluation risk. The most significant exposures arise in connection with our operations in Venezuela and Canada, which usually are substantially unhedged.
At various times, we utilize local currency borrowings (foreign currency-denominated debt), the payment structure of customer contracts and foreign exchange contracts to selectively hedge our exposure to exchange rate fluctuations in connection with monetary assets, liabilities, cash flows and commitments denominated in certain foreign currencies. A foreign exchange contract is a foreign currency transaction, defined as an agreement to exchange different currencies at a given future date and at a specified rate.
Credit Risk
Our financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash equivalents, short-term and long-term investments, oil and gas financing receivables, accounts receivable and our range-cap-and-floor derivative instrument. Cash equivalents such as deposits and temporary cash investments are held by major banks or investment firms. Our short-term and long-term investments are managed within established guidelines which limit the amounts that may be invested with any one issuer and provide guidance as to issuer credit quality. We believe that the credit risk in our cash and investment portfolio
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is minimized as a result of the mix of our investments. In addition, our trade receivables are with a variety of U.S., international and foreign-country national oil and gas companies. Management considers this credit risk to be limited due to the financial resources of these companies. We perform ongoing credit evaluations of our customers and we generally do not require material collateral. We do occasionally require prepayment of amounts from customers whose creditworthiness is in question prior to providing services to them. We maintain reserves for potential credit losses, and these losses historically have been within management’s expectations.
Interest Rate and Marketable and Non-marketable Security Price Risk
Our financial instruments that are potentially sensitive to changes in interest rates include our 0.94% senior exchangeable notes, our 5.375%, 6.15%, 9.25% and 5.0% senior notes, our range-cap-and-floor derivative instrument, our investments in debt securities (including corporate, asset-backed, mortgage-backed debt and mortgage-CMO debt securities) and our investments in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages), which are classified as long-term investments.
We may utilize derivative financial instruments that are intended to manage our exposure to interest rate risks. The use of derivative financial instruments could expose us to further credit risk and market risk. Credit risk in this context is the failure of a counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty would owe us, which can create credit risk for us. When the fair value of a derivative contract is negative, we would owe the counterparty, and therefore, we would not be exposed to credit risk. We attempt to minimize credit risk in derivative instruments by entering into transactions with major financial institutions that have a significant asset base. Market risk related to derivatives is the adverse effect on the value of a financial instrument that results from changes in interest rates. We try to manage market risk associated with interest-rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that we undertake.
On October 21, 2002, we entered into an interest rate swap transaction with a third-party financial institution to hedge our exposure to changes in the fair value of $200 million of our fixed rate 5.375% senior notes due 2012, which has been designated as a fair value hedge. Additionally on that date, we purchased a LIBOR range-cap and sold a LIBOR floor, in the form of a cashless collar, with the same third-party financial institution with the intention of mitigating and managing our exposure to changes in the three-month U.S. dollar LIBOR rate. This transaction does not qualify for hedge accounting treatment, and any change in the cumulative fair value of this transaction will be reflected as a gain or loss in our consolidated statements of income (loss). In June 2004, we unwound $100 million of the $200 million range-cap-and-floor derivative instrument. During the fourth quarter of 2005, we unwound the interest rate swap resulting in a loss of $2.7 million, which has been deferred and will be recognized as an increase to interest expense over the remaining life of our 5.375% senior notes due 2012. During the year ended December 31, 2005, we recorded interest savings of $2.7 million related to our interest rate swap agreement accounted for as a fair value hedge, which served to reduce interest expense.
The fair value of our range-cap-and-floor transaction is recorded as a derivative liability and included in other long-term liabilities. It totaled approximately $3.4 million and $3.3 million as of December 31, 2010 and 2009, respectively. During 2010, 2009 and 2008, we recorded gains or (losses) of approximately $(.1) million, $1.4 million and $(4.7) million, respectively, related to this derivative instrument; these amounts are included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss).
In September 2008 we entered into a three-month written put option for one million of our common shares with a strike price of $25 per share. We settled this contract during the fourth quarter of 2008 and paid
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cash of $22.6 million, net of the premium received on this contract, and recognized a loss of $9.9 million which is included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss).
Note 11
Debt
Long-term debt consists of the following:
As of December 31, 2010, the maturities of our primary debt for each of the five years after 2010 and thereafter are as follows:
(1)
Represents our 0.94% senior exchangeable notes due May 2011.
(2)
Represents our 5.375% senior notes due August 2012.
(3)
Represents our 6.15% senior notes due February 2018, 9.25% senior notes due January 2019, and 5.0% senior notes due September 2020.
0.94% Senior Exchangeable Notes Due May 2011
As of December 31, 2010, the current portion of our long-term debt included $1.4 billion par value of Nabors Delaware’s 0.94% senior exchangeable notes that will mature in May 2011.
On May 23, 2006, Nabors Delaware completed a private placement of $2.5 billion aggregate principal amount of 0.94% senior exchangeable notes due 2011 that are fully and unconditionally guaranteed by Nabors. On June 8, 2006, the initial purchasers exercised their option to purchase an additional $250 million par value of the 0.94% senior exchangeable notes due 2011, increasing the aggregate issuance of such notes to $2.75 billion. Nabors Delaware sold the notes to the initial purchasers in reliance on the exemption from
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registration provided by Section 4(2) of the Securities Act. The notes were reoffered by the initial purchasers of the notes to qualified institutional buyers under Rule 144A of the Securities Act. Nabors and Nabors Delaware filed a registration statement on Form S-3 pursuant to the Securities Act with respect to resale of the notes and shares received in exchange for the notes on August 21, 2006. The notes bear interest at a rate of 0.94% per year payable semi-annually on May 15 and November 15, beginning on November 15, 2006. Debt issuance costs of $28.7 million were capitalized in connection with the issuance of the notes in other long-term assets in our consolidated balance sheet and are being amortized through May 2011.
As of December 31, 2010, we had purchased $1.35 billion par value of these notes in the open market for cash of $1.22 billion. During 2010, 2009 and 2008, we recognized pre-tax gains (losses) of $(7.0) million, $11.5 million and 12.2 million, respectively, all of which are included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss) for the respective year.
The notes are exchangeable into cash and, if applicable, Nabors’ common shares based on an exchange rate of the equivalent value of 21.8221 our common shares per $1,000 principal amount of notes (which is equal to an initial exchange price of approximately $45.83 per share), subject to adjustment during the 30 calendar days ending at the close of business on the business day immediately preceding the maturity date and prior thereto only under the following circumstances: (1) during any calendar quarter (and only during such calendar quarter), if the closing price of Nabors’ common shares for at least 20 trading days in the 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is more than 130% of the applicable exchange rate; (2) during the five business day period after any ten consecutive trading day period in which the trading price per note for each day of that period was less than 95% of the product of the closing sale price of Nabors’ common shares and the exchange rate of the note; or (3) upon the occurrence of specified corporate transactions set forth in the indenture.
The notes are unsecured and are effectively junior in right of payment to any of Nabors Delaware’s future secured debt. The notes rank equally with any of Nabors Delaware’s other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s future subordinated debt. Our guarantee of the notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. Holders of the notes who exchange their notes in connection with a change in control, as defined in the indenture, may be entitled to a make-whole premium in the form of an increase in the exchange rate. Additionally, in the event of a change in control, noteholders may require Nabors Delaware to purchase all or a portion of their notes at a purchase price equal to 100% of the principal amount of notes, plus accrued and unpaid interest, if any. Upon exchange of the notes, a holder will receive for each note exchanged an amount in cash equal to the lesser of (i) $1,000 or (ii) the exchange value, determined in the manner set forth in the indenture. In addition, if the exchange value exceeds $1,000 on the exchange date, a holder will also receive a number of Nabors’ common shares for the exchange value in excess of $1,000 equal to such excess divided by the exchange price.
In connection with the sale of the notes in May 2006, Nabors Delaware entered into exchangeable note hedge transactions with respect to our common shares. The call options are designed to cover, subject to customary anti-dilution adjustments, the net number of our common shares that would be deliverable to exchanging noteholders in the event of an exchange of the notes. Nabors Delaware paid an aggregate amount of approximately $583.6 million of the proceeds from the sale of the notes to acquire the call options.
Nabors also entered into separate warrant transactions at the time of the sale of the notes whereby we sold warrants that give the holders the right to acquire approximately 60.0 million of our common shares at a strike price of $54.64 per share. On exercise of the warrants, we have the option to deliver cash or our common shares equal to the difference between the then market price and strike price. All of the warrants will be exercisable and will expire on August 15, 2011. We received aggregate proceeds of approximately
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$421.2 million from the sale of the warrants and used $353.4 million of the proceeds to purchase 10.0 million of our common shares.
The purchased call options and sold warrants are separate contracts entered into by Nabors and Nabors Delaware with two financial institutions and are not part of the terms of the notes and do not affect the holders’ rights under the notes. The purchased call options are expected to offset the potential dilution upon exchange of the notes in the event the market value of a share of our common shares at the time of exercise is greater than the strike price of the purchased call options, which corresponds to the initial exchange price of the notes, subject to customary adjustments. The warrants effectively increase the exchange price of the notes to $54.64 per common share from the perspective of Nabors, representing a 55% premium over the last reported bid price of $35.25 per share on May 17, 2006. We recorded the exchangeable note hedge and warrants in capital in excess of par value as of the transaction date, and do not recognize subsequent changes in fair value.
We continue to assess our ability to meet this obligation, along with our other operating and capital requirements or other potential opportunities over the next 12 months, through a combination of cash on hand, future operating cash flows, possible disposition of non-core assets, availability under our unsecured revolving credit facilities and our ability to access the capital markets, if required. We also have the ability to defer, delay or even cancel some of the planned capital expenditures, if necessary. We believe that through a combination of these sources, we will have sufficient liquidity to meet these obligations.
5.0% Senior Notes Due September 2020
On September 14, 2010, Nabors Delaware completed a private placement of $700 million aggregate principal amount of 5.0% senior notes due 2020, which are unsecured and fully and unconditionally guaranteed by us. The notes are subject to registration rights. The notes were resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The notes pay interest semiannually on March 15 and September 15, beginning on March 15, 2011 and will mature on September 15, 2020.
The notes rank equal in right of payment to all of Nabors Delaware’s existing and future unsubordinated indebtedness, and senior in right of payment to all of Nabors Delaware’s existing and future senior subordinated and subordinated indebtedness. Our guarantee of the notes is unsecured and an unsubordinated obligation and ranks equal in right of payments to all of our unsecured and unsubordinated indebtedness from time to time outstanding. In the event of a change of control triggering event, as defined in the indenture, the holders of the notes may require Nabors Delaware to purchase all or a portion of the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any. The notes are redeemable in whole or in part at any time at the option of Nabors Delaware at a redemption price, plus accrued and unpaid interest, as specified in the indenture. Nabors Delaware used a portion of the proceeds to repay the borrowing under the Revolving Credit Facility (defined below) incurred to fund the Superior Merger.
On December 14, 2010, we and Nabors Delaware filed a registration statement on Form S-4 under the Securities Act. The registration statement related to the exchange offer to noteholders required under the registration rights agreement related to the 5.0% senior notes. On January 20, 2011, Nabors Delaware commenced an exchange offer for the notes pursuant to the registration statement, which was declared effective by the SEC on January 19, 2011. The exchange offer expired on February 23, 2011 and closed on February 28, 2011.
Prior to the issuance of the notes, we entered into a Treasury rate lock with a total notional amount of $500 million to hedge the risk of changes in semiannual interest payments. We designated the Treasury rate lock derivative as a cash flow hedge and upon settlement paid $5.7 million, due to the change in the fair value of the derivative. The loss was recognized as a component of accumulated other comprehensive income in our
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consolidated statement of changes in equity and will be amortized as additional interest expense over the life of the notes. There was no ineffectiveness associated with this hedge during the year ended December 31, 2010.
6.15% Senior Notes Due February 2018
On February 20, 2008, Nabors Delaware completed a private placement of $575 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. On July 22, 2008, Nabors Delaware completed a private placement of $400 million aggregate principal amount of 6.15% senior notes due 2018 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. These new senior notes were an additional issuance under the indenture pursuant to which Nabors Delaware issued $575 million 6.15% senior notes due 2018 on February 20, 2008 described above and are subject to the same rates, terms and conditions and together will be treated as a single class of debt securities under the indenture (together $975 million 6.15% senior notes due 2018). The issue of senior notes was resold by the initial purchasers to qualified institutional buyers under Rule 144A of the Securities Act and to certain investors outside of the United States under Regulation S of the Securities Act. The senior notes bear interest at a rate of 6.15% per year, payable semi-annually on February 15 and August 15 of each year, beginning August 15, 2008. The senior notes will mature on February 15, 2018.
The senior notes are unsecured and are effectively junior in right of payment to any of Nabors Delaware’s future secured debt. The senior notes rank equally with any of Nabors Delaware’s other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s future senior subordinated debt. Our guarantee of the senior notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The senior notes are subject to redemption by Nabors Delaware, in whole or in part, at any time at a redemption price equal to the greater of (i) 100% of the principal amount of the senior notes then outstanding to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest, determined in the manner set forth in the indenture. In the event of a change in control triggering event, as defined in the indenture, the holders of senior notes may require Nabors Delaware to purchase all or any part of each senior note in cash equal to 101% of the principal amount plus accrued and unpaid interest, if any, to the date of purchase, except to the extent Nabors Delaware has exercised its right to redeem the senior notes. Nabors Delaware used the proceeds of the offering of the senior notes for general corporate purposes, including the repayment of debt.
On August 20, 2008, we and Nabors Delaware filed a registration statement on Amendment No. 1 to Form S-4 with the SEC with respect to an offer to exchange the combined $975 million aggregate principal amount of 6.15% senior notes due 2018 for other notes that would be registered and have terms substantially identical in all material respects to these notes pursuant to the applicable registration rights agreement, including being fully and unconditionally guaranteed by us. On September 2, 2008, the registration statement was declared effective by the SEC and the exchange offer expired on October 9, 2008. On October 16, 2008, Nabors Delaware issued $974,965,000 of notes pursuant to the registration statement in exchange for an equal amount of the original notes due 2018 that were properly tendered.
9.25% Senior Notes Due January 2019
On January 12, 2009, Nabors Delaware completed a private placement of $1.125 billion aggregate principal amount of 9.25% senior notes due 2019 with registration rights, which are unsecured and are fully and unconditionally guaranteed by us. The issue of senior notes was resold by the initial purchasers to qualified institutional buyers under Rule 144A and to certain investors outside of the United States under Regulation S of the Securities Act. The senior notes bear interest at a rate of 9.25% per year, payable semi-annually on January 15 and July 15 of each year, beginning July 15, 2009. The senior notes will mature on January 15, 2019.
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The senior notes are unsecured and are junior in right of payment to any of Nabors Delaware’s future secured debt. The senior notes rank equally with any of Nabors Delaware’s other existing and future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s future senior subordinated debt. Our guarantee of the senior notes is unsecured and ranks equal in right of payment to all of our unsecured and unsubordinated indebtedness from time to time outstanding. The senior notes are subject to redemption by Nabors Delaware, in whole or in part, at any time at a redemption price equal to the greater of (i) 100% of the principal amount of the senior notes then outstanding to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest, determined in the manner set forth in the applicable indenture. In the event of a change in control triggering event, as defined in the indenture, the holders of senior notes may require Nabors Delaware to purchase all or any part of each senior note in cash equal to 101% of the principal amount plus accrued and unpaid interest, if any, to the date of purchase, except to the extent Nabors Delaware has exercised its right to redeem the senior notes. Nabors Delaware is using the proceeds of the offering of the senior notes for the repayment or repurchase of indebtedness and general corporate purposes.
On March 30, 2009, we and Nabors Delaware filed a registration statement on Form S-4 under the Securities Act. The registration statement related to the exchange offer to noteholders required under the registration rights agreement related to the 9.25% senior notes. On May 11, 2009 the registration statement was declared effective by the SEC. On July 23, 2009 Nabors Delaware issued $1,069,392,000 of notes pursuant to the registration statement in exchange for an equal amount of the original notes due 2019 that were properly tendered.
5.375% Senior Notes Due August 2012
On August 22, 2002, Nabors Delaware issued $275 million aggregate principal amount of 5.375% senior notes due 2012, which are fully and unconditionally guaranteed by Nabors. The senior notes were resold by a placement agent to qualified institutional buyers under Rule 144A of the Securities Act of 1933. Interest on the senior notes is payable semi-annually on February 15 and August 15 of each year.
The notes are unsecured and are effectively junior in right of payment to any of Nabors Delaware’s future secured debt. The notes rank equal in right of payment with any of Nabors Delaware’s future unsubordinated debt and are senior in right of payment to any of Nabors Delaware’s subordinated debt. The guarantee of Nabors with respect to the senior notes issued by Nabors Delaware, is similarly unsecured and has a similar ranking to the series of senior notes so guaranteed.
Subject to certain qualifications and limitations, the indentures governing the senior notes issued by Nabors Delaware limit the ability of Nabors and its subsidiaries to incur liens and to enter into sale and lease-back transactions. In addition, the indentures limit our ability to enter into mergers, consolidations or transfers of all or substantially all of our assets unless the successor company assumes their obligations under the applicable indenture.
Revolving Credit Facilities
On September 7, 2010, we and Nabors Delaware entered into a credit agreement under which the lenders committed to provide to Nabors Delaware up to $700 million under an unsecured revolving credit facility (the “Revolving Credit Facility”) or the (“Facility”). The Facility also provides Nabors Delaware the option to increase the aggregate principal amount of commitments to $850 million by adding new lenders to the Facility or by asking existing lenders under the Facility to increase their commitments (in each case with the consent of the new lenders or the increasing lenders). In January 2011, Nabors Delaware added a new lender to the Facility and increased the total commitments under the Facility to $750 million. We fully and unconditionally guarantee the obligations under the Revolving Credit Facility, which matures in four years.
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Borrowings under the Revolving Credit Facility bear interest, at Nabors Delaware’s option, at either (x) the “Base Rate” (as defined below) plus the applicable interest margin, calculated on the basis of the actual number of days elapsed in a year of 365 days and payable quarterly in arrears or (y) interest periods of one, two, three or six months at an annual rate equal to the LIBOR for the corresponding deposits of U.S. dollars, plus the applicable interest margin, payable on the last days of the relevant interest periods (but in any event at least every three months). The “Base Rate” is defined, for any day, as a fluctuating rate per annum equal to the highest of (i) the Federal Funds Rate, as published by the Federal Reserve Bank of New York, plus 1/2 of 1%, (ii) the prime commercial lending rate of UBS AG, as established from time to time at its Stamford Branch and (iii) LIBOR for an interest period of one month beginning on such day plus 1%.
On February 11, 2011, one of our subsidiaries established a credit facility, which we unconditionally guarantee, for approximately US$50 million.
Other Debt Transactions
In January and February 2009, Nabors Holdings 1, ULC, one of our wholly owned subsidiaries (“Nabors Holdings”), repurchased $56.6 million par value of the $225 million principal amount of its 4.875% senior notes due August 2009 in the open market for cash totaling $56.8 million. In August 2009, Nabors Holdings paid $168.4 million to redeem the remaining notes. The redemption resulted in no gain or loss as the notes were redeemed at a price equal to their carrying value.
Short-Term Borrowings
We had five letter-of-credit facilities with various banks as of December 31, 2010. We did not have any short-term borrowings outstanding at December 31, 2010 or 2009. Availability and borrowings under our letter-of-credit facilities are as follows:
Note 12
Income Taxes
We apply the provisions of the Income Taxes Topic in the ASC relating to uncertain tax positions. The change in our unrecognized tax benefits for years ended December 31, 2010, 2009 and 2008 were as follows:
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The balance also represents the amount of unrecognized tax benefits that, if recognized, would favorably impact the effective income tax rate in future periods. As of December 31, 2010, 2009 and 2008, we had approximately $42.9 million, $38.5 million and $18.6 million, respectively, of interest and penalties related to our total gross unrecognized tax benefits. During the years ended December 31, 2010, 2009 and 2008, we accrued and recognized estimated interest related to unrecognized tax benefits and penalties of approximately $5.1 million, $5.2 million and $5.3 million, respectively. We recognize interest and penalties related to income tax matters in the income tax expense line item in our consolidated statements of income (loss).
We are subject to income taxes in the United States and numerous other jurisdictions. A number of our United States and non-United States income tax returns from 1995 through 2009 are currently under audit examination. We anticipate that several of these audits could be finalized within 12 months. It is possible that the benefit that relates to our unrecognized tax positions could significantly increase or decrease within 12 months. However, based on the current status of examinations, and the protocol for finalizing audits with the relevant tax authorities, which could include formal legal proceedings, it is not possible to estimate the future impact of the amount of changes, if any, to recorded uncertain tax positions at December 31, 2010.
Income (loss) from continuing operations before income taxes was comprised of the following:
Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. We are a Bermuda-exempt company. Bermuda does not impose corporate income taxes. Our U.S. subsidiaries are subject to a U.S. federal tax rate of 35%.
Income tax expense (benefit) from continuing operations consisted of the following:
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Nabors is not subject to tax in Bermuda. A reconciliation of the differences between taxes on income (loss) before income taxes computed at the appropriate statutory rate and our reported provision for income taxes follows:
Our effective income tax rate for 2010 and 2009 reflects the disparity between losses in our U.S. operations (attributable primarily to impairments) and income in our other operations primarily in lower tax jurisdictions. Because the U.S. income tax rate is higher than that of other jurisdictions, the tax benefit from our U.S. losses was not proportionately reduced by the tax expense from our other operations. During 2010 and 2009, the result was a net tax benefit. In 2009, that benefit represented a significant percentage of our consolidated loss from continuing operations before income taxes. Because of the manner in which that number was derived, we do not believe it presents a meaningful basis for comparing our 2009 effective income tax rate to either the 2010 or 2009, effective income tax rate.
The significant components of our deferred tax assets and liabilities were as follows:
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(1)
This amount is included in other long-term assets.
(2)
This amount is included in accrued liabilities.
For U.S. federal income tax purposes, we have net operating loss (“NOL”) carryforwards of approximately $759.3 million that, if not utilized, will expire between 2018 and 2030. The NOL carryforwards for alternative minimum tax purposes are approximately $413 million. Additionally, we have NOL carryforwards in other jurisdictions of approximately $5.4 billion of which $343 million that, if not utilized, will expire at various times from 2011 to 2030. We provide a valuation allowance against NOL carryforwards in various tax jurisdictions based on our consideration of existing temporary differences and expected future earning levels in those jurisdictions. We have recorded a deferred tax asset of approximately $1.46 billion as of December 31, 2010 relating to NOL carryforwards that have an indefinite life in several non-U.S. jurisdictions. A valuation allowance of approximately $1.46 billion has been recognized because we believe it is more likely than not that substantially all of the deferred tax asset will not be realized.
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The NOL carryforwards by year of expiration:
In addition, for state income tax purposes, we have net operating loss carryforwards of approximately $511 million that, if not utilized, will expire at various times from 2011 to 2030.
Under U.S. federal tax law, the amount and availability of loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests applicable to Nabors and our subsidiaries. The utilization of these carryforwards could be limited or effectively lost upon certain changes in our shareholder base. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given concerning these loss carryforwards, or whether or not they will be available in the future.
Various bills have been introduced in Congress that could reduce or eliminate the tax benefits associated with our reorganization as a Bermuda company. Legislation enacted by 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 United States federal income tax purposes. Nabors’ reorganization was completed June 24, 2002. There has been and we expect that there may continue to be legislation proposed in 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 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.
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Note 13
Common Shares
Our authorized share capital consists of 800 million common shares, par value $.001 per share, and 25 million preferred shares, par value $.001 per share. Common shares issued were 315,034,436 and 313,915,220 at $.001 par value as of December 31, 2010 and 2009, respectively.
For the year ended December 31, 2008, we repurchased 8.5 million of our common shares in the open market for $281.1 million, all of which are held in treasury. No shares were purchased in the open market during 2009 or 2010. From time to time, treasury shares may be reissued. When shares are reissued, we use the weighted-average-cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from our capital in excess of par value account.
During 2008 we entered into a three-month written put option for 1 million of our common shares with a strike price of $25 per common share. We settled this contract during the fourth quarter of 2008 and paid cash of $22.6 million, net of the premium, and recognized a loss of $9.9 million which is included in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in our consolidated statements of income (loss).
During 2010 and 2009 our outstanding shares increased by 110,805 and 218,835, respectively, pursuant to a share settlement of stock options exercised by Mr. Petrello. As part of these transactions, Mr. Petrello surrendered unexercised vested stock options to the Company with a value of approximately $24.5 million and $5.6 million, respectively, to satisfy the option exercise price and related income taxes for 2010 and 2009. During 2010 our outstanding shares also increased by 22,385, pursuant to a similar share settlement of stock options exercised by Mr. Isenberg. As part of these transactions, Mr. Isenberg surrendered unexercised vested stock options to the Company with a value of approximately $50.1 million to satisfy the option exercise price and related income taxes for 2010.
For the years ended December 31, 2010, 2009 and 2008 the Compensation Committee of our Board of Directors granted restricted stock awards to some of our executive officers, other key employees, and independent directors. We awarded 538,496, 85,000 and 4,982,536 restricted shares at an average market price of $22.15, $11.55 and $20.68 to these individuals for 2010, 2009 and 2008, respectively. See Note 6 - Share-Based Compensation for a summary of our restricted stock and option awards as of December 31, 2010.
For the years ended December 31, 2010, 2009 and 2008 our employees exercised vested options to acquire .7 million, 1.5 million and 2.5 million of our common shares, respectively, resulting in proceeds of $8.2 million, $11.2 million and $56.6 million, respectively.
Note 14
Subsidiary Preferred Stock
Superior had 75,000 shares of Series A Preferred Stock (“preferred stock”), $0.01 par value per share, which remained outstanding at December 31, 2010. There are 10,000,000 shares authorized. The preferred stock is issuable in series with such voting rights, if any, designations, powers, preferences and other rights and such qualifications, limitations and restrictions as may be determined by Superior’s board; the board may also fix the number of shares constituting each series and increase or decrease the number of shares of any series.
The preferred stock is perpetual and ranks senior to Superior’s common stock with respect to payment of dividends, and amounts upon liquidation, dissolution or winding up.
We have presented the preferred stock within the mezzanine section of our consolidated balance sheets and have accounted for the preferred stock under the ASC Topic for Distinguishing Liabilities from Equity.
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Dividends
Holders of the preferred stock are entitled to receive, when and if declared by Superior’s board, out of assets legally available therefor, cumulative cash dividends at the rate per annum of $40.00 per share of preferred stock. Dividends on the preferred stock are payable quarterly in arrears on December 1, March 1, June 1 and September 1 of each year (and, in the case of any undeclared and unpaid dividends, at such additional times and for such interim periods, if any, as determined by Superior’s board), at such annual rate. Dividends are cumulative from the date of the original issuance of the preferred stock, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.
As of December 31, 2010, dividends on outstanding shares of preferred stock had been declared and paid in full with respect to each quarter since its initial issuance.
Liquidation Preference
Holders of preferred stock are entitled to receive, in the event that Superior is liquidated, dissolved or wound up, whether voluntarily or involuntarily, $1,000 per share (the “Liquidation Value”) plus an amount per share equal to all dividends undeclared and unpaid thereon to the date of final distribution (the “Liquidation Preference”), and no more. Until the holders of preferred stock have been paid the Liquidation Preference in full, Superior may not make any payment to any holder of stock that ranks junior to the preferred stock upon liquidation, dissolution or winding up. As of December 31, 2010, the preferred stock had a total Liquidation Preference of $75.0 million.
Redemption
The preferred stock is redeemable, in whole or in part and at Superior’s option, at any time on or after November 18, 2013, for a redemption price of 101% of the Liquidation Value, plus all accrued dividends. The redemption price is payable in cash.
As a result of the Superior Merger, each share of preferred stock is convertible, at the option of the holder thereof, into $22.12 for each share of Superior common stock into which the preferred share would have been convertible prior to the Superior Merger (a “deemed common share”). The preferred shares had a conversion price of $25.00 per deemed common share prior to the Superior Merger (equivalent to a conversion rate of 40 deemed common shares for each share of preferred stock), representing 3,000,000 deemed common shares. This results in a redemption value of $66.4 million at December 31, 2010, payable in cash. The right to convert shares of preferred stock that may be called for redemption will terminate at the close of business on the day preceding a redemption date.
Voting Rights
Except as otherwise required from time to time by applicable law or upon certain events of default, the holders of preferred stock have no voting rights, and their consent is not required for taking any corporate action. When and if the holders of the preferred stock are entitled to vote, each holder will be entitled to one vote per share.
Note 15
Pension, Postretirement and Postemployment Benefits
Pension Plans
In conjunction with our acquisition of Pool Energy Services Co. (“Pool”) in November 1999, we acquired the assets and liabilities of a defined benefit pension plan, the Pool Company Retirement Income Plan (the “Pool Pension Plan”). Benefits under the Pool Pension Plan are frozen and participants were fully vested in their accrued retirement benefit on December 31, 1998.
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Summarized information on the Pool Pension Plan is as follows:
(1)
As of December 31, 2010 and 2009, the accumulated benefit obligation was the same as the projected benefit obligation.
For the years ended December 31, 2010, 2009 and 2008, the net actuarial loss amounts included in accumulated other comprehensive income (loss) in the consolidated statements of changes in equity were approximately $(6.7) million, $(6.3) million and $(7.4) million, respectively. There were no other components, such as prior service costs or transition obligations relating to pension costs recorded within accumulated other comprehensive income (loss) during 2010, 2009 and 2008.
The amount included in accumulated other comprehensive income (loss) in the consolidated statements of changes in equity that is expected to be recognized as a component of net periodic benefit cost during 2011 is approximately $.5 million.
We analyze the historical performance of investments in equity and debt securities, together with current market factors such as inflation and interest rates to help us make assumptions necessary to estimate a long-term rate of return on plan assets. Once this estimate is made, we review the portfolio of plan assets and make
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adjustments thereto that we believe are necessary to reflect a diversified blend of investments in equity and debt securities that is capable of achieving the estimated long-term rate of return without assuming an unreasonable level of investment risk.
The following table sets forth, by level within the fair value hierarchy, the investments in the Pool Pension Plan as of December 31, 2010. The investments’ fair value measurement level within the fair value hierarchy is classified in its entirety based on the lowest level of input that is significant to the measurement.
(1)
Includes investments in collective trust funds that are valued based on the fair value of the underlying investments using quoted prices in active markets or other significant inputs that are deemed observable.
(2)
Includes funds that invest primarily in U.S. common stocks and foreign equity securities.
(3)
Includes funds that invest primarily in investment grade debt.
The measurement date used to determine pension measurements for the plan is December 31.
Our weighted-average asset allocations as of December 31, 2010 and 2009, by asset category are as follows:
We invest plan assets based on a total return on investment approach, pursuant to which the plan assets include a diversified blend of investments in equity and debt securities toward a goal of maximizing the long-term rate of return without assuming an unreasonable level of investment risk. We determine the level of risk based on an analysis of plan liabilities, the extent to which the value of the plan assets satisfies the plan liabilities and our financial condition. Our investment policy includes target allocations approximating 55% investment in equity securities and 45% investment in debt securities. The equity portion of the plan assets represents growth and value stocks of small, medium and large companies. We measure and monitor the investment risk of the plan assets both on a quarterly basis and annually when we assess plan liabilities.
We expect to contribute approximately $1.3 million to the Pool Pension Plan in 2011. This is based on the sum of (1) the minimum contribution for the 2010 plan year that will be made in 2011 and (2) the estimated minimum required quarterly contributions for the 2011 plan year. We made contributions to the Pool Pension Plan in 2010 and 2009 totaling $.1 million and $.6 million, respectively.
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As of December 31, 2010, we expect that benefits to be paid in each of the next five years after 2010 and in the aggregate for the five years thereafter will be as follows:
Some of our employees are covered by defined contribution plans. Our contributions to the plans totaled $13.6 million and $19.8 million for the years ended December 31, 2010 and 2009, respectively. Nabors does not provide post-employment benefits to its employees.
Post-retirement Benefits Other Than Pensions
Prior to the date of our acquisition, Pool provided certain post-retirement healthcare and life insurance benefits to eligible retirees who had attained specific age and years of service requirements. Nabors terminated this plan at the date of acquisition (November 24, 1999). A liability of approximately $.2 million was recorded in our consolidated balance sheets as of each of December 31, 2010 and 2009, to cover the estimated costs of beneficiaries covered by the plan at the date of acquisition.
Note 16
Related-Party Transactions
Nabors and its Chairman and Chief Executive Officer, its Deputy Chairman, President and Chief Operating Officer, and certain other key employees entered into split-dollar life insurance agreements, pursuant to which we pay a portion of the premiums under life insurance policies with respect to these individuals and, in some instances, members of their families. These agreements provide that we are reimbursed for the premium payments upon the occurrence of specified events, including the death of an insured individual. Any recovery of premiums paid by Nabors could be limited to the cash surrender value of the policies under certain circumstances. As such, the values of these policies are recorded at their respective cash surrender values in our consolidated balance sheets. We have made premium payments to date totaling $11.7 million related to these policies. The cash surrender value of these policies of approximately $9.5 million and $9.3 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2010 and 2009, respectively.
Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors under the agreements with our Chairman and Chief Executive Officer and with our Deputy Chairman, President and Chief Operating Officer could be deemed to be prohibited loans by us to these individuals. Consequently, we have paid no premiums related to our agreements with these individuals since the adoption of the Sarbanes-Oxley Act.
In the ordinary course of business, we enter into various rig leases, rig transportation and related oilfield services agreements with our unconsolidated affiliates at market prices. Revenues from business transactions with these affiliated entities totaled $271.6 million, $327.3 million and $285.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. Expenses from business transactions with these affiliated entities totaled $3.4 million, $9.8 million and $9.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. Additionally, we had accounts receivable from these affiliated entities of $97.8 million and $104.2 million as of December 31, 2010 and 2009, respectively. We had accounts payable to these affiliated entities of $12.7 million and $14.8 million as of December 31, 2010 and 2009, respectively, and long-term payables with these affiliated entities of $.8 million as of each of December 31, 2010 and 2009, respectively, which are included in other long-term liabilities.
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In addition to the equity investment in our unconsolidated U.S. oil and gas joint venture, in April 2010 we purchased $20.0 million face value of NFR Energy LLC’s 9.75% senior notes. These notes mature in 2017 with interest payable semi-annually on February 15 and August 15. During 2010, we recognized $1.4 million in interest income from these notes.
We own an interest in Shona Energy Company, LLC (“Shona”), a company of which Mr. Payne, an independent member of our Board of Directors, is the Chairman and Chief Executive Officer. During the fourth quarter of 2008, we purchased 1.8 million common shares of Shona for $.9 million. During the first quarter of 2010, we purchased shares of Shona’s preferred stock and warrants to purchase additional common shares for $.9 million. We currently hold a minority interest of approximately 10% of the issued and outstanding shares of Shona.
Note 17
Commitments and Contingencies
Commitments
Leases
Nabors and its subsidiaries occupy various facilities and lease certain equipment under various lease agreements.
The minimum rental commitments under capital leases, with lease terms in excess of one year subsequent to December 31, 2010, are as follows:
The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2010, are as follows:
The above amounts do not include property taxes, insurance or normal maintenance that the lessees are required to pay. Rental expense relating to operating leases with terms greater than 30 days amounted to $26.7 million, $25.5 million and $29.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Employment Contracts
We have entered into employment contracts with certain of our employees. Our minimum salary and bonus obligations under these contracts as of December 31, 2010 are as follows:
Nabors’ Chairman and Chief Executive Officer, Eugene M. Isenberg, and its Deputy Chairman, President and Chief Operating Officer, Anthony G. Petrello, had employment agreements (“prior employment agreements”) in effect through the first quarter of 2009. Effective April 1, 2009, the Company entered into amended and restated employment agreements (“new employment agreements”) with them which extended the terms through March 30, 2013.
For the three months ended March 31, 2009, the prior employment agreements provided for annual cash bonuses in an amount equal to 6% and 2%, for Messrs. Isenberg and Petrello, respectively, of Nabors’ net cash flow (as defined in the respective employment agreements) in excess of 15% of the average shareholders’ equity for each fiscal year. Mr. Petrello’s bonus was subject to a minimum of $700,000 per year.
Effective April 1, 2009, the new employment agreements for Messrs. Isenberg and Petrello amend and restate the prior employment agreements. The new employment agreements provide for an extension of the employment term through March 30, 2013, with automatic one-year extensions beginning April 1, 2011, unless either party gives notice of non-renewal. The base salaries for Messrs. Isenberg and Petrello were increased to $1.3 million and $1.1 million, respectively. Mr. Isenberg has agreed to donate the after-tax proceeds of his base salary to an educational fund intended to benefit Company employees or other worthy candidates.
On June 29, 2009, the new employment agreements for Messrs. Isenberg and Petrello were amended to provide for a reduction in the annual rate of base salary payable to each of Messrs. Isenberg and Petrello to $1.17 million per year and $990,000 per year, respectively, for the period from June 29, 2009 to December 27, 2009. On December 28, 2009, the agreements were further amended to extend through June 27, 2010 the previously agreed salary reduction.
In addition to a base salary, the new employment agreements provide for annual cash bonuses in an amount equal to 2.25% and 1.5%, for Messrs. Isenberg and Petrello, respectively, of Nabors’ net cash flow (as defined in the respective employment agreements) in excess of 15% of the average shareholders’ equity for each fiscal year. For 2010, the annual cash bonuses for Messrs. Isenberg and Petrello pursuant to the formulas described in their employment agreements were $9.7 million and $6.5 million, respectively. The new employment agreements also provide a quarterly deferred bonus of $.6 million and $.25 million, respectively, to the accounts of Messrs. Isenberg and Petrello under Nabors’ executive deferred compensation plan for each quarter they are employed beginning June 30, 2009 and, in Mr. Petrello’s case, ending March 30, 2019.
Messrs. Isenberg and Petrello also are eligible for awards under Nabors’ equity plans, may participate in annual long-term incentive programs and pension and welfare plans on the same basis as other executives, and may receive special bonuses from time to time as determined by the Board of Directors. The new employment agreements effectively eliminated the risk of forfeiture of outstanding stock awards. Accordingly, we recognized compensation expense during the second quarter of 2009 with respect to all previously granted unvested awards to Messrs. Isenberg and Petrello. As of December 31, 2010, there was no unrecognized
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compensation expense related to restricted stock and stock option awards for either Mr. Isenberg or Mr. Petrello.
Termination in the event of death, disability, or termination without cause (including in the event of a Change in Control). The new employment agreements provide for severance payments in the event that either Mr. Isenberg’s or Mr. Petrello’s employment agreement is terminated (i) upon death or disability, (ii) by Nabors prior to the expiration date of the employment agreement for any reason other than for Cause (as defined in the respective employment agreements), or (iii) by either individual for Constructive Termination Without Cause, each as defined in the respective employment agreements. Termination in the event of a Change in Control (as defined in the respective employment agreements) is considered a Constructive Termination Without Cause. Mr. Isenberg would be entitled to receive within 30 days of any such triggering event a payment of $100 million. Mr. Petrello would be entitled to receive within 30 days of his death or disability a payment of $50 million or in the event of Termination Without Cause or Constructive Termination Without Cause, a payment based on a formula of three times the average of his base salary and annual bonus (calculated as though the bonus formula under the new employment agreement had been in effect) paid during the three fiscal years preceding the termination. If, by way of example, Mr. Petrello were Terminated Without Cause subsequent to December 31, 2010, his payment would be approximately $34 million. The formula will be further reduced to two times the average stated above effective April 1, 2015.
The Company does not have insurance to cover its obligations in the event of death, disability, or termination without cause for either Messrs. Isenberg or Petrello and the Company has not recorded an expense or accrued a liability relating to these potential obligations.
In addition, under the new employment agreements, the affected individual would be entitled to receive (a) any unvested restricted stock or stock options outstanding, which would immediately and fully vest; (b) any amounts earned, accrued or owing to the executive but not yet paid (including executive benefits, life insurance, disability benefits and reimbursement of expenses and perquisites), which would be continued through the later of the expiration date or three years after the termination date; (c) continued participation in medical, dental and life insurance coverage until the executive received equivalent benefits or coverage through a subsequent employer or until the death of the executive or his spouse, whichever were later; and (d) any other or additional benefits in accordance with applicable plans and programs of Nabors. The vesting of unvested equity awards would not result in the recognition of any additional compensation expense, as all compensation expense related to Messrs. Isenberg’s and Petrello’s outstanding awards has been recognized as of December 31, 2010. In addition, the new employment agreements eliminate all tax gross-ups, including without limitation tax gross-ups on golden parachute excise taxes, which applied under the prior employment agreements. Estimates of the cash value of Nabors’ obligations to Messrs. Isenberg and Petrello under (b), (c) and (d) above are included in the payment amounts above.
Other Obligations. In addition to salary and bonus, each of Messrs. Isenberg and Petrello receive group life insurance at an amount at least equal to three times their respective base salaries, various split-dollar life insurance policies, reimbursement of expenses, various perquisites and a personal umbrella insurance policy in the amount of $5 million. Premiums payable under the split-dollar life insurance policies were suspended as a result of the adoption of the Sarbanes-Oxley Act of 2002.
Contingencies
Income Tax Contingencies
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
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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 possible that future changes to 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 2002 corporate reorganization. See Note 12 - Income Taxes for additional discussion.
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 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 made and we ultimately did not prevail, we would be required to recognize additional tax for the amount in excess of the current reserve.
Self-Insurance
We estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Our estimates are based on the facts and circumstances specific to existing claims and our past experience with similar claims. These loss estimates and accruals recorded in our financial statements for claims have historically been reasonable in light of the actual amount of claims paid. Although we believe our insurance coverage and reserve estimates are reasonable, a significant accident or other event that is not fully covered by insurance or contractual indemnity could occur and could materially affect our financial position and results of operations for a particular period.
We self-insure for certain losses relating to workers’ compensation, employers’ liability, general liability, automobile liability and property damage. Some workers’ compensation claims are subject to a minimum $1.0 million deductible liability, plus an additional $3.0 million corridor deductible. Some employers’ liability and marine employers’ liability claims are subject to a $2.0 million per-occurrence deductible. Some automobile liability is subject to a $.5 million per-occurrence deductible, plus an additional $1.0 million corridor deductible. General liability claims are subject to a $5.0 million per-occurrence deductible.
In addition, we are subject to a $5.0 million deductible for all land rigs and for offshore rigs. This applies to all kinds of risks of physical damage except for named windstorms in the U.S. Gulf of Mexico for which we are self-insured.
Political risk insurance is procured for select operations in South America, Africa, the Middle East and Asia. Losses are subject to a $.25 million deductible, except for Colombia, which is subject to a $.5 million deductible. There is no assurance that such coverage will adequately protect Nabors against liability from all potential consequences.
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As of December 31, 2010 and 2009, our self-insurance accruals totaled $145.6 million and $139.0 million, respectively, and our related insurance recoveries/receivables were $9.0 million and $12.9 million, respectively.
Litigation
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 has 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 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.
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Off-Balance Sheet Arrangements (Including Guarantees)
We are a party to some transactions, agreements or other contractual arrangements defined as “off-balance sheet arrangements” that could have a material future effect on our financial position, results of operations, liquidity and capital resources. The most significant of these off-balance sheet arrangements involve agreements and obligations under which we provide financial or performance assurance to third parties. Certain of these agreements serve as guarantees, including standby letters of credit issued on behalf of insurance carriers in conjunction with our workers’ compensation insurance program and other financial surety instruments such as bonds. In addition, we have provided indemnifications, which serve as guarantees, to some third parties. These guarantees include indemnification provided by Nabors to our share transfer agent and our insurance carriers. We are not able to estimate the potential future maximum payments that might be due under our indemnification guarantees.
Management believes the likelihood that we would be required to perform or otherwise incur any material losses associated with any of these guarantees is remote. The following table summarizes the total maximum amount of financial guarantees issued by Nabors:
Note 18
Earnings (Losses) Per Share
We include unvested restricted stock awards in the calculation of basic and diluted earnings per share using the two-class method as required by the Earnings Per Share Topic of the ASC.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
A reconciliation of the numerators and denominators of the basic and diluted earnings (losses) per share computations is as follows:
(1)
Diluted earnings (losses) per share for the years ended December 31, 2010, 2009 and 2008 exclude any incremental shares issuable upon exchange of the 0.94% senior exchangeable notes due 2011. As of December 31, 2010, we have purchased $1.3 billion par value of these notes in the open market, leaving approximately $1.4 billion par value outstanding. The number of shares that we would be required to issue upon exchange consists of only the incremental shares that would be issued above the principal amount of the notes, as we are required to pay cash up to the principal amount of the notes exchanged. We would issue an incremental number of shares only upon exchange of these notes. Such shares are included in the calculation of the weighted-average number of shares outstanding in our diluted earnings per share calculation only when our stock price exceeds $45.83 as of the last trading day of the quarter and the average price of our shares for the ten consecutive trading days beginning on the third business day after the last trading day of the quarter exceeds $45.83, which did not occur during any period for the years ended December 31, 2010, 2009 and 2008.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2)
In June and July 2008 Nabors Delaware paid cash of $171.8 million and $528.2 million, respectively, to redeem all of the notes. In addition to the $700 million in cash, we issued 5.25 million common shares with a fair value of $249.8 million, which equated to the excess of the exchange value of the notes over their principal amount. Because the conversion was completed during 2008, diluted earnings per share for the year ended December 31, 2008 reflect the conversion of the zero coupon senior exchangeable notes due 2023 which included the effect of the 5.25 million shares in the calculation of the weighted-average number of basic shares outstanding.
(3)
On July 31, 2009, the exchangeable shares of Nabors Exchangeco were exchanged for Nabors’ common shares on a one-for-one basis. Basic shares outstanding includes the following weighted-average number of common shares and restricted stock of Nabors and weighted-average number of exchangeable shares of Nabors Exchangeco, respectively: 285.1 million shares cumulatively for the year ended December 31, 2010; 283.2 million and .1 million shares for the year ended December 31, 2009; and 281.5 million and .1 million shares for the year ended December 31, 2008.
For all periods presented, the computation of diluted earnings (losses) per Nabors’ share excludes outstanding stock options and warrants with exercise prices greater than the average market price of Nabors’ common shares, because their inclusion would be anti-dilutive and because they are not considered participating securities. The average number of options and warrants that were excluded from diluted earnings (losses) per share that would potentially dilute earnings per share in the future was 14,004,749, 34,113,887 and 7,416,865 shares during the years ended December 31, 2010, 2009 and 2008, respectively. In any period during which the average market price of Nabors’ common shares exceeds the exercise prices of these stock options and warrants, such stock options and warrants will be included in our diluted earnings (losses) per share computation using the if-converted method of accounting. Restricted stock will be included in our basic and diluted earnings (losses) per share computation using the two-class method of accounting in all periods because such stock is considered participating securities.
Note 19
Supplemental Balance Sheet, Income Statement and Cash Flow Information
At December 31, 2010, other long-term assets included a deposit of $40 million of restricted funds held at a financial institution to assure future credit availability for an unconsolidated affiliate. This cash is excluded from cash and cash equivalents in the Consolidated Balance Sheets and Statements of Cash Flows.
Accrued liabilities include the following:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Investment income (loss) includes the following:
(1)
Reflects gain on sale of debt securities and gains from our long-term investments of $4.9 million, partially offset by net unrealized losses of $4.4 million from our trading securities.
(2)
Reflects net unrealized gains of $9.8 million from our trading securities.
(3)
Reflects net unrealized gains of $8.5 million from our trading securities, offset by losses of $27.4 million from our actively managed funds classified as long-term investments.
Losses (gains) on sales and retirements of long-lived assets and other expense (income), net includes the following:
(1)
Includes involuntary conversion losses recorded as a result of Hurricanes Gustav and Ike during 2008 of approximately $12.0 million, net of insurance recoveries.
(2)
Includes a $9.9 million loss on a three-month written put option and a $4.7 million loss on the fair value of our range-cap-and-floor derivative.
(3)
Includes $(7.0) million, $11.5 million and $12.2 million pre-tax (losses) gains on our purchases of our 0.94% senior exchangeable notes in the open market during 2010, 2009 and 2008, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Supplemental cash flow information for the years ended December 31, 2010, 2009 and 2008 is as follows:
Note 20
Unaudited Quarterly Financial Information
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $7.6 million, $8.8 million, $11.8 million and $4.9 million, respectively.
(2)
Earnings per share is computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the total computed for the year.
(3)
Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $(64.5) million, $(5.7) million, $17.1 million and $(102.3) million, respectively.
Note 21
Discontinued Operations
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, we reclassified these wholly owned oil and gas assets from our property, plant and equipment, net, as well as our investment balances for Remora and SMVP from investments in unconsolidated affiliates to assets held for sale in our consolidated balance sheet at September 30, 2010.
The operating results from these assets for all periods presented are reported as discontinued operations in the accompanying audited consolidated statements of income (loss) and the respective accompanying notes to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the consolidated financial statements. Our condensed statements of income (loss) from discontinued operations for the years ended December 31, 2010, 2009 and 2008 were as follows:
(1)
Includes our proportionate share of full-cost ceiling test writedowns of $47.8 million and $21.0 million for the years ended December 31, 2009 and 2008, respectively.
Note 22
Segment Information
As of December 31, 2010, we operated our business out of 11 operating segments. Our seven Contract Drilling operating segments are engaged in drilling, workover and well-servicing and pressure pumping operations, on land and offshore, and represent reportable segments. These operating segments consist of our Alaska, U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, Pressure Pumping, U.S. Offshore, Canada and International business units. Our oil and gas operating segment includes our wholly owned exploration entities and our unconsolidated oil and gas joint ventures with First Reserve Corporation. This segment is engaged in the exploration for, and the development of and production of oil and natural gas. Our Other Operating Segments, consisting of Canrig Drilling Technology Ltd., Ryan Energy Technologies, and Nabors Blue Sky Ltd., are engaged in the manufacturing of top drives, manufacturing of drilling instrumentation systems, construction and logistics services, trucking and logistics services, manufacturing and marketing of directional drilling and rig instrumentation systems, directional drilling, rig instrumentation and data collection services, and heliportable well services. These Other Operating Segments do not meet the criteria for disclosure, individually or in the aggregate, as reportable segments.
The accounting policies of the segments are the same as those described in Note 2 - Summary of Significant Accounting Policies. Inter-segment sales are recorded at cost or cost plus a profit margin. We evaluate the performance of our segments based on several criteria, including adjusted income (loss) derived from operating activities.
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The following table sets forth financial information with respect to our reportable segments:
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(1)
All information presents the operating activities of oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia as discontinued operations.
(2)
These segments include our drilling, workover and well-servicing and pressure pumping operations, on land and offshore.
(3)
Includes operating results of the Superior Merger after September 10, 2010.
(4)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $6.9 million, $9.7 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(5)
Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated U.S. oil and gas joint venture of $(189.3) million and $(207.3) million for the years ended December 31, 2009 and 2008, respectively.
(6)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $18.7 million, $(182.6) million and $(204.1) million for the years ended December 31, 2010, 2009 and 2008, respectively. Additional information is provided in Note 24 - Supplemental Information on Oil and Gas Exploration and Production Activities.
(7)
Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations.
(8)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $7.7 million, $17.5 million and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(9)
Represents the elimination of inter-segment transactions.
(10)
Adjusted income (loss) derived from operating activities is computed by subtracting direct costs, general and administrative expenses, depreciation and amortization, and depletion expense from Operating revenues and then adding Earnings (losses) from unconsolidated affiliates. Such amounts should not be used as a substitute for those amounts reported under GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income
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(loss) derived from operating activities, because it believes that these financial measures are an accurate reflection of the ongoing profitability of our Company. A reconciliation of this non-GAAP measure to income (loss) before income taxes, which is a GAAP measure, is provided within the above table.
(11)
Represents the elimination of inter-segment transactions and unallocated corporate expenses, assets and capital expenditures.
(12)
Represents impairments and other charges recorded during the years ended December 31, 2010, 2009 and 2008, respectively.
(13)
Includes the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.
(14)
Includes $54.8 million, $49.8 million and $49.2 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2010, 2009 and 2008, respectively.
(15)
Includes $146.5 million, $190.1 million and $298.3 million investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2010, 2009 and 2008, respectively.
(16)
Includes $64.5 million, $65.8 million and $63.3 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2010, 2009 and 2008, respectively.
(17)
Includes $1.9 million and $.9 million of investments in unconsolidated affiliates accounted for using the cost method as of December 31, 2010 and 2009, respectively.
The following table sets forth financial information with respect to Nabors’ operations by geographic area:
Note 23
Condensed Consolidating Financial Information
Nabors has fully and unconditionally guaranteed all of the issued public debt securities of Nabors Delaware, and Nabors and Nabors Delaware fully and unconditionally guaranteed the 4.875% senior notes due August 2009 issued by Nabors Holdings 1, ULC, an unlimited liability company formed under the Companies Act of Nova Scotia, Canada and a subsidiary of Nabors (“Nabors Holdings”). During 2009, we paid the balance of Nabors Holdings 1, ULC’s 4.875% senior notes. Effective September 30, 2009, Nabors Holdings 1, ULC was amalgamated with Nabors Drilling Canada ULC, the successor company.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following condensed consolidating financial information is included so that separate financial statements of Nabors Delaware and Nabors Holdings are not required to be filed with the SEC. The condensed consolidating financial statements present investments in both consolidated and unconsolidated affiliates using the equity method of accounting.
The following condensed consolidating financial information presents condensed consolidating balance sheets as of December 31, 2010 and 2009, statements of income (loss) for the years ended December 31, 2010, 2009 and 2008 and the consolidating statements of cash flows for the years ended December 31, 2010, 2009 and 2008 of (a) Nabors, parent/guarantor, (b) Nabors Delaware, issuer of public debt securities guaranteed by Nabors and guarantor of the 4.875% senior notes issued by Nabors Holdings, (c) Nabors Holdings, issuer of the 4.875% senior notes, (d) the non-guarantor subsidiaries, (e) consolidating adjustments necessary to consolidate Nabors and its subsidiaries and (f) Nabors on a consolidated basis.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Condensed Consolidating Balance Sheets
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Condensed Consolidating Statements of Income (Loss)
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Condensed Consolidating Statements of Cash Flows
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 24
Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited)
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 Canadian 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 natural gas and oil 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 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.
The following supplementary information includes our results of operations for oil and gas production activities; capitalized costs related to oil and gas producing activities; and costs incurred in oil and gas property acquisition, exploration and development. Supplemental information is also provided for the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.
Results of Operations
Results of operations consist of all activities within our Oil and Gas operating segment. Net revenues from production include only the revenues from the production and sale of natural gas, oil, and natural gas liquids. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
(1)
Represents our proportionate share of interests in our equity companies.
(2)
Equity companies are pass-through entities for tax purposes.
Capitalized Cost
Capitalized costs include the cost of properties, equipment and facilities for oil and gas-producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.
(1)
Represents our proportionate share of interests in our equity companies.
Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development
Amounts reported as costs incurred include both capitalized costs and costs charged to expense during 2010 for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs include the costs of drilling and equipping successful exploration wells, as well as dry-hole costs, geological and
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.
(1)
Represents our proportionate share of interests in equity companies.
Oil and Gas Reserves
The reserve disclosures that follow reflect estimates of proved reserves for our consolidated subsidiaries and equity companies of natural gas, oil, and natural gas liquids owned at December 31, 2010 and changes in proved reserves during 2010. Our year-end reserve volumes for 2010 shown in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserve quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Estimates of volumes of proved reserves of natural gas at year end are expressed in billions of cubic feet (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 liquid natural gas and $61.12 per barrel for oil at December 31, 2010. The prices used in our 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 liquid natural gas 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.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in average prices and year-end costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.
Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and our ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others.
In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, we do not view equity company reserves any differently than those from our consolidated subsidiaries.
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(1)
Represents our proportionate share of interests in equity companies.
Standardized Measure of Discounted Future Cash Flows
For the year ended December 31, 2010, the standardized measure of discounted future net cash flow was computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and global, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The 10-percent discount factor is prescribed by GAAP.
The present value of future net cash flows does not purport to be an estimate of the fair market value of our consolidated subsidiaries and equity companies’ proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Significant changes in estimated reserve volumes or commodity prices could have a material effect on our consolidated financial statements.
(1)
Represents our proportionate share of interests in equity companies.
(2)
For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.
(3)
Equity companies are pass-through entities for tax purposes.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following table reflects the estimate of changes in the standardized measure of discounted future net cash flows from proved reserves:
(1)
Represents our proportionate share of interests in equity companies.
(2)
For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.
(3)
Equity companies are pass-through entities for tax purposes.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures. We maintain a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. We have investments in certain unconsolidated entities that we do not control or manage. Because we do not control or manage these entities, our disclosure controls and procedures with respect to these entities are necessarily more limited than those we maintain with respect to our consolidated subsidiaries.
The Company’s management, with the participation of the Company’s Chairman and Chief Executive Officer and principal accounting and financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on this evaluation, the Company’s Chairman and Chief Executive Officer and principal accounting and financial officer have concluded that, as of the end of the period, the Company’s disclosure controls and procedures are effective, at the reasonable assurance level, in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Company in reports that it files or submits under the Exchange Act and are effective, at the reasonable assurance level, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the Company’s Chairman and Chief Executive Officer and principal accounting and financial officer, as appropriate to allow timely decisions regarding required disclosure.
(b) Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company’s internal control over financial reporting (identified in connection with the evaluation required by paragraph (d) in Rules 13a-15 and 15d-15 under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of these limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010. Management excluded the acquisition of Superior Well Services, Inc. (“Superior”) from the assessment of internal control over financial reporting as of December 31, 2010 because Superior was acquired in a business combination on September 10, 2010. Superior’s total assets and revenues constitute 10 and 8 percent, respectively, of our related consolidated financial statements as of and for the year ended December 31, 2010. PricewaterhouseCoopers LLP has issued a report on the effectiveness of internal control over financial reporting, which is included in Part II, Item 8 of this report.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information called for by this item will be contained in the definitive Proxy Statement to be distributed in connection with our 2011 annual meeting of shareholders under the captions “Election of Directors”, “Other Executive Officers”, “Section 16(a) Beneficial Ownership Reporting Compliance”, and is incorporated into this document by reference.
We have adopted a Code of Business Conduct that satisfies the SEC’s definition of a “Code of Ethics” and applies to all employees, including our principal executive officer, principal financial officer, and principal accounting officer. The Code of Ethics is posted on our website at www.nabors.com. We intend to disclose on our website any amendments to the Code of Conduct and any waivers of the Code of Conduct that apply to our principal executive officer, principal financial officer, and principal accounting officer.
On June 30, 2010, we filed with the New York Stock Exchange, or NYSE, the Annual CEO Certification regarding our compliance with the NYSE’s Corporate Governance listing standards as required by Section 303A-12(a) of the NYSE Listed Company Manual.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2011 annual meeting of shareholders under the caption “Management Compensation” and except as specified in the following sentence, is incorporated into this document by reference. Information in Nabors’ 2011 proxy statement not deemed to be “soliciting material” or “filed” with the Commission under its rules, including the Compensation Committee Report, is not deemed to be incorporated by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
We maintain five different equity compensation plans: 1996 Employee Stock Plan, 1997 Executive Officers Incentive Stock Plan, 1998 Employee Stock Plan, 1999 Stock Option Plan for Non-Employee Directors and 2003 Employee Stock Plan pursuant to which we may grant equity awards to eligible persons. The terms of our equity compensation plans are described more fully below.
The following table gives information about these equity compensation plans as of December 31, 2010:
(1)
The 1996 Employee Stock Plan incorporated an evergreen formula pursuant to which on each January 1, the aggregate number of shares reserved for issuance under the plan were increased by an amount equal to 1 1/2 % of
the common shares outstanding on September 30 of the immediately preceding fiscal year. The 1996 Employee Stock Plan expired on January 17, 2006.
(2)
The 2003 Employee Stock Plan provides, commencing on June 1, 2006 and thereafter for a period of four (4) years on each January 1, for an automatic increase in the number of shares reserved and available for
issuance under the Plan by an amount equal to two percent (2%) of the Company’s outstanding common shares as of each June 1 or January 1 date.
Following is a brief summary of the material terms of the plans that have not been approved by our shareholders. Unless otherwise indicated, (1) each plan is administered by an independent committee appointed by the Company’s Board of Directors; (2) the exercise price of options granted under each plan must be no less than 100% of the fair market value per common share on the date of the grant of the option; (3) the term of an award granted under each plan may not exceed 10 years; (4) options granted under the plan are nonstatutory options (“NSOs”) not intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended (the “IRC”); and (5) unless otherwise determined by the committee in its discretion, options may not be exercised after the optionee has ceased to be employed by the Company.
Employee Stock Plan
The plan reserves for issuance up to 35,000,000 common shares of the Company pursuant to the exercise of options granted under the plan. The persons eligible to participate in the plan are employees and consultants of the Company. Options granted to employees may either be awards of shares, non-qualified stock options (each, an “NQSO”), incentive stock options (each, an “ISO”) or stock appreciation rights (each, an “SAR”). An optionee may reduce the option exercise price by paying the Company in cash, shares, options, or the equivalent, an amount equal to the difference between the exercise price and the reduced exercise price of the option. The administrative committee must establish performance goals for stock awards in writing not later than the date required for compliance under Section 162(m) of the IRC, and vesting of these shares is contingent upon the attainment of such performance goals. Stock awards vest over a period determined by the Committee, which period must expire no later than January 9, 2008. The committee may grant ISOs of not less than 100% of the fair market value per common share on the date of grant; except that in the event the optionee owns on the date of grant, securities possessing more than 10% of the total combined voting power of all classes of securities of the Company or of any subsidiary of the Company, the price per share must not be less than 110% of the fair market value per common share on the date of the grant. The option must expire five years from the date it is granted. SARs may be granted in conjunction with all or part of any option granted under the plan, in which case the exercise of the SAR must require the cancellation of a corresponding portion of the option; conversely, the exercise of the option will result in cancellation of a corresponding portion of the SAR. In the case of a NQSO, SARs may be granted either at or after the time of grant of the option. In the case of an ISO, SARs may be granted only at the time of grant of the option. A SAR may also be granted on a stand-alone basis. The term of a SAR must be established by the committee. The exercise price of a SAR cannot be less than 100% of the fair market value per common share on the date of grant. The committee has the authority to make provisions in its award and grant agreements to address vesting and other issues arising in connection with a change of control.
Stock Option Plan for Non-Employee Directors
The plan reserves for issuance up to 3,000,000 common shares of the Company pursuant to the exercise of options granted under the plan. The plan is administered by the Company’s Board of Directors or a committee appointed by the Board to administer the plan. Eligible directors may not consider or vote on the administration of the plan or serve as a member of the committee. Options may be granted under the plan to non-employee directors of the Company. Options vest and become non-forfeitable on the first anniversary of the option grant if the optionee has continued to serve as a director until that day, unless otherwise provided. In the event of termination of an optionee’s service as a director by reason of voluntary retirement, declining to stand for re-election or becoming a full-time employee of the Company or a subsidiary of the Company, all unvested options granted under the Plan automatically expire and are not exercisable, and all unexercised options continue to be exercisable until their stated expiration date. In the event of death or disability of an optionee while the optionee is a director, the then-outstanding options of such optionee become exercisable for two years from the date of the death or disability. All unvested options automatically vest and become non-forfeitable as of the date of death or disability and become exercisable for two years from the date of the death of the optionee or until the stated expiration date, whichever is earlier. In the event of the termination of
an optionee’s service as a director by the Board of Directors for cause or the failure of such director to be re-elected, the administrator of the plan in its sole discretion can cancel the then-outstanding options of such optionee, including options that have vested and such options automatically expire and become non-exercisable on the effective date of such termination.
The remainder of the information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2011 annual meeting of shareholders under the caption “Share Ownership of Management and Principal Shareholders” and is incorporated into this document by reference.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2011 annual meeting of shareholders under the caption “Certain Relationships and Related Transactions” and is incorporated into this document by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2011 annual meeting of shareholders under the caption “Principal Accounting Fees and Services” and is incorporated into this document by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULE
(a) The following documents are filed as part of this report:
(1) Financial Statements
(2) Financial Statement Schedules
All other supplemental schedules are omitted because of the absence of the conditions under which they would be required or because the required information is included in the financial statements or related notes.
(b)
Exhibits
*
Filed herewith.
(+)
Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NABORS INDUSTRIES LTD.
By:
/s/ Eugene M. Isenberg
Eugene M. Isenberg
Chairman and
Chief Executive Officer
By:
/s/ R. Clark Wood
R. Clark Wood
Principal accounting and
financial officer
Date: March 1, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2010, 2009 and 2008
Exhibit Index