NABORS INDUSTRIES LTD
ITEM 1.
BUSINESS
Introduction
Nabors is the largest land drilling contractor in the world, with approximately 542 actively marketed land drilling rigs. We conduct oil, gas and geothermal 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 are also one of the largest land well-servicing and workover contractors in the United States and Canada. We actively market approximately 558 rigs for land workover and well-servicing work in the United States, primarily in the southwestern and western United States, and actively market approximately 172 land workover and well-servicing rigs in Canada. Nabors is a leading provider of offshore platform workover and drilling rigs, and actively markets 40 platform, 13 jack-up and 3 barge rigs in the United States and multiple international markets. These rigs provide well-servicing, workover and drilling services. We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets 9 rigs in addition to the rigs we lease to the joint venture. We also offer a wide range of ancillary well-site services, including engineering, transportation, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select domestic and international markets. We provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft. 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 also invest in oil and gas exploration, development and production activities and have 49-50% ownership interests in joint ventures in the U.S., Canada and International areas.
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. Our phone number at our principal executive offices 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 by using our fleet of cranes, loaders and transport vehicles or those from a third-party service vendor. Well-servicing rigs are generally self-propelled; 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 21 - 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, foreign national oil and gas companies and independent oil and gas companies. No customer accounted for more than 10% of our consolidated revenues in 2009 or 2008.
On land in the U.S. Lower 48 states and Canada, we have historically been contracted on a single-well basis, with extensions subject to mutual agreement on pricing and other significant terms. Beginning in late 2004, as a result of increasing demand for drilling services, our customers started entering into longer term 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 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 things, 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 that are 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.
Oil and Gas Investments
Through our wholly owned Ramshorn business unit, we invest in oil and gas exploration, development and production operations in the United States, Canada and internationally. 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 International areas. We hold a 50% ownership interest in the Canadian entity and 49.7% ownership interests in the U.S. and international entities. 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 Ramshorn business unit through both wholly
owned and joint venture operations is focused 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.
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 - Oil and Gas.
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. During the last three years, approximately 41% of our top drive sales were made to other Nabors companies. We also 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. During the last three years, approximately 63% of our equipment sales were made to other Nabors companies. 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, 2009, Nabors employed approximately 18,390 persons, of whom approximately 3,148 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 Canadian and Alaskan 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. Global warming could lengthen these periods of reduced activity, but we cannot currently estimate to what degree. Seasonality does not materially impact the remaining portions of our business. Our overall financial results reflect the seasonal variations experienced in our Canadian and Alaskan operations.
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 exploration, development and production activities by our customers and could materially affect our financial position, results of operations and cash flows. See Part I,
Item 1A. - Risk Factors - Changes to or noncompliance with governmental regulation or exposure to environmental liabilities could adversely affect Nabors’ results of operations.
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.
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. Many of our customers have 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.
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.
We have a substantial amount of debt outstanding
As of December 31, 2009, we had long-term debt outstanding of approximately $3.9 billion, including $.2 million in current maturities and $1.6 billion in long-term debt that matures in May 2011, and cash and cash equivalents and investments of $1.2 billion, including $100.9 million of long-term investments and other receivables. Long-term investments and other receivables include $92.5 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 and our access to capital markets. 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 our capital (i.e., shareholders’ equity) utilizing two commonly used ratios:
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Gross funded debt to capital ratio, 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 ratio, 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, 2009, our gross funded debt to capital ratio was 0.41:1 and our net funded debt to capital ratio was 0.33:1.
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 to us. 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, which are currently “BBB+,” “Baa1” and “BBB+”, respectively, and our historical ability to access those markets as needed. Standard & Poor’s recently affirmed its “BBB+” credit rating on Nabors, but revised its outlook to negative from stable in early 2009 due primarily to worsening industry conditions. 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 in which 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, if not insured or indemnified against, could adversely affect our results of operations
Our operations are subject to many hazards inherent in the drilling, workover and well-servicing industries, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, 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 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. In addition, our international operations are subject to risks of war, civil disturbances or other political events. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for some of these risks. To the extent that we are unable to transfer these risks to customers by contract or indemnification agreements, we seek protection through insurance. However, there is no assurance that our insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. 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, there can be no assurance that insurance will 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. 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 2009, 2008 and 2007, our impairment tests on the oil and gas-related assets of our wholly owned Ramshorn business unit resulted in impairment charges of $205.9 million, $21.5 million and $41.0 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, 2009 using the 12-month average price, whereas during 2008 and 2007, the full-cost ceiling was evaluated using year-end prices. During 2009 and 2008, our unconsolidated oil and gas joint ventures recorded full-cost ceiling test writedowns, of which $237.1 million and $228.3 million, respectively, represented our proportionate share. During 2007, our joint ventures did not record full-cost ceiling test writedowns. 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.
The profitability of our operations outside the United States 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 international 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 certain countries, our operations may be subject to the additional risk of fluctuating currency values and exchange controls, such as the recent foreign currency devaluation in Venezuela. In the international markets where we operate, 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, Mr. Eugene M. Isenberg and our Deputy Chairman, President and Chief Operating Officer, Mr. Anthony G. Petrello, with terms through March 30, 2013. If either Mr. Isenberg’s or Mr. Petrello’s employment is terminated in the event of death or disability, or without cause or in the event of a change in control, significant cash payments up to $100 million and $50 million, respectively, would be made by the Company. 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 damages from such spills. 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 waste materials, some of which are classified as 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 U.S., 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 damage and other costs and claims. We generally require customers to assume responsibility for environmental liabilities. However, we are not always successful in allocating all of these risks to customers, and there is no assurance that customers who assume the risks will be financially able to bear them.
Under the Comprehensive Environmental Response, Compensation and Liability Act, 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 U.S. federal and state environmental regulations may also negatively impact 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, which would make the reclassified wastes subject to more stringent handling, disposal and clean-up requirements. Also, regulators in the United States and other jurisdictions in which we operate are increasingly focused on restricting the emission of carbon dioxide, methane and other greenhouse gases that may contribute to warming of the Earth’s atmosphere, including the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol of which the United States is not a participating member), the Regional Greenhouse Gas Initiative in the Northeastern United States, the Western Regional Climate Action Initiative in the Western United States, and the 2007 U.S. Supreme Court decision in Massachusetts, et al. v. EPA that greenhouse gases are an “air pollutant” under the federal Clean Air Act and thus subject to future regulation. 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, contains provisions specifying responsibility for removal costs and damages resulting from discharges of oil into navigable waters or onto the adjoining shorelines. 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.
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, 2010, we had 800,000,000 authorized common shares, of which 284,669,913 shares were outstanding. In addition, 40,641,861 common shares were reserved for issuance pursuant to option and employee benefit plans, and 78,013,925 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 and 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 under audit 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 Mexican 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 Mexican branch took similar deductions for depreciation and labor expenses from 2004 to 2008. On June 30, 2009, the government proposed similar assessments against the Mexican 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 2009. 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 2009 years would also lack merit, a reserve has been recorded in accordance with accounting principles generally accepted in the United States of America (“GAAP”). 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 of the aggregate over 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 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 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.
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
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.
UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
PROPERTIES
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.
Nabors and its subsidiaries own or lease executive and administrative office space in Hamilton, Bermuda (principal executive office); Anchorage, Alaska; Romance, Arkansas; New Iberia and Youngsville, Louisiana; Bakersfield, Coalinga, Rancho Dominguez-Compton and Ventura, California; Duson, Houma, Lafayette, Minden, New Iberia, Shreveport and Youngsville, Louisiana; Laurel, Mississippi; Alice, Andrews, Big Lake, Big Spring, Breckenridge, Bridgeport, Bryan, Corpus Christi, Crane, Cresson, Crosby, Decator, Denver City, El Campo, Fairfield, Fort Stockton, Haslet, Hillsboro, Houston, Iraan, Kilgore, La Grange, Longview, Magnolia, Midland, Mission, Monohans, Nacogdoches, Odessa, Ozona, Palestine, San Angelo, Snyder, Sonora, Three Rivers and Victoria, Texas; Roosevelt, Utah; Casper, Wyoming; El Reno, Enid, Hartshorne, Lindsay, Oklahoma City, Pocola and Weatherford, Oklahoma; Baker, Billings and Plentywood, Montana; Belfield and Williston, North Dakota; Carlsbad, Eunice and Hobbs, New Mexico; Denver, Fort Lupton, Fruita and Grand Junction, Colorado; Casper and Rock Springs, Wyoming; Mendoza, Argentina; Victoria, Australia; Santa Cruz, Bolivia; Alberta, Brooks, Clairmont, Drayton Valley, Leduc, Lloydminster, Nisku, Slave Lake and Whitecourt, Canada; Bogota, Colombia; Quito, Ecuador; Mumbai, India; Dubai, U.A.E.; Dhahran, Saudi Arabia; Hassi-Messaoud, Algeria; Atyrau and East Ahmadi, Kazakhstan; Ahmadi, Kuwait; Tripoli, Libya; CD Del Carmen, Mexico; Azaira and Muscat, Oman; Guanghan, Peoples Republic of China; Doha, Qatar; Luanda, Republic of Angola; Port Gentil, Republic of Gabon; Kuala Lumpur, Malaysia; Pointe Noire, Congo; Moscow, Russia; Ploeisti, Romania; Maracaibo, Venezuela; Perth, Western Australia; and Sana’a, Yemen. 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.
Additional information about our properties can be found in Notes 2 - Summary of Significant Accounting Policies and 8 - Property, Plant and Equipment (each, under the caption Property, Plant and Equipment) and 15 - Commitments and Contingencies (under the caption Operating Leases) 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, 2009, 2008 and 2007, can be found in Note 21 - 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.
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 U.S. Department of Justice relating to its investigation of one of one of our vendors and compliance with the Foreign Corrupt Practices Act. The inquiry relates to transactions with and involving Panalpina, which provides 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. The Audit Committee 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 Department of Justice have been advised of the Company’s 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 the Company is 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.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
STOCK PERFORMANCE GRAPH
The following graph illustrates comparisons of five-year cumulative total returns among Nabors, the S&P 500 Index and the Dow Jones Oil Equipment and Services Index. Total return assumes $100 invested on December 31, 2004 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, 2005 - 2009.
I.
Market and Share Prices
Our common shares are traded on the New York Stock Exchange under the symbol “NBR”. At February 24, 2010, there were approximately 1,774 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, 2009:
(1)
Shares were withheld from employees 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. Both the 2003 Employee Stock Plan 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, 2009, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2009, 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.
III. Shareholder Matters
Bermuda has exchange controls which apply to residents in respect of the Bermudian 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.
SELECTED FINANCIAL DATA
(1)
All periods present the Sea Mar business as a discontinued operation.
(2)
The operating data for the year ended December 31, 2005 and the balance sheet data at December 31, 2005 do not reflect the adoption of the revised provisions relating to convertible debt within the Debt with Conversions and Other Options Topic of the Accounting Standards Codification.
(3)
Our acquisitions’ results of operations and financial position have been included beginning on the respective dates of acquisition and include Pragma Drilling Equipment Ltd. assets (May 2006), 1183011 Alberta Ltd. (January 2006), Sunset Well Service, Inc. (August 2005), Alexander Drilling, Inc. assets (June 2005), Phillips Trucking, Inc. assets (June 2005), and Rocky Mountain Oil Tools, Inc. assets (March 2005).
(4)
Represents capital expenditures and the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.
(5)
The interest coverage ratio is a trailing 12-month quotient of the sum of net income (loss) attributable to Nabors, interest expense, 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. 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.
(6)
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, 2009, 2008 and 2007 amounts include $92.5 million, $224.2 million and $123.3 million, respectively, in oil and gas financing receivables that are included in long-term investments and other receivables.
(7)
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.
(8)
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.
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.
Nabors is the largest land drilling contractor in the world, with approximately 542 actively marketed land drilling rigs. We conduct oil, gas and geothermal 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 are also one of the largest land well-servicing and workover contractors in the United States and Canada. We actively market approximately 558 rigs for land workover and well-servicing work in the United States, primarily in the southwestern and western United States, and approximately 172 rigs for land workover and well-servicing work in Canada. Nabors is a leading provider of offshore platform workover and drilling rigs, and actively markets 40 platform, 13 jack-up and 3 barge rigs in the United States and multiple international markets. These rigs provide well-servicing, workover and drilling services. We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets 9 rigs in addition to the rigs we lease to the joint venture. We also offer a wide range of ancillary well-site services, including engineering, transportation, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select domestic and international markets. We provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft. 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 also invest in oil and gas exploration, development and production activities in the U.S., Canada and international areas through both our wholly owned subsidiaries and our separate joint venture entities. We hold a 50% ownership interest in our Canadian entity and 49.7% ownership interests in our U.S. and International entities. Each joint venture pursues development and exploration projects with our existing customers and with other operators in a variety of forms, including operated and non-operated working interests, joint ventures, farm-outs and acquisitions.
The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, workover and well-servicing 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.
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 determinate of customer spending is their cash flow and earnings which are largely driven by natural gas prices in our U.S. Lower 48 Land Drilling and Canadian Drilling operations, while oil prices are the primary determinate in our Alaskan, International, U.S. Offshore (Gulf of Mexico), Canadian Well-servicing
and U.S. Land Well-servicing operations. 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 has resulted in sustained lower natural gas and oil prices. The price of natural gas reached a low for 2009 of $1.83 per mcf during September and while showing improvement remains depressed, having averaged $3.77 per mcf during the second half of 2009. The significant drop in the price of oil reached a low for 2009 of $33.98 per barrel in February with continuous recovery throughout 2009, averaging $72.08 per barrel during the second half of 2009. These reduced prices for natural gas and oil have led to a sharp decline in the demand for drilling and workover services. 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, 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 $356.2 million and $(85.5) million ($(.30) per diluted share), respectively, representing decreases of 66% and 118%, respectively, compared to the year ended December 31, 2008. Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2008 totaled $5.3 billion, representing an increase of $325.5 million, or 7% as compared to the year ended December 31, 2007. Adjusted income derived from operating activities and net income (loss) attributable to Nabors for the year ended December 31, 2008 totaled $1.1 billion and $475.7 million ($1.65 per diluted share), respectively, representing decreases of 16% and 45%, respectively, compared to the year ended December 31, 2007.
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 $(237.1) million and $(228.3) million, respectively, for the years ended December 31, 2009 and 2008, representing our proportionate share of full-cost ceiling test writedowns from our unconsolidated oil and gas joint ventures which utilize the full-cost method of accounting. During 2009, our joint ventures 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 and 2008, our operating results were also negatively impacted as a result of our impairments and other charges of $339.1 million and $176.1 million, respectively. During 2009, impairments and other charges 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. Additionally, we recorded impairment charges of $205.9 million and $21.5 million, respectively, to our wholly owned Ramshorn business unit under application of the successful-efforts method of accounting for some of our oil and gas-related assets during the years ended December 31, 2009 and 2008. During 2008, impairments and other charges 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., one of our Canadian subsidiaries reported in Other
Operating Segments. 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. These impairments and other charges are reflected separately as impairments and other charges in our consolidated statements of income (loss) for the years ended December 31, 2009 and 2008.
Excluding these charges, our operating results were lower than the previous year results primarily due to the continuing weak environment in our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, Canada and U.S. Offshore operations where activity levels and demand for our drilling rigs have decreased substantially in response to uncertainty in the financial markets and commodity price deterioration. Operating results have been further negatively impacted by higher levels of depreciation expense due to our increased capital expenditures in recent years.
Our operating results for 2010 are expected to approximate levels realized during 2009 given our current expectation of the continuation of lower commodity prices during 2010 and the related impact on drilling and well-servicing activity and dayrates. We expect the decrease in drilling activity and dayrates to continue to adversely impact our U.S. Lower 48 Land Drilling and our U.S. Land Well-servicing operations for 2010, as compared to 2009, because the number of working rigs and average dayrates have declined. We expect our International operations to decrease slightly during 2010 as a result of lower drilling activity and utilization partially offset by the deployment of new and incremental rigs under long-term contracts and the renewal of multi-year contracts. Although rig count is expected to be lower overall, the reductions are primarily comprised of lower yielding assets, leaving higher margin contracts in place partially offset by certain contracts rolling over at lower current market rates. Our investments in new and upgraded rigs over the past five years have resulted in long-term contracts which we expect will enhance our competitive position when market conditions improve.
The following tables set forth certain information with respect to our reportable segments and rig activity:
(1)
All segment information excludes the Sea Mar business, which has been classified as a discontinued operation.
(2)
These segments include our drilling, workover and well-servicing operations, on land and offshore.
(3)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $9.7 million, $5.8 million and $5.6 million for the years ended December 31, 2009, 2008 and 2007, respectively.
(4)
Represents our oil and gas exploration, development and production operations. Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated oil and gas joint ventures of $(237.1) million and $(228.3) million for the years ended December 31, 2009 and 2008, respectively.
(5)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(241.9) million, $(241.4) million and $(3.9) million for the years ended December 31, 2009, 2008 and 2007, respectively.
(6)
Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations.
(7)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $17.5 million, $5.8 million and $16.0 million for the years ended December 31, 2009, 2008 and 2007, respectively.
(8)
Represents the elimination of inter-segment transactions.
(9)
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 (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.
(10)
Represents the elimination of inter-segment transactions and unallocated corporate expenses.
(11)
Represents impairments and other charges recorded during the years ended December 31, 2009 and 2008, respectively.
(12)
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.
(13)
International rig years include our equivalent percentage ownership of rigs owned by unconsolidated affiliates which totaled 2.5 years, 3.5 years and 4.0 years during the years ended December 31, 2009, 2008 and 2007, respectively.
(14)
Rig hours represents the number of hours that our well-servicing rig fleet operated during the year.
(15)
The percentage is so large that is not meaningful.
Segment Results of Operations
Contract Drilling
Our Contract Drilling operating segments contain one or more of the following operations: drilling, workover and well-servicing, on land and offshore.
U.S. Lower 48 Land Drilling. The results of operations for this reportable segment are as follows:
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. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.
The increase in operating results from 2007 to 2008 was due to overall year-over-year increases in rig activity and increases in average dayrates, driven by higher natural gas prices throughout 2007 and most of 2008. This increase was only partially offset by higher operating costs and an increase in depreciation expense related to capital expansion projects.
U.S. Land Well-servicing. The results of operations for this reportable segment are as follows:
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.
Operating revenues and Earnings from unconsolidated affiliates increased from 2007 to 2008 primarily as a result of higher average dayrates year-over-year, driven by high oil prices during 2007 and the majority of
2008 as well as market expansion. Higher average dayrates were partially offset by lower rig utilization. Adjusted income derived from operating activities decreased from 2007 to 2008 despite higher revenues due primarily to higher depreciation expense related to capital expansion projects and, to a lesser extent, higher operating costs.
U.S. Offshore. The results of operations for this reportable segment are as follows:
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.
The increase in operating results from 2007 to 2008 primarily resulted from higher average dayrates and increased drilling activity driven by high oil prices during the majority of 2008, especially in the Sundowner and Super Sundowner platform workover and re-drilling rigs and the MASE®
platform drilling rigs. The increase in 2008 was partially offset by higher operating costs and increased depreciation expense relating to new rigs added to the fleet in early 2007.
Alaska. The results of operations for this reportable segment are as follows:
The increases in operating results from 2008 to 2009 and from 2007 to 2008 were 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. Drilling activity levels increased in 2008 as a result of the deployment and utilization of rigs added to the fleet in late 2007 under long-term contracts. The increases during 2009 and 2008 have been partially offset by higher operating costs and increased depreciation expense as well as increased labor and repairs and maintenance costs in 2009 and 2008 as compared to prior years.
Canada. The results of operations for this reportable segment are as follows:
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.
The decrease in operating results from 2007 to 2008 resulted from year-over-year decreases in drilling and well-servicing activity and decreases in average dayrates for drilling and well-servicing operations as a result of economic uncertainty and Alberta’s tight labor market which led to a number of projects being delayed. Our operating results were further negatively impacted by proposed changes to the Alberta royalty and tax regime causing customers to assess the impact of such changes. The strengthening of the Canadian dollar versus the U.S. dollar during 2007 and throughout the majority of 2008 positively impacted operating results, but negatively impacted demand for our services as much of our customers’ revenue is denominated in U.S. dollars while their costs are denominated in Canadian dollars. Additionally, operating results were negatively impacted by increased operating expenses, including depreciation expense related to capital expansion projects.
International. The results of operations for this reportable segment are as follows:
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.
The increase in operating results from 2007 to 2008 primarily resulted from year-over-year increases in average dayrates and drilling activities, reflecting strong customer demand for drilling services, stemming from
sustained higher oil prices throughout 2007. Operating results during 2007 and most of 2008 were also positively impacted by an expansion of our rig fleet and continuing renewal of existing multi-year contracts at higher average dayrates. These increases were partially offset by increased operating expenses, including depreciation expense related to capital expenditures for new and refurbished rigs deployed throughout 2007 and 2008.
Oil and Gas. The results of operations for this reportable segment are as follows:
Our operating results decreased from 2008 to 2009 primarily as a result of full-cost ceiling test writedowns recorded during 2009 by our unconsolidated joint ventures. During 2009, our U.S., international and Canadian oil and gas joint ventures recorded full-cost ceiling test writedowns, of which our proportionate share totaled $237.1 million. 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 further decreased from 2008 to 2009 due to declines in natural gas prices and production volumes from our Ramshorn and joint venture operations. Additionally, operating results for 2008 included a $12.3 million gain recorded on the sale of leasehold interests.
Our operating results decreased from 2007 to 2008 as a result of full-cost ceiling test writedowns recorded during 2008 by our unconsolidated oil and gas joint ventures. During 2008, our U.S., international and Canadian oil and gas joint ventures recorded full-cost ceiling test writedowns, of which our proportionate share totaled $228.3 million. The full-cost ceiling test was determined using the single-day, year-end price as required by SEC rules at the time.
Additionally during 2008, our proportionate share of losses from our unconsolidated oil and gas joint ventures included $10.0 million of depletion charges from lower-than-expected performance of certain oil and gas developmental wells and $5.8 million of mark-to-market unrealized losses from derivative instruments representing forward gas sales through swaps and price floor guarantees utilizing puts. Beginning in May 2008 our U.S. joint venture began to apply hedge accounting to its forward contracts to minimize the volatility in reported earnings caused by market price fluctuations of the underlying hedged commodities. These losses were partially offset by income from our production volumes and oil and gas production sales as a result of higher oil and natural gas prices throughout most of 2008 and a $12.3 million gain on the sale of leasehold interests in 2008.
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 decreases in operating results from 2008 to 2009 primarily resulted from (i) lower demand in the U.S. and Canadian 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.
The increase in operating results from 2007 to 2008 primarily resulted from year-over-year increases in third-party sales and higher margins on top drives occasioned by the strengthening of the oil drilling market, increased equipment sales, increased market share in Canada and increased demand in the U.S. directional drilling market. Results were also improved in 2008 due to increases in customer demand for our construction and logistics services in Alaska.
Discontinued Operations
In 2007, we sold our Sea Mar business which had previously been included in Other Operating Segments to an unrelated third party. The assets included 20 offshore supply vessels and some related assets, including rights under a vessel construction contract. We have not had any continuing involvement subsequent to the sale of this business and have accounted for the Sea Mar business as discontinued operations in the accompanying audited consolidated statements of income (loss). Our condensed statement of income from discontinued operations related to the Sea Mar business for the year ended December 31, 2007 was as follows:
OTHER FINANCIAL INFORMATION
General and administrative expenses
General and administrative expenses decreased from 2008 to 2009 primarily as a result of significant decreases in wage-related expenses and other cost-reduction efforts across all business units, partially offset by an increase of approximately $61.2 million in stock compensation expense. During 2009, share-based compensation expense 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. General and administrative expenses as a percentage of operating revenues increased primarily due to lower revenues.
General and administrative expenses increased from 2007 to 2008 primarily as a result of increases in wages and wage-related expenses for a majority of our operating segments compared to each prior year, which resulted from an increase in the number of employees required to support higher activity levels. The increase was also driven by higher compensation expense, primarily resulting from higher bonuses and non-cash compensation expenses recorded for restricted stock awards during 2007 and 2008.
Depreciation and amortization, and depletion expense
Depreciation and amortization expense. Depreciation and amortization expense increased from 2008 to 2009 and from 2007 to 2008 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 decreased from 2008 to 2009 and from 2007 to 2008 primarily as a result of decreased natural gas production volumes during each year.
Interest expense
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.
Interest expense increased from 2007 to 2008 as a result of the additional interest expense related to our February 2008 and July 2008 issuances of 6.15% senior notes due February 2018 in the amounts of $575 million and $400 million, respectively.
Investment income (loss)
Investment income during 2009 was $25.8 million compared to $21.7 million during the prior year. 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 $21.7 million compared to a net investment loss of $15.9 million during the prior year. Investment income in 2008 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.
Investment income (loss) during 2007 included a net loss of $61.4 million from our actively managed funds classified as long-term investments inclusive of substantial gains from sales of our marketable equity securities. This net loss was offset by interest and dividend income of $45.5 million from our short-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 2009 represents a net loss of $13.0 million and includes: (i) foreign currency exchange losses of approximately $8.4 million, (ii) increases of 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 $15.0 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) increases of 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.
The amount of gains (losses) on sales and retirements of long-lived assets and other income(expense), net for 2007 represents a net loss of $11.3 million and includes: (i) losses on retirements and impairment charges on long-lived assets of approximately $40.0 million and (ii) increases of litigation expenses of $9.6 million. These losses were partially offset by the $38.6 million gain on the sale of three accommodation jack-up rigs in the second quarter of 2007.
Impairments and Other Charges
During the years ended December 31, 2009 and 2008, we recognized goodwill impairments of approximately $14.7 million and $150.0 million, respectively, related to our Canadian operations. During 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., one of our Canadian subsidiaries reported in our Other Operating segments. During 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd. The impairment charges resulted from of 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. 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 has led to reduced capital spending by some of our customers and has diminished demand for our drilling services and for immediate access to remote drilling sites. A significantly prolonged period of lower oil and natural gas prices 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.
During the year ended December 31, 2009, we retired some rigs and rig components in our U.S. Offshore, Alaska, Canada and International Contract Drilling segments and reduced their aggregate carrying value from $69.0 million to their estimated aggregate salvage value, resulting in impairment charges of approximately $64.2 million. 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. A prolonged 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.
Also in 2009, we recorded impairments totaling $205.9 million to some of the oil and gas-related assets of our wholly owned Ramshorn business unit. We recorded an impairment of $149.1 million to one of our oil and gas financing receivables, which reduced the carrying value of our oil and gas financing receivables recorded as long-term investments to $92.5 million. The impairment resulted primarily from commodity price deterioration and the lower price environment lasting longer than expected. This prolonged period of lower prices has significantly reduced demand for future gas production and development in the Barnett Shale area of north central Texas, which has influenced our decision not to expend capital to develop on some of the undeveloped acreage. The impairment 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. We believe the estimates used provide a reasonable estimate of current fair value. A further protraction or continued period of lower commodity prices could result in recognition of future impairment charges. During the years ended December 31, 2009, 2008 and 2007, our impairment tests on the oil and gas properties of our wholly owned Ramshorn business unit resulted in impairment charges of $56.8 million, $21.5 million and $41.0 million, respectively. The impairments recognized during 2009 were primarily the result of a write down of the carrying value of some acreage in the U.S. and Canada because we do not have future plans to develop. The impairments recognized during 2008 were primarily due to the significant decline in oil and natural gas prices at the end of 2008. The impairments recognized during 2007 were necessary from lower than expected performance of some oil and gas development wells. Additional discussion of our policy pertaining to the calculations of these impairments is set forth in “Oil and Gas Properties” under Critical Accounting Estimates below in this section or in Note 2 - Summary of Significant Accounting Policies in Part II Item 8. - Financial Statements and Supplementary Data.
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, we determined the investment was other than temporarily impaired and it was appropriate to write down the investment’s carrying value to its current estimated fair value of approximately $27.0 million at December 31, 2009.
Income tax rate
Our effective income tax rate for 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. The result is a net tax benefit that represents a significant percentage (63.5%) of our consolidated loss before income taxes. Because of the manner in which this number is derived, we do not believe it presents a meaningful basis for comparing our 2009 effective income tax rate to our 2008 effective income tax rate.
The increase in our effective income tax rate from 2007 to 2008 resulted from (1) our goodwill impairments which had no associated tax benefit, (2) the reversal of certain tax reserves during 2007 in the amount of $25.5 million, (3) a decrease in 2007 tax expense of approximately $16.0 million resulting from a reduction in Canada’s tax rate, and (4) a higher proportion of our 2008 taxable income being generated in the United States, which generally imposes a higher tax rate than the other jurisdictions in which we operate.
We are subject to income taxes in the U.S. 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 under audit 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 United States 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 on 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, 2009 and 2008.
Operating Activities. Net cash provided by operating activities totaled $1.6 billion during 2009 compared to net cash provided by operating activities of $1.5 billion during 2008. 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 $1.1 billion and $1.7 billion for the years ended December 31, 2009 and 2008, respectively. Additionally, changes in working capital items such as collection of receivables can be a significant component of operating cash flows. Changes in working capital items provided $471.9 million in cash flows for the year ended December 31, 2009 and required $278.6 million in cash flows for the year ended December 31, 2008.
Investing Activities. Net cash used for investing activities totaled $1.2 billion during 2009 compared to net cash used for investing activities of $1.5 billion during 2008. During 2009 and 2008, cash was used primarily for capital expenditures totaling $1.1 billion and $1.5 billion, respectively, and investments in unconsolidated affiliates totaling $125.1 million and $271.3 million, respectively. During 2009 and 2008, cash was derived from sales of investments, net of purchases, totaling $24.4 million and $251.6 million, respectively.
Financing Activities. Net cash provided by financing activities totaled $19.4 million during 2009 compared to net cash used for financing activities of $89.2 million during 2008. 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. Also during 2009, cash totaling $862.6 million was used to purchase $964.8 million par value of 0.94% senior exchangeable notes due 2011 and cash totaling $225.2 million was used to redeem the 4.875% senior notes. During 2008, cash totaling $836.5 million was used to redeem Nabors Delaware’s zero coupon senior exchangeable notes due 2023 and zero coupon senior convertible debentures due 2021 and for the purchase of $100 million par value of 0.94% senior exchangeable notes due 2011 in the open market. During 2008, cash was used to repurchase our common shares in the open market for $281.1 million. Also during 2008, cash was provided by the receipt of $955.6 million in net proceeds from the February and July 2008 issuances of the 6.15% senior notes due 2018, net of debt issuance costs. During 2009 and 2008, cash was provided by our receipt of proceeds totaling $11.2 million and $56.6 million, respectively, from the exercise by our employees of options to acquire our common shares.
Future Cash Requirements
As of December 31, 2009, we had long-term debt, including current maturities, of $3.9 billion and cash and investments of $1.2 billion, including $100.9 million of long-term investments and other receivables. Long-term investments and other receivables include $92.5 million in oil and gas financing receivables.
Our 0.94% senior exchangeable notes mature in May 2011. During 2008 and 2009 collectively, we purchased $1.1 billion par value of these notes in the open market for cash totaling $938.4 million, leaving approximately $1.7 billion par value outstanding. The balance of these notes will be reclassified to current debt in the second quarter of 2010. We believe our positive cash flow from operations in combination with our
ability to access the capital markets will be sufficient to enable us to satisfy the payment obligation due in May 2011.
Our 0.94% senior exchangeable notes due 2011 provide that upon an exchange of these notes, we will be required to pay holders of the notes cash up to the principal amount of the notes and our common shares for any amount that the exchange value of the notes exceeds the principal amount of the notes. The notes cannot be exchanged until the price of our shares exceeds approximately $59.57 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 during the five business days immediately following 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 sale price of Nabors’ common shares and the then applicable exchange rate for the notes; or upon the occurrence of specified corporate transactions set forth in the indenture. On February 24, 2010, the closing market price for our common stock was $21.92 per share. If any of the events described above were to occur and the notes were exchanged at a purchase price equal to 100% of the principal amount of the notes before 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. Management believes that in the event the price of our shares were to exceed $59.57 for the required period of time, the holders of these notes would not be likely to exchange the notes as it would be more economically beneficial to them if they sold the notes to other investors on the open market. However, there can be no assurance that the holders would not exchange the notes.
As of December 31, 2009, we had outstanding purchase commitments of approximately $152.4 million, primarily for rig-related enhancements, construction and sustaining capital expenditures and other operating expenses. Capital expenditures over the next twelve months, including these outstanding purchase commitments, are currently expected to total approximately $.6 - $.8 billion, including currently planned rig-related enhancements, construction and sustaining capital expenditures. This amount could change significantly based on market conditions and new business opportunities. The level of our outstanding purchase commitments and our expected level of capital expenditures over the next twelve months represent a number of capital programs that are currently underway. These programs, which are nearing an end, have resulted in an expansion in the number of drilling and well-servicing rigs that we own and operate and consist primarily of land drilling and well-servicing rigs. The expansion of our capital expenditure programs to build new state-of-the-art drilling rigs has impacted a majority of our operating segments, most significantly within our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, Alaska, Canada and International operations.
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, 2009:
The table above excludes liabilities for unrecognized tax benefits totaling $107.5 million as of December 31, 2009 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 and 5.375% senior notes due August 2012.
(3)
Represents Nabors Delaware’s aggregate 6.15% senior notes due February 2018 and 9.25% senior notes due January 2019.
(4)
See Note 16 - Commitments and Contingencies in Part II, Item 8. - Financial Statements and Supplementary Data.
(5)
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.
(6)
See Note 14 - Pension, Postretirement and Postemployment Benefits in Part II, Item 8. - Financial Statements and Supplementary Data.
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, 2009, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2009, 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 16 - 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 and $45 million to Messrs. Isenberg and 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, 2009, we had 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. 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 $824.2 million (including $240.0 million of long-term investments and other receivables, inclusive of $224.2 million in oil and gas financing receivables) and working capital of $1.0 billion as of December 31, 2008.
Our gross funded debt to capital ratio was 0.41:1 as of each December 31, 2009 and 2008. Our net funded debt to capital ratio was 0.33:1 as of December 31, 2009 and 0.35:1 as of December 31, 2008.
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 6.2:1 as of December 31, 2009 and 20.7:1 as of December 31, 2008. The interest coverage ratio is a trailing 12-month quotient of the sum of net income (loss) attributable to Nabors, interest expense, 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. 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.
We had four letter of credit facilities with various banks as of December 31, 2009. Availability under our credit facilities as of December 31, 2009 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, which are currently “BBB+”, “Baa1” and “BBB+”, respectively, 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 of this magnitude, in addition to our other cash obligations, would not ultimately have a material adverse impact on our liquidity or financial position. In addition, Standard & Poor’s recently affirmed its BBB+ credit rating, but revised its outlook to negative from stable in early 2009 due primarily to worsening industry conditions. A credit downgrade may impact our ability to access credit markets.
Our current cash and investments and projected cash flows from operations 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 discussed under
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, 2009 would result in a $8.2 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, investments and marketable and non-marketable securities, 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 investments in marketable and non-marketable securities 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% and 9.25% senior notes, our range-cap-and-floor derivative instrument, our investments in debt
securities (including corporate, asset-backed, U.S.-government, foreign-government, 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 non-marketable securities.
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 $3.3 million and $4.7 million as of December 31, 2009 and 2008, respectively. We recorded a gain of approximately $1.4 million for the year ended December 31, 2009 and losses of approximately $4.7 million and $1.3 million for the years ended December 31, 2008 and 2007, 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, 2009 would decrease the fair value of our range-cap-and-floor derivative instrument by approximately $.3 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. As of January 1, 2008, we adopted the provisions of the Fair Value Measurements and Disclosures Topic of the ASC and have estimated the fair value of our financial instruments in accordance with this framework. 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 carrying and fair values of our long-term debt, including the current portion, are as follows:
(1)
During 2009 and 2008, we purchased $964.8 million and $100 million, respectively, par value of these notes in the open market.
(2)
Includes the effect of interest savings realized from the interest-rate swap executed on October 21, 2002.
(3)
Includes $1.1 million and $1.5 million as of December 31, 2009 and 2008, 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. Our cash, cash equivalents, short-term and long-term investments and other receivables are included in the table below:
Our investments in debt securities listed in the above table and a portion of our long-term investments are sensitive to changes in interest rates. Additionally, our investment portfolio of debt and equity securities, which are carried at fair value, exposes us to price risk. A hypothetical 10% decrease in the market prices for all securities as of December 31, 2009 would decrease the fair value of our trading securities and available-for-sale securities by $2.4 million and $13.9 million, respectively.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Page No.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Income (Loss) for the Years Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
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 at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009, 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 it accounts for convertible debt instruments and participating securities included in the computation of earnings per share as of January 1, 2009. Additionally, as discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which its oil and gas reserves are estimated, and its unconsolidated oil and gas joint ventures 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.
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
February 26, 2010
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 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
Nabors Industries Ltd. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - (Continued)
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, with approximately 542 actively marketed land drilling rigs. We conduct oil, gas and geothermal 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 are also one of the largest land well-servicing and workover contractors in the United States and Canada. We actively market approximately 558 rigs for land workover and well-servicing work in the United States, primarily in the southwestern and western United States, and approximately 172 rigs for land workover and well-servicing work in Canada. Nabors is a leading provider of offshore platform workover and drilling rigs, and actively markets 40 platform, 13 jack-up and 3 barge rigs in the United States and multiple international markets. These rigs provide well-servicing, workover and drilling services. We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets 9 rigs in addition to the rigs we lease to the joint venture. We also offer a wide range of ancillary well-site services, including engineering, transportation, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select domestic and international markets. We provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft. 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 also invest in oil and gas exploration, development and production activities in the U.S., Canada and international areas through both our wholly owned subsidiaries and our separate joint venture entities. We hold a 50% ownership interest in our Canadian entity and 49.7% ownership interests in our U.S. and International entities. Each joint venture pursues development and exploration projects with our existing customers and with other operators in a variety of forms, including operated and non-operated working interests, joint ventures, farm-outs and acquisitions.
The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, workover and well-servicing 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.
During the third quarter of 2007 we sold our Sea Mar business to an unrelated third party. 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 the Sea Mar business, previously included in Other Operating Segments, as a discontinued operation for all periods presented. See Note 20 - Discontinued Operation for additional discussion.
The accompanying 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.
As used in the Report, “we,” “us,” “our,” “the Company” and “Nabors” means Nabors Industries Ltd. and, where the context requires, includes our subsidiaries and “Nabors Delaware” means Nabors Industries, Inc., a Delaware corporation, and our subsidiaries.
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
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $305.7 million and $410.8 million and investments in unconsolidated affiliates accounted for using the cost method totaled $.9 million as of each December 31, 2009 and 2008, respectively. Similarly, investments in certain offshore funds classified as non-marketable 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, U.S.-government debt securities, foreign-government 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.
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 classified as non-marketable, because they 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.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 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. For the years ended December 31, 2009, 2008 and 2007, our impairment tests on the oil and gas-related assets of our wholly owned Ramshorn business unit resulted in impairment charges of $205.9 million, $21.5 million and $41.0 million, respectively. As further discussed below in Recent Accounting
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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. For the year ended December 31, 2009, our unconsolidated oil and gas joint ventures’ application of the full-cost ceiling test resulted in impairment charges, of which $237.1 million represented our proportionate share.
For the years ended December 31, 2008 and 2007, 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. Our unconsolidated oil and gas joint ventures’ application of the full-cost ceiling test resulted in impairment charges during 2008, of which $228.3 million represented our proportionate share. There were no ceiling test impairment charges recorded by our unconsolidated oil and gas joint ventures during 2007.
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.
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.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2009 and 2008 was as follows:
Acquisitions and
Cumulative
Balance as of
Purchase Price
Translation
Balance as of
December 31, 2007
Adjustments
Impairments
Adjustment
December 31, 2008
(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling
$
30,154
$
-
$
-
$
-
$
30,154
U.S. Land Well-servicing
50,839
-
-
-
50,839
U.S. Offshore
18,003
-
-
-
18,003
Alaska
19,995
-
-
-
19,995
Canada
181,267
-
(145,447
)(1)
(35,820
)
-
International
18,983
-
-
18,983
Subtotal Contract Drilling
319,241
-
(145,447
)
(35,820
)
137,974
Other Operating Segments
49,191
(4,561
)(2)
(7,139
)
37,775
Total
$
368,432
$
$
(150,008
)
$
(42,959
)
$
175,749
Acquisitions and
Cumulative
Balance as of
Purchase Price
Translation
Balance as of
December 31, 2008
Adjustments
Impairments
Adjustment
December 31, 2009
(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling
$
30,154
$
-
$
-
$
-
$
30,154
U.S. Land Well-servicing
50,839
-
-
-
50,839
U.S. Offshore
18,003
-
-
-
18,003
Alaska
19,995
-
-
-
19,995
International
18,983
-
-
-
18,983
Subtotal Contract Drilling
137,974
-
-
-
137,974
Other Operating Segments
37,775
-
(14,689
)(2)
3,205
26,291
Total
$
175,749
$
-
$
(14,689
)
$
3,205
$
164,265
(1)
Represents goodwill impairment associated with our Canada Well-servicing and Drilling segment primarily relating to acquisitions of Enserco Energy Services Company, Inc. in 2002 and Command Drilling Corporation in 2001. As of December 31, 2009, Canada Well-servicing and Drilling segment no longer had any recorded goodwill.
(2)
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
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
diminished demand for immediate heliportable access to remote drilling sites. As of December 31, 2009, Nabors Blue Sky Ltd has no recorded goodwill.
Our Oil and Gas segment does not have any goodwill. Goodwill for the consolidated company, totaling approximately $6.2 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 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 16 - 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.
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
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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.
Effective January 1, 2007, we adopted the revised provisions of the Income Taxes Topic in the ASC relating to uncertain tax positions. In connection with that adoption, we recognized increases to our tax reserves for uncertain tax positions along with interest and penalties as an increase to other long-term liabilities and as a reduction to retained earnings at January 1, 2007.
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 foreign 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 $105.0 million, $537.7 million and $477.6 million as of December 31, 2009, 2008 and 2007, 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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;
•
income taxes;
•
litigation and self-insurance reserves;
•
fair value of assets acquired and liabilities assumed; and
•
share-based compensation.
Recent Accounting Pronouncements
On July 1, 2009, the Financial Accounting Standards Board (“FASB”) released the Accounting Standards Codification (“ASC”). The ASC became the single source of authoritative nongovernmental GAAP. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The ASC is not intended to change GAAP, but changes the approach by referencing authoritative literature by topic (each, a “Topic”) rather than by type of standard. Accordingly, references in the Notes to Consolidated Financial Statements to former FASB positions, statements, interpretations, opinions, bulletins or other pronouncements are now presented as references to the corresponding Topic in the ASC.
Effective January 1, 2009, Nabors changed its method of accounting for certain of its convertible debt instruments in accordance with the revised provisions of the Debt with Conversions and Other Options Topic of the ASC. Additionally, Nabors changed its method for calculating its basic and diluted earnings per share using the two-class method in accordance with the revised provisions of the Earnings Per Share Topic of the ASC. As required by the Accounting Changes and Error Corrections Topic of the ASC, financial information and earnings per share calculations for prior periods have been adjusted to reflect retrospective application.
The revised provisions of the Debt with Conversions and Other Options Topic clarify that convertible debt instruments that may be settled in cash upon conversion are accounted for with a liability component based on
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the fair value of a similar nonconvertible debt instrument and an equity component based on the excess of the initial proceeds from the convertible debt instrument over the liability component. Such excess represents proceeds related to the conversion option and is recorded as capital in excess of par value. The liability is recorded at a discount, which is then amortized as additional non-cash interest expense over the convertible debt instrument’s expected life. The retrospective application and impact of these provisions on our consolidated financial statements is described in Note 11 - Debt.
The revised provisions relating to use of the two-class method for calculating earnings per share within the Earnings Per Share Topic provide that securities that are granted in share-based transactions are “participating securities” prior to vesting if they have a nonforfeitable right to participate in any dividends, and such securities therefore should be included in computing basic earnings per share. Our awards of restricted stock are considered participating securities under this definition. The retrospective application and impact of these provisions on our consolidated financial statements is set forth in Note 17 - Earnings (Losses) Per Share.
Effective January 1, 2008, we adopted and applied the provisions of the Fair Value Measurements and Disclosures Topic of the ASC to our financial assets and liabilities and on January 1, 2009 applied the same provisions to our nonfinancial assets and liabilities. Effective April 1, 2009, we adopted the provisions of this Topic relating to fair value measures in inactive markets. These provisions provide additional guidance for determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements. The application of these provisions did not have a material impact on our consolidated financial statements. Our fair value disclosures are provided in Note 5 - Fair Value Measurements.
Effective January 1, 2009, we adopted the revised provisions of the Business Combinations Topic of the ASC and will apply those provisions on a prospective basis to acquisitions. The revised provisions retain the fundamental requirement that the acquisition method of accounting be used for all business combinations and expands the use of the acquisition method to all transactions and other events in which one entity obtains control over one or more other businesses or assets at the acquisition date and in subsequent periods. The revised provisions require measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any noncontrolling interests. Additionally, acquisition-related costs, including restructuring costs, are recognized as expense separately from the acquisition.
Effective January 1, 2009, new provisions relating to noncontrolling interests of a subsidiary within the Identifiable Assets and Liabilities, and Any Noncontrolling Interest Topic of the ASC were released. The provisions establish the accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. The provisions clarify that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Our consolidated financial statements reflect the adoption and have been adjusted to reflect retrospective application. The application of these provisions did not have a material impact on our consolidated financial statements.
Effective January 1, 2009, we adopted the revised provisions relating to expanded disclosures of derivatives within the Derivatives and Hedging Topic of the ASC. The revised provisions are intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced qualitative and quantitative disclosures regarding such instruments, gains and losses thereon and their effects on an entity’s financial position, financial performance and cash flows. The application of these provisions did not have a material impact on our consolidated financial statements.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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. In line with the one-year deferral, we will provide the oil and gas disclosures in annual periods beginning after December 31, 2009.
Effective April 1, 2009, we adopted the provisions in the Investments of Debt and Equity Securities Topic of the ASC relating to recognition and presentation of other-than-temporary impairments to debt securities. The impact of these provisions is set forth in Notes 3 - Impairments and Other Charges and 4 - Cash and Cash Equivalents and Investments.
Effective June 30, 2009, we adopted the provisions in the Financial Instruments Topic of the ASC relating to quarterly disclosure of the fair value of financial instruments. The disclosures required by this Topic are provided in Note 5 - Fair Value Measurements.
Effective June 30, 2009, we adopted the revised provisions in the Subsequent Events Topic of the ASC and evaluated subsequent events through the date of the release of our financial statements. The adoption of the Subsequent Events Topic of the ASC did not have any impact on our financial position, results of operations or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 3 Impairments and Other Charges
The following table provides the components of impairments and other charges recorded during the years ended December 31, 2009, 2008 and 2007:
During the years ended December 31, 2009 and 2008, we recognized goodwill impairments of approximately $14.7 million and $150.0 million, respectively, related to our Canadian operations. During 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., one of our Canadian subsidiaries reported in our Other Operating segments. During 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd. 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 has led to reduced capital spending by some of our customers and has diminished demand for our drilling services and for immediate access to remote drilling sites. A significantly prolonged period of lower oil and natural gas prices 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Significant Accounting Policies (included under the caption “Goodwill”) for amounts of goodwill related to each of our reporting units.
During the year ended December 31, 2009, we retired some rigs and rig components in our U.S. Offshore, Alaska, Canada and International Contract Drilling segments and reduced their aggregate carrying value from $69.0 million to their estimated aggregate salvage value, resulting in impairment charges of approximately $64.2 million. 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. A prolonged 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.
Also in 2009, we recorded impairments totaling $205.9 million to some of the oil and gas-related assets of our wholly owned Ramshorn business unit. We recorded an impairment of $149.1 million to one of our oil and gas financing receivables, which reduced the carrying value of our oil and gas financing receivables recorded as long-term investments to $92.5 million. The impairment resulted primarily from commodity price deterioration and the lower price environment lasting longer than expected. This prolonged period of lower prices has significantly reduced demand for future gas production and development in the Barnett Shale area of north central Texas, which has influenced our decision not to expend capital to develop on some of the undeveloped acreage. The impairment 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. We believe the estimates used provide a reasonable estimate of current fair value. We determined that this represented a Level 3 fair value measurement. A further protraction or continued period of lower commodity prices could result in recognition of future impairment charges. During the years ended December 31, 2009, 2008 and 2007, our impairment tests on the oil and gas properties of our wholly owned Ramshorn business unit resulted in impairment charges of $56.8 million, $21.5 million and $41.0 million, respectively. The impairments recognized during 2009 were primarily the result of a write down of the carrying value of some acreage in the U.S. and Canada because we do not have future plans to develop. The impairments recognized during 2008 were primarily due to the significant decline in oil and natural gas prices at the end of 2008. The impairments recognized during 2007 were necessary from lower than expected performance of some oil and gas development wells. Additional discussion of our policy pertaining to the calculations of these impairments is set forth in Note 2 - Summary of Significant Accounting Policies.
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 the investment’s carrying value to its current estimated fair value of approximately $27.0 million at December 31, 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Certain information related to our cash and cash equivalents and short-term investments follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2009.
The estimated fair values of our corporate, mortgage-backed, mortgage-CMO and asset-backed debt securities at December 31, 2009, 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:
Year Ended December 31,
(In thousands)
Available-for-sale:
Proceeds from sales and maturities
$
23,411
$
202,382
$
531,230
Realized gains (losses), net
(54,314
)(1)
49,947
(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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 5 Fair Value Measurements
Effective January 1, 2008, we provided enhanced disclosures about our assets and liabilities carried at fair value as required by the provisions of the Fair Value Measurements and Disclosures Topic of the ASC.
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, 2009. 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.
Nonrecurring Fair Value Measurements
Effective January 1, 2009, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 carrying and fair values of our long-term debt, including the current portion, are as follows:
(1)
Includes $1.1 million and $1.5 million as of December 31, 2009 and 2008, 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, 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. As of December 31, 2008, our short-term investments were carried at fair market value and included $127.9 million and $14.3 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 $8.3 million and $15.7 million as of December 31, 2009 and 2008, respectively. The carrying value of our oil and gas financing receivables included in long-term investments approximate fair value. The fair value of our oil and gas financing receivables totaled $92.5 million and $224.2 million as of December 31, 2009 and 2008, 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 $106.7 million, $45.4 million and $33.5 million for the years ended December 31, 2009, 2008 and 2007, respectively. Compensation expense related to awards of restricted stock totaled $88.9 million, $44.6 million and $26.4 million for the years ended December 31, 2009, 2008 and 2007, 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 21 - 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 16 - Commitments and Contingencies for additional information.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2009, 2008 and 2007 was $.3 million, $7.6 million and $3.3 million, respectively.
Stock Option Plans
As of December 31, 2009, 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 12.0 million and 15.6 million Nabors common shares remained available for grant as of December 31, 2009 and 2008, respectively. Of the common shares available for grant as of December 31, 2009, approximately 11.1 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 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock option transactions under our various stock-based employee compensation plans are presented below:
Of the options outstanding, 27.2 million, 25.9 million and 27.8 million were exercisable at weighted-average exercise prices of $21.04, $21.99 and $22.03, as of December 31, 2009, 2008 and 2007, respectively. There were no options granted during the years ended December 31, 2008 or 2007.
During the year ended December 31, 2009, we awarded options vesting over periods up to four years to purchase 10,015,883 of our common shares to our employees, executive officers and directors. 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, in February 2009, and an option to purchase 1,726 shares, with a grant date fair value of $.01 million, to Mr. Petrello in September 2009 in lieu of certain portions of their cash compensation.
The fair value of stock options granted during 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
A summary of our unvested stock options as of December 31, 2009, and the changes during the year then ended is presented below:
The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007 was $19.7 million, $43.6 million and $76.2 million, respectively. The total fair value of options that vested during the years ended December 31, 2009, 2008 and 2007 was $10.8 million, $4.3 million and $11.9 million, respectively.
As of December 31, 2009, there was $9.5 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 1.6 years.
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, 2009, and the changes during the year then ended, is presented below:
During 2009, we awarded 84,000 shares of restricted stock to our directors. These awards had an aggregate value at their date of grant of $1.0 million and were scheduled to vest over a period of three years. The fair value of restricted stock that vested during the year ended December 31, 2009, 2008 and 2007 was $23.9 million, $39.6 million and $13.2 million, respectively.
As of December 31, 2009, there was $14.6 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7 Acquisitions and Divestitures
On August 8, 2007, we sold our Sea Mar business which had previously been included in Other Operating Segments. The assets included 20 offshore supply vessels and certain related assets, including a right under a vessel construction contract. See Note 20 - Discontinued Operations for operating results which have been accounted for as a discontinued operation.
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.
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, 2009 or 2008.
Repair and maintenance expense included in direct costs in our consolidated statements of income (loss) totaled $282.1 million, $476.6 million and $438.0 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Interest costs of $29.9 million, $29.8 million and $34.6 million were capitalized during the years ended December 31, 2009, 2008 and 2007, 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 U.S. and international (49.7% ownership) and Canada (50% ownership). These unconsolidated affiliates are integral to our operations in those locations. During 2008, our 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 and see Note 15 - Related-Party Transactions for a discussion of transactions with all of these related parties.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As of December 31, 2009 and 2008, our investments in unconsolidated affiliates accounted for using the equity method totaled $305.7 million and $410.8 million, respectively, and our investments in unconsolidated affiliates accounted for using the cost method totaled $.9 million. Combined condensed financial data for investments in unconsolidated affiliates is summarized as follows:
Cumulative undistributed (losses) earnings of our unconsolidated affiliates included in our retained earnings as of December 31, 2009 and 2008 totaled approximately $(387.5) million and $(157.7) 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 includes our proportionate share of full-cost ceiling test writedowns of $237.1 million and $228.3 million, respectively, from our unconsolidated oil and gas joint ventures. These writedowns are included in our Oil and Gas operating segment results.
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, investments in marketable and non-marketable securities, oil and gas financing receivables,
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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 investments in marketable and non-marketable securities 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 our 0.94% senior exchangeable notes, our 5.375%, 6.15% and 9.25% senior notes, our range-cap-and-floor derivative instrument, our investments in debt securities (including corporate, asset-backed, U.S.-government, foreign government, 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 non-marketable securities.
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 $3.3 million and $4.7 million as of December 31, 2009 and 2008, respectively. We recorded a gain of approximately $1.4 million for the year ended December 31, 2009 and losses of approximately $4.7 million and $1.3 million for the years ended December 31, 2008 and 2007,
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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 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, 2009, the maturities of our primary debt for each of the five years after 2009 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 and 9.25% senior notes due January 2019.
0.94% Senior Exchangeable Notes Due 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
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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 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.
During 2009 and 2008 collectively, we purchased $1.1 billion par value of Nabors Delaware’s 0.94% senior exchangeable notes due 2011 in the open market for cash of $938.4 million and recognized pre-tax gains of $11.5 million and $12.2 million 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 year ended December 31, 2009 and 2008, respectively.
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
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be exercisable and will expire on August 15, 2011. We received aggregate proceeds of approximately $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 also recognized a deferred tax asset of $215.9 million in the second quarter of 2006 for the effect of the future tax benefits related to the exchangeable note hedge. See Convertible Debt Accounting below for impact to our deferred tax asset in the 2009 adoption of accounting rules relating to convertible debt.
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
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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.
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.
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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.
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.
In July 2008, Nabors Delaware paid $60.6 million in cash to redeem its zero coupon senior convertible debentures due 2021 which equaled the issue price of $50.4 million plus accrued original issue discount of $10.2 million. The redemption of the debentures did not result in any gain or loss since they were redeemed at a price equal to their carrying value on July 7, 2008.
In June and July 2008, Nabors Delaware paid cash of $171.8 million and $528.2 million to redeem all of its zero coupon senior exchangeable notes due 2023. In addition to $700 million in cash, we issued approximately 5.25 million of our common shares, with a fair value of $249.8 million, the price equal to the principal amount of the notes plus the excess of the exchange value of the notes over their principal amount. Nabors Delaware was required to pay noteholders cash up to the principal amount of the notes and at its option, either cash or common shares for any amount above the principal amount of the notes. The number of common shares issued equaled the amount in excess of the principal of the notes divided by the average of the volume-weighted average price of our common shares for the five or ten trading day period beginning on the second business day following the day the notes were surrendered for exchange. The notes were exchangeable into the equivalent value of 28.5306 common shares per $1,000 principal amount of the notes. The redemption of the notes did not result in any gain or loss since the amount of cash paid for redemption of the notes was equal to their carrying amount. The excess of the exchange value of the notes over the carrying amount was recorded as a reduction to capital in excess of par value in our consolidated statement of changes in equity. A deferred tax liability of $81.8 million recorded during the five-year period that the notes were outstanding was reclassified to and increased our capital in excess of par value account. This reclassification reflects the permanent income tax savings to the Company relating to the notes.
Short-Term Borrowings
We had four letter-of-credit facilities with various banks as of December 31, 2009. We did not have any short-term borrowings outstanding at December 31, 2009 or 2008. Availability and borrowings under our credit facilities are as follows:
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Convertible Debt Accounting
Prior to January 1, 2009, separate accounting for the embedded conversion option in our convertible long-term debt was not required when the conversion spread feature did not qualify for accounting as a derivative instrument.
Effective January 1, 2009, we account for our convertible debt instruments with a liability component based on the fair value of a similar nonconvertible debt instrument and an equity component based on the excess of the initial proceeds from the convertible debt instrument over the liability component. Such excess represents proceeds related to the conversion option and is recorded as capital in excess of par value. The liability is recorded at a discount, which is then amortized as additional non-cash interest expense over the convertible debt instrument’s expected life. We have accounted for our convertible debt instruments on a retrospective basis in all past periods presented for all convertible debt instruments required to be accounted for in this manner. Both our 0.94% senior exchangeable notes issued May 2006 and our zero coupon senior exchangeable notes issued June 2003 have been presented in this manner.
The following assumptions were made in our accounting change:
Conversion Triggers
Zero coupon senior exchangeable notes
In May 2008 Nabors Delaware called for redemption of all of its zero coupon senior exchangeable notes due 2023. The total consideration exchanged to effect the redemption and related exchange was $700 million in cash and approximately 5.25 million of our common shares, with a fair value of $249.8 million, which represents the principal amount of the notes plus the excess of the exchange value of the notes over their principal amount.
0.94% senior exchangeable notes
The notes are exchangeable into cash and, if applicable, Nabors common shares based on an exchange rate equal to 21.8221 common shares per $1,000 principal amount of notes (equating 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.
Upon exchange, we would be required to issue only incremental shares above the principal amount of the notes, since we are required to pay cash up to the principal amount of the notes exchanged. There would be an if-converted value in excess of the principal amount of the notes only when the price of our shares 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.
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The effect of the accounting change on our previously reported consolidated balance sheet is as follows:
The increase to deferred income tax liabilities related partially to the reduction of a deferred tax asset of $215.9 million (which was recorded during the second quarter of 2006) for the effect of the future tax benefits related to the exchangeable note hedge.
The effect of the accounting change on our previously reported consolidated statements of income (loss) is as follows:
(1)
Includes accounting change related to earnings per share calculation. See Note 17 - Earnings (Losses) Per Share.
The following information illustrates the effect of the accounting change on our convertible debt instruments. The balances of the liability and equity components as of December 31, 2009 and 2008 are as follows:
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The remaining debt discount is being amortized into interest expense over the expected remaining life of the convertible debt instruments using the effective interest rate. Interest expense related to the convertible debt instruments was recognized as follows:
Note 12 Income Taxes
Effective January 1, 2007, we adopted the revised provisions of the Income Taxes Topic in the ASC relating to uncertain tax positions. We recognized increases of $24 million and $21 million to our tax reserves for uncertain tax positions and interest and penalties, respectively. These increases were accounted for as an increase to other long-term liabilities and as a reduction to retained earnings at January 1, 2007. The change in our unrecognized tax benefits for years ended December 31, 2009, 2008 and 2007 are as follows:
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, 2009, 2008 and 2007, we had approximately $38.5 million, $18.6 million and $28.4 million, respectively, of interest and penalties related to our total gross unrecognized tax benefits. During the years ended December 31, 2009, 2008 and 2007, we accrued and recognized estimated interest related to unrecognized tax benefits and penalties of approximately $5.2 million, $5.3 million and $6.9 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. Internationally, a number of our income tax returns from 1995 through 2007 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, 2009.
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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 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. The result is a net tax benefit that represents a significant percentage (63.5%) of our consolidated GAAP loss.
The increase in our effective income tax rate from 2007 to 2008 resulted from (1) our goodwill impairments which had no associated tax benefit, (2) the reversal of certain tax reserves during 2007 in the amount of $25.5 million, (3) a decrease in 2007 tax expense of approximately $16.0 million resulting from a reduction in Canada’s tax rate, and (4) a higher proportion of our 2008 taxable income being generated in the United States, which generally imposes a higher tax rate than the other jurisdictions in which we operate.
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The significant components of our deferred tax assets and liabilities were as follows:
(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 $715.7 million that, if not utilized, will expire during 2017 to 2018. The NOL carryforwards for alternative minimum tax purposes are approximately $12.8 million. Additionally, we have NOL carryforwards in other jurisdictions of approximately $5.8 billion of which $219.9 million that, if not utilized, will expire at various times from 2010 to 2029. 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 $1.53 billion as of December 31, 2009 relating to NOL carryforwards that have an indefinite life in several non-U.S. jurisdictions. A valuation allowance of approximately $1.52 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 $280 million that, if not utilized, will expire at various times from 2010 to 2029.
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 313,915,220 and 312,343,407 at $.001 par value as of December 31, 2009 and 2008, respectively.
For the years ended December 31, 2008 and 2007, we repurchased 8.5 million and 3.8 million, respectively, of our common shares in the open market for $281.1 million and $102.5 million, respectively, all of which are held in treasury. No shares were purchased in the open market during 2009. 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 2009 our outstanding shares increased by 218,835 pursuant to a share settlement of stock options exercised by Nabors’ Deputy Chairman, President and Chief Operating Officer, Anthony G. Petrello. As part of the transaction, Mr. Petrello surrendered 531,165 unexercised vested stock options to the Company with a value of approximately $5.6 million to satisfy the option exercise price and related income taxes. During 2007 our outstanding shares increased by 729,866 pursuant to a share settlement of stock options exercised by Nabors’ Chairman and Chief Executive Officer, Eugene M. Isenberg. As part of the transaction, Mr. Isenberg surrendered 4,142,812 unexercised vested stock options to the Company with a value of approximately $29.7 million to satisfy the option exercise price and related income taxes.
For the years ended December 31, 2009, 2008 and 2007 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 85,000, 4,982,536 and 1,744,627 restricted shares at an average market price of $11.55, $20.68 and $30.18 to these individuals for 2009, 2008 and 2007, respectively. See Note 6 - Share-Based Compensation for a summary of our restricted stock and option awards as of December 31, 2009.
For the years ended December 31, 2009, 2008 and 2007 our employees exercised vested options to acquire 1.5 million, 2.5 million and 4.5 million of our common shares, respectively, resulting in proceeds of $11.2 million, $56.6 million and $61.6 million, respectively.
During 2008 in connection with the redemption of the zero coupon senior exchangeable notes due 2023, we issued 5.25 million of our treasury shares with a fair value of $249.8 million to satisfy the obligation to the noteholders to pay the excess over the principal amount of the notes that were exchanged. The treasury shares issued in connection with the redemption of the zero coupon senior exchangeable notes had a cost basis of $181.2 million. See Note 11 - Debt for additional discussion.
In conjunction with our acquisition of Ryan Energy Technologies Inc. in October 2002 and our acquisition of Enserco Energy Services Company Inc. in April 2002, we issued 760,528 and 7,098,164 exchangeable shares of Nabors Exchangeco (Canada) Inc., one of our wholly owned Canadian subsidiaries (“Nabors Exchangeco”), respectively. During 2009 we redeemed the exchangeable shares of Nabors Exchangeco for Nabors’ common shares on a one-for-one basis.
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Note 14 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.
Summarized information on the Pool Pension Plan is as follows:
(1)
As of December 31, 2009 and 2008, the accumulated benefit obligation was the same as the projected benefit obligation.
For the years ended December 31, 2009, 2008 and 2007, the net actuarial loss amounts included in accumulated other comprehensive income (loss) in the consolidated statements of changes in equity were approximately $(6.3) million, $(7.4) million and $(2.6) million, respectively. There were no other components,
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such as prior service costs or transition obligations relating to pension costs recorded within accumulated other comprehensive income (loss) during 2009, 2008 and 2007.
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 2010 is approximately $.4 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 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, 2009. 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 which 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, 2009 and 2008, 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
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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 $.5 million to the Pool Pension Plan in 2010. This is based on the sum of (1) the minimum contribution for the 2009 plan year that will be made in 2010 and (2) the estimated minimum required quarterly contributions for the 2010 plan year. We made contributions to the Pool Pension Plan in 2009 and 2008 totaling $.6 million, respectively.
As of December 31, 2009, we expect that benefits to be paid in each of the next five years after 2009 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 $19.8 million and $17.5 million for the years ended December 31, 2009 and 2008, respectively. Nabors does not provide postemployment benefits to its employees.
Postretirement Benefits Other Than Pensions
Prior to the date of our acquisition, Pool provided certain postretirement 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 is recorded in our consolidated balance sheets as of December 31, 2009 and 2008, respectively, to cover the estimated costs of beneficiaries covered by the plan at the date of acquisition.
Note 15 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 $9.3 million and $8.4 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2009 and 2008, 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.
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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 $327.3 million, $285.3 million and $153.4 million for the years ended December 31, 2009, 2008 and 2007, respectively. Expenses from business transactions with these affiliated entities totaled $9.8 million, $9.6 million and $6.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. Additionally, we had accounts receivable from these affiliated entities of $104.2 million and $107.5 million as of December 31, 2009 and 2008, respectively. We had accounts payable to these affiliated entities of $14.8 million and $10.0 million as of December 31, 2009 and 2008, respectively, and long-term payables with these affiliated entities of $.8 million and $7.8 million as of December 31, 2009 and 2008, respectively, which are included in other long-term liabilities.
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. After these transactions, we hold a minority interest of approximately 11% of the issued and outstanding shares of Shona.
Note 16 Commitments and Contingencies
Commitments
Operating Leases
Nabors and its subsidiaries occupy various facilities and lease certain equipment under various lease agreements. The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2009, 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 $25.5 million, $29.4 million and $25.9 million for the years ended December 31, 2009, 2008 and 2007, respectively.
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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, 2009 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. 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.
For 2009, the annual cash bonuses for Messrs. Isenberg and Petrello pursuant to the formulas described in their employment agreements were $15.4 million and $4.9 million, respectively, for the first quarter of 2009 in accordance with the prior employment agreement provisions and $4.5 million and $3.0 million, respectively, for the second through fourth quarter of 2009 in accordance with the new employment agreement provisions.
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
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agreements effectively eliminated the risk of forfeiture of outstanding stock awards. Accordingly, we recognized compensation expense during the second quarter with respect to all previously granted unvested awards to Messrs. Isenberg and Petrello. As a result, as of December 31, 2009, there was no unrecognized 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, 2009, his payment would be approximately $45 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, 2009. 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 under audit 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 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 Mexican 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 Mexican branch took similar deductions for depreciation and labor expenses from 2004 to 2008. On June 30, 2009, the government proposed similar assessments against the Mexican 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 2009. 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 relating to the 2004 to 2009 years would also lack merit, a reserve has been recorded in accordance with GAAP. If these additional assessments were made and we ultimately did not prevail, we would be required to recognize additional tax for the amount of the aggregate over the current reserve.
Self-Insurance
We self-insure for certain losses relating to workers’ compensation, employers’ liability, general liability, automobile liability and property damage. Effective April 1, 2009 with our insurance renewal, changes have been made to our self-insured retentions. 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 a $10.0 million deductible 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, 2009 and 2008, our self-insurance accruals totaled $139.0 million and $163.0 million, respectively, and our related insurance recoveries/receivables were $12.9 million and $9.7 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 U.S. Department of Justice relating to its investigation of one of one of our vendors and compliance with the Foreign Corrupt Practices Act. The inquiry relates to transactions with and involving Panalpina, which provides 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. The Audit Committee 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 Department of Justice have been advised of the Company’s 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 the Company is 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.
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. We have also guaranteed payment of contingent consideration in conjunction with an acquisition in 2005. Potential contingent consideration is based on future operating results of the acquired business. 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
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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 and guarantees representing contingent consideration in connection with a business combination:
Note 17 Earnings (Losses) Per Share
Prior to January 1, 2009, we excluded unvested restricted stock awards in the calculation of basic earnings per share and applied the treasury stock method of accounting in calculating the effect on fully diluted shares of unvested restricted stock.
Effective January 1, 2009, 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. This accounting change resulted in reductions to our basic earnings per share calculations of $.02 and to our diluted earnings per share calculations of $.02 for the years ended December 31, 2008 and 2007.
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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, 2009, 2008 and 2007 exclude any incremental shares issuable upon exchange of the 0.94% senior exchangeable notes due 2011. During 2008 and 2009 collectively, we purchased $1.1 billion par value of these notes in the open market, leaving approximately $1.7 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2009, 2008 and 2007.
(2)
In July 2008 Nabors Delaware paid $60.6 million in cash to redeem the notes, which equaled the issue price of $50.4 million plus accrued original issue discount of $10.2 million. No common shares were issued as part of the redemption of the zero coupon convertible senior debentures.
(3)
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. Diluted earnings per share for the year ended December 31, 2007 did not include any incremental shares issuable upon exchange because the incremental shares would only be included in the weighted-average number of shares outstanding in our diluted earnings per share calculation when the price of our shares exceeded $35.05 on the last trading day of the quarter, which did not occur on December 31, 2007.
(4)
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: 283.2 million and .1 million shares for the year ended December 31, 2009; 281.5 million and .1 million shares for the year ended December 31, 2008; 281.1 million and .1 million shares for the year ended December 31, 2007.
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 34,113,887, 7,416,865 and 5,083,510 shares during the years ended December 31, 2009, 2008 and 2007, 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 18 Supplemental Balance Sheet, Income Statement and Cash Flow Information
At December 31, 2009, 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.
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Accrued liabilities include the following:
Investment income (loss) includes the following:
(1)
This amount reflects net unrealized gains of $9.8 million from our trading securities.
(2)
This amount reflects net unrealized gains of $8.5 million from our trading securities, partially offset by losses of $27.4 million from our actively managed funds classified as long-term investments.
(3)
This amount reflects a net loss of approximately $61.4 million from the portion of our long-term investments comprised of our actively managed funds inclusive of substantial gains from sales of our marketable equity securities.
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Losses (gains) on sales and retirements of long-lived assets and other expense (income), net includes the following:
(1)
This amount 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)
This amount includes a $38.6 million gain from the sale of three accommodation units in the second quarter of 2007 and $40.0 million in losses on long-lived asset retirements during 2007.
(3)
This amount 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.
(4)
These amounts include $11.5 million and $12.2 million pre-tax gains on our purchases of our 0.94% senior exchangeable notes in the open market during 2009 and 2008, respectively.
Supplemental cash flow information for the years ended December 31, 2009, 2008 and 2007 is as follows:
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Comprehensive income (loss) for the years ended December 31, 2009, 2008 and 2007 is as follows:
Note 19 Unaudited Quarterly Financial Information
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(1)
Includes earnings (losses) from unconsolidated affiliates, net, accounted for by the equity method, of $(64.4) million, $(8.1) million, $13.5 million and $(155.6) 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 $(4.4) million, $(4.0) million, $7.9 million and $(229.3) million, respectively.
Note 20 Discontinued Operation
In August 2007, we sold our Sea Mar business which had previously been included in Other Operating Segments to an unrelated third party for a cash purchase price of $194.3 million, resulting in a pre-tax gain of $49.5 million. The assets included 20 offshore supply vessels and some related assets, including its right under a vessel construction contract. The operating results of this business for all periods presented are reported as discontinued operations in the accompanying audited consolidated statements of income (loss) and the respective accompanying notes to the consolidated financial statements. Our condensed statements of income
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
from discontinued operations related to the Sea Mar business for the year ended December 31, 2007 was as follows:
Condensed Statements of Income
Note 21 Segment Information
As of December 31, 2009, we operate our business out of 10 operating segments. Our six Contract Drilling operating segments are engaged in drilling, workover and well-servicing 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, U.S. Offshore, Canada and International business units. Our oil and gas operating segment includes Ramshorn Investments, Inc. 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.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table sets forth financial information with respect to our reportable segments:
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
All segment information excludes the Sea Mar business, which has been reclassified as a discontinued operation.
(2)
These segments include our drilling, workover and well-servicing operations, on land and offshore.
(3)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $9.7 million, $5.8 million and $5.6 million for the years ended December 31, 2009, 2008 and 2007, respectively.
(4)
Includes our proportionate share of full-cost ceiling test writedowns recorded by our unconsolidated oil and gas joint ventures of $(237.1) million and $(228.3) million for the years ended December 31, 2009 and 2008, respectively.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(5)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $(241.9) million, $(241.4) million and $(3.9) million for the years ended December 31, 2009, 2008 and 2007, respectively.
(6)
Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations.
(7)
Includes earnings (losses), net from unconsolidated affiliates, accounted for using the equity method, of $17.5 million, $5.8 million and $16.0 million for the years ended December 31, 2009, 2008 and 2007, respectively.
(8)
Represents the elimination of inter-segment transactions.
(9)
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 (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.
(10)
Represents the elimination of inter-segment transactions and unallocated corporate expenses, assets and capital expenditures.
(11)
Represents impairments and other charges recorded during the years ended December 31, 2009, 2008 and 2007, respectively.
(12)
Includes the portion of the purchase price of acquisitions allocated to fixed assets and goodwill based on their fair market value.
(13)
Includes $49.8 million, $49.2 million and $47.3 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2009, 2008 and 2007, respectively.
(14)
Includes $21.4 million of investments in unconsolidated affiliates accounted for by the cost method of accounting as of December 31, 2007. There were no investments in unconsolidated affiliates accounted for by the cost method as of December 31, 2009 or 2008.
(15)
Includes $190.1 million, $298.3 million and $274.1 million investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2009, 2008 and 2007, respectively.
(16)
Includes $65.8 million, $63.3 million and $62.0 million of investments in unconsolidated affiliates accounted for using the equity method as of December 31, 2009, 2008 and 2007, respectively.
(17)
Includes $.9 million of investments in unconsolidated affiliates accounted for using the cost method as of each of December 31, 2009 and 2008, respectively.
Nabors Industries Ltd. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table sets forth financial information with respect to Nabors’ operations by geographic area:
Note 22 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 have 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”). On August 17, 2009, we paid $168.4 million to discharge the remaining balance of our 4.875% senior notes. Effective September 30, 2009, Nabors Holdings 1, ULC was amalgamated with Nabors Drilling Canada ULC, the successor company.
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, 2009 and 2008, statements of income (loss) for the years ended December 31, 2009, 2008 and 2007 and the consolidating statements of cash flows for the years ended December 31, 2009, 2008 and 2007 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)
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
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, 2009. 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.
OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information called for by this item will be contained in the Nabors Industries Ltd. definitive Proxy Statement to be distributed in connection with its 2010 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 July 2, 2009, 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.
EXECUTIVE COMPENSATION
The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2010 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’ 2010 proxy statement not deemed to be “soliciting material” or “filed” with the Commission under its rules, including the Compensation Committee Report, is not deemed to be incorporated by reference.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
We maintain five different equity compensation plans: 1996 Employee Stock Plan, 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, 2009:
(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 1996 Employee Stock 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 ten years; (4) options granted under the plan are nonstatutory options not intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended (NSOs); 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.
Executive Officers Incentive Stock Plan
The plan reserves for issuance up to 4,900,000 common shares of the Company pursuant to the exercise of options granted under the plan. Options may be granted under the plan to executive officers of the Company. No optionee may receive grants in excess of 50% of the total number of common shares authorized to be issued under the plan.
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 United States Internal Revenue Code, 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 18, 2006. 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 2010 annual meeting of shareholders under the caption “Share Ownership of Management and Principal Shareholders” and is incorporated into this document by reference.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information called for by this item will be contained in our definitive Proxy Statement to be distributed in connection with our 2010 annual meeting of shareholders under the caption “Certain Relationships and Related Transactions” and is incorporated into this document by reference.
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 2010 annual meeting of shareholders under the caption “Principal Accounting Fees and Services” and is incorporated into this document by reference.
PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
(1) Financial Statements
Page No.
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Income (Loss) for the Years Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2009, 2008 and 2007
(2) Financial Statement Schedules
Page No.
Schedule II - Valuation and Qualifying Accounts
Schedule III - Financial Statements and Notes for NFR Energy LLC
s-1
All other supplemental schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or related notes.
(b) Exhibits
Exhibit No.
Description
.1
Agreement and Plan of Merger among Nabors Industries, Inc., Nabors Acquisition Corp. VIII, Nabors Industries Ltd. and Nabors US Holdings Inc. (incorporated by reference to Annex I to the proxy statement/prospectus included in Nabors Industries Ltd.’s Registration Statement on Form S-4 (File No. 333-76198) filed with the Commission on May 10, 2002, as amended).
.2
Amended and Restated Acquisition Agreement, dated as of March 18, 2002, by and between Nabors Industries, Inc. and Enserco Energy Service Company Inc. (incorporated by reference to Exhibit 2.1 to Nabors Industries, Inc.’s Registration Statement on Form S-3 (File No. 333-85228) filed with the Commission on March 29, 2002).
.3
Form of Plan of Arrangement Under Section 192 of the Canada Business Corporations Act Involving and Affecting Enserco Energy Service Company Inc. and its Security holders (included in Schedule B to Exhibit 2.2).
.4
Arrangement Agreement dated August 12, 2002 between Nabors Industries Ltd. and Ryan Energy Technologies Inc. (incorporated by reference to Exhibit 2.4 to Nabors Industries Ltd.’s Form 10-K for the year ended December 31, 2002 (File No. 000-49887) filed with the Commission on March 31, 2003).
.5
Asset Purchase Agreement dated July 20, 2007, by and among Nabors US Finance LLC, Nabors Well Services Co. (inclusive of its Sea Mar Division), Sea Mar Management LLC and Hornbeck Offshore Services, Inc. (incorporated by reference to Exhibit 2.5 to Nabors Industries Ltd.’s Form 10-Q (File No. 001-32657) filed with the Commission on August 2, 2007).
.1
Memorandum of Association of Nabors Industries Ltd. (incorporated by reference to Annex II to the proxy statement/prospectus included in Nabors Industries Ltd.’s Registration Statement on Form S-4 (File No. 333-76198) filed with the Commission on May 10, 2002, as amended).
.2
Amended and Restated Bye-Laws of Nabors Industries Ltd. (incorporated by reference to Exhibit 4.2 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed with the Commission on August 3, 2005).
.3
Amendment to Amended and Restated Bye-Laws of Nabors Industries Ltd. (incorporated by reference to Exhibit A of Nabors Industries Ltd.’s Notice of Special General Meeting and Proxy Statement (File No. 001-32657) filed with the Commission on February 24, 2006).
.4
Form of Resolutions of the Board of Directors of Nabors Industries Ltd. authorizing the issue of the Special Voting Preferred Share (incorporated by reference to Exhibit 3.3 to Nabors Industries Ltd.’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (File No. 333-85228-99) filed with the Commission on June 11, 2002).
.1
Indenture, dated August 22, 2002, among Nabors Industries, Inc., as issuer, Nabors Industries Ltd., as guarantor, and Bank One, N.A., with respect to Nabors Industries, Inc.’s Series A and Series B 5.375% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to Nabors Industries, Inc.’s Registration Statement on Form S-4 (File No. 333-10049201) filed with the Commission on October 11, 2002).
.2
Indenture, dated August 22, 2002, among Nabors Holdings 1, ULC, as issuer, Nabors Industries, Inc. and Nabors Industries Ltd., as guarantors, and Bank One, N.A., with respect to Nabors Holdings 1, ULC’s Series A and Series B 4.875% Senior Notes due 2009 (incorporated by reference to Exhibit 4.1 to Nabors Holdings 1, ULC’s Registration Statement on Form S-4 (File No. 333-10049301) filed with the Commission on October 11, 2002).
.3
Purchase Agreement, dated May 18, 2006, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc. and Lehman Brothers Inc., with respect to Nabors Industries, Inc.’s 0.94% Senior Exchangeable Notes due 2011 (incorporated by reference to Exhibit 4.1 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on May 24, 2006).
.4
Indenture, dated as of May 23, 2006, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 0.94% Senior Exchangeable Notes due 2011 (including form of 0.94% Senior Exchangeable Note due 2011) (incorporated by reference to Exhibit 4.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on May 24, 2006).
Exhibit No.
Description
.5
Registration Rights Agreement, dated as of May 23, 2006, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc. and Lehman Brothers Inc., with respect to Nabors Industries, Inc.’s 0.94% Senior Exchangeable Notes due 2011 (incorporated by reference to Exhibit 4.3 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on May 24, 2006).
.6
Amended and Restated 2003 Employee Stock Plan (incorporated by reference to Exhibit A of Nabors Industries Ltd. Notice of 2006 Annual General Meeting of Shareholders and Proxy Statement (File No. 001-32657) filed with the Commission on May 4, 2006).
.7
Purchase Agreement, dated February 14, 2008, among Nabors Industries, Inc., Nabors Industries Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on February 25, 2008).
.8
Indenture, dated February 20, 2008, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (including form of 6.15% Senior Note due 2018) (incorporated by reference to Exhibit 4.2 to Nabors Industries Ltd. Form 8-K (File No. 001-32657) filed with the Commission on February 25, 2008).
.9
Registration Rights Agreement, dated as of February 20, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.3 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on February 25, 2008).
.10
Purchase Agreement, dated July 17, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on July 23, 2008).
.11
Registration Rights Agreement, dated July 22, 2008, among Nabors Industries, Inc., Nabors Industries, Ltd., Citigroup Global Markets Inc. and UBS Securities LLC, with respect to Nabors Industries, Inc.’s 6.15% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on July 23, 2008).
.12
Purchase Agreement, dated January 7, 2009, among Nabors Industries, Inc., Nabors Industries Ltd., Goldman, Sachs & Co., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Howard Weil Incorporated, J.P. Morgan Securities Inc., Morgan Stanley & Co. Incorporated, Tudor, Pickering, Holt & Co. Securities, Inc. and Wells Fargo Securities, LLC, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on January 14, 2009).
.13
Indenture related to the Senior Notes due 2019, dated as of January 12, 2009, among Nabors Industries, Inc., Nabors Industries Ltd. and Wells Fargo Bank, National Association, as trustee, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (including form of 9.25% Senior Note due 2019) (incorporated by reference to Exhibit 4.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on January 14, 2009).
.14
Registration Rights Agreement, dated as of January 12, 2009, among Nabors Industries, Inc., Nabors Industries Ltd., Goldman, Sachs & Co., UBS Securities LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Howard Weil Incorporated, J.P. Morgan Securities Inc., Morgan Stanley & Co. Incorporated, Tudor, Pickering, Holt & Co. Securities, Inc. and Wells Fargo Securities, LLC, with respect to Nabors Industries, Inc.’s 9.25% Senior Notes due 2019 (incorporated by reference to Exhibit 4.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on January 14, 2009).
.1 (+)
1996 Employee Stock Plan (incorporated by reference to Nabors Industries Inc.’s Registration Statement on Form S-8 (File No. 333-11313) filed with the Commission on September 3, 1996).
.2 (+)
Employment Agreement effective October 1, 1996, between Nabors Industries, Inc. and Eugene M. Isenberg (incorporated by reference to Exhibit 10.7 to Nabors Industries Inc.’s Form 10-Q (File No. 1-9245) filed with the Commission on May 16, 1997).
Exhibit No.
Description
.3 (+)
First Amendment to Amended and Restated Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg dated as of June 24, 2002 (incorporated by reference to Exhibit 10.1 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed with the Commission on August 14, 2002).
.4 (+)
Second Amendment to Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg dated as of July 17, 2002 (incorporated by reference to Exhibit 10.1 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed with the Commission on August 14, 2002).
.5 (+)
Third Amendment to Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg dated as of December 28, 2005 (incorporated by reference to Exhibit 10.01 to Nabors Industries Ltd.’s Form 8-K (File No. 000-49887) filed with the Commission on December 28, 2005).
.6 (+)
Fourth Amendment to Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg dated as of March 10, 2006 (incorporated by reference to Exhibit 10.8 to Nabors Industries Ltd.’s Form 10-K (File No. 000-49887) filed with the Commission on March 16, 2006).
.7 (+)
Fifth Amendment to Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg dated as of December 31, 2008 (incorporated by reference to Exhibit 10.1 to Nabors Industries Ltd. Form 8-K (File No. 001-32657) filed with the Commission on January 7, 2009).
.8 (+)
Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of April 1, 2009 (incorporated by reference to Exhibit 10.1 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on April 30, 2009).
.9 (+)
First Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of June 29, 2009 (incorporated by reference to Exhibit 10.1 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on July 1, 2009).
.10 (+)
Second Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Eugene M. Isenberg, dated as of December 28, 2009 (incorporated by reference to Exhibit 10.1 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on December 28, 2009).
.11 (+)
Employment Agreement effective October 1, 1996, between Nabors Industries, Inc. and Anthony G. Petrello (incorporated by reference to Exhibit 10.8 to Nabors Industries Inc.’s Form 10-Q (File No. 1-9245) filed May 16, 1997).
.12 (+)
First Amendment to Amended and Restated Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello dated as of June 24, 2002 (incorporated by reference to Exhibit 10.2 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed August 14, 2002).
.13 (+)
Second Amendment to Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello dated as of July 17, 2002 (incorporated by reference to Exhibit 10.3 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed August 14, 2002).
.14 (+)
Third Amendment to Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello dated as of December 28, 2005 (incorporated by reference to Exhibit 10.02 to Nabors Industries Ltd.’s Form 8-K (File No. 000-49887) filed December 28, 2005).
.15 (+)
Fourth Amendment to Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello dated as of December 31, 2008 (incorporated by reference to Exhibit 10.2 to Nabors Industries Ltd. Form 8-K (File No. 001-32657) filed with the Commission on January 7, 2009).
.16 (+)
Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of April 1, 2009 (incorporated by reference to Exhibit 10.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on April 30, 2009).
Exhibit No.
Description
.17 (+)
First Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of June 29, 2009 (incorporated by reference to Exhibit 10.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on July 1, 2009).
.18 (+)
Second Amendment to Executive Employment Agreement between Nabors Industries, Inc., Nabors Industries Ltd. and Anthony G. Petrello, dated as of December 28, 2009 (incorporated by reference to Exhibit 10.2 to Nabors Industries Ltd.’s Form 8-K (File No. 001-32657) filed with the Commission on December 28, 2009).
.19 (+)
Waiver dated as of September 27, 2002, pursuant to Section 9.[c] and Schedule 9.[c] of the Amended Employment Agreement among Nabors Industries, Inc., Nabors Industries Ltd., and Anthony G. Petrello (incorporated by reference to Exhibit 10.1 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed November 14, 2002).
.20 (+)
Nabors Industries, Inc. 1997 Executive Officers Incentive Stock Plan (incorporated by reference to Exhibit 10.20 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed December 29, 1997).
.21 (+)
Nabors Industries, Inc. 1998 Employee Stock Plan (incorporated by reference to Exhibit 10.19 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed March 31, 1999).
.22 (+)
Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.21 to Nabors Industries Inc.’s Form 10-K (File No. 1-9245) filed March 31, 1999).
.23 (+)
Amendment to Nabors Industries, Inc. 1999 Stock Option Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.19 to Nabors Industries Inc.’s Form 10-K (File No. 1-09245) filed March 19, 2002).
.24
Form of Indemnification Agreement entered into between Nabors Industries Ltd. and the directors and executive officers identified in the schedule thereto (incorporated by reference to Exhibit 10.28 to Nabors Industries Ltd.’s Form 10-K (File No. 000-49887) filed with the Commission on March 31, 2003).
.25 (+)
Amended and Restated 1999 Stock Option Plan for Non-Employee Directors (amended on May 2, 2003) (incorporated by reference to Exhibit 10.29 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed with the Commission on May 12, 2003).
.26 (+)
2003 Employee Stock Plan (incorporated by reference to Annex D of Nabors Industries Ltd.’s Notice of 2003 Annual General Meeting of Shareholders and Proxy Statement (File No. 000-49887) filed with the Commission on May 8, 2003).
.27
Purchase and Sale Agreement (Red River) by and among El Paso Production Company and El Paso Production GOM Inc., jointly and severally as Seller and Ramshorn Investments, Inc., as Purchaser dated October 8, 2003 (incorporated by reference to Exhibit 10.23 to Nabors Industries Ltd.’s Form 10-K (File No. 000-49887) filed with the Commission on March 15, 2004).
.28
Purchase and Sale Agreement (USA) between El Paso Production Oil & Gas USA, L.P., as Seller and Ramshorn Investments, Inc., as Purchaser dated October 8, 2003 (incorporated by reference to Exhibit 10.24 to Nabors Industries Ltd.’s Form 10-K (File No. 000-49887) filed with the Commission on March 15, 2004).
.29 (+)
Form of Stock Option Agreement - Isenberg/Petrello (incorporated by reference to Exhibit 10.03 to Nabors Industries Ltd.’s Form 8-K (File No. 000-49887) filed with the Commission on March 2, 2005).
.30 (+)
Form of Stock Option Agreement - Others (incorporated by reference to Exhibit 10.04 to Nabors Industries Ltd.’s Form 8-K (File No. 000-49887) filed with the Commission on March 2, 2005).
.31
First Amendment to 2003 Employee Stock Plan (incorporated by reference to Exhibit 4.1 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed with the Commission on August 3, 2005).
.32
Nabors Industries Ltd. Amended and Restated 2003 Employee Stock Plan (incorporated by reference to Exhibit A of Nabors Industries Ltd.’s Revised Definitive Proxy Statement on Schedule 14A (File No. 001-32657) filed with the Commission on May 4, 2006) (incorporated by reference to Exhibit 99.1 to Nabors Industries Ltd.’s Form S-8 filed with the Commission on November 12, 2008.
Computation of Ratios.*
Exhibit No.
Description
Code of Business Conduct (incorporated by reference to Exhibit 14 to Nabors Industries Ltd.’s Form 10-K (File No. 000-49887) filed with the Commission on March 15, 2004).
Preference Letter of Independent Accountants Regarding Change in Accounting Principle (incorporated by reference to Exhibit 18 to Nabors Industries Ltd.’s Form 10-Q (File No. 000-49887) filed with the Commission on November 2, 2005).
Significant Subsidiaries of Nabors Industries Ltd.*
.1
Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP - Houston.*
.2
Consent of Independent Auditors - Ernst & Young LLP - Houston.*
.1
Rule 13a-14(a)/15d-14(a) Certification, executed by Eugene M. Isenberg, Chairman and Chief Executive Officer of Nabors Industries Ltd.*
.2
Rule 13a-14(a)/15d-14(a) Certification, executed by R. Clark Wood, principal accounting and financial officer of Nabors Industries Ltd.*
.1
Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Eugene M. Isenberg, Chairman and Chief Executive Officer of Nabors Industries Ltd. and R. Clark Wood, principal accounting and financial officer of Nabors Industries Ltd. (furnished herewith).
The following materials from Nabors Industries Ltd.’s Annual Report on Form 10-K for the year ended December 31, 2009, formatted in XBRL (Extensible Business Reporting Language):(i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income (Loss), (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Changes in Equity, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.
*
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: February 26,2010
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Eugene M. Isenberg
Eugene M. Isenberg
Chairman and Chief Executive Officer
February 26, 2010
/s/ James L. Payne
James L. Payne
Director
February 26, 2010
/s/ Anthony G. Petrello
Anthony G. Petrello
Deputy Chairman, President and
Chief Operating Officer
February 26, 2010
/s/ John V. Lombardi
John V. Lombardi
Director
February 26, 2010
/s/ Myron M. Sheinfeld
Myron M. Sheinfeld
Director
February 26, 2010
/s/ Martin J. Whitman
Martin J. Whitman
Director
February 26, 2010
/s/ William T. Comfort
William T. Comfort
Director
February 26, 2010
Schedule Of Valuation And Qualifying Accounts Disclosure
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2009, 2008 and 2007
(1)
Uncollected receivables written-off, net of recoveries.
Schedule Of Financial Statements and Notes for Joint Venture Entity
Consolidated Financial Statements
NFR Energy LLC
Years Ended December 31, 2009 and 2008 and for
the Period From July 27, 2006 (Inception) Through December 31, 2007
Consolidated Financial Statements
NFR Energy LLC
Index
Page(s)
Report of Independent Auditors
Report of Independent Auditors
Audited Consolidated Financial Statements
Consolidated Balance Sheets
Consolidated Statement of Operations
Consolidated Statement of Members’ Capital
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
8-23
Supplemental Oil and Gas Disclosures (Unaudited)
24-28
Report of Independent Auditors
The Members of NFR Energy LLC
In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations, of members’ capital, and of cash flows present fairly, in all material respects, the financial position of NFR Energy LLC and its subsidiaries (the “Company”) at December 31, 2009, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, at December 31, 2009, the Company changed the manner in which its oil and natural gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and natural gas costs.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2010
Report of Independent Auditors
The Members of NFR Energy LLC
We have audited the accompanying consolidated balance sheet of NFR Energy LLC as of December 31, 2008, and the related consolidated statement of operations, changes in members’ capital, and cash flows for the year ended December 31, 2008 and for the period from July 27, 2006 (inception) through December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes 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. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of NFR Energy LLC at December 31, 2008, and the consolidated results of its operations and its cash flows for the year ended December 31, 2008 and for the period from July 27, 2006 (inception) through December 31, 2007, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Houston, Texas
March 27, 2009
NFR Energy LLC
Consolidated Balance Sheets
As of December 31, 2009 and 2008
The accompanying notes are an integral part of these consolidated financial statements.
NFR Energy LLC
Consolidated Statement of Operations
For the Years Ended December 31, 2009 and 2008 and for the Period From July 27, 2006
(Inception) Through December 31, 2007
The accompanying notes are an integral part of these consolidated financial statements.
NFR Energy LLC
Consolidated Statement of Members’ Capital
For the Years Ended December 31, 2009 and 2008 and for the Period From July 27, 2006
(Inception) Through December 31, 2007
The accompanying notes are an integral part of these consolidated financial statements.
NFR Energy LLC
Consolidated Statement of Cash Flows
For the Years Ended December 31, 2009 and 2008 and for the Period From July 27, 2006
(Inception) Through December 31, 2007
The accompanying notes are an integral part of these consolidated financial statements.
NFR Energy LLC
Notes to Consolidated Financial Statements
1.
Organization
NFR Energy LLC (NFR or the Company) was established as a Delaware limited liability company in July 2006. Ramshorn Investments, Inc. (Ramshorn), a wholly owned subsidiary of Nabors Industries Ltd. (Nabors), and First Reserve Corporation (First Reserve) have formed NFR as a joint venture to invest in oil and natural gas exploration opportunities within the onshore U.S. market. Ramshorn and First Reserve each committed $500 million in equity. Operations of the Company commenced in 2007. Nabors is one of the largest land drilling contractors in the world, conducting drilling operations and providing well and other services in the U.S. and internationally. First Reserve was founded in 1983 and is the oldest and largest private equity firm specializing in the energy industry. Additional equity commitments were made by certain members of NFR management and the Company’s board of representatives (the Members).
The Company is operating in one segment and is pursuing development and exploration projects in a variety of forms including operated and non-operated working interests, joint ventures, farm-outs, and acquisitions, including conventional and unconventional resources. NFR is a holding company within which it conducts its operations through, and its operating assets are owned by its subsidiaries.
2.
Significant Accounting Policies
Basis of Presentation
The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (GAAP). The accompanying consolidated financial statements include NFR and its subsidiaries. All significant intercompany transactions have been eliminated.
For comparative purposes, amounts in 2007 and 2008 for noncontrolling interest have been adjusted to reflect the retroactive application of Accounting Standards Codification (ASC) 810 to conform to the current period’s presentation. Certain other reclassifications have been made to prior periods to conform to the current presentation.
Change in Accounting Method
As more fully described below in Property Plant and Equipment, net and in Supplemental Oil and Gas Disclosures to these consolidated financial statements, in January 2010 the Financial Accounting Standard Board (FASB) issued Accounting Standards Update 2010-03 (ASU 2010-03), “Extractive Industries - Oil and Gas”, which conforms the authoritative guidance to the requirements of the new Securities Exchange Commission (SEC) rules released in December 2008 “Modernization of Oil and Gas Reporting” and are effective December 31, 2009. The principle revisions under the new FASB and SEC authoritative guidance include changing the manner in which 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. These changes will result in future amounts of depreciation, depletion and amortization (DD&A) being different from what would have been recorded if the new rules had not been mandated. This change in accounting has been treated in these financial statements as a change in accounting principle that is inseparable from a change in accounting estimate. As noted below, reserves and discounted cash flows prepared using the new rules were used in the calculation of DD&A for the fourth quarter of 2009 and the ceiling test at December 31, 2009.
Cash and Cash Equivalents
All highly liquid investments purchased with an initial maturity of three months or less are considered to be cash equivalents.
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
Concentration of Credit Risk
The Company’s receivables are comprised of oil and natural gas revenue receivables. The amounts are due from a limited number of entities; therefore, the collectability is dependent upon the general economic conditions of a few purchasers. The Company regularly reviews collectability and establishes the allowance for doubtful accounts as necessary using the specific identification method. The receivables are not collateralized.
Inventory
Inventory, which is included in prepaid expenses and other, consists principally of tubular goods, spare parts, and equipment, that is used in our drilling operations. The inventory balance, net of impairments, was $27.1 million and $64.7 million for 2009 and 2008, respectively. Inventory is stated at the lower of weighted-average cost or market. In 2009, the Company revamped its drilling program and moved to a horizontal program due to improved economics versus a vertical program, leaving it with inventory not properly designed for its horizontal drilling activities, in effect, rendering it obsolete. As of December 31, 2009, the total impairment relating to obsolete inventory was $21.3 million, included in Impairments in the consolidated statement of operations.
Oil and Natural Gas Properties and Equipment
The Company uses the full-cost method of accounting for its investment in oil and natural gas properties. Under this method, the Company capitalizes all acquisition, exploration, and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits, and other internal costs directly attributable to these activities. The Company capitalized $3.3 million, $1.5 million and $0.2 million of internal costs in 2009, 2008 and 2007, respectively. Costs associated with production and general corporate activities, however, are expensed in the period incurred. The Company also includes the present value of its dismantlement, restoration, and abandonment costs within the capitalized oil and natural gas property balance (see “Asset Retirement Obligation” below). Unless a significant portion of the Company’s proved reserve quantities is sold (greater than 25%), proceeds from the sale of oil and natural gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.
Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. The properties are reviewed on a quarterly basis for impairment, and if impaired, are reclassified to proved property and included in the ceiling test and depletion calculations.
Under the full cost method of accounting, a ceiling test is performed on a quarterly basis. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A, may not exceed the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheets, using prices based on the prior twelve month period for 2009 and prices in effect at the end of the period for periods ended before December 31, 2009, held flat for the life of production, discounted at 10%, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as accumulated DD&A.
In December 2008, the SEC adopted major revisions to its rules governing oil and natural gas company reporting requirements. The new rules include provisions that permit the use of new technologies to determine proved reserves, and allow companies to disclose their probable and possible reserves to investors in SEC
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
documents outside of the financial statements. The previous rules limited disclosure to only proved reserves. The new rules also require companies that have an audit performed on their reserves to report the independence and qualifications of the reserve auditor, and file the reserve engineer’s reports when a third party reserve engineer is relied upon to prepare reserve estimates. The new rules also require that oil and natural gas reserves be reported and the full cost ceiling value be calculated using an average price based upon the beginning of the month for the prior twelve-month period. The new reporting requirements are effective for reporting periods ending on or after December 31, 2009. The FASB has issued ASU 2010-03 “Extractive Industries - Oil and Gas” to align its rules for oil and natural gas reserves estimation and disclosure requirements with the SEC’s final rule. The impact of these new rules is reflected below in the Supplemental Oil and Gas Disclosures section.
In 2008 and the first quarter of 2009, the Company recognized an impairment of $415.8 million and $155.9 million, respectively, due to a decrease in the period end price reserve estimates, as required under the former SEC rules. In the fourth quarter of 2009, the Company recognized an impairment of $230.1 million, as a result of the change in the reserve estimates defined under the new SEC rules as noted above.
Gathering assets and related facilities, certain other property and equipment, and furniture and fixtures are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from 3 to 30 years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.
The Company’s DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities. The new SEC oil and gas reserves measurement and disclosure rules that went into effect as of December 31, 2009 impacted our DD&A expense for the fourth quarter of 2009, increasing DD&A expense by $1.7 million, or $0.11 per mcfe, for the quarter and year ended December 31, 2009.
Capitalized Interest
The Company capitalizes interest costs to oil and natural gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. During 2009, the Company capitalized $3.7 million of interest expense relating to the second lien term loan facility borrowings (the Second Lien Agreement) (see Note 5). The Company did not have capitalized interest in 2008.
Leases
The Company accounts for leases with escalation clauses and rent holidays on a straight-line basis in accordance with ASC 840, Leases.
Derivative Instruments and Hedging Activities
The Company uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Such derivative instruments, which are placed with major financial institutions who are participants in the Company’s first lien credit facility (the Credit Agreement) (see Note 5) that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps, options, or basis swaps. Substantially, with the exception of basis swaps, all of our natural gas derivative contracts are settled based upon reported New York Mercantile Exchange (NYMEX) prices. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables from separate hedging arrangements with that counterparty. The oil and natural gas reference prices, upon which the commodity derivative contracts are based, reflect
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
various market indices that have a generally high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. Our fixed-price swap, option, and collar agreements are used to fix the sales price for our anticipated future oil and natural gas production. Upon settlement, the Company receives a fixed price for the hedged commodity and receives or pays our counterparty a floating market price, as defined in each instrument. The instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, the Company pays our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to the Company. The Company has designated these swap, option and collar agreements as cash flow hedges.
The Company accounts for these activities pursuant to ASC 815, Derivatives and Hedging (formerly Statements of Financial Accounting Standards (SFAS) 133). This statement establishes accounting and reporting standards requiring that derivative instruments other than those that meet the normal purchases and sales exception, be recorded on the balance sheets as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties). ASC 815 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in accumulated other comprehensive income. Realized gains and losses from the Company’s oil and natural gas cash flow hedges are generally recognized in realized gain or loss on derivative instruments when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current-period earnings as an unrealized gain or loss on derivative instruments in the consolidated statement of operations. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting under ASC 815 will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in accumulated other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in accumulated other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative instruments and the hedged item over time, and any ineffectiveness is immediately reported as unrealized gain or loss on derivative instruments in the consolidated statement of operations.
Deferred Financing Costs
Deferred financing costs of approximately $3.6 million and $1.1 million incurred during 2009 and 2008, respectively, include the costs associated with execution of the Company’s Credit Agreement and Second Lien Agreement, as amended during 2009 and 2008 (see Note 5). Deferred financing costs are being amortized over the life of the notes.
Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Since considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the purchase or refinancing of such instruments.
Asset Retirement Obligation
The Company follows ASC 410, Asset Retirement and Environmental Obligations. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheets and capitalize the present value of the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. The capitalized costs associated with an ARO are included in amortization base for purposes of calculating the ceiling test.
The information below reconciles the value of the asset retirement obligation:
Revenue Recognition
The Company records revenues from the sales of natural gas and crude oil when the production is produced and sold, and also when collectability is ensured. The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of natural gas actually sold by the Company. The Company also reduces revenue for other owners’ natural gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and natural gas reserves. The Company did not have any gas imbalances at December 31, 2009, 2008 or 2007.
Use of Estimates
The preparation of the consolidated financial statements for the Company in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas reserve quantities that are the basis for the calculation of DD&A and impairment of oil and natural gas properties, and timing and costs associated with its retirement obligations.
Income Taxes
The Company is a limited liability company treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of the Company being passed through to the members. As such, no recognition of federal or state income taxes for the Company or its subsidiaries that are organized
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
as limited liability companies have been provided for in the accompanying consolidated financial statements. Any uncertain tax position taken by the members are not uncertain positions of the Company.
In accordance with the operating agreement of NFR, to the extent possible without impairing the Company’s ability to continue to conduct its business and activities, and in order to permit its members to pay taxes on their allocable share of the taxable income of the Company, NFR would be required to make distributions to the members in the amount equal to the estimated tax liability of each member computed as if each member paid income tax at the highest marginal federal and state rate applicable to an individual resident of New York, New York, in the event that taxable income is generated for the members. There was no taxable income and therefore no distributions to the members in 2009 and 2008.
Recent Accounting Pronouncements
In 2006, the FASB issued guidance under the Fair Value Measurements topic of ASC 820 which defined fair value, established a framework for measuring fair value and expanded disclosures about fair value measurements. In February 2008, the FASB delayed the effective date of the new guidance for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We adopted the new guidance for all financial assets and financial liabilities on January 1, 2008 and we adopted the new guidance for all nonfinancial assets and non financial liabilities on January 1, 2009. As this pronouncement is only disclosure in nature, the adoption of this guidance did not have any impact on our financial position or results of operations.
In December 2007, the FASB issued guidance under the Business Combinations topic of ASC 805 to broaden the definition of a business combination to include all transactions or other events in which control of one or more businesses is obtained. Further, the statement establishes principles and requirements for how an acquirer recognizes assets acquired, liabilities assumed and any noncontrolling interests acquired. NFR has adopted this guidance as of January 1, 2009, although, during 2009 there were no such transactions.
In December 2007, the FASB issued guidance under the Consolidations topic of ASC 810 which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest, and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. The new guidance also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. NFR adopted this guidance as of January 1, 2009 which resulted in a retroactive reclassification of its noncontrolling interest in subsidiaries into Members’ Capital.
In March 2008, the FASB issued guidance under the Derivatives and Hedging topic of ASC 815 which requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit risk related contingent features contained within derivatives. The guidance also requires entities to disclose additional information about the amounts and location of derivatives within the financial statements, how the provisions of accounting guidance related to derivatives and hedging have been applied, and the impact that hedges have on an entity’s financial position, financial performance and cash flows. The Company adopted the disclosure requirement beginning January 1, 2009.
In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which is effective January 1, 2010 for reporting 2009 oil and gas reserve information. We adopted the guidance as of December 31, 2009. In January 2010, the FASB issued ASU 2010-03 “Extractive Industries - Oil and Gas” to align its rules for oil and natural gas reserves estimation and disclosure requirements with the SEC’s final rule.
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
In April 2009, the FASB issued new rules to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. The FASB enhanced its guidance to 1) determine fair value when the volume and level of activity for an asset or liability have significantly decreased and 2) identify transactions that are not orderly. The FASB issued guidance under the Financial Instruments topic (820) of the ASC to enhance consistency in financial reporting by increasing the frequency of fair value disclosures. The FASB also issued guidance under the Investments - Debt and Equity Securities topic of ASC 320 to provide additional guidance to create greater clarity and consistency in accounting for and presenting impairment losses on securities. The new guidance was effective for interim and annual periods ending after June 15, 2009. The Company adopted the disclosure requirement changes in 2009.
In August 2009, the FASB issued guidance under the Fair Value Measurements and Disclosures topic of ASC 820 to provide additional guidance on measuring the fair value of liabilities. The new guidance was effective for the Company on October 1, 2009 and did not have an impact on the Company’s financial position or results of operations.
In May 2009, the FASB issued an amendment to the accounting and disclosure requirements to re-map the auditing guidance on subsequent events to the accounting standards with some terminology changes. The amendment also requires additional disclosures which includes the date through which the entity has evaluated subsequent events and whether that evaluation date is the date of issuance or the date the financial statements were available to be issued. The amendment is effective for interim or annual financial periods ending after June 15, 2009 and should be applied prospectively. Management has evaluated subsequent events through February 25, 2010 which represents the date the consolidated financial statements were issued.
In June 2009, the FASB issued the FASB Accounting Standards Codification (“Codification”). The Codification will become the single source for all authoritative GAAP recognized by the FASB to be applied for financial statements issued for the periods ending after September 15, 2009. The Codification does not change GAAP and will not have an effect on the Company’s financial position, results of operations or liquidity.
In June 2009, the FASB also issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities (“VIEs”) under the Consolidation topic of ASC 810. The elimination of the concept of a qualifying special-purpose entity (“QSPE”), removes the exception from applying the consolidation guidance within this amendment. This amendment requires an enterprise to perform a qualitative analysis when determining whether or not it must consolidate a VIE. The amendment also requires an enterprise to continuously reassess whether it must consolidate a risk exposure due to that involvement, as well as how its involvement with VIEs impacts the enterprise’s financial statements. Finally, an enterprise will be required to disclose significant judgments and assumptions used to determine whether or not to consolidate a VIE. This amendment is effective for financial statements issued for fiscal years beginning after November 15, 2009. The Company has determined this standard will not have an impact on its consolidated financial statements.
3.
Significant Customers
During the year ended December 31, 2009, purchases by one company exceeded 10% of the total oil and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP accounted for approximately 28% of total oil and natural gas sales. During the year ended December 31, 2008, purchases by three companies exceeded 10% of the total oil and natural gas revenues of the Company. Purchases by Enbridge Pipeline (East Texas) LP accounted for approximately 33% of total oil and natural gas sales, purchases by Riverbend Gas Gathering Company, LLC, accounted for approximately 11% of total oil and natural gas sales, and purchases by Woodlawn Pipeline Company, Inc., accounted for approximately 10% of total oil and natural gas sales. During the year ended December 31, 2007, purchases by two companies exceeded 10% of the total oil and gas sales of the Company. Purchases by Riverbend Gas Gathering Company, LLC, accounted for
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
approximately 51% of total revenues, and purchases by Woodlawn Pipeline Company, Inc. accounted for approximately 12% of total oil and natural gas sales. The Company believes that the loss of any of the purchasers above would not result in a material adverse effect on its ability to market future oil and natural gas production.
4.
Property Acquisitions
In June 2009, NFR entered into an agreement to acquire the deep rights (Haynesville Shale) with approximately 23,000 net acres in East Texas for a cash purchase price of approximately $60 million as adjusted in accordance with the purchase and sale agreement. The acquisition closed on June 22, 2009. None of the acreage was developed or proved at the time of acquisition.
In August 2008, NFR entered into an agreement to acquire interest in certain producing properties and undeveloped acreage in the Bear Paws Basin, located in north central Montana for a cash purchase price of approximately $221 million as adjusted in accordance with the purchase and sale agreement. The acquisition closed on October 3, 2008, and also included membership interests in each of Lodge Creek Pipelines LLC, Willow Creek Gathering LLC, and Redrock Drilling LLC, which collectively provide compression, transportation, gathering, and drilling services to properties in the Bear Paws Basin acquired by NFR.
In July 2008, NFR entered into an agreement and closed the acquisition to acquire interests in certain producing properties and oil, natural gas, and mineral leases and other mineral rights in East Texas for a cash purchase price of approximately $34 million.
In April 2008, NFR entered into a carry and earning agreement covering approximately 47,000 gross acres of oil, natural gas, and mineral leases in East Texas. In accordance with the carry and earnings agreement, NFR is committed to drill a certain number of wells between April 1, 2008 and December 31, 2012. The Company will pay disproportionate share of drilling costs in exchange for earning an interest in the respective acreage.
In connection with the carry and earnings agreement, NFR executed a $72 million performance bond. The bond will be reduced by a certain amount upon the completion of each well under the agreement.
In November 2007, NFR entered into an agreement to acquire interests in certain producing properties and undeveloped acreage in East Texas for a cash purchase price of approximately $410 million as adjusted in accordance with the purchase and sale agreement. The acquisition closed on December 31, 2007.
In October 2007, NFR entered into an agreement to acquire interests in certain producing properties and undeveloped acreage in East Texas for a cash purchase price of approximately $100 million as adjusted in accordance with the purchase and sale agreement. The acquisition closed on November 20, 2007.
In October 2007, the Company signed a lease purchase and exploration agreement to obtain an undivided 60% working interest in certain acreage located in East Texas in exchange for total consideration of approximately $2 million in cash and disproportionate share of drilling costs up to $2.1 million. NFR satisfied the obligation during 2008.
On August 24, 2007, Ramshorn assigned all of its rights, duties, obligations, and liabilities under its agreement with Behm Energy, Inc. (Behm), to NFR Williston Basin LLC, a subsidiary of NFR. The total consideration of $11.4 million paid by the Company consisted of $5.7 million of cash and $5.7 million treated as Ramshorn’s capital contribution to NFR. The acquisition included a 50% working interest in oil and natural gas leases covering approximately 80,000 acres (40,000 net acres to NFR) and seismic data for the same area. In 2008, NFR agreed to sell its operatorship rights to Hess Corporation for approximately $10 million, which reduced the Company’s basis in the assets. As a result of this transaction, NFR’s interest in the assets has not changed. Additionally, during 2008 NFR drilled an exploratory well for $1.7 million, which was declared a dry hole and as such included in proved properties as of December 31, 2008.
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
In July 2007, NFR entered into an agreement to participate in drilling of 30 wells in the Uinta Basin of Utah. NFR paid approximately $19 million at signing of the agreement representing its share of Program Wells costs already incurred and committed to spending approximately $24 million for its share of remaining Program Wells costs.
Additionally, during 2009 and 2008, NFR acquired leases for acreage in the same areas as the acquisitions listed above for the $6.3 million and $38.4 million for each of the respective years.
Acquired properties are recorded at their fair value. In determining the fair value of the proved and unproved properties, the Company prepares estimates of oil and natural gas reserves. The Company estimates future prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing unproved reserves, probable and possible reserves are reduced by additional risk-weighting factors.
The results of each of the acquisitions are included in the accompanying consolidated statement of operations since the respective date of purchase.
Total costs incurred for property acquisitions for 2009 and 2008 were approximately $69.0 million and $254.8 million respectively (excluding related asset retirement costs), of which approximately $62.7 million and $42.8 million related to unproved properties. The Company incurred $252.8 million and $211.9 million in development costs, for 2009 and 2008 respectively. All development related costs were included in proved properties. The Company incurred unsuccessful exploration costs of $2.3 million and $1.7 million in 2009 and 2008, respectively.
The unproved costs associated with the Company’s drilling projects will be transferred to proved properties as the wells are drilled or impaired.
5.
Long-Term Debt
On November 30, 2007, the Company entered into a first lien credit agreement with a syndication of banks, with BNP Paribas as administrative agent for the syndicators. On October 28, 2009, the Company amended and restated the Credit Agreement.
Borrowings made under the Credit Agreement are guaranteed by the first priority perfected liens and security interest on substantially all assets of NFR and its subsidiaries and pledge of 100% of NFR’s ownership of stock of subsidiaries.
The aggregate commitment under the Credit Agreement is $400 million, subject to a borrowing base that was set at $250 million at December 31, 2009, and is redetermined semiannually or at the Company’s request. The Company’s most recent redetermination was October 28, 2009. Borrowings under the Credit Agreement totaled $214.5 million and $188.5 million as of December 31, 2009 and 2008 respectively. The amount borrowed under the Credit Agreement is due in full on November 30, 2011. There is no penalty for early repayment of debt.
In addition to the Credit Agreement, NFR entered into a second lien term loan facility for $50 million on April 28, 2009. As of December 31, 2009, the outstanding balance under our Second Lien Agreement was $50 million, with accrued interest at floating rates in accordance with the Credit Agreement. The average annual interest rate for our term loan borrowings for the twelve months ended December 31, 2009 was 4%, plus an applicable margin of 1,000 basis points, or 14%.
As discussed in Note 13, on February 12, 2010 the Company issued $200 million of senior unsecured notes. The proceeds of the issuance were used to repay the Second Lien Agreement in full and to repay a
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
portion of the outstanding indebtedness under the Credit Agreement. Additionally, the terms of the Credit Agreement which are discussed below were amended.
Interest on borrowings under the Credit Agreement accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (ABR). The Eurodollar rate is calculated as London Interbank Offered Rate (LIBOR) plus an applicable margin that varies from 2.25% (for periods in which NFR has utilized less than 50% of the borrowing base) to 3.00% (for periods in which NFR has utilized equal to or greater than 90% of the borrowing base). The ABR is calculated as the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 1/2%, or (c) Eurodollar rate on such day (or if such day is not a business day, the immediately preceding business day) plus 1.5%. The Company elects the basis of the interest rate at the time of each borrowing. In addition, NFR pays a commitment fee under the Credit Agreement (quarterly in arrears) for the amount that the aggregate commitments exceed borrowings under the agreement. The commitment fee varies from 0.375% to 0.500% based on the percentage of the borrowing base utilized.
Under the Credit Agreement, the Company may request letters of credit, provided that the borrowing base is not exceeded or will not be exceeded as a result of issuance of the letter of credit. There were no outstanding letters of credit on December 31, 2009.
The Credit Agreement requires the Company to comply with certain financial covenants to maintain (a) a Current Ratio, defined as a ratio of consolidated current assets (including the unused amount of the total commitments under the Credit Agreement, but excluding noncash assets under ASC 815 to consolidated current liabilities (excluding noncash obligations under ASC 815 and the current maturities under the Credit Agreement), determined at the end of each quarter, of not less than 1.0 to 1.0; (b) an Interest Coverage ratio at the end of each quarter defined as a ratio of EBITDA (as such terms are defined in the Credit Agreement) for the period of four fiscal quarters then ending to interest expense for such period of not less than 2.5 to 1.0; and (c) ratio of debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to be greater than 3.75 to 1.0. The Second Lien Agreement requires a ratio of debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to be greater than 4.0 to 1.0. In addition, the Credit Agreement contains covenants that restrict the Company’s ability to incur other indebtedness, create liens, or sell its assets; merge with other entities; pay dividends; and make certain investments. At December 31, 2009 and 2008, NFR was in compliance with its financial debt covenants under the Credit and Second Lien Agreements. See Note 13 for changes in financial covenants as the result of an amendment to the Credit Agreement subsequent to year end.
6.
Members’ Capital
The Company is authorized to issue two classes of members units to be designated as “Common Units” and “Incentive Units.” The Units are not represented by certificates. All Common Units are issued at a price equal to $1,000 per unit. Each common unit holder will have one vote on any matter put before the Members.
Incentive units
The Incentive Units of the Company represent “profits interest” in the Company and are subject to vesting, forfeiture, and other provisions that set forth in grants evidencing their issuance. The incentive unit holders have no voting power. In accordance with its operating agreement, the Company is authorized to issue 10,000 of Incentive Units. As of December 31, 2009, 2008 and 2007, the Company has issued 7,297, 6,585 and 3,782 Incentive Units, respectively.
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
7.
Statement of Cash Flows
During the year ended December 31, 2009, the Company’s noncash investing and financing activities consisted of the following transactions:
•
Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $1.1 million.
•
Additions to oil and natural gas properties of $36.6 million, included in accrued exploration and development.
During the year ended December 31, 2008, the Company’s noncash investing and financing activities consisted of the following transactions:
•
Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $4.9 million.
•
Additions to oil and natural gas properties of $21.1 million, included in accrued exploration and development.
For the period from July 27, 2006 (inception) through December 31, 2007, the Company’s noncash investing and financing activities consisted of the following transactions:
•
Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $1.6 million.
•
Additions to oil and natural gas properties of $8.8 million, of which $3.1 million is included in accrued exploration and development and $5.7 million represents a noncash capital contribution.
NFR paid $11.8 million and $5.5 million for interest during 2009 and 2008, respectively. There was no interest for the period from July 27, 2006 (inception) through December 31, 2007.
8.
Derivative Financial Instruments
The Company is exposed to risks associated with unfavorable changes in the market price of natural gas as a result of the forecasted sale of its production and uses derivative instruments to hedge or reduce its exposure to certain of these risks. During 2009, a portion of commodity derivative instruments were designated as cash flow hedges and were subject to cash flow hedge accounting under ASC 815. For the remaining derivative instruments, the Company did not elect hedge accounting for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative instruments in the consolidated statement of operations.
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
The following swaps, put options, basis swaps and costless collars were outstanding with associated notional volumes and contracted swap, floor, and ceiling prices that represent hedge weighted average prices for the index specified as of December 31, 2009:
(1)
Basis swaps settle based on NYMEX pricing minus a differencial, which is then compared to Inside Federal Energy Regulatory Commission (FERC) for the index on which volumes are being hedged.
For our energy commodity derivative instruments that were designated as cash flow hedges, the portion of the change in the value of derivative instruments that is effective in offsetting changes in expected cash flows (the effective portion) is reported as a component of accumulated other comprehensive income, but only to the extent that they can later offset the undesired changes in expected cash flows during the period in which the hedged cash flows affect earnings. To the contrary, the portion of the change in the value of derivative instruments that is not effective in offsetting undesired changes in expected cash flows (the ineffective portion), as well as any component excluded from the assessment of the effectiveness of the derivative instruments, is required to be recognized currently in earnings. The Company excludes time value associated with put options, swaps and costless collars from the assessment of effectiveness.
The Company recorded a short-term and a long-term derivative asset of $30.8 million and $28.1 million, respectively, related to the fair value of the hedging instrument’s prices on hedged volumes as of December 31, 2009 after application of ASC 820, Fair Value Measurements.
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
The table below provides data about the carrying values of derivatives that are designated as cash flow hedge instruments as of December 31, 2009.
The following table summarizes the cash flow hedge gains and losses and their locations on the Consolidated Balance Sheet as of December 31, 2009 and Consolidated Statement of Operations for the year ended December 31, 2009:
Amount of Gain
Amount of Gain (Loss)
Recognized in
Location of Gain
Amount of Gain
Recognized in Income
Derivatives in Cash
Other
Reclassified from
Reclassified from
(Ineffective Portion and
Flow Helging
Comprehensive
Accumulated OCI
Accumulated OCI into
Location of Loss on
Amount Excluded from
Relationships
Income (OCI)
into Income
Income
Ineffective Hedges
Effectiveness Testing)
(In thousands)
Derivative Instruments
$
75,363
Realized gain on derivative instruments
$
61,809
Unrealized loss on derivative instruments
$
(2,497
)
Total
$
75,363
$
61,809
$
(2,497
)
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
The following table summarizes the location in the Consolidated Statement of Operations and amounts gains and losses on derivative instruments that do not qualify for hedge accounting for the year ended December 31, 2009:
Recognized in
Income
Derivatives Not
on Derivatives for the
Designated as Hedging
Year Ended
Instruments
Location of Gain Recognized in Income on Derivatives
December 31, 2009
(In thousands)
Derivative Instruments
Unrealized gain on Derivative Instruments
$
The consolidated accumulated other comprehensive income balance was $54.5 million as of December 31, 2009, and $40.9 million as of December 31, 2008. Approximately $17.6 million of this total accumulated gain associated with commodity price risk management activities as of December 31, 2009, is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur.)
None of the derivative instruments were designated as hedges in 2007.
9.
Fair Value Measurements
In September 2006, the FASB issued ASC 820, Fair Value Measurement, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of ASC 820 are effective January 1, 2008. The FASB has also issued 820-10-55, which delayed the effective date of ASC 820 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company adopted ASC 820 as discussed above and elected to defer the application thereof to nonfinancial assets and liabilities in accordance with 820-10-55 until January 1, 2009.
As discussed in Note 8, the Company utilizes derivative instruments to hedge against the variability in cash flows associated with the forecasted sale of its anticipated future natural gas production. The Company generally hedges a substantial, but varying, portion of anticipated natural gas production for the next 12 to 60 months. These derivatives are carried at fair value on the consolidated balance sheets.
As defined in ASC 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes 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. The Company classifies fair value balances based on the observability of those inputs. ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).
The three levels of the fair value hierarchy defined by ASC 820 are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, basis swaps, options, and collars.
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
The following table sets forth, by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2009 and 2008. As required by ASC 820, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Recurring Fair Value Measures
As of December 31,
Level 1
Level 2
Level 3
Total
(In millions)
Derivative Assets, net
$
-
$
45.9
$
-
$
45.9
$
-
$
58.2
$
-
$
58.2
Derivatives listed above include commodity swaps, basis swaps, options, and collars that are carried at fair value. The fair value amounts on the consolidated balance sheets associated with the Company’s derivatives resulted from Level 2 fair value methodologies, that is, the Company is able to value the assets and liabilities based on observable market data for similar instruments.
This observable data includes the forward curve for commodity prices and interest rates based on quoted markets prices and prospective volatility factors related to changes in commodity prices, as well as the impact of our non-performance risk of the counterparties which is derived using credit default swap values.
10.
Related-Party Transactions
NFR paid $42.2 million and $16.1 million during 2009 and 2008 respectively to Nabors and its subsidiaries for drilling and other oilfield services.
NFR paid $0.8 million and $1.2 million during 2009 and 2008, respectively, to Smith International, Inc. (Smith), an oil and natural gas services company, for services provided. A member of the Company’s board of representatives is the Chief Executive Officer, President, and Chief Operating Officer of Smith.
No payments were made to related parties in 2007.
11.
Commitments
The Company leases approximately 36,500 square feet of office space in downtown Houston, Texas, under a lease, which terminates on May 1, 2013. The average rent for this space over the life of the lease is approximately $0.6 million per year. The Company has an option to extend its lease term for additional 60 months. As of December 31, 2009, total future commitments are $2.0 million.
NFR Energy LLC
Notes to Consolidated Financial Statements - (Continued)
In December 2008, the Company signed a lease agreement to lease approximately 11,000 square feet of office space in downtown Denver, Colorado. The lease term began on June 1, 2009, and terminates on August 31, 2014. The average rent for this space over the life of the lease is approximately $0.2 million per year. The Company has two options to extend its lease term for additional 60 months each time. As of December 31, 2009, total future commitments are $1.0 million.
As part of our ongoing operations, we have contracted with affiliates of Nabors to secure drilling rigs for drilling the oil and natural gas well activity we expect to undertake. As of December 31, 2009, total future commitments are $156.1 million.
As of December 31, 2009, future minimum lease payments were as follows (in thousands):
Rent expense was approximately $1.1 million for the year ended December 31, 2009, $0.6 million for the year ended December 31, 2008 and $0.1 million for the period from July 27, 2006 (inception) through December 31, 2007.
In connection with the Carry and Earning Agreement for the East Texas properties described in Note 4, the Company executed a $72 million performance bond. As of December 31, 2009, the face amount of the performance bond had been reduced to approximately $20 million.
As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not pay such commitments, the acreage positions or wells may be lost.
12.
Employee Benefit Plans
The Company co-sponsors a 401(k) tax deferred savings plan (the Plan) and makes it available to employees. The Plan is a defined contribution plan, and the Company may make discretionary matching contributions of up to 6% of each participating employee’s compensation to the Plan. The contributions made by the Company totaled approximately $502,000 during the year ended December 31, 2009, $220,000 during the year ended December 31, 2008 and $32,000 for the period from July 27, 2006 (inception) through December 31, 2007.
13.
Subsequent Events
On February 12, 2010, the Company issued $200 million of senior unsecured notes. The notes were priced at 98.733% of par, have a coupon of 9.75%, and yield 10.00%. The notes are non-callable for four years and are due in full in 2017. The Company used the proceeds from the offering to repay the Second Lien Agreement in full and to repay a portion of the outstanding indebtedness under the Credit Agreement. As a result of repaying the Second Lien Agreement, the Company will expense associated unamortized debt issuance costs of $1.9 million in 2010.
In conjunction with the issuance of the notes, the Credit Agreement terms were amended by extending the maturity to February 12, 2014 and by modifying the existing debt to EBITDA covenant ratio to be 4.5 to 1.0, 4.25 to 1.0 and 4.0 to 1.0 for the years ending December 31, 2011, 2012 and 2013, respectively.
NFR Energy LLC
Supplemental Oil and Gas Disclosure (Unaudited)
The following supplemental information regarding our natural gas and oil producing activities is presented in accordance with the requirements of Section 932-235-50 of the ASC.
Costs Incurred and Capitalized Costs
The costs incurred in oil and natural gas acquisitions, exploration and development activities were as follows:
(1)
Property acquisition and development costs for the year ended December 31, 2008 differ from the amounts reflected in the notes to our audited consolidated financial statements due in part to the inclusion in the amount shown in the notes of the acquisition costs related to the acquisition of certain gathering assets and to the recharacterization as development costs of a portion of the costs originally characterized as property acquisition costs. The Company reclassified and recharacterized these cost to reflect the total cost incurred for oil and gas producing activities during the period, versus costs relating solely to acquisitions that closed during the period, which are disclosed in Note 4.
Results of Operations
Results of operations for oil and natural gas producing activities, which exclude processing and other activities, corporate general and administrative expenses, and straight-line depreciation expense on non oil and gas assets, were as follows:
NFR Energy LLC
Supplemental Oil and Gas Disclosure (Unaudited) - (Continued)
Oil and Natural Gas Reserves and Related Financial Data
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.
The following tables set forth our total proved reserves and the changes in our total proved reserves. These reserve estimates are based in part on reports prepared by Miller and Lents, Ltd. (Miller and Lents), independent petroleum engineers, utilizing data compiled by us. In preparing its reports, Miller and Lents evaluated properties representing all of our proved reserves at December 31, 2009 and approximately 94% of our proved reserves at December 31, 2008 and December 31, 2007. Our proved reserves are located onshore in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved reserves are the estimated quantities of natural gas, natural gas liquids and oil that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in future years from known oil and natural gas reservoirs under existing economic conditions, operating methods and government regulations at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves as of December 31, 2009 were estimated using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve months as required under new SEC rules effective for fiscal years ending on or after that date. Future prices actually received may materially differ from current prices or the prices used in making the reserve estimates. With respect to future development costs and operating expenses, the Company derived estimates using the current cost environment at year end, which is consistent with both the current and former SEC rules. The new SEC rules also contain new reserve definitions and permit the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. As reflected in the table below, approximately 472.4 Bcfe of the increase in our total estimated proved reserves from December 31, 2008 to December 31, 2009 relates to the application of the new SEC rules discussed herein.
NFR Energy LLC
Supplemental Oil and Gas Disclosure (Unaudited) - (Continued)
(1)
Primarily due to the application of revised definitions contained in the SEC’s new rules, particularly the definition of proved oil and natural gas reserves, which now permits the addition of undrilled locations beyond immediate offsets of producing wells that are supported by a determination, with reasonable certainty, of reservoir continuity.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information was developed utilizing procedures prescribed by ASC 932, Disclosures about Oil and Gas Producing Activities. The information is based on estimates prepared by our petroleum
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engineering staff. The “standardized measure of discounted future net cash flows” should not be viewed as representative of the current value of our proved oil and natural gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.
In reviewing the information that follows, we believe that the following factors should be taken into account:
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future costs and sales prices will probably differ from those required to be used in these calculations;
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actual production rates for future periods may vary significantly from the rates assumed in the calculations;
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a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and natural gas revenues; and
Under the standardized measure, future cash inflows were estimated by using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for 2009 and by using year-end oil and natural gas prices applicable to our reserves to the estimated future production of year-end proved reserves for 2008 and prior periods. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Use of a 10% discount rate and year-end prices and costs are required by ASC 932.
In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.
The standardized measure of discounted future net cash flows from our estimated proved oil and natural gas reserves follows:
(1)
The high effective discount factor is attributable to the negative present value factor, which is due to the addition of proved undeveloped properties that require a large amount of development costs. Additionally, these costs are weighted heavily in the first five years.
NFR Energy LLC
Supplemental Oil and Gas Disclosure (Unaudited) - (Continued)
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas and crude oil reserves follows:
(1)
The negative value of additions is attributable to a large number of wells that were proved as a result of the new SEC rules. Consistent with the new SEC rules, the Company only adds proved undeveloped reserves that will be developed within a five year time horizon. As a result, a large of amount of future development costs are included in the present value calculation. Additionally, these costs are not discounted as heavily as costs in the later years, thus causing the total present value to be negative.