ROWAN COMPANIES INC
ITEM 1. BUSINESS
Rowan Companies, Inc. (“Rowan” or the “Company”) is a major provider of international and domestic contract drilling services. Rowan also owns and operates a manufacturing division that produces equipment for the drilling, mining and timber industries. Organized in 1947 as a Delaware corporation under the name Rowan Drilling Company, Inc., Rowan is a successor to a contract drilling business conducted since 1923.
Information with respect to Rowan’s revenues, operating income, assets, and other financial information relating to the Company’s business segments and geographic areas of operation is presented in Note 10 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.rowancompanies.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
DRILLING OPERATIONS
Rowan provides contract drilling services utilizing a fleet of 23 self-elevating mobile offshore drilling platforms (“jack-up rigs”) and 29 marketed deep-well land drilling rigs. Our primary focus is on high-specification and premium jack-up rigs, which our customers use for offshore exploratory and development drilling and, in certain areas, well workover operations.
We conduct offshore drilling operations in various markets throughout the world, and onshore drilling operations in the United States. At February 16, 2010, we had nine offshore rigs in the Middle East, eight in the U.S. Gulf of Mexico, two in the North Sea, and one each offshore West Africa, Eastern Canada, Mexico and Egypt. At that date, we had twenty-one marketed land rigs in Texas, six in Louisiana, and one each in Oklahoma and Alaska.
During 2009, our drilling operations generated revenues of $1,214.9 million and income from operations of $472.1 million, compared with $1,451.6 million and $670.1 million, respectively, in 2008. Our results of operations are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.
Offshore Operations
Rowan operates large jack-up rigs capable of drilling depths up to 35,000 feet in maximum water depths ranging from 250 to 550 feet, depending on rig size and location. Our jack-ups are designed with a floating hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered until they penetrate the ocean floor, and the hull is jacked up to the elevation required to drill the well. Each of our jack-ups was designed and built by our manufacturing division.
We have aggressively grown our jack-up fleet over the past decade to better serve the needs of the industry for drilling in harsher environments, and we are particularly well positioned to serve the niche market for high-pressure/high-temperature (“HPHT”) wells. All of our rigs feature top-drive drilling systems, solids-control equipment, AC power and mud pumps that greatly accelerate the drilling process. Most have been designed or upgraded to handle the toughest environmental criteria. At February 16, 2010, our offshore drilling fleet was comprised of the following:
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Eleven high-specification cantilever jack-up rigs, including one harsh-environment Gorilla class rig, four enhanced Super Gorilla class rigs, four Tarzan Class rigs and two 240C class rigs, as described below. We use the term “high-specification” to describe the most capable jack-ups; i.e., those having a hook-load capacity of at least two million pounds to handle the casing strings required to drill beyond 30,000 feet.
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Nine premium cantilever jack-up rigs, including two Gorilla class rigs and seven 116-C class rigs. We use the term “premium jack-ups” to denote independent-leg cantilever rigs that can operate in at least 300 feet of water in benign environments.
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Three conventional or slot jack-up rigs with skid-off capability, as described below.
Cantilever jack-ups can extend a portion of the sub-structure containing the drilling equipment over fixed production platforms to perform drilling operations with a minimum of interruption to production. Our conventional jack-ups use “skid-off” technology, which allows the rig floor drilling equipment to be “skidded” out over the top of a fixed platform, enabling these slot type jack-up rigs to be used on drilling assignments that would otherwise require a cantilever jack-up or platform rig.
Our Gorilla class rigs, designed in the early 1980s as a heavier-duty class of jack-up rig, are capable of operating in water depths up to 328 feet in extreme hostile environments (winds up to 100 miles per hour and seas up to 90 feet) such as the North Sea and offshore eastern Canada. Gorillas II and III can drill to 30,000 feet, and Gorilla IV is equipped to reach 35,000 feet.
Our four Super Gorilla class rigs were delivered during the period from 1998 to 2003 and are enhanced versions of our Gorilla class rigs featuring simultaneous drilling and production capabilities. They can operate year-round in 400 feet of water south of the 61st parallel in the North Sea, within the worst-case combination of 100-year storm criteria for waves, wave periods, winds and currents. The Bob Palmer (formerly the Gorilla VIII), is an enhanced version of the Super Gorilla class jack-up designated a Super Gorilla XL. With 713 feet of leg, 139 feet more than the Super Gorillas, and 30% larger spud cans, this rig can operate in water depths to 550 feet in relatively benign environments like the Gulf of Mexico or in water depths to 400 feet in the hostile environments of the North Sea and offshore eastern Canada and West Africa.
Our four Tarzan Class rigs were specifically designed for deep-well, HPHT drilling in up to 300 feet of water in benign environments.
Our 240C class rigs are designed for HPHT drilling in water depths to 400 feet. Construction of the first 240C, the Rowan-Mississippi, was completed in the fourth quarter of 2008, and the second rig, the Ralph Coffman, was delivered in the fourth quarter of 2009. The third 240C jack-up, the Joe Douglas, is currently under construction with delivery expected in the third quarter of 2011.
Additionally, we have four EXL class rigs under construction at the Keppel AmFELS, Inc. (“Keppel”) shipyard in Brownsville, Texas, with expected deliveries of three rigs in 2010 and one in early 2012. Our EXL class rigs will employ the latest technology to enable drilling of HPHT and extended-reach wells in most of the prominent jack-up markets throughout the world, and will be equipped with the hook-load and horsepower required to efficiently drill beyond 30,000 feet.
Onshore Operations
In addition to our offshore drilling operations, we provide drilling equipment and personnel on a contract basis for exploration and development of onshore areas. At February 16, 2010, our onshore fleet consisted of 29 marketed deep-well land rigs, 28 of which are 2,000 HP or greater and capable of drilling wells to 35,000 feet, and 19 of which are AC drive. These premium specifications are ideal for targeting shale and gas plays such as the Haynesville and Deep Bossier in Louisiana and Texas.
See Item 2, “Properties,” of this Form 10-K for additional information with respect to the rigs in our fleets.
Contracts
Our drilling contracts generally provide for a fixed amount of compensation per day, known as the day rate, and are usually obtained either through competitive bidding or individual negotiations.
Our drilling contracts are either “well-to-well,” “multiple-well” or for a fixed term generally ranging from one month to four years. Well-to-well contracts are cancelable by either party upon completion of drilling. Fixed-term contracts usually provide for termination by either party if drilling operations are suspended for extended periods as a result of events of force majeure. While many fixed-term contracts are for relatively short periods, some can continue for periods longer than the original terms, and well-to-well contracts can be extended over multiple series of wells. Many drilling contracts contain renewal or extension provisions exercisable at the option of the customer at mutually-agreeable rates and, in certain cases, such option rates are agreed-upon at the outset of the contract. Many of our drilling contracts provide for separate lump-sum payments for rig mobilization and demobilization, for which we recognize the revenues and related expenses over the primary contract term, and for reimbursement of certain other costs, for which we recognize both revenues and expenses when incurred. Our contracts for work in foreign countries generally provide for payment in United States dollars except for minimal amounts required to meet local expenses.
A number of factors affect our ability to obtain contracts, both onshore and offshore, at profitable rates within a given area. Such factors, which are detailed below under “Competition,” include the location and availability of competitive equipment, the suitability of equipment for the project, comparative operating cost of the equipment, competence of drilling personnel and other competitive factors. Profitability may also depend on receiving adequate compensation for the cost of moving equipment to drilling locations.
During periods of weak demand and declining day rates, we have historically accepted lower rates in an attempt to keep our rigs working and to mitigate the substantial costs of maintaining and reactivating stacked rigs. In periods of strong demand and rising day rates, we strive to maintain a mix of short- and long-term contracts to enable us to both take advantage of potential higher future rates (and cover potential higher operating costs) as well as provide down-side protection when markets inevitably decline. As of February 16, 2010, ten of our offshore rigs were operating under drilling contracts estimated to complete in 2010, eight had contracts estimated to complete in 2011, one had a contract estimated to complete in 2012, and four were without contracts. The five rigs currently under construction are expected to be delivered over the period from early 2010 through early 2012. We have a contract for the use of one rig, and the remaining four are not yet contracted.
Our drilling revenue backlog was estimated to be approximately $1.3 billion at February 16, 2010, down from approximately $1.7 billion one year earlier.
Competition
The contract drilling industry is highly competitive, and success in obtaining contracts involves many factors, including price, equipment capability, operating and safety performance and reputation. We believe that Rowan competes favorably with respect to all of these factors.
Currently, we compete with several offshore drilling contractors that together have close to 700 mobile rigs available worldwide, including approximately 460 jack-ups. We estimate that 26 or less than 6% of the world’s existing jack-up fleet are high-specification, including the eleven rigs that we own. Sixty-one additional jack-up rigs are under construction for delivery through 2012, eleven of which are considered high-specification, including all five of our rigs.
Our onshore operations compete with several domestic drilling contractors that have approximately 250 deep-well land rigs available. Based on the number of rigs as tabulated by ODS-Petrodata, Rowan is the seventh largest offshore drilling contractor in the world and the fifth largest jack-up rig operator. Some of our competitors have greater financial and other resources and may be more able to make technological improvements to existing equipment or replace equipment that becomes obsolete. In addition, those contractors with larger and more diversified drilling fleets may be better positioned to withstand unfavorable market conditions.
We market our drilling services by contacting present and potential customers, including large international energy companies, many smaller energy companies and foreign government-owned or -controlled energy companies. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K for a discussion of current and anticipated industry conditions and their impact on our operations.
Regulations and Hazards
Rowan’s drilling operations are subject to many hazards, including blowouts, well fires and severe weather, which could cause personal injury, suspend drilling operations, seriously damage or destroy equipment, and cause substantial damage to producing formations and the surrounding environment. Offshore drilling rigs are also subject to marine hazards, either while on site or under tow, such as vessel capsizing, collision or grounding. Raising and lowering the legs of jack-up rigs into the ocean floor requires skillful handling to avoid capsizing or other serious damage. Drilling into high-pressure formations is a complex process and problems can frequently occur.
Much of the Gulf of Mexico, the North Sea and offshore eastern Canada frequently experience hurricanes or other extreme weather conditions. Many of our offshore drilling rigs are located in these areas and are thus subject to potential damage or destruction by such conditions. Damage caused by high winds and turbulent seas could cause us to suspend operations on drilling rigs for significant periods of time until the damage can be repaired. Additionally, even if our drilling rigs are not damaged or lost in such conditions, we may still experience disruptions in our operations due to damage to our customer’s platforms and other related facilities in these areas.
Hurricanes (or “windstorms”) have caused tremendous damage to drilling and production equipment and facilities throughout the Gulf Coast in recent years, and insurance companies have incurred substantial losses as a result. Accordingly, insurance companies have substantially reduced the levels of windstorm coverage available and have dramatically increased the cost of such coverage. Coverage for potential liabilities to third parties associated with property damage and personal injuries, as well as coverage for environmental liabilities and removal of wreckage and debris associated with hurricane losses has also been limited. Any ongoing change in weather patterns or climate could further increase costs and reduce availability of insurance coverage for windstorms.
Rowan suffered a significant loss of prospective revenues and has incurred significant claims for removal of wreckage from the total destruction of six rigs in four separate storms from 2002 through 2008. Due to the increased cost and reduced availability of coverage as discussed above, in 2009 we decided to discontinue windstorm physical damage coverage on four of our older, lower-specification jack-up rigs, and our coverage for removal of wreckage is subject to a $100 million per occurrence deductible. Currently, our windstorm physical damage coverage is subject to a $50 million per occurrence deductible with an annual aggregate limit of $150 million and covers only the Gorilla II, the Bob Palmer and the Rowan-Mississippi.
We seek to maintain adequate insurance coverage for worker’s compensation, maritime employer’s liability, automobile liability and various other types of exposures customarily encountered in our operations. Certain of our liability insurance policies specifically exclude coverage for fines, penalties and punitive or exemplary damages. We can give no assurance that insurance coverage will continue to be available at rates considered reasonable, that self-insured amounts or deductibles will not increase or that certain types of coverage will be available at any cost. We renew our insurance policies annually, and the level of coverage that we maintain is reevaluated each year based on a variety of factors. We can provide no assurance that we will maintain future coverage at current levels.
Foreign operations are often subject to political, economic and other uncertainties not encountered in domestic operations, such as arbitrary taxation policies, onerous customs restrictions, unstable currencies, exchange rate fluctuations and the risk of asset expropriation due to foreign sovereignty over operating areas. We attempt to minimize the risk of currency fluctuations by generally contracting for payment in U.S. dollars and limit our holdings of foreign currencies to amounts needed to cover local expenditures. As our international operations have grown in recent years, exchange rate and other risks of operating internationally have become more significant.
Many aspects of our operations are subject to governmental regulation in the areas of equipping and operating vessels, drilling practices and methods, and taxation. In addition, the United States and other countries in which we operate have regulations relating to environmental protection and pollution control. Rowan could become liable for damages resulting from pollution of offshore waters and, under United States regulations, we must document financial responsibility. Generally, we are indemnified under our drilling contracts for pollution damages, except in certain cases of pollution emanating above the surface of land or water from spills of pollutants, or pollutants emanating from our drilling rigs. We can provide no assurance, however, that such indemnification provisions can be enforced.
During 2004, we learned that the Environmental and Natural Resources Division, Environmental Crimes Section of the U.S. Department of Justice (“DOJ”) had begun conducting a criminal investigation of environmental matters involving several of our offshore drilling rigs that at various times operated in the Gulf of Mexico. In late 2007, we entered into a plea agreement with the DOJ, as amended, under which we paid fines and made community service payments totaling $9 million and agreed to be subject to unsupervised probation for a period of three years. During this period we must ensure that we commit no further criminal violations of federal, state, or local laws or regulations and must also continue to implement our comprehensive Environmental Management System Plan. Concurrent with the plea agreement, the Environmental Protection Agency approved a compliance agreement with us which, among other things, contains a certification that the conditions giving rise to the violations to which we entered guilty pleas have been corrected. We believe that if we fully comply with the terms of the compliance agreement, we will not be suspended or debarred from entering into or participating in contracts with the U.S. Government or any of its agencies.
We believe we are in compliance in all material respects with the health, safety and environmental regulations affecting the operation of our rigs and the drilling of oil and gas wells in the countries and jurisdictions in which we operate. Except as discussed above, regulatory compliance has not materially affected our capital expenditures, earnings or competitive position to date, although such measures do increase drilling costs and may adversely affect drilling operations. Further regulations may reasonably be anticipated, but any effects on our drilling operations cannot be accurately predicted.
In the United States, Rowan is subject to the requirements of OSHA and comparable state statutes. OSHA requires us to provide our employees with information about the chemicals used in our operations. There are comparable requirements in other non-U.S. jurisdictions in which we operate.
In addition to the federal, state, and foreign regulations that directly affect our operations, regulations associated with the production and transportation of oil and gas affect the operations of our customers and thereby could potentially impact demand for our services.
MANUFACTURING OPERATIONS
Our manufacturing operations are conducted by LeTourneau Technologies, Inc. (“LeTourneau”), a wholly-owned subsidiary of the Company headquartered in Longview, Texas. LeTourneau has two operating segments: Drilling Products and Systems and Mining, Forestry and Steel Products, each of which serves markets that require large-scale, steel-intensive, high load-bearing products and related parts and services.
In 2009, our manufacturing operations reported external revenues of $555.3 million and income from operations of $28.9 million, compared with revenues of $761.1 million and a loss from operations of $12.0 million in 2008. Results for 2008 included material charges and other operating expenses of $86.5 million, which are set forth in Note 11 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K. Our backlog of external manufacturing orders totaled approximately $413 million at December 31, 2009, nearly all of which is scheduled for delivery in 2010, compared with $562 million at December 31, 2008. Our manufacturing results of operations and backlog are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.
Drilling Products and Systems
Our Drilling Products and Systems segment built the first jack-up drilling rig in 1955, and has since designed, built or licensed the construction of more than 200 units including all 23 of our current jack-up rigs. This segment also designs and manufactures primary drilling equipment in a wide range of sizes, including mud pumps, top drives, drawworks and rotary tables, as well as variable-speed motors, variable-frequency drive systems and other electrical components for the oil and gas, marine, mining and dredging industries. We also manufacture complete land rigs and related drilling equipment packages.
Drilling Products and Systems completed construction of our second 240C class jack-up in December 2009 and is currently constructing our third 240C class jack-up, the Joe Douglas, at our Vicksburg, Mississippi, shipyard for delivery in the third quarter of 2011. Our Longview, Texas, facility is providing the rig kit (design, legs, jacking system, cranes and other equipment) and certain drilling equipment for each of the EXL class jack-ups being built for Rowan by Keppel.
The Vicksburg facility is dedicated primarily to vessel construction for the offshore drilling industry, and is heavily dependent upon demand for offshore jack-up rigs. We currently have no further plans for rig construction in Vicksburg following the delivery of the Joe Douglas in 2011. Absent additional orders or sufficient prospects for future work, the activities at the facility would be significantly reduced at that time, in which case we would incur additional costs such as employee severance, among other charges. Closing or significantly reducing activity levels at the facility could result in the incurrence of cash charges ranging from $5 million to $6 million and noncash charges ranging from $7 million to $10 million. Rig component manufacturing, rig repair services and design engineering continue to be performed at our Longview facility.
Mining, Forestry and Steel Products
Our Mining, Forestry and Steel Products segment manufactures heavy equipment such as large-wheeled front-end loaders, diesel-electric powered log stackers and steel plate products.
Our mining loaders feature bucket capacities up to 53 cubic yards, which are the largest in the industry. LeTourneau loaders are generally used in coal, copper, and iron ore mines, and utilize a proprietary diesel-electric drive system with digital controls. This system allows large, mobile equipment to stop, start and reverse direction without gear shifting and high-maintenance braking. LeTourneau’s wheeled loaders can load rear-dump trucks in the 85-ton to 400-ton range. Our log stackers offer two- or four-wheel drive configurations and load capacities ranging from 35 to 55 tons.
Mining products and parts are distributed through our own distribution network serving the western United States, Australia, Canada, China and Brazil as well as through a worldwide network of independent dealers. These dealers have agreements to sell our products to end-users and provide follow-up service and parts directly to those end-users. We focus on after-market parts and components for the repair and maintenance of our machines and market these items through the same dealer network. Global sites for parts stocking, rebuilding and service include approximately 60 locations on six continents.
From our mini-mill in Longview, Texas, we recycle scrap metal and produce carbon, alloy and tool steel plate products for internal needs as well as external customers. We concentrate on niche markets that require higher-end alloy steel grades, including mold steels, aircraft-quality steels and resulfurized and boron grades. Sales consist primarily of steel plate, but also include value-added fabrication of steel products. Our products are generally sold to steel service centers, fabricators and manufacturers through a direct sales force. Plate products are sold throughout North America while sales of fabricated products are more regional, encompassing Texas, Oklahoma, Louisiana, Mississippi and Arkansas. Carbon and alloy plate products are also used internally in the production of equipment and parts.
We conduct ongoing research and product development, primarily to increase the capacity and performance of our product lines on a continuous improvement basis, and routinely evaluate our products and after-market applications for potential enhancements.
We offer warranties and parts guarantees extending for stipulated periods of ownership or hours of usage, whichever occurs first. In most cases, dealers of our products perform the warranty work. For drilling equipment, we generally perform warranty work directly and accrue for estimated future warranty costs based on historical experience.
Raw Materials
The principal raw material used in our manufacturing operations is steel plate, much of which is supplied by our Longview mini-mill. Other required materials are generally available in sufficient quantities to meet our manufacturing needs through purchases in the open market, and we do not believe that we are dependent on any single supplier.
Competition
Since 1955, when the first LeTourneau jack-up was delivered, LeTourneau has been recognized as a leading designer and builder of jack-up drilling rigs, having designed or built approximately one-third of all jack-ups currently in operation worldwide. We believe there are currently 61 jack-ups under construction worldwide, 11 of which are LeTourneau designs. At present, we have a limited number of competitors in jack-up rig design, though several shipyard facilities have emerged in recent years to provide jack-up rig construction and repair services, and some of these competitors are significantly larger than LeTourneau.
We encounter significant competition in the drilling equipment market. The leading competitor in the mud pump market is estimated to have more than a 50% share of the market. Our shares of the top drive, drawworks, rotary table and land rig markets are not significant.
We have four major steel plate competitors. Our share of the overall steel market is small, but we are very competitive in certain niche applications for high-strength alloy, thick plate. Internal requirements for steel plate provide a base load for the steel mill.
We encounter competition worldwide from several sources in mining products. Our wheeled loader product lines have a number of competitors. In forestry, our log stackers have four major competitors.
Our competition in the sale of after-market parts for mining and forestry products is fragmented, with only three other companies considered to be direct competitors. Vendors supplying parts directly to end-users and others who obtain and copy the parts for cheaper and lower-quality substitutes provide more intense competition to us than do direct competitors.
Regulations and Hazards
Our jack-up rig designs are subject to regulatory approval by various agencies, depending on the geographic areas where the rig will be qualified for drilling. Other than the approvals that classify the jack-up as a vessel, the rules relate primarily to safety and environmental issues, vary by location and are subject to frequent change.
In the United States, our manufacturing operations and facilities are subject to regulation by a variety of local, state, and federal agencies with authority over safety and environmental compliance. These include the Environmental Protection Agency (“EPA”), OSHA, and other state and local jurisdictions with comparable statutes. Internationally, our operations and facilities are subject to comparable regulations in the countries in which we operate.
We have the required permits at our manufacturing facilities for wastewater discharges, solid waste disposal and air emissions. Our manufacturing operations may generate waste products which are considered hazardous by the EPA or other governmental agencies. We properly contain and dispose of these waste products at approved waste disposal facilities. In
the event we experience an unplanned release of waste products, we may be liable for damages from any air, water or land pollution that may result. We believe that our compliance with environmental protection laws and regulations will have no material effect on our capital expenditures, earnings or competitive position during 2010. Further regulations may reasonably be anticipated, but any effects on our manufacturing operations cannot be accurately predicted at this time.
As a manufacturing company, we may be responsible for certain risks associated with the use of our products. These risks include product liability claims for personal injury and/or death, property damage, loss of product use, business interruption and necessary legal expenses to defend us against such claims. We carry insurance, and we believe we are adequately covered for such risks.
EMPLOYEES
At December 31, 2009, we had 4,846 employees, as compared to 6,023 and 5,704 at December 31, 2008 and 2007, respectively. Included in these numbers are citizens of the United States and other countries. None of our employees are covered by collective bargaining agreements with labor unions. We consider relations with our employees to be satisfactory.
CUSTOMERS
One drilling customer, Saudi Aramco, accounted for 15% of consolidated revenues in each of 2009 and 2008, and 13% in 2007.
Historically, our manufacturing customer base has been diverse, and none of our product lines are highly dependent on any one customer or small group of customers.
ITEM 1A. RISK FACTORS
You should consider carefully the following risk factors, in addition to the other information contained and incorporated by reference in this Form 10-K, before deciding to invest in our common stock.
We operate in volatile businesses that are heavily dependent upon commodity prices and other factors beyond our control.
The success of our Drilling operations depends heavily upon conditions in the oil and gas industry and the level of demand for drilling services. Demand for our drilling services is vulnerable to declines that are typically associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices may cause oil and gas companies to reduce their spending, in which case demand for our drilling services could decrease and our drilling revenues may be adversely affected by lower rig utilization and/or day rates. Oil and natural gas prices have historically been very volatile, and our drilling operations have in the past suffered through long periods of weak market conditions.
Demand for our drilling services also depends on additional factors that are beyond our control, including:
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fluctuations in worldwide demand for oil and natural gas
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the willingness and ability of the Organization of Petroleum Exporting Countries, or “OPEC,” to limit production levels and influence prices;
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political and military conflicts in oil-producing areas and the effects of terrorism;
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the level of production in non-OPEC countries;
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laws, regulations and policies of various governments regarding exploration and development of their oil and natural gas reserves;
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domestic and international tax policies;
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disruption of exploration and development activities due to hurricanes and other severe weather conditions;
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advances in exploration and development technology; and
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further consolidation of our customer base
Our drilling operations have been and will continue to be adversely affected by dramatic declines in oil and natural gas prices, as occurred in late 2008 and early 2009, but we cannot predict the extent of that effect. Nor can we assure you that a reduction in offshore drilling activity will not occur for other reasons. Our Manufacturing operations are also dependent on commodity prices and financial market conditions which affect demand for rigs and related components, mining and timber equipment and after-market parts.
The delivery of new offshore drilling rigs currently under construction may further reduce our rig utilization and day rates and could lead to impairment charges.
We believe there are currently 61 competitive jack-up rigs under construction worldwide, or approximately 13% of the existing fleet. Most of these rigs do not have drilling contracts in place, and their delivery will increase the supply of available rigs competing for work, which could further reduce rig utilization and day rates. In addition, many of these rigs will likely enter the market at a time of excess capacity and low day rates. Prolonged periods of low rig utilization require us to accept lower day rates, or may cause us to temporarily take rigs out of service, or “stack” rigs, which would adversely affect our operating results and cash flows. We may be required to recognize impairment charges on our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that their carrying values may not be recoverable.
Our markets are highly competitive, and satisfactory price levels are difficult to maintain.
Our drilling and manufacturing markets are highly competitive, and no single participant is dominant. Drilling contracts are often awarded on a competitive bid basis, with intense price competition frequently being the primary factor determining which qualified contractor is awarded the job. Relocation of offshore rigs from areas of lower activity, such as the U.S. Gulf of Mexico, to more active international markets has further increased the competition among rigs looking for work in those areas. The anticipated delivery of 61 new jack-ups over the next three years and ongoing consolidation by oil and gas exploration and production companies will further increase the supply of rigs while reducing the number of available customers. This consolidation has also resulted in drilling projects being delayed. We may have to further reduce our prices in order to remain competitive, which would have an adverse effect on our operating results.
Our rigs under construction do not yet have drilling contracts.
We have not yet obtained drilling contracts for four of our rigs under construction. Failure to secure economical contracts for them prior to delivery could negatively impact our operating results.
Many of our drilling rigs are subject to damage or destruction by severe weather, and our business may be affected by the threat of severe weather.
Much of the Gulf of Mexico, the North Sea and offshore eastern Canada frequently experience hurricanes or other extreme weather conditions. Many of our offshore drilling rigs are located in these areas and are thus subject to potential damage or destruction by such conditions. Damage caused by high winds and turbulent seas could cause us to suspend operations on drilling rigs for significant periods of time until the damage can be repaired. Even if our drilling rigs are not damaged by such conditions, we may still experience disruptions in our operations due to damage to our customers’ platforms and other related facilities in these areas. Additionally our customers may choose not to contract our rigs for use during hurricane season, particularly our conventional rigs in the Gulf of Mexico. During Hurricanes Katrina and Rita in 2005, we lost four jack-up rigs and another was significantly damaged. During Hurricane Ike in 2008, we lost one jack-up rig. Future storms could result in the loss or damage of additional rigs, which would adversely affect our financial position, results of operations and cash flows.
Our insurance coverage for windstorms may be inadequate, has become more expensive, and may become unavailable or cost-prohibitive.
Hurricanes (or “windstorms”) have caused tremendous damage to drilling and production equipment and facilities throughout the Gulf Coast in recent years, and insurance companies have incurred substantial losses as a result. Accordingly, insurance companies have substantially reduced the levels of windstorm coverage available and have dramatically increased the cost of such coverage. Coverage for potential liabilities to third parties associated with property damage and personal injuries, as well as coverage for environmental liabilities and removal of wreckage and debris associated with hurricane losses has also been limited.
As a result of the increased cost and reduced availability of coverage, in 2009 we decided to discontinue windstorm physical damage coverage on four of our older, less capable jack-up rigs, and our current coverage for removal of wreckage is subject to a $100 million per occurrence deductible. Currently, our windstorm physical damage coverage is subject to a $50 million per occurrence deductible with an annual aggregate limit of $150 million and covers only the Gorilla II, the Bob Palmer and the Rowan-Mississippi. Losses due to future windstorms not covered by insurance could adversely affect our financial position, results of operations and cash flows. We renew our rig insurance policies annually each April. The level of coverage that we maintain is reevaluated each year based on a variety of factors, and we can provide no assurance that we will maintain future coverage at current levels.
Taxing authorities may challenge our tax positions, and we may not be able to realize expected benefits.
In 2009, we recognized tax benefits of $25 million as a result of applying our facts to a recent third-party tax case that provides a more favorable tax treatment for certain foreign contracts entered into in prior years. Our income tax returns are subject to audit by U.S. federal, state, and foreign tax authorities. Determinations by such taxing authorities that differ materially from our recorded estimates, either favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows.
Our foreign operations typically present additional risk, and operations in certain foreign areas present higher costs.
In recent years, we have significantly expanded our operations internationally. Foreign operations are often subject to political, economic and other uncertainties not typically encountered in domestic operations, including arbitrary taxation policies, onerous customs restrictions, foreign currency exchange fluctuations, security threats including terrorism, and the risk of asset expropriation due to foreign sovereignty over operating areas. With regard to the risk that our customer may terminate contracts without cause on short notice, contractually or by governmental action, we assume greater risks of such events in foreign areas, where legal protections may be less available to the Company. Any such unforeseen events could have a material adverse effect on our financial position, results of operations and cash flows. Additionally, operations in certain foreign areas, such as the North Sea, are highly regulated and have higher compliance and operating costs in general.
Most of our contracts are fixed-price contracts, and increases in our operating costs or the impact of any general inflation could have an adverse effect on the profitability of those contracts.
Most of our drilling contracts provide for the payment of a fixed day rate during periods of operation, and reduced day rates during periods of other activities, and our manufacturing contracts typically provide for a fixed price. Many of our operating costs are unpredictable and can vary based on events beyond our control. Our gross margins will therefore vary over the terms of our contracts. If our costs increase or we encounter unforeseen costs, we may not be able to recover them from our customers, which could adversely affect our financial position, results of operations and cash flows.
High costs associated with maintaining idle rigs may cause us to experience losses, and cold-stacking rigs may result in impairment charges.
In the past, Rowan generally has not cold-stacked its offshore drilling rigs during extended idle periods, as the long-term costs of rehiring and retraining personnel and restarting equipment typically negate any short-term savings. As noted previously, however, we have recently cold-stacked the Rowan-Juneau, one of our oldest rigs. Should we cold-stack additional idle rigs, we could be exposed to additional severance costs and potential impairment charges from reductions in the fair value of our equipment.
Deterioration in global capital markets reduces customer spending and results in lower demand for our products and services and reduced or delayed collections of expected revenues.
Weakness in global capital markets, coupled with declining oil and natural gas prices, have caused a number of oil and gas producers to reduce operating and capital budgets, cancel projects or large purchases and/or slow the payment of receivables in an effort to preserve liquidity. Many of our customers have approached us in an effort to cancel contracts, reduce rates and prices or extend payment terms. We can provide no assurance that all of our receivables will be collected.
We will experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts.
Some of our drilling contracts are cancelable by the customer upon specific notice, or upon the occurrence of events beyond our control, such as the loss or destruction of the rig due to weather, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. Not all of our contracts require the customer to make an early termination payment upon cancellation. Any early termination payments that may be required under our contracts may not
be sufficient to fully compensate us for the loss of the contract and could result in the rig becoming idle for an extended period of time. Additionally, in weak market conditions, a customer may be able to obtain a comparable rig at a lower daily rate and seek to renegotiate the terms of its existing drilling contract with us.
Weakness in global capital markets may limit our ability to meet our future capital needs.
At December 31, 2009, we had $640 million of cash and equivalents plus a $155 million revolving credit facility to be used, if necessary, for general corporate purposes, including capital expenditures and debt service requirements. Given the volatility in global capital markets, it is possible our credit facility will not be available when and if required. Lack of access to capital may limit our ability to expand our businesses, engage in acquisitions or otherwise take advantage of business opportunities.
We are subject to operating risks such as blowouts and well fires that could result in environmental damage, property loss, personal injury and death, some of which may not be covered by insurance or recoverable indemnification.
Our drilling operations are subject to many hazards that could increase the likelihood of accidents. Accidents can result in:
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costly delays or cancellations of drilling operations;
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serious damage to or destruction of equipment;
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personal injury or death;
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significant impairment of producing wells, leased properties or underground geological formations; and
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major environmental damage.
Our offshore drilling operations are also subject to marine hazards, whether at drilling sites or while equipment is under tow, such as vessel capsizings, collisions or groundings. In addition, raising and lowering jack-up rigs and drilling into high-pressure formations are complex, hazardous activities, and we frequently encounter problems. Any ongoing change in weather patterns or climate could increase the adverse impact of marine hazards.
Our manufacturing processes could pollute the air, land, and inland waters, and the products we manufacture could be implicated in lawsuits alleging environmental harm, property loss, personal injury and death.
We have experienced some of the types of incidents described above, including high-pressure drilling accidents resulting in lost or damaged drilling formations and towing accidents resulting in lost drilling equipment. Any future such events could result in operating losses and have a significant adverse impact on our business.
We have a significant insurance receivable related to the salvage of several offshore drilling rigs lost or damaged during recent hurricanes.
During 2005, we lost four offshore rigs, including the Rowan-Halifax, and incurred significant damage on a fifth as a result of Hurricanes Katrina and Rita. We also lost another offshore rig during Hurricane Ike in 2008. Since 2005, we have been working to locate the lost rigs, salvage related equipment, remove debris, wreckage and pollutants from the water, mark or clear navigational hazards and clear rights of way. As of December 31, 2009, we had incurred $229 million of costs related to such efforts, of which $199 million had been reimbursed through insurance, leaving $30 million included in receivables. Some of these expenditures may not be reimbursed by our insurance coverage, which could have a material adverse effect on our financial position, results of operations and cash flows.
Our four Super Gorilla class rigs and two of our Tarzan Class rigs are pledged as security under our government-guaranteed debt arrangements.
If operating conditions deteriorate and if market conditions were to remain depressed for a long period of time, our results of operations would suffer, and working capital and other financial resources may not be available or adequate to service our outstanding debt. Our four Super Gorilla class jack-ups and two of our Tarzan Class jack-ups are pledged as security under our government-guaranteed debt arrangements. If we were unable to service our debt, it is possible that these assets could be removed from our fleet, in which case our ability to generate sufficient revenues and cash flows would be significantly reduced.
Changes to our inventory valuation allowances may reduce our future operating results.
We recognize valuation allowances against our inventories based on historical usage of inventory on hand, assumptions about future demand based on market conditions, and estimates about potential alternative uses, which are usually limited. Our inventories generally consist of spare parts, work in process, and raw materials to support ongoing manufacturing operations and our installed base of drilling, mining and timber equipment. Customers rely on us to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The estimated carrying values of our inventories are therefore indirectly affected by demand for oil, natural gas and other commodities, general economic conditions worldwide, and the potential obsolescence of various types of equipment we sell, among other factors. As a result of the 2008 declines in oil and natural gas prices, the onset of global recession and weakness in capital markets, we reduced our estimates of future usage of our inventories and significantly increased our inventory reserves at December 31, 2008.
Further deterioration in worldwide demand for oil, natural gas and certain other commodities, or the development of new technologies which make older drilling, mining and timber technologies obsolete, could require us to record additional reserves to reduce the value of our inventory and reduce our future operating results.
Rig upgrades, enhancements and new construction projects are subject to risks which could cause delays or cost overruns and adversely affect our financial position, results of operations and cash flows.
New drilling rigs may experience start-up complications following delivery or other unexpected operational problems that could result in significant uncompensated downtime, reduced day rates or the cancellation or termination of drilling contracts. Rig construction projects are subject to risks of delay or cost overruns inherent in any large construction project from numerous factors, including the following:
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shortages of equipment, materials or skilled labor;
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unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;
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failure of equipment to meet quality and/or performance standards;
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financial or operating difficulties of equipment vendors or the shipyard;
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unanticipated actual or purported change orders;
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inability to obtain required permits or approvals;
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unanticipated cost increases between order and delivery, which can be up to two years;
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adverse weather conditions and other events of force majeure;
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design or engineering changes; and
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work stoppages and other labor disputes.
Significant cost overruns or delays could adversely affect our financial position, results of operations and cash flows. Additionally, failure to complete a project on time may result in the delay of revenue from that rig, which also could adversely affect our financial position, results of operations and cash flows.
Our customers may be unable to indemnify us.
Consistent with standard industry practice, we typically obtain contractual indemnification from our customers whereby they generally agree to protect and indemnify us for liabilities resulting from various hazards associated with the drilling industry. We can provide no assurance, however, that our customers will be financially able to meet these indemnification obligations. The failure of a customer to meet such obligations, the failure of one or more of our insurance providers to meet claim obligations, or losses or liabilities resulting from unindemnified, uninsured or underinsured events could have a material adverse effect on our financial position, results of operations and cash flows.
We are subject to governmental laws and regulations that could cause significant costs and liability on us for environmental and natural resource damages.
Many aspects of our operations are subject to governmental regulation in the areas of equipping and operating vessels, drilling practices and methods, and taxation. In addition, the United States and other countries in which we operate have regulations relating to environmental protection and pollution control. Rowan could become liable for damages resulting from pollution of offshore waters and, under United States regulations, we must document financial responsibility. Generally, we are substantially indemnified under our drilling contracts for pollution damages, except in certain cases of pollution emanating above the surface of land or water from spills of pollutants, or pollutants emanating from our drilling rigs. We can provide no assurance, however, that such indemnification provisions can be enforced.
In late 2007, we entered into a plea agreement with the Environmental and Natural Resources Division, Environmental Crimes Section of the U.S. Department of Justice, as amended, under which we paid fines and made community service payments totaling $9 million. Additionally, we agreed to be subject to unsupervised probation for a period of three years in connection with a criminal investigation of environmental matters involving several of our offshore drilling rigs that at various times operated in the Gulf of Mexico. During the probation period we must ensure that we commit no further criminal violations of federal, state, or local laws or regulations and must also continue to implement our comprehensive Environmental Management System Plan.
In the United States, Rowan is subject to the requirements of OSHA and comparable state statutes. OSHA requires us to provide our employees with information about the chemicals used in our operations. There are comparable requirements in other non-U.S. jurisdictions in which we operate.
In addition to the federal, state, and foreign regulations that directly affect our operations, regulations associated with the production and transportation of oil and gas affect the operations of our customers and thereby could potentially impact demand for our services.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Some scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.
In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which established emission targets for GHGs, became binding on the countries that had ratified it. We currently operate one of our rigs in eastern Canada, which is one of the countries that ratified the Kyoto Protocol. International discussions are underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012.
In the United States, federal legislation imposing restrictions on GHGs is under consideration. Proposed legislation has been introduced that would establish an economy-wide cap on emissions of GHGs and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions. In addition, the EPA is taking steps that would result in the regulation of GHGs as pollutants under the Clean Air Act (“CAA”). To date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, effective December 29, 2009, which establishes a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; and (ii) an "Endangerment Finding" final rule, effective January 14, 2010, which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, allowing the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil). Finally, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. As a result, the EPA has proposed to tailor these programs such that only large stationary sources will be required to have air permits that authorize GHG emissions.
Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have an adverse impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have an adverse impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customer's operations.
Also, on June 26, 2009, the U.S. House of Representatives passed “American Clean Energy and Security Act of 2009” or ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of “greenhouse gases.” The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions, and the Obama Administration has indicated its support of legislation to reduce greenhouse gas
emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, the adoption and implementation of any CAA regulations, and any future federal, state or local laws or implementing regulations that may be adopted to address greenhouse gas emissions, could require us to incur increased operating costs and could adversely affect demand for oil and natural gas and our services. The effect on our operations could include increased costs to operate and maintain our equipment and facilities, install new emission controls on our equipment or facilities, measure and report our emissions, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.
Anti-takeover provisions in our Certificate of Incorporation and bylaws could make it difficult for holders of our common stock to receive a premium for their shares upon a change of control.
Holders of the common stock of acquisition targets may receive a premium for their shares upon a change of control. Delaware law and the following provisions, among others, of our Certificate of Incorporation and bylaws could have the effect of delaying or preventing a change of control and could prevent holders of our common stock from receiving such a premium:
•
Currently the affirmative vote of 80% of the outstanding shares of our capital stock is required to approve business combinations with any related person that has not been approved by our board of directors. We are also subject to a provision of Delaware corporate law that prohibits us from engaging in a business combination with any interested stockholder for three years from the date that person became an interested stockholder unless specified conditions are met.
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Special meetings of stockholders may not be called by anyone other than our board of directors, our chairman, our executive committee or our president or chief executive officer.
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Our board of directors is divided into three classes whose terms end in successive years, so that less than a majority of our board comes up for election at any annual meeting.
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Our board of directors has the authority to issue up to 5,000,000 shares of preferred stock and to determine the voting rights and other privileges of these shares without any vote or action by our stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
The Company has no unresolved Securities and Exchange Commission staff comments.
ITEM 2. PROPERTIES
Rowan leases as its corporate headquarters approximately 79,300 square feet of space in an office tower located at 2800 Post Oak Boulevard in Houston, Texas.
DRILLING RIGS
Following are summaries of the principal drilling equipment owned by the Company and location at February 16, 2010.
Offshore Rigs
____________
(1)
Class number is assigned by LeTourneau and denotes the design and construction. Class name is assigned by Rowan. The Gorilla class unit is designed for extreme hostile environments. The Super Gorilla class unit is an enhanced version of the Gorilla class, and the Super Gorilla XL class unit is an enhanced version of our Super Gorilla class. The 240C is LeTourneau’s latest design. The EXL class unit is an enhanced version of the 116C. All rigs are equipped with top-drive drilling systems.
(2)
Indicates rated water depth in current location and rated drilling depth.
(3)
High-specification rigs are those that have hook-load capacity of at least two million pounds.
(4)
Unit is equipped with three mud pumps.
(5)
Unit is equipped with four mud pumps.
(6)
Premium jack-ups are cantilevered rigs capable of operating in water depths of 300 feet or more.
(7)
Units are equipped with a skid-off capability. For a discussion of skid-off technology, refer to “Offshore Operations” in Item 1, Business, of this Form 10-K.
(8)
The Rowan-Louisiana was damaged during Hurricane Katrina in 2005 and was substantially refurbished in 2006.
Onshore Rigs
____________
(1)
All but Rig 29 are equipped with top-drive drilling systems.
Rowan’s drilling division leases and, in some cases, owns various operating and administrative facilities generally consisting of office, maintenance and storage space in the United States in Texas and Alaska and in Canada, Scotland, Saudi Arabia, Qatar, Egypt and Mexico.
MANUFACTURING FACILITIES
LeTourneau’s principal manufacturing facility and headquarters are located in Longview, Texas, on approximately 2,400 acres with approximately 1.2 million square feet of covered working area. The facility is owned and contains:
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a steel mini-mill with 330,000 square feet of covered working area;
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a fabrication shop with 300,000 square feet of covered working area;
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a machine shop with 140,000 square feet of covered working area; and
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an assembly shop with 124,000 square feet of covered working area.
The mini-mill has two 25-ton electric arc furnaces capable of producing 120,000 melted tons per year.
We machine, fabricate, assemble, and test drilling products and systems at a facility we own in Houston, Texas, that has approximately 450,000 square feet of covered work area and 45,000 square feet of office space. This capacity is supported by the Longview, Texas, facility. Additionally, we lease warehouse and administrative facilities in Texas, Louisiana and Canada.
We also own a jack-up rig construction facility located in Vicksburg, Mississippi, on 1,850 acres of land that has approximately 560,000 square feet of covered work area. Our rig service and repair operation is carried out primarily at our Sabine Pass, Texas, facility.
Our distributor of forestry products in the northwestern United States is located on a six-acre site in Troutdale, Oregon, with approximately 22,000 square feet of building space.
Our distributor of mining products in the western United States is located in a leased facility in Tucson, Arizona, having approximately 20,000 square feet. Our distributor of mining products in Australia is located in a leased facility in Murarrie, Queensland, having approximately 29,500 square feet. There are additional branch locations in each Australian territory. Our distributor of mining products in Brazil leases an office building and warehouse.
ITEM 3. LEGAL PROCEEDINGS
Reference should be made to Note 6 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K for the status of significant legal proceedings.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, positions, years of credited service and ages of the officers of the Company as of March 1, 2010 are listed below. Officers are appointed by the Board of Directors and serve at the discretion of the Board of Directors. There are no family relationships among these officers, nor any arrangements or understandings between any officer and any other person pursuant to which the officer was selected.
Since January 2009, Mr. Ralls’ principal occupation has been President and Chief Executive Officer. From June 2005 until his retirement in November 2007, Mr. Ralls served as Executive Vice President and Chief Operating Officer of GlobalSantaFe Corporation. Prior to that time, Mr. Ralls served as Senior Vice President and Chief Financial Officer of GlobalSantaFe Corporation. Mr. Ralls also serves on the Board of Complete Production Services, Inc.
Since January 2007, Mr. Buvens’ principal occupation has been Executive Vice President, Legal. Prior to that time, Mr. Buvens served as Senior Vice President, Legal.
Since January 2007, Mr. Keller’s principal occupation has been Executive Vice President, Business Development. Prior to that time, Mr. Keller served as Senior Vice President, Marketing.
Since January 2007, Mr. Russell’s principal occupation has been Executive Vice President, Drilling Operations. From January 2005 to January 2007, Mr. Russell served as Vice President, Drilling. Prior to that time, Mr. Russell served as Vice President, Rowan Drilling Company, Inc., a Rowan subsidiary.
Since June 2007, Mr. Bartol’s principal occupation has been Vice President, Strategic Planning. From January 2007 to June 2007, Mr. Bartol served as a consultant to the Company on strategic initiatives. From June 2004 to August 2006, Mr. Bartol was Chief Financial Officer of Jindal United Steel Corporation.
Since May 2008, Ms. Carroll’s principal occupation has been Vice President, Health, Safety and Environmental Affairs. From October 2007 to May 2008, Ms. Carroll served as Vice President, Environmental Affairs. From July 2006 to October 2007, Ms. Carroll served as a consultant to the Company. Prior to that time, Ms. Carroll was Vice President of Environmental, Health and Safety for TEPPCO Partners, LLP.
Since April 2006, Mr. Dowdy’s principal occupation has been Vice President, Engineering. Prior to that time, Mr. Dowdy was Chief Engineer, Marine Group for LeTourneau.
Since January 2010, Dr. Burke’s principal occupation has been President and Chief Executive Officer of LeTourneau. Prior to that time, Dr. Burke was employed by Complete Production Services, Inc., an oilfield services company, as Division President from 2006 to 2009, and as Vice President Corporate Development from 2004 to 2006.
Since January 2007, Mr. Wells’ principal occupation has been Vice President, Finance and Chief Financial Officer. From May 2005 to January 2007, Mr. Wells served as Vice President, Finance and Treasurer. Prior to that time, Mr. Wells served as Controller.
Since July 2005, Mr. Woodall’s principal occupation has been Vice President, Human Resources. Prior to that time, Mr. Woodall was Manager, U.S. Employee Services for Schlumberger.
Since July 2007, Mr. Jones’ principal occupation has been Compliance Officer. From July 2006 to July 2007, Mr. Jones served as Senior Corporate Counsel. Prior to that time, Mr. Jones practiced corporate law at Andrews Kurth LLP.
Since May 2005, Mr. Hatfield’s principal occupation has been Controller. Prior to that time, Mr. Hatfield served as Corporate Accountant of the Company.
Since January 2009, Ms. Trent’s principal occupation has been Corporate Secretary. From January 2007 to January 2009, Ms. Trent served as Corporate Secretary and Special Assistant to the CEO. From October 2005 to January 2007, Ms. Trent served as Corporate Secretary and Compliance Officer. From 2004 to September 2005, Ms. Trent performed contract legal services, primarily for Jindal United Steel Corporation.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Rowan’s common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RDC.” The following table sets forth the high and low sales prices of our common stock for each quarterly period within the two most recent years as reported by the NYSE Consolidated Transaction Reporting System.
On February 26, 2010, there were 1,396 stockholders of record.
In May 2006, Rowan’s Board of Directors approved a regular quarterly cash dividend of $0.10 per share, which the Company paid approximately every three months thereafter through November 2008. The Company did not pay any dividends in 2009. Future dividends, if any, will only be paid at the discretion of the Board of Directors. At December 31, 2009, Rowan had approximately $615 million of retained earnings available for distribution to stockholders under the provisions of its debt agreements. We do not expect to pay dividends in the foreseeable future.
The graph below presents the relative investment performance of Rowan’s common stock, the Dow Jones U.S. Oil Equipment and Services Index, and the S&P 500 Index for the five-year period ending December 31, 2009, assuming reinvestment of dividends.
* $100 invested on 12/31/04 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.
During the fourth quarter of 2009, we acquired 66 shares of our common stock in connection with the vesting of an employee restricted stock award.
In 1998, our Board of Directors authorized us to purchase up to eight million shares of our common stock. We last purchased shares under this program in 2002, and at December 31, 2009, we could purchase up to 1,524,600 additional shares. We have no plans to purchase additional shares at the present time.
For information concerning our common stock to be issued in connection with our equity compensation plans, see Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” of this Form 10-K.
ITEM 6. SELECTED FINANCIAL DATA
The following information summarizes Rowan’s results of operations and financial position for each of the last five years ended December 31.
___________________
(1)
Material charges and other operating expenses in 2008 included $62.4 million of inventory valuation charges, a $13.6 million charge for goodwill impairment, $12.7 million for professional fees related to the suspended LeTourneau monetization, an $11.8 million impairment charge due to the cancellation of the fourth 240C jack-up rig and $10.7 million for severance payments. The 2006 amount reflected an accrual for payments made in 2007 related to a Department of Justice investigation.
(2)
Income from discontinued operations in 2005 consisted primarily of the aggregate after-tax results of Rowan’s boat operations, which were sold in 2005, and include an after-tax gain on sale of $13.1 million. The 2006 amount reflected a refund of excise taxes related to the Company’s aviation operations, which were sold in 2004.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SUMMARY
During 2009, our results of operations continued to benefit from contracts executed prior to the downturn that began in mid 2008 in markets for our products and services. Reduced activity levels, however, caused by the continuing global economic weakness resulted in a decline in our 2009 revenues and profitability. We are currently receiving above-market day rates on several long-term drilling contracts, most of which are scheduled to conclude in 2010 or 2011. Absent a rebound in drilling demand sufficient to enable a recovery in market day rates, our future results of operations would be further negatively impacted as lower market rates are realized in our reported results. Although our operations are currently profitable overall, we can provide no assurance that they will continue to be profitable.
As of February 16, 2010, we had nine offshore rigs in the Middle East, eight in the U.S. Gulf of Mexico, two in the North Sea, and one each offshore West Africa, Eastern Canada, Mexico and Egypt.
RESULTS OF OPERATIONS
The following table highlights Rowan’s operating results for the years indicated (in millions):
As indicated in the preceding table, Rowan’s results of operations are primarily driven by the performance of our Drilling Services segment, which comprises about 95% of our fixed assets and, over the past three years, has generated two-thirds of our aggregate revenues and 95% of our aggregate operating income. Our manufacturing division, featuring our Drilling Products and Systems segment, has led the strategic expansion and upgrade of our drilling fleet over the past decade and, in recent years, has expanded product lines and sought to grow its external business.
Costs and expenses in 2008 included $111.2 million of special items, including (i) impairment charges relating to a cancelled rig construction project, the realizable value of manufacturing inventories and goodwill, (ii) professional service fees and other expenses incurred in connection with the suspended LeTourneau monetization process and (iii) severance costs in
connection with the retirement of the Company’s former Chief Executive Officer in 2008 and headcount reductions. These items are described more fully in the operating segment discussions below and in Note 11 of “Notes to Consolidated Financial Statements.”
Net income includes income from operations plus the following items (in millions):
In 2009, the Company recognized a $25.4 million tax benefit as a result of applying our facts to a recent third-party tax case that provides a more favorable tax treatment for certain foreign contracts entered into in prior years. The Company has deferred recognition of a remaining $49.2 million estimated benefit in accordance with the accounting guidelines for income tax uncertainties.
The performance of each of our operating segments over the period from 2007 through 2009 is discussed more fully below.
Drilling Operations
Drilling Services’ operating results are primarily a function of the activity (or utilization) and day rates achieved by our land and offshore rig fleets. Rig activity and day rates are primarily determined by oil and gas exploration and development expenditures, which are heavily influenced by trends in oil and natural gas prices, and the availability of competitive equipment. When drilling markets are strengthening, day rates generally lag the upward trend in rig activity, and day rate increases can be more significant as utilization approaches 100%. When drilling markets are weakening, day rates are often significantly reduced in an effort to maintain utilization. Due to intense competition in the contract drilling industry, both market utilization and day rates have historically declined much faster than they have risen.
Market Conditions
Over the period from 2007 through mid 2008, global demand for oil and natural gas continued to increase, especially in developing nations such as China and India. At the same time, many key producers increasingly struggled with depleting reserves, requiring more drilling simply to maintain production levels. These market forces caused a dramatic increase in energy prices, and the per-barrel price of oil rose from the low $50s in early 2007 to an all-time high of more than $145 in July 2008. Natural gas prices followed a similar pattern during the period, though with much more volatility, generally ranging from $5.50 to $8.50 per mcf during 2007 and peaking in mid 2008 at nearly $14.
As a result, drilling demand surged over the period, with all available rigs benefiting. Many of the projects were in increasingly difficult drilling environments and demanded the most capable drilling equipment. Meanwhile, the global jack-up fleet, with relatively few net rig additions between 1986 and 2005, continued to age. The more capable rigs were marketable throughout the world, and were generally able to obtain longer-term contracts and higher day rates than older and less capable “commodity” rigs.
In mid 2008, when the global economy began slipping into recession and access to capital diminished significantly due to weakening financial markets, both oil and natural gas prices began to decline precipitously, and were down from their highs by approximately 79% and 61%, respectively, by the end of 2008. Most companies reduced spending in 2009, and energy companies in particular, with the prospect of significantly reduced cash flows and constrained capital resources, dramatically cut exploration and development expenditures, with most of the reductions targeted at shallow water and land drilling.
As access to capital began to be restored and global economies began to stabilize in 2009, oil prices more than doubled from their lows and global drilling activity appeared to bottom during the second quarter. Most drilling budgets in 2010 show increases over the reduced 2009 levels. Natural gas prices remained weak for most of 2009, causing a collapse in domestic land and offshore drilling markets early in the year, particularly in the Gulf of Mexico, though prices began strengthening and activity had begun to recover by year’s end. See further discussion under “Drilling Operations - Outlook.”
Our Rig Fleets
Our offshore fleet currently consists of 23 jack-up rigs, featuring:
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Two 240C class jack-ups, one of which was delivered in late 2008 and one in late 2009,
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Four Tarzan Class jack-ups delivered during the 2004-2008 period,
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Four Super Gorilla class jack-ups delivered during the 1998-2003 period,
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Three Gorilla class jack-ups built during the early 1980s,
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Seven 116C class jack-ups built during the early 1980s, and
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Two 84 class jack-ups and one 116 class jack-up built during the mid-to-late 1970s.
The 240Cs, Tarzan Class, Super Gorillas and one of the Gorilla class rigs have at least two million pounds of hook-load capability, enabling efficient drilling beyond 30,000 feet. We consider such rigs “high-specification” jack-ups.
Five additional high-specification jack-ups are under construction with deliveries currently expected over the period from the second quarter of 2010 through the first quarter of 2012, including one 240C class rig and four EXL class rigs. See further discussion of our offshore newbuild program under “Liquidity and Capital Resources - Capital Expenditures.”
During 2009, we discontinued active marketing of three of our thirty-two land rigs. Our land fleet currently consists of 29 marketed rigs, including 16 rigs constructed since 2005, four rigs built during 2001-2002 and nine older rigs that have been refurbished over the years.
Current Operations
The U.S. Gulf of Mexico offshore drilling market is highly fragmented among several oil and gas companies, many of which are independent operators whose drilling activities are highly dependent on near-term operating cash flows. A typical drilling assignment may call for 60 days of exploration or development work performed under a single-well contract with negotiable renewal options. Long-term contracts have been relatively rare, and generally are available only from the major integrated oil companies and a few of the larger independent operators. Drilling activity and day rates in the Gulf of Mexico have tended to fluctuate rather quickly, and generally follow trends in natural gas prices. Offshore drilling demand in the Gulf reached a peak in 2007, began weakening in late 2008, and generally has remained weak since that time. We currently have eight rigs in the U.S. Gulf of Mexico - seven under contracts expiring in 2010 and one that is idle.
International markets present more opportunities for longer-term drilling contracts and high-specification rigs than do domestic markets. The relocation of rigs from domestic to foreign markets is a significant undertaking, and often interrupts revenues and cash flows for up to three to four months, particularly when equipment upgrades are involved. Thus, major relocations are typically carried out only when the likelihood of higher long-term returns heavily outweighs the short-term costs.
The North Sea is a mature, harsh-environment offshore drilling market that has long been dominated by major oil and gas companies operating within a relatively tight regulatory environment. Project lead times are often lengthy, and drilling assignments, which typically require ultra premium equipment capable of handling extreme weather conditions and high down-hole pressures and temperatures, can range from several months to several years. Thus, drilling activity and day rates in the North Sea move slowly in response to market conditions, and generally follow trends in oil prices. We currently have two Super Gorilla class rigs operating in the North Sea - one under contract that is expected to be completed in the second quarter of 2011 and another under contract that is estimated to be completed in the third quarter of 2011.
We have operated offshore eastern Canada at varying levels since the early 1980s, though we had vacated that market in late 2006. In July 2009, one of our Gorilla class rigs returned to eastern Canada, where it is operating under a contract that is expected to continue through the third quarter of 2010.
The Middle East has been a primary focus among our international operations in recent years. In 2007, we added four rigs to our four existing rigs in the region - two 116Cs with initial two-year contracts with Maersk offshore Qatar, and two Tarzan Class rigs under four-year contracts with Saudi Aramco. We added a third Tarzan Class rig in the Middle East under a three-year contract in 2008 and currently have nine rigs in the region - two under contracts expiring in 2010, four under contracts expiring in 2011 and three that are idle.
In October 2009, we completed mobilizing the J.P. Bussell to Egypt where it began operating for Shell under an approximate 20-month contract. Our two remaining rigs operating internationally are the Rowan Gorilla IV, which is operating for PEMEX in the Gulf of Mexico under a contract that is expected to conclude in the third quarter of 2011, and the Rowan Gorilla VII, which, after completion of the current contract in the second quarter of 2010, will mobilize from West Africa to the North Sea, where it has a contract that is expected to be completed in the first quarter of 2012.
Compared to 2008
The following table highlights the performance of our Drilling Services segment during 2009 compared to 2008 (dollars in millions, except day rates):
The following table summarizes average prices for oil and natural gas and our utilization and average day rates by quarter in 2009, and for the full years 2009 and 2008 for our offshore fleet:
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*
Source: New York Mercantile Exchange (NYMEX)
The dramatic declines in oil and natural gas prices that began in mid 2008 coupled with the weakness in the global capital markets increased our customers’ efforts to preserve liquidity and adversely affected the economics of certain drilling projects. Most oil and gas producers significantly reduced their 2009 drilling expenditures, and that reduction was most prominent for shallow water and onshore projects. The reduction in demand reduced global jack-up and land rig utilization, increased competition among available rigs for fewer drilling assignments, and pressured day rates.
Drilling revenues for 2009 decreased by $236.7 million, or 16%, compared to 2008 as a result of the following (in millions):
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1The Rowan-Anchorage was lost in September 2008 during Hurricane Ike.
2The four land rigs added to the fleet over the period from May 2008 through June 2009 contributed an additional 939 revenue-producing days in 2009 as compared to 2008.
3The J.P. Bussell and Rowan-Mississippi commenced operations in November 2008 and contributed 548 revenue-producing days in 2009, as compared to 86 days in 2008.
The following table presents certain key performance measures by geographic area for our offshore fleet for 2009 and 2008. The number of rigs in each location is based on location for the majority of the period and includes active and idle rigs. Revenues include those attributable to reimbursable costs. Average day rates are computed by dividing revenues recognized during the year, excluding reimbursables, by the number of revenue-producing days. Rig utilization is computed as the number of revenue-producing days divided by total available rig-days.
Drilling operating costs in 2009 decreased by $104.6 million, or 17% from 2008, as set forth in the table below (in millions):
The declines in personnel and related costs and repairs and maintenance expenses were primarily the result of reduced activity levels. Additionally, several shipyard upgrade projects on many of our idle rigs absorbed certain personnel-related costs and resulted in lower routine repair and maintenance expenses that we would have otherwise incurred. Operating margins before depreciation and selling, general and administrative expenses were 57% in both 2009 and 2008. Drilling depreciation expense increased by $30.0 million or 24% between periods due primarily to the addition of the J.P. Bussell and Rowan-Mississippi in November 2008.
Compared to 2007
The following table highlights the performance of our Drilling Services segment during 2008 compared to 2007 (dollars in millions):
Drilling revenues increased by $69.0 million or 5% in 2008, due primarily to the effects of increased drilling activity and average day rates, as follows (in millions):
Our overall offshore fleet utilization was 95% in 2008, up from 94% in 2007, with most of the downtime in each period associated with rigs being prepared for long-term assignments overseas. Our average offshore day rate was $163,200 in 2008, an increase of approximately 4% over 2007. Total revenue-producing days offshore increased by 103 or 1% between years, with most of that increase associated with our new rigs.
Middle East. Our nine jack-ups working offshore Saudi Arabia and Qatar collectively generated approximately $480 million of drilling revenues in 2008, averaging more than $155,000 per day, compared to almost $400 million from eight rigs averaging $149,000 per day in 2007. Our utilization averaged 94% in 2008, up from 92% in 2007.
North Sea. Our two rigs working in the North Sea generated approximately $164 million of drilling revenues in 2008, averaging about $245,000 per day, compared to $246 million from three rigs averaging $241,000 per day in 2007. Our utilization averaged 91% in 2008, down from 96% in 2007, with most of the downtime in 2008 due to rigs undergoing shipyard upgrades.
Other International. After relocating from the North Sea in early January 2008, Gorilla VII was 96% utilized offshore West Africa and provided almost $325,000 per day in drilling revenues during the remainder of the year. Gorilla III was 100% utilized offshore Trinidad during the first five months of 2008, generating approximately $40 million of drilling revenues during the period, or more than $249,000 per day. Gorilla III relocated to the Gulf of Mexico during the second quarter of 2008 where the rig was 98% utilized during the remainder of the year.
Gulf of Mexico. The following table summarizes average oil and natural gas prices and our Gulf of Mexico fleet utilization and average day rates by quarter in 2008, and for the full years 2008 and 2007:
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*
Source: New York Mercantile Exchange (NYMEX)
Natural gas prices remained at historically high levels over the first half of 2008, and our fleet achieved stable utilization and increasing average day rates during that period, though shipyard time for upgrades to the Bob Palmer reduced average utilization during the first quarter. As prices weakened dramatically over the last half of the year, our contracted backlog helped to insulate Rowan from the effects of reduced drilling demand that ensued in the Gulf of Mexico and throughout the United States. The addition of the Rowan-Mississippi and J.P. Bussell in November 2008, coupled with the loss of our oldest jack-up, the Rowan-Anchorage, during Hurricane Ike in September, increased our average rate during the fourth quarter. As shown in the preceding table, our average Gulf of Mexico day rate increased by $1,100 or 1% during 2008, though, by year end, we had begun to feel the impact of weakening demand for our three skid-off rigs. Our total revenue-producing days in the Gulf of Mexico decreased by 97 or 3% in 2008, due primarily to the effects of rig relocations.
Land. Contracted backlog also enabled our 30 deep-well land rigs in Texas, Louisiana, Oklahoma and Alaska to withstand the volatile domestic market conditions during 2008, and attain 93% utilization and an average day rate of $22,600 during the year, compared to 95% and $22,800 in 2007. The fleet included four new 2000 horsepower rigs that were delivered during 2008, which contributed to a 701 or 7% increase in revenue-producing days during the year.
Operating Costs. Drilling operating costs increased by $38.4 million or 6% in 2008 compared to 2007, due primarily to effects of the following (in millions):
Depreciation expense incurred by our drilling operations increased by $24.1 million or 24% in 2008, due primarily to the addition of the rigs noted above. Selling, general and administrative costs increased by $0.9 million or 1% in 2008, due primarily to higher professional service fees resulting from our international expansion and incremental incentive compensation costs associated with our improved financial results.
Our drilling operations realized $68.0 million of gains on asset disposals during 2008, including $37.1 million from insurance proceeds received in connection with the loss of the Rowan-Anchorage during Hurricane Ike, $14.5 million from the sale of our London office, $5.4 million from the sale of our Fourchon, Louisiana, yard and $4.7 million from the sale of a land rig. Our 2007 net gain was $40.7 million, and included $14.1 million from the sale of our Alaska-based drilling camps and $23.4 million related to the installment sale of the Rowan-Midland and related equipment.
Our 2008 Drilling Services operating income included $24.6 million of special charges, including $11.8 million for the estimated unrecoverable cost of amounts expended on construction of our fourth 240C rig which we cancelled, $8.5 million related to severance costs, including the impact of accelerated equity awards primarily resulting from our CEO’s 2008 retirement, $2.8 million of primarily professional service fees incurred in connection with the suspended LeTourneau monetization process, and $1.5 million related to the impairment of goodwill.
Outlook
Worldwide rig demand is inherently volatile and has historically varied from one geographic market to the next, as has the supply of competitive equipment. Exploration and development expenditures can be impacted by many local factors, such as political and regulatory policies, seasonal weather patterns, lease expirations, new oil and gas discoveries and reservoir depletion. Over time, the level and expected direction of oil and natural gas prices are the principal determinants of drilling activity, and oil and gas prices are ultimately a function of the supply of and demand for those commodities.
Our backlog of drilling contracts as of February 16, 2010, was approximately $1.3 billion, which we estimate will be realized as follows: 2010 - $905 million, 2011 - $335 million, 2012 and later years - $70 million. About 58% of our remaining available offshore rig days in 2010, and 17% of available days in 2011 are currently under contract, and most of our drilling contracts have termination penalties. Though we have had several notable additions to our drilling backlog over the past year, the total is down by approximately one-quarter over this period.
Certain of our customers have sought to modify existing contracts, and we have accepted modifications in the few cases where we felt it in our best long-term interest to do so. We intend to enforce our drilling contracts and will vigorously defend our rights thereunder. Any such disputes may adversely impact our results of operations and cash flows to the extent that collections are delayed and administrative costs are increased.
As of February 16, 2010, ten of our offshore rigs had drilling contracts estimated to complete in 2010, eight had contracts estimated to complete in 2011, one had a contract estimated to complete in 2012 and four were available. We received delivery of the newly constructed Ralph Coffman in December 2009, and the rig commenced operations in the U.S. Gulf of Mexico in January 2010. Among the five rigs currently under construction and expected to be delivered over the period from early 2010 through early 2012, we have a contract from a customer for the use of one rig, and the remaining four are not yet contracted.
Hurricanes (or “windstorms”) have caused tremendous damage to drilling and production equipment and facilities throughout the Gulf Coast in recent years, and insurance companies have incurred substantial losses as a result. Accordingly, insurance companies have substantially reduced the levels of windstorm coverage available and have dramatically increased the cost of such coverage. Coverage for potential liabilities to third parties associated with property damage and personal injuries, as well as coverage for environmental liabilities and removal of wreckage and debris associated with hurricane losses has also been limited.
Rowan suffered a significant loss of prospective revenues and has incurred significant claims for removal of wreckage from the total destruction of six rigs in four separate storms from 2002 through 2008. Due to the increased cost and reduced availability of coverage as discussed above, in 2009 we decided to discontinue windstorm physical damage coverage on four of our older, lower-specification jack-up rigs, and our coverage for removal of wreckage is subject to a $100 million per occurrence deductible. Our windstorm physical damage coverage is subject to a $50 million per occurrence deductible with an annual aggregate limit of $150 million and covers only the Gorilla II, the Bob Palmer and the Rowan-Mississippi.
In each of the past several years, the onset of hurricane season has coincided with declines in drilling activity in the Gulf of Mexico. We expect this pattern to continue in future years.
Our drilling operations are currently benefiting from contracted backlog obtained during the predominantly favorable market conditions of the past few years. As our rigs rolled off existing contracts throughout 2009, opportunities for new contracts were limited, and some of our rigs became and remain idle. Such opportunities have become more prevalent in recent months, though most encounter interest from many competing contractors and rigs. We believe there are currently 61 jack-ups under construction for completion by 2012, most of which do not have drilling contracts in place. Delivery of those rigs is expected to further increase competition among jack-up contractors. Thus, we can provide no assurance that we will be able to replace our contract backlog as it is realized, that we can maintain current utilization levels, that spot day rates will remain above breakeven levels, or that our drilling operations will remain profitable.
Manufacturing Operations
We have manufacturing facilities in Longview and Houston, Texas, and Vicksburg, Mississippi, which collectively produce drilling rigs and various rig components and mining and forestry equipment, alloy steel and steel plate under two operating segments - Drilling Products and Systems and Mining, Forestry and Steel Products.
The Drilling Products and Systems segment provides equipment, parts and services for the offshore and onshore oil and gas drilling industry. Featured products include complete jack-up rigs, rig kits and component packages, primary drilling equipment such as mud pumps, drawworks, top drives and rotary tables, and electrical components such as variable-speed motors and drives. The segment built the first offshore jack-up drilling rig in 1955 and has since designed, built or licensed the construction of more than 200 rigs, including all 23 in our fleet. During 2008, Drilling Products and Systems completed construction of our fourth Tarzan Class rig, the J.P. Bussell, and our first 240C class rig, the Rowan-Mississippi, and in December 2009, completed construction of the second 240C class rig, the Ralph Coffman.
The Mining, Forestry and Steel Products segment produces large-wheeled mining and timber equipment and related parts and carbon and alloy steel and steel plate.
Our manufacturing revenues are greatly influenced by the timing of product shipments, and our profitability is impacted by the mix of product sales. Original equipment sales, for example, have traditionally yielded lower margins than the related after-market parts sales. Land rigs and component packages typically require more costs for commissioning than do individual pumps and other drilling equipment, and often carry a package discount. Thus, our gross margins are typically higher on equipment sales than on rigs and component packages.
Compared to 2008
The following table highlights the performance of our Drilling Products and Systems segment for 2009 and 2008 (dollars in millions):
Revenues from Drilling Products and Systems decreased by $124.1 million, or 25%, between periods due primarily to the following:
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A decrease of $78.0 million attributable to $111.6 million of revenues recognized on five offshore rig kit projects in 2009, as compared to $189.6 million recognized on eight projects in 2008;
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A decrease of $36.3 million attributable to $103.0 million recognized on shipments of land rigs and component packages in 2009, down from $139.3 million in 2008;
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A decrease of $23.8 million attributable to $1.9 million of revenues recognized on shipments of top drives in 2009, down from $25.7 million in 2008;
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An increase of $8.6 million attributable to $50.1 million recognized on 57 mud pumps shipped in 2009, up from $41.5 million on 63 pumps in 2008.
Our average margin before depreciation and selling, general and administrative expenses decreased to 8% of revenues in 2009 from 15% in 2008. Margins in 2009 were negatively affected by sales mix, with a greater share of revenues from some of our lower-margin products as compared to the prior year and poor results on several land rig projects.
Selling, general and administrative costs declined by $9.1 million or 36% between periods due primarily to lower compensation and related fringe benefit costs associated with reduced employment levels.
Our Drilling Products and Systems operating results for 2009 exclude $278.9 million of revenues and $182.3 million of expenses in connection with sales of products and services to our Drilling Services segment, much of which was attributable to construction of the newbuild jack-up, Ralph Coffman, and kits and equipment provided for our EXL rigs. Drilling Products and Systems operating results for 2008 excludes $382.9 million of revenues and $307.7 million of expenses, primarily for construction of the J.P. Bussell, Rowan-Mississippi and Ralph Coffman.
The following table highlights the performance of our Mining, Forestry and Steel Products segment for 2009 and 2008 (dollars in millions):
Revenues from Mining, Forestry and Steel Products decreased by $81.7 million or 31% between periods due primarily to the following:
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Lower sales of new mining loaders and forestry stackers, which declined by $38.9 million or 38%, from $102.6 million in 2008 to $63.7 million in 2009. We shipped 14 new mining loaders and forestry stackers 2009, as compared to 29 units in 2008;
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Lower sales of steel plate, which declined by $35.0 million or 52%, from $66.9 million in 2008 to $31.9 million in 2009;
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A two-percent increase in part sales, to $73.3 million in 2009 from $71.9 million in 2008.
Our average margin before depreciation and selling, general and administrative expenses increased to 28% of revenues in 2009 from 24% in 2008. The higher margins were attributable to primarily product sales mix, particularly a greater proportion of higher-margin after-market parts and service revenues in 2009.
Compared to 2007
The following table highlights the performance of our Drilling Products and Systems segment during 2008 compared to 2007 (dollars in millions):
Our Drilling Products and Systems segment sustained a $5.1 million or 1% decrease in revenues in 2008, which featured the following:
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$175.4 million associated with 16 land rigs and component packages shipped in 2008, up from $148.3 million in 2007;
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$153.5 million recognized on eight rig kit projects in 2008, up from $116.9 million in 2007;
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$41.5 million from 63 mud pumps shipped in 2008, down from $49.8 million and 70 pumps in 2007;
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$14.9 million related to drive and control system packages, down from $33.4 million in 2007;
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$12.9 million from 216 motors shipped in 2008, down from $15.2 million in 2007; and
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$7.7 million from custom fabrication work, down from $27.9 million in 2007.
Our 2007 operating results included $41.6 million of revenues and a $15.8 million loss on the external rig construction project which required many more labor hours than we originally anticipated. There were no such revenues in 2008. Thus, as is shown in the preceding table, our average margin over operating costs increased slightly to 15% of revenues in 2008 from 14% in 2007.
Depreciation expense incurred by Drilling Products and Systems in 2008 decreased by $2.2 million or 19% over 2007, due primarily to incremental depreciation related to a land rig lease transaction during 2007. Selling, general and administrative costs increased by $7.9 million or 46% in 2008, due primarily to higher expenses related to our sales and marketing efforts.
Drilling Products and Systems operating results for 2008 included material charges and other operating expenses of $81.9 million, which included a $62.4 million charge for estimated surplus inventory, $10.9 million for goodwill impairment, $6.4 million of allocated monetization costs and $2.2 million for severance costs incurred in connection with headcount reductions.
Operating results for 2008 shown in the preceding table exclude the effects of the approximately $383 million of revenues and $308 million of expenses in connection with products and services provided to our Drilling Services segment during the year, most of which was attributable to construction progress on the Rowan-Mississippi, the J.P. Bussell and the Ralph Coffman.
The following table highlights the performance of our Mining, Forestry and Steel Products segment during 2008 compared to 2007 (dollars in millions):
Our Mining, Forestry and Steel Products segment achieved an aggregate $53.8 million or 25% increase in revenues in 2008, which featured the following:
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$107.9 million of equipment revenues in 2008, up from $94.9 million in 2007; shipments of mining loaders and forestry stackers totaled 29 units in 2008, down from 30 units in 2007, though 16 of the 2008 units were the larger L-1850 model which carry a higher selling price, up from 13 larger units in 2007;
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$71.9 million from parts sales in 2008, up from $62.6 million in 2007;
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$66.9 million from steel plate revenues in 2008, up from $41.2 million in 2007; shipments totaled 61,900 tons in 2008, up by 9,000 tons or 17% over 2007, and the mix changed from 51% external in 2007 to 59% external in 2008, yielding a 33% increase in external volume between years.
Thus, as is shown in the preceding table, our average margin on operating costs increased to 24% of revenues in 2008 from 21% in 2007.
Depreciation expense incurred by Mining, Forestry and Steel Products in 2008 increased by $.8 million or 15% from 2007, due to machinery and equipment additions made in the previous year to increase our manufacturing capacity. Selling, general and administrative costs increased by $11.4 million or 121% in 2008, due primarily to higher expenses related to our sales and marketing efforts and increased amounts of professional fees and other shared administrative costs that are allocated between our manufacturing segments based upon revenues.
Mining, Forestry and Steel Products operating results for 2008 included charges and other operating expenses of $4.7 million, which included $3.5 million of allocated monetization costs and $1.2 million for goodwill impairment.
Outlook
Our manufacturing operations are highly impacted by world commodities prices. Our Drilling Products and Systems segment is closely tied to the condition of the overall drilling industry and demand for drilling equipment, parts and services. The prospects for our Mining, Forestry and Steel Products segment are strongly affected by prices for copper, iron ore, coal and timber. The volatility of commodity prices and weakness in global capital markets over the latter half of 2008 and much of 2009 resulted in reduced demand for most of the manufactured products and services that we offer, though prices and demand, particularly for mined commodities, began improving in late 2009. We cannot predict the duration of the current operating environment or quantify the impact that current business conditions will have on our future operations.
Our external manufacturing backlog, which consists of executed contracts and customer commitments, was approximately $413 million at December 31, 2009, compared to $562 million at December 31, 2008, and included $217 million related to offshore rig projects, $71 million related to land rig projects, $67 million of mining and forestry equipment, $29 million of drilling equipment and $29 million primarily for parts and other components. We expect that about 95% of our external backlog at December 31, 2009, will be realized as revenue in 2010 and the balance in 2011 and 2012. We can provide no assurance we will be able to maintain or significantly increase our backlog going forward.
Facing reduced liquidity, certain of our customers sought to modify existing orders by delaying deliveries and related payments. Others attempted to reduce or cancel orders altogether. Though we fully intend to enforce our contractual rights, such actions by our customers could adversely impact our results of operations and cash flows to the extent that collections are delayed, administrative costs are increased, and we are otherwise unable to fully recover the in-process cost attributable to such orders. We estimate that approximately $15 million or less than 4% of our December 31, 2009, manufacturing backlog is at risk of being delayed or canceled. Should market conditions worsen, these actions may intensify, though we cannot assess that likelihood or the resulting impact on our results of operations or cash flows.
We currently have no further plans for rig construction at our Vicksburg shipyard following the delivery of our third 240C class rig, the Joe Douglas, in 2011. Absent additional orders or sufficient prospects for future work, the activities at the facility would be significantly reduced at that time, in which case we would incur additional costs such as employee severance, among other charges. Closing or significantly reducing activity levels at the facility could result in the incurrence of cash charges ranging from $5 million to $6 million and noncash charges ranging from $7 million to $10 million.
LIQUIDITY AND CAPITAL RESOURCES
Key balance sheet amounts and ratios for 2009 and 2008 were as follows (dollars in millions):
Reflected in the comparison above are the effects of the following sources and uses of cash and cash equivalents in 2009, with comparable amounts for 2008:
Operating Cash Flows
Operating cash flows approximated $544.1 million for 2009 as compared to $694.5 million for 2008. Our cash flows from operations have benefited and will continue to benefit from long-term drilling contracts entered into when rates were significantly higher than current market rates. Several of our offshore rigs are operating under contracts at above-market rates negotiated in periods of stronger demand. As a result, operating cash flows may be negatively affected in the future as these higher day-rate contracts are completed.
Capital Expenditures
Capital expenditures in 2009 totaled $566 million and included:
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$261 million towards construction of the four EXL class rigs;
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$99 million towards construction of our second and third 240C class rigs, the Ralph Coffman and Joe Douglas;
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$164 million for improvements to the existing offshore fleet;
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$8 million for our land rig fleet, including $5 million towards construction of two new land rigs.
The remaining $34 million included the cost of drill pipe, improvements to our rig service and repair facility at Sabine Pass and other enhancements.
Reference should be made to Note 6 of “Notes to Consolidated Financial Statements” in this Form 10-K for a detailed status of our newbuild projects.
Our 2010 capital budget, as approved by our Board of Directors, is approximately $501 million, and includes $107 million toward construction of the 240C-class rig, Joe Douglas, $229 million toward construction of the four EXL class rigs and $119 million for upgrades to existing rigs.
Over the past few years, as a result of our fleet expansion program, our cash flows from operations have not been sufficient to cover our capital expenditures and debt service requirements. As noted under “Long-term Debt” below, in July 2009, the Company completed the issuance and sale of $500 million aggregate principal amount of 7.875% Senior Notes due August 2019 (the “Senior Notes”), and received net proceeds of $492 million. Despite the current weak operating environment, we anticipate that our cash flows from operations will continue to cover a significant amount of our capital expenditures, debt service, and other cash requirements over the next twelve months, and cash flows from operations plus available cash balances will be sufficient to meet such requirements over this period.
We will periodically review and adjust the capital budget as necessary based upon current and forecasted cash flows and liquidity, anticipated market conditions in our drilling and manufacturing businesses, the availability of financing sources, and alternative uses of capital to enhance shareholder value. Certain such adjustments would require Board approval.
Long-term Debt
On July 21, 2009, the Company completed the issuance and sale of $500 million aggregate principal amount of 7.875% Senior Notes. Net proceeds to the Company, after underwriting discount and offering expenses, were $492 million. The Company intends to use the net proceeds from the offering for general corporate purposes. Interest on the Senior Notes is payable in semi-annual installments of $19.7 million on February 1 and August 1 of each year, commencing in 2010. No principal payments are required prior to maturity.
The Company may, at its option, redeem all or part of the Senior Notes at any time at a make-whole price. The Senior Notes are general unsecured, senior obligations that rank (a) pari passu in right of payment with any of the Company’s existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes, including any indebtedness under the Company’s senior revolving credit facility (other than letter of credit reimbursement obligations that are secured by cash deposits), (b) effectively junior to the Company’s existing and future secured indebtedness (including indebtedness under its secured notes issued pursuant to the MARAD Title XI program to finance several offshore drilling rigs), in each case, to the extent of the value of the Company’s assets constituting collateral securing that indebtedness and (c) effectively junior to all existing and future indebtedness and other liabilities of the Company’s subsidiaries (other than indebtedness and liabilities owed to the Company).
In August 2009, we fixed the interest rate for the remaining term on the $65.7 million of outstanding MARAD debt collateralized by the offshore rig, Bob Keller, at an annual rate of 3.525%. Prior to that time, the rate floated based on a short-term commercial-paper rate plus 0.15%.
In November 2009, we fixed the interest rate for the remaining term on the $124.9 million of outstanding MARAD debt collateralized by the offshore rig, Bob Palmer, at an annual rate of 3.158%. Prior to that time, the rate floated based on a short-term commercial-paper rate plus 0.25%.
Rowan’s first two Tarzan Class jack-up rigs and each of our four Super Gorilla class rigs were substantially financed through long-term bank loans guaranteed by the U.S. Department of Transportation’s Maritime Administration (“MARAD”). Under the MARAD Title XI program, we obtained financing as a reimbursement for qualifying expenditures up to a pre-approved limit and based upon actual construction progress. Each note requires semi-annual payments of principal and interest and is secured by a preferred mortgage on the rig. The following table summarizes the status of each of our Title XI borrowings at December 31, 2009 (dollars in millions):
Our debt agreements contain provisions that require minimum levels of working capital and stockholders’ equity and limit the amount of long-term debt and, in the event of noncompliance, restrict investment activities, asset purchases and sales, lease obligations, borrowings and mergers or acquisitions. Our debt agreements also specify the minimum insurance coverage for our financed rigs. The extent of hurricane damage sustained throughout the Gulf Coast area in recent years has dramatically increased the cost and reduced the availability of insurance coverage for windstorm losses. As a result, we determined that windstorm coverage meeting the requirements of our existing debt agreements was cost-prohibitive. At the Company’s request, MARAD waived certain windstorm insurance coverage requirements under the loan agreements, for which the Company agreed to a covenant to maintain a minimum cash balance, which is currently $25 million. Rowan remains subject to restrictions on the use of certain insurance proceeds should the Company experience future windstorm losses. Each of these security provisions will be released by MARAD should Rowan be able to obtain windstorm coverage that satisfies the original terms of its debt agreements.
In June 2008, we entered into a three-year $155 million revolving credit facility, which we intend to use, as necessary, for general corporate purposes. The underlying credit agreement limits new borrowings, requires minimum cash flows, provides that the facility will not be available in the event of a material adverse change in our condition, operations, business, assets, liabilities or ability to perform, and otherwise contains restrictions similar to those noted above. We had no borrowings outstanding under the credit facility at December 31, 2009. We believe that funding under the credit facility continues to be available, if necessary.
We were in compliance with each of our debt covenants at December 31, 2009 and, based on current projections, we expect to be in compliance in 2010. We believe our most restrictive financial covenant is the requirement that our prior 12-month earnings before interest, taxes and depreciation be at least three times interest expense. At December 31, 2009, we exceeded that requirement by $579 million.
Pension Obligations
Minimum pension contributions are determined based upon actuarial calculations of pension assets and liabilities that involve, among other things, assumptions about long-term asset returns and interest rates. Similar calculations were used to estimate pension costs and obligations as reflected in our consolidated financial statements. As of December 31, 2009, our financial statements reflected an aggregate unfunded pension liability of $195 million, most of which relates to our drilling employees’ plan. In order to slow the rate at which plan benefits were growing, we amended the benefit formula for new drilling plan entrants effective January 1, 2008, and further amended the plan for remaining active participants effective July 1, 2009. The plan changes that became effective in 2009 resulted in an approximately $15 million annualized reduction in pension expense. Despite the changes to the drilling plan, we will need to make significant pension contributions over the next several years, and additional funding would be required if asset values decline. We currently expect to make minimum pension contributions of approximately $57 million in 2010.
Cash Dividends
In May 2006, our Board of Directors approved a regular quarterly cash dividend of $0.10 per common share, which we paid approximately every three months thereafter through November 2008. In January 2009, in light of prevailing business conditions, our Board of Directors decided to discontinue the payment of dividends, and no dividends have been paid since that time. Future dividends, if any, will only be paid at the discretion of the Board of Directors. At December 31, 2009, we had approximately $615 million of retained earnings available for distribution to stockholders under provisions of our debt agreements. We do not expect to pay dividends in the foreseeable future.
Proceeds from Asset Disposals
In 2008, we sold our London office building for $17.6 million and a land rig for $10.8 million, and recognized gains of $14.5 million and $4.7 million, respectively. In 2008 we also received approximately $16.5 million in cash and recognized a $5.4 million gain in connection with the sale of our Fourchon, Louisiana service facility.
In 2008, we lost the jack-up rig Rowan-Anchorage during Hurricane Ike. The rig was insured for $60 million and subject to a $17.5 million deductible. In 2008, we received the full $42.5 million of insurance proceeds and recognized a $37.1 million gain.
In 2005, we sold our semi-submersible rig, the Rowan-Midland, for approximately $60 million in cash, which was received over a 15-month period ending in January 2007, at which time title to the rig was transferred to the buyer. We retained ownership of much of the drilling equipment on the rig through 2006 and 2007 and continued to provide a number of operating personnel under a separate services agreement through February 2007. The transaction was accounted for as a sales-type lease with the expected gain on sale and imputed interest income of approximately $46 million deferred until the net book value of the rig had been recovered. During 2007, we received remaining payments totaling $23.4 million and recognized such amount as additional gain on the sale. Another $14.1 million of gain was realized in 2007 on the June sale of our Alaska drilling camps.
Contractual Obligations and Commercial Commitments
The following is a summary of our contractual obligations at December 31, 2009 (dollars in millions):
We periodically employ letters of credit or other bank-issued guarantees in the normal course of our businesses, and had outstanding letters of credit of approximately $42.0 million at December 31, 2009.
Based on current and anticipated near-term operating levels, we believe that operating cash flows together with existing working capital and our currently available borrowing capacity will be adequate to sustain planned capital expenditures and debt service and other requirements at least through the remainder of 2010.
Contingent Liabilities
Reference should be made to Note 6 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K for a discussion of the status of significant legal proceedings.
Critical Accounting Policies and Management Estimates
Rowan’s significant accounting policies are presented in Note 2 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K. These policies, and management judgments, assumptions and estimates made in their application underlie reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. We believe that our most critical accounting policies and management estimates involve revenue recognition (primarily upfront service fees for equipment moves and modifications and longer-term manufacturing projects), inventory (primarily valuation allowances for excess and obsolete inventories), property and depreciation (particularly capitalizable costs, useful lives and salvage values), carrying values of long-lived assets, pension and other postretirement benefit liabilities and costs (specifically assumptions used in actuarial calculations), and income taxes (particularly our estimated reserves for uncertain tax positions), as changes in such policies and/or estimates would produce significantly different amounts from those reported herein.
Revenue recognition
Our drilling contracts generally provide for payment on a day rate basis, and revenues are recognized as the work progresses with the passage of time. We frequently receive lump-sum payments at the outset of a drilling assignment as upfront service fees for equipment moves or modifications, and such payments (and related costs) are recognized as drilling revenues (and expenses) over the contract period. At December 31, 2009, we had deferred $38.4 million of revenues and $27.5 million of costs related to such upfront service fees, with such amounts primarily related to mobilization and modification activities in connection with our foreign drilling contracts.
We also recognize revenue for certain reimbursable costs. Each reimbursable item and amount is stipulated in our drilling contract with the customer, and such items and amounts frequently vary between contracts. We have recognized reimbursable costs on the gross basis, as both revenues and expenses, because we are the primary obligor in the arrangement, we have discretion in supplier selection, we are involved in determining product or service specifications and we assume full credit risk related to the reimbursable costs.
We generally recognize manufacturing sales and related costs when title passes as products are shipped. Revenues from longer-term contracts such as for the construction of offshore rigs and rig kits are recognized on the percentage-of-completion basis using contract costs incurred relative to total estimated project costs. An offshore rig construction project typically occurs over a two-year period at our Vicksburg, Mississippi, shipyard and includes a significant labor cost component for fabrication and assembly. A rig kit includes selected rig components and parts manufactured over a six- to nine-month period in our Longview, Texas, facility. Costs are recorded separately for each offshore rig or rig kit project, and by significant activity or component within each project, and include materials issued to the project, labor expenses that are incurred directly for the project and overhead expenses that are allocated across all projects at consistent rates per labor hour.
Incurred costs include only those that measure project work performed. Material costs incurred, for example, do not include materials purchased but remaining in inventory. Only when such materials have been used in production on the project are they included in incurred project costs. The determination of total estimated project costs is performed monthly based upon then-current information. This process involves an evaluation of progress towards project milestones and an assessment of work left to complete each project activity or component, and is based on physical observations by project managers and engineers. An estimate of project costs is then developed for each significant activity or component based upon the assessment of project status, actual costs incurred to date and outstanding commitments for project materials and services. We do not recognize any estimated profit until such projects are at least 10% complete, though a full provision is made immediately for any anticipated losses.
During 2007, we recognized a $15.8 million loss on our external rig construction project, bringing the total loss on the project to approximately $17.9 million. This was the first rig construction project for an external customer that we had performed in over a decade, and we have no further plans for additional external rig construction projects at this time. With respect to our rig kits, due to the smaller size and duration of the projects and lesser labor cost component, we have not experienced any significant fluctuations in the percentage-of-completion measurements, nor have we incurred any losses on such projects. In 2009 we recognized $101.4 million of manufacturing revenues and $69.5 million of costs related to rig kit projects on the percentage-of-completion basis.
Inventory
Inventory is carried at the lower of average cost or estimated net realizable value. Costs include labor, material and an allocation of production overhead. We determine valuation allowances or reserves for inventory based on historical usage of inventory on-hand, assumptions about future demand based on market conditions, and estimates about potential alternative uses, which are usually limited. Our inventory generally consists of spare parts, work in process, and raw materials to support ongoing manufacturing operations and the Company’s installed base of drilling, mining and timber equipment. Customers rely on us to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The estimated carrying value of our inventory therefore ultimately depends upon demand driven by oil, natural gas and other commodity prices, general economic conditions worldwide and the potential obsolescence of various types of equipment we sell, among other factors. At December 31, 2009 and 2008, our inventory reserves totaled 8% and 13% of gross inventory, respectively. As a result of declines in oil and natural gas prices, the onset of global recession and weakness in capital markets in 2008, we reduced our estimates of the future usage of our drilling equipment inventories and significantly increased our inventory valuation reserves at December 31, 2008.
Further deterioration in worldwide demand for oil, natural gas and certain other commodities, or the development of new technologies which make older drilling, mining and timber equipment technologies obsolete, could require us to record additional reserves to reduce the value of our inventory.
Property and depreciation
Expenditures for new property or enhancements to existing property are capitalized, and expenditures for maintenance and repairs are charged to operations as incurred. Capitalized cost includes labor expended during installation and, on newly constructed assets, a portion of interest cost incurred during the construction period. We provide depreciation under the straight-line method from the date an asset is placed into service based upon estimated service lives ranging up to 40 years and salvage values ranging up to 20%. Thirteen of our twenty-three jack-up rigs were placed into service at various dates during the period from 1971 to 1986. Many of those rigs had met or far exceeded their assigned useful lives of 12 to 15 years by the time our Super Gorilla class rig, the Gorilla V, was delivered in 1998. The Super Gorilla class and the subsequent Tarzan Class and 240C class have been assigned 25-year useful lives. Each class of rig has been specifically designed to achieve greater drilling performance while encountering tougher well conditions and employs technological advances in load-bearing capability, power distribution, and solids control designed to provide more efficient drilling to greater depths, helping to ensure continuing economic life to the Company.
Impairment of long-lived assets
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or our inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry has historically been highly cyclical and it is not unusual for rigs to be unutilized or underutilized for extended periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of excess supply, rigs are frequently contracted at or near cash break-even rates for extended periods. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic region. Our rigs are mobile and may generally be moved from regions with excess supply, if economically feasible.
Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs and are based on management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future expected utilization, contract rates, expense levels and capital requirements of our drilling rigs. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different carrying values of assets and operating results.
Pension and other postretirement benefit liabilities and costs
Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, annual compensation increases, mortality rates and other factors. Key assumptions at December 31, 2009, included discount rates ranging from 5.83% to 5.97%, an expected long-term rate of return on pension plan assets of 8% and annual healthcare cost increases ranging from 8.7% in 2010 to 4.5% in 2029 and beyond. The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $90 million, while a one-percentage-point change in the expected long-term rate of return on plan assets would change annual net benefits cost by approximately $3.5 million. A one-percentage-point increase in the assumed healthcare cost trend rate would increase 2010 net other postretirement benefit cost by $0.6 million.
Income taxes
As discussed in Note 9 to the financial statements, in 2009 we recognized tax benefits of $25 million as a result of applying our facts to a recent third-party tax case that provides a more favorable tax treatment for certain foreign contracts entered into in prior years. In accordance with accounting guidelines for income tax uncertainties, we evaluate a tax position to determine if it is more likely than not that the tax position will be sustained upon examination, based on its merits. A tax position that meets the more-likely-than-not recognition threshold is subject to a measurement assessment to determine the amount of benefit to recognize in income for the period, and a reserve, if any. Our income tax returns are subject to audit by U.S. federal, state, and foreign tax authorities. Determinations by such taxing authorities that differ materially from our recorded estimates, either favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows. We believe our reserve for uncertain tax positions totaling $55 million at December 31, 2009, is properly recorded in accordance with the accounting guidelines.
New Accounting Standards
In October 2009, the FASB issued Accounting Standards Update (“ASU”) No. 2009-13, Revenue Recognition (Topic 605), Multiple-Deliverable Revenue Arrangements, a consensus of the FASB Emerging Issues Task Force. ASU No. 2009-13 addresses accounting by vendors who provide multiple products or services to customers at different points in time or over different time periods. Specifically, ASU No. 2009-13 eliminates the residual method of allocating revenues to each activity and requires that revenue be allocated at inception of the arrangement to all deliverables using a relative selling price method. ASU No. 2009-13 is effective for fiscal years beginning on or after June 15, 2010 and may be applied prospectively for arrangements entered into after the effective date or retrospectively for all periods presented. The Company is currently studying what impact, if any, adoption may have on its financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Rowan’s outstanding debt at December 31, 2009, was comprised entirely of fixed-rate debt with a carrying value of $852.4 million, bearing a weighted-average annual interest rate of 6.2%. Due to the fixed-rate nature of the Company’s debt, management believes the risk of loss due to changes in market interest rates is not material.
The majority of Rowan’s transactions are denominated in United States dollars. The Company has some exposure to currency exchange fluctuations primarily in Brazil and Australia as a result of its manufacturing presence in those countries. In order to reduce the impact of exchange rate fluctuations, Rowan generally requires customer payments to be in U.S. dollars and limits foreign currency holdings to the extent they are needed to pay liabilities denominated in such currencies. The Company recognized a net foreign currency gain of $5.4 million in 2009 and a loss of $10.8 million in 2008, primarily attributable to operations in Australia and Brazil.
Fluctuating commodity prices affect Rowan’s future earnings materially to the extent that they influence demand for the Company’s products and services. As a general practice, Rowan does not hold or issue derivative financial instruments.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Rowan Companies, Inc.
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
Rowan Companies, Inc.
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
Rowan Companies, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements.
Rowan Companies, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
See Notes to Consolidated Financial Statements.
Rowan Companies, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Rowan Companies, Inc., operating through its drilling subsidiaries, is a major provider of international and domestic oil and gas contract drilling services. Rowan’s wholly owned manufacturing subsidiary, LeTourneau Technologies, Inc. (“LeTourneau”), produces equipment for the international and domestic oil and gas drilling, mining and timber industries.
The consolidated financial statements are presented in U.S. dollars in accordance with accounting principles generally accepted in the United States of America and include the accounts of Rowan Companies, Inc. and its subsidiaries (hereafter referred to as “Rowan” or the “Company”), all of which are wholly owned. Intercompany balances and transactions are eliminated in consolidation. Certain prior period amounts have been reclassified to conform to the current presentation.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles (“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 those estimates.
Revenue and Expense Recognition
Drilling Services. Rowan’s drilling contracts generally provide for payment on a daily rate basis, and revenues are recognized as the work progresses with the passage of time. Rowan frequently receives lump-sum payments at the outset of a drilling assignment as upfront service fees for equipment moves or modifications, and such payments (and related costs) are recognized as drilling revenues (and expenses) over the contract period. Drilling revenues received but unearned are included in current and other liabilities and totaled $38.4 million and $47.6 million at December 31, 2009 and 2008, respectively. Deferred drilling costs are included in prepaid expenses and other assets and totaled $27.5 million and $32.9 million at December 31, 2009 and 2008, respectively.
Rowan also recognizes revenue for certain reimbursable costs. Each reimbursable item and amount is stipulated in the Company’s contract with the customer, and such items and amounts frequently vary between contracts. The Company recognizes reimbursable costs on the gross basis, as both revenues and expenses, because Rowan is the primary obligor in the arrangement, has discretion in supplier selection, is involved in determining product or service specifications and assumes full credit risk related to the reimbursable costs.
Manufacturing Sales and Services. Rowan generally recognizes revenues and costs from sales of manufactured products when title passes as products are shipped. Revenues from longer-term contracts such as for the construction of offshore rigs and rig kits are recognized on the percentage-of-completion basis using contract costs incurred relative to total estimated contract costs. An offshore rig construction project typically occurs over a two-year period at the Company’s Vicksburg, Mississippi, shipyard and includes a significant labor cost component for fabrication and assembly. Rowan’s latest offshore rig construction project for an external customer was completed in 2007, and the Company has no such projects currently underway. A rig kit includes selected rig components and parts manufactured over a six- to nine-month period at the Company’s Longview, Texas, facility. Costs are recorded separately for each offshore rig or rig kit project, and by significant activity or component within each project, and include materials issued to the project, labor expenses that are incurred directly for the project and overhead expenses that are allocated across all projects at consistent rates per labor hour. Incurred costs include only those costs that measure project work performed. Material costs incurred, for example, do not include materials purchased but remaining in inventory. Only when such materials have been used in production on a project are they included in incurred project costs. The determination of total estimated project costs is performed monthly based upon then-current information. This process involves an evaluation of progress towards project milestones and an assessment of work left to complete each project activity or component, and is based on physical observations by project managers and engineers. An estimate of project costs is then developed for each significant activity or component based upon the assessment of project status, actual costs incurred to date, and outstanding commitments for project materials and services. The Company does not recognize any estimated profit until projects are at least 10% complete, though a full provision is made immediately for any anticipated losses.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the status of long-term manufacturing contracts in process. Payments, revenues and costs are cumulative from inception of the contract through the date indicated. Payments include those received for contracts in progress or not yet begun and completed contracts with outstanding collections (in thousands):
Manufacturing service revenues are recognized as the work progresses, and totaled $22.9 million, $21.1 million and $21.9 million in 2009, 2008 and 2007, respectively.
Product Warranties
Rowan’s manufacturing operations offer warranties and parts guarantees extending for stipulated periods of ownership or hours of usage, whichever occurs first. In most cases, dealers of the Company’s products perform the warranty work. For drilling equipment, the Company generally performs warranty work directly and accrues for estimated future warranty costs based on historical experience. Accrued liabilities for product warranties totaled $10.4 million and $9.9 million at December 31, 2009 and 2008, respectively.
Cash Equivalents
Cash equivalents consist of highly liquid temporary cash investments with maturities no greater than three months at the time of purchase.
Accounts Receivable and Allowance for Doubtful Accounts
Inherent in the Company’s revenue recognition policy is the assessment of receivable collectability, and an allowance for uncollectible accounts, recorded as an offset to accounts receivable, is estimated to cover the risk of credit losses. The allowance is based on historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. The Company’s allowance for uncollectible accounts was $3.1 million and $1.2 million at December 31, 2009 and 2008, respectively.
Receivables included unreimbursed costs related to the salvage of lost or damaged rigs and related equipment totaling $29.5 million and $53.2 million at December 31, 2009 and 2008, respectively. See Note 6 for additional information regarding the Company’s salvage operations and related insurance reimbursements.
Inventories
Inventories are carried at the lower of average cost or estimated net realizable value. Costs include labor, material and an allocation of production overhead. Management regularly reviews inventory for obsolescence and reserves for items unlikely to be sold in order to reduce the cost to its estimated realizable value. Allowances for excess and obsolete inventories are determined based on both historical and projected usage.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the changes in the Company’s inventory reserves for each of the past three years (in thousands):
Property and Depreciation
Rowan provides depreciation under the straight-line method from the date an asset is placed into service until it is sold or becomes fully depreciated based on the following estimated lives and salvage values. Lives for jack-ups reflect weighted averages of the hull, legs, other major components and related equipment:
Expenditures for new property or enhancements to existing property are capitalized and depreciated over the asset’s estimated useful life. Expenditures for maintenance and repairs are charged to operations as incurred. As assets are sold or retired, property cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in results of operations. Rowan capitalizes a portion of interest cost incurred during the construction period. Long-lived assets are reviewed for impairment whenever circumstances indicate their carrying amounts may not be recoverable, based upon estimated future cash flows.
The amounts of depreciation and amortization expense, capital expenditures and repairs and maintenance expense by operating segment for each of the last three years are presented in Note 10.
Foreign Currency Transactions
The U.S. dollar is the functional currency for all of Rowan’s operations. Non-U.S. subsidiaries translate their nonmonetary assets at exchange rates prevailing at the time they were acquired; monetary assets and liabilities are translated at year-end rates. Resulting translation gains and losses and foreign currency transaction gains and losses are included in “other income” on the Company’s Consolidated Statements of Income. In order to reduce the impact of exchange rate fluctuations, Rowan generally requires customer payments to be in U.S. dollars and limits foreign currency holdings to the extent they are needed to pay liabilities denominated in such currencies. The Company recognized a net foreign currency gain of $5.4 million in 2009 and a loss of $10.8 million in 2008, primarily attributable to operations in Australia and Brazil.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes
Rowan recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statement and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. See Note 9 for further information regarding the Company’s income tax assets and liabilities.
Environmental Costs
Environmental remediation costs are accrued using estimates of future monitoring, testing and clean-up costs where it is probable that such costs will be incurred. Estimates of future monitoring, testing and clean-up costs, and assessments of the probability that such costs will be incurred incorporate many factors, including approved monitoring, testing and/or remediation plans; ongoing communications with environmental regulatory agencies; the expected duration of remediation measures; historical monitoring, testing and clean-up costs, and current and anticipated operational plans and manufacturing processes. Ongoing environmental compliance costs are expensed as incurred, and expenditures to mitigate or prevent future environmental contamination are capitalized. Environmental liabilities at December 31, 2009 and 2008, were not material. See Note 6 for further information regarding the Company’s environmental liabilities.
Income Per Common Share
Basic income per share is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding during the period. Diluted income per share includes the additional effect of all potentially dilutive securities, which includes dilutive stock options and stock appreciation rights, contingently issuable shares such as performance-based stock awards, and shares issuable under the 1998 Convertible Debenture Incentive Plan (see Note 7).
A reconciliation of shares for basic and diluted income per share for each of the past three years is set forth below. There were no income adjustments to the numerators of the basic or diluted computations for the periods presented (in thousands):
The following table sets forth the share effects of securities excluded from the diluted calculations because they were antidilutive for the periods indicated. Options and other potentially dilutive securities are antidilutive when the exercise or conversion price exceeds the average stock market price during the period. Such securities could potentially dilute earnings per share in the future (in thousands):
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Comprehensive Income
Comprehensive income is comprised of net income and other comprehensive income (loss). Other comprehensive income (loss) for 2009, 2008 and 2007, consisted solely of adjustments relating to pension and other postretirement benefits, the components of which were as follows, net of income taxes (in thousands):
See Note 8 for further information regarding the Company’s pension and other postretirement benefits.
New Accounting Standards
In June 2009, the Financial Accounting Standards Board (“FASB”) issued The FASB Accounting Standards Codification and Hierarchy of Generally Accepted Accounting Principles, which establishes the Accounting Standards Codification (“ASC”) as the authoritative source of U.S. GAAP to be applied to nongovernmental entities. On the effective date, the ASC superseded all then-existing non-SEC accounting and reporting standards, with certain limited exceptions. Concurrently, all nongrandfathered, non-SEC accounting literature not included in the ASC was deemed nonauthoritative. The ASC will be updated by Accounting Standards Updates (“ASUs”), which will replace guidance previously issued as FASB Statements, Interpretations, Staff Positions and other non-SEC GAAP. Rowan adopted the ASC in the third quarter of 2009. Adoption had no material impact on the Company’s financial statements other than to change references to previously issued accounting standards to conform to the ASC.
In May 2009, the FASB issued new guidance under ASC 855, Subsequent Events. The new guidance establishes general standards of accounting and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued, and is effective for interim or annual periods ending after June 15, 2009. Rowan adopted the provisions of ASC 855 in the second quarter of 2009. Adoption had no material impact on the Company’s financial statements. (See Note 13.)
In October 2009, the FASB issued Accounting Standards Update No. 2009-13, Revenue Recognition (Topic 605), Multiple-Deliverable Revenue Arrangements, a consensus of the FASB Emerging Issues Task Force. ASU No. 2009-13 addresses accounting by vendors who provide multiple products or services to customers at different points in time or over different time periods. Specifically, ASU No. 2009-13 eliminates the residual method of allocating revenues to each activity and requires that revenue be allocated at inception of the arrangement to all deliverables using a relative selling price method. ASU No. 2009-13 is effective for fiscal years beginning on or after June 15, 2010, and may be applied prospectively for arrangements entered into after the effective date or retrospectively for all periods presented. The Company is currently studying what impact, if any, adoption may have on its financial statements.
In December 2008, the FASB issued new guidance under ASC 715, Compensation - Retirement Benefits. The new guidance requires sponsors of defined benefit pension or other postretirement plans to disclose (i) how plan asset investment allocation decisions are made, (ii) the fair value of each major category of plan assets, (iii) the inputs and valuation techniques used to develop fair value measurements, and (iv) significant concentrations of risk in plan assets. The Company adopted the new disclosure provisions of the guidance effective December 31, 2009. (See Note 8.)
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 3 - ACCRUED LIABILITIES
Accrued liabilities consisted of the following (in thousands):
NOTE 4 - LONG-TERM DEBT
Long-term debt consisted of the following (in thousands):
Annual maturities over the next five years are $64.9 million in 2010, $52.2 million in 2011, $45.0 million in 2012, $37.9 million in 2013 and $22.5 million in 2014.
The Company’s Title XI notes (the “Title XI Notes”) are guaranteed by the U.S. Government under the U.S. Department of Transportation’s Maritime Administration (“MARAD”) Title XI Federal Ship Financing Program. Principal and interest on the Title XI Notes are payable semiannually on various dates throughout the year.
On July 21, 2009, Rowan issued $500 million aggregate principal amount of 7.875% Senior Notes due 2019 (the “Senior Notes”), in an SEC registered offering at a price to the public of 99.341% of the principal amount. After deduction for underwriters’ discount and offering expenses, the Company received net proceeds of approximately $492 million, and expects to use the net proceeds for general corporate purposes. The Senior Notes will mature on August 1, 2019. Interest on the Senior Notes is payable semiannually on February 1 and August 1 of each year, beginning February 1, 2010, to the holders of record on the immediately preceding January 15 or July 15, respectively.
The Senior Notes are general unsecured, senior obligations. Accordingly, they rank:
• senior in right of payment to all of the Company’s subordinated indebtedness, if any;
• pari passu in right of payment with any of the Company’s existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes, including any indebtedness under the Company’s senior revolving credit facility (other than letter of credit reimbursement obligations that are secured by cash deposits);
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
• effectively junior to the Company’s existing and future secured indebtedness (including indebtedness under its secured notes issued pursuant to the MARAD Title XI program to finance several offshore drilling rigs), in each case, to the extent of the value of the Company’s assets constituting collateral securing that indebtedness; and
• effectively junior to all existing and future indebtedness and other liabilities of the Company’s subsidiaries (other than indebtedness and liabilities owed to the Company).
The Company may, at its option, redeem any or all of the Senior Notes at any time for an amount equal to 100% of the principal amount to be redeemed plus a make-whole premium and accrued and unpaid interest to the redemption date. The Company may purchase Senior Notes in the open market, or otherwise, at any time without restriction under the indenture. The Company is not required to make mandatory redemption or sinking fund payments with respect to the Senior Notes.
On November 24, 2009, Rowan fixed the interest rate for the remainder of the term on the Title XI Note collateralized by the offshore rig, Bob Palmer, at an annual rate of 3.158%. Prior to that time, the rate floated based on a short-term commercial-paper rate plus 0.25%.
On August 4, 2009, Rowan fixed the interest rate for the remainder of the term on the Title XI Note collateralized by the offshore rig, Bob Keller, at an annual rate of 3.525%. Prior to that time, the rate floated based on a short-term commercial paper rate plus 0.15%.
On June 23, 2008, Rowan entered into a three-year $155 million revolving credit facility agreement. In July 2008, the Company borrowed $80 million under the facility to complete the purchase of the Cecil Provine and repaid such amount in full in August 2008. The Company had no borrowings under the credit facility outstanding during 2009 or at December 31, 2009.
The Company had $1.0 million of Series C Floating Rate Subordinated Convertible Debentures (the “Convertible Debentures”) outstanding at December 31, 2009, issued pursuant to the Rowan Companies, Inc. 1998 Convertible Debenture Incentive Plan. The Convertible Debentures are convertible into common stock through April 27, 2010, at a price of $28.25 per share for each $1,000 principal amount of debenture. The Convertible Debentures were issued in exchange for promissory notes receivable containing provisions for setoff, protecting Rowan against any credit risk. The Convertible Debentures and notes receivable and related accrued interest have been offset in the consolidated financial statements pursuant to ASC 210-20 of the FASB Accounting Standards Codification. See Note 7 for further information regarding the 1998 Convertible Debenture Incentive Plan.
Rowan’s debt agreements contain provisions that require minimum levels of working capital, stockholders’ equity and “EBITDA,” as defined in the agreements, limit the amount of long-term debt, limit the ability of the Company to create liens that secure debt, engage in sale and leaseback transactions, merge or consolidate with another company and, in the event of noncompliance, restrict investment activities and asset purchases and sales, among other things. Additionally, the revolving credit facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with each of its debt covenants at December 31, 2009.
Rowan’s debt agreements also specify the minimum insurance coverage for the Company’s financed rigs. The extent of hurricane damage sustained throughout the Gulf Coast area in recent years has dramatically increased the cost and reduced the availability of insurance coverage for windstorm losses. As a result, management has determined that windstorm coverage meeting the requirements of the Company’s existing debt agreements was cost-prohibitive. At the Company’s request, MARAD waived certain windstorm insurance coverage requirements under the loan agreements, for which the Company agreed to a covenant to maintain a minimum cash balance, which is currently $25 million. Rowan remains subject to restrictions on the use of certain insurance proceeds should the Company experience future windstorm losses. Each of these security provisions will be released by MARAD should Rowan be able to obtain windstorm coverage that satisfies the original terms of its debt agreements.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 5 - FINANCIAL INSTRUMENTS
Fair Values of Financial Instruments
The carrying amounts of the Company’s cash and cash equivalents and trade receivables and payables approximated their fair values due to their short maturity.
Carrying values and fair values of the Company’s fixed-rate debt at December 31, 2009, were as follows (amounts in thousands):
Concentrations of Credit Risk
Rowan invests its excess cash primarily in time deposits at several large commercial banks with strong credit ratings and high-quality money market accounts and therefore believes that its risk of loss is minimal.
Approximately 90% of the Company’s revenues are attributable to the Drilling Services and Drilling Products and Services segments, and a substantial portion of the Company’s accounts receivable are from customers in the oil and gas drilling industry. The Company’s drilling customers largely consist of international oil and gas exploration companies and foreign national oil companies; Rowan routinely evaluates the credit quality of potential customers and, with respect to manufacturing operations, may require letters of credit, down payments, milestone payments and/or payment in full prior to shipping in some instances. Rowan’s customers are diversified geographically. One customer provided 10% or more of consolidated revenues in any of the last three years - Saudi Aramco accounted for 15% of consolidated revenues in 2009 and 2008, and 13% in 2007. The Company maintains reserves for credit losses and actual losses have been within management’s expectations.
NOTE 6 - COMMITMENTS AND CONTINGENT LIABILITIES
The Company has operating leases covering office space and equipment. Certain of the leases are subject to escalations based on increases in building operating costs. Rental expense under all operating leases was $7.1 million in 2009, $10.9 million in 2008, and $15.4 million in 2007.
At December 31, 2009, future minimum payments to be made under noncancelable operating leases were as follows (in thousands):
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the status of all of the Company’s rigs under construction as of December 31 2009. Project costs include capitalized interest (in millions):
Rowan periodically employs letters of credit or other bank-issued guarantees in the normal course of its businesses, and had outstanding letters of credit of approximately $42.0 million at December 31, 2009.
Legal Proceedings
During 2005, Rowan lost four offshore rigs, including the Rowan-Halifax, and incurred significant damage on a fifth as a result of Hurricanes Katrina and Rita. The Company had leased the Rowan-Halifax under a charter agreement that commenced in 1984 and was scheduled to expire in March 2008. The rig was insured for $43.4 million, a value that Rowan believes to be more than sufficient to satisfy its obligations under the charter agreement, and by a margin sufficient to cover the $6.3 million carrying value of Rowan equipment installed on the rig. However, the parties holding interests in the rig under the charter claimed that the rig should have been insured for its fair market value and sought recovery from Rowan for compensation above the insured value. Thus, Rowan assumed no insurance proceeds related to the Rowan-Halifax and recorded a charge during 2005 for the full carrying value of its equipment. On November 3, 2005, the Company filed a declaratory judgment action styled Rowan Companies, Inc. vs. Textron Financial Corporation and Wilmington Trust Company as Owner Trustee of the Rowan-Halifax 116-C Jack-Up Rig in the 215th Judicial District Court of Harris County, Texas. The owner interests filed a counterclaim for a variety of relief, claiming a right to payment under the charter based on a post-casualty rig valuation of approximately $83 million. The insurance proceeds were placed in escrow. The district court ultimately granted judgment against Rowan for the difference between (a) what Rowan had already paid to the Owner Trustee out of the escrowed insurance proceeds and (b) that rig valuation. On March 31, 2009, the Court of Appeals for the 14th District of Texas reversed this judgment, holding that the Company’s interpretation of the charter was substantially correct, but directing Rowan to pay additional amounts due under the charter. The Company has since made this payment out of the escrowed insurance proceeds. In addition, the Court of Appeals remanded the case for further proceedings in the district court to resolve additional issues and to determine the parties’ respective rights to the balance of the escrowed insurance proceeds, which is currently $21.4 million. The owner interests filed a motion for rehearing of the Court of Appeals’ decision. On October 8, 2009, the Court of Appeals denied the motion, but issued a substitute opinion to clarify the scope of the remand. The Court of Appeals again held that the trial court is to resolve issues concerning the proper disposition of excess insurance proceeds. The Court of Appeals further held that the owner interests’ claim that Rowan breached the charter agreement by failing to maintain adequate insurance remains to be decided by the trial court. The owner interests filed another motion for rehearing, which motion was denied in January 2010. The Company believes that no further payment is owed to the opposing parties under the charter and intends to pursue that position vigorously in all subsequent court proceedings.
During 2004, Rowan learned that the Environmental and Natural Resources Division, Environmental Crimes Section of the U.S. Department of Justice (“DOJ”) had begun conducting a criminal investigation of environmental matters involving several of the Company’s offshore drilling rigs, including a rig known as the Rowan-Midland, which at various times operated in the Gulf of Mexico. In 2007, the Company entered into a plea agreement with the DOJ, as amended, under which the Company paid fines and made community service payments totaling $9 million and agreed to be subject to unsupervised probation for a period of three years. During this period the Company must ensure that it commits no further criminal violations of federal, state, or local laws or regulations and must also continue to implement its comprehensive Environmental Management System Plan. Subsequent to the conduct at issue, the Company sold the Rowan-Midland to a third party. Concurrent with the plea agreement, the Environmental Protection Agency approved a compliance agreement
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
with Rowan which, among other things, contains a certification that the conditions giving rise to the violations to which the Company entered guilty pleas have been corrected. The Company believes that if it fully complies with the terms of the compliance agreement, it will not be suspended or debarred from entering into or participating in contracts with the U.S. Government or any of its agencies.
On January 3, 2008, a civil lawsuit styled State of Louisiana, ex. rel. Charles C. Foti, Jr., Attorney General vs. Rowan Companies, Inc. was filed in U.S District Court, Eastern District of Texas, Marshall Division, seeking damages, civil penalties and costs and expenses for alleged commission of maritime torts and violations of environmental and other laws and regulations involving the Rowan-Midland and other facilities in areas in or near Louisiana. Subsequently, the case was transferred to U.S. District Court, Southern District of Texas, Houston Division. The Company intends to vigorously defend its position in this case but cannot estimate any potential liability at this time.
In June 2007, Rowan received a subpoena for documents from the U.S. District Court, Eastern District of Louisiana, relating to a grand jury hearing. The agency requesting the information is the U.S. Department of the Interior, Office of Inspector General Investigations. The documents requested include all records relating to use of the Company’s entertainment facilities and entertainment expenses for a former employee of the Minerals Management Service, U.S. Department of Interior, and other records relating to items of value provided to any official or employee of the U.S. Government. The Company fully cooperated with the subpoena.
The construction of Rowan’s fourth Tarzan Class jack-up rig, the J.P. Bussell, was originally subcontracted to an outside Gulf of Mexico shipyard, Signal International LLC (“Signal”), and scheduled for delivery in the third quarter of 2007 at a total cost of approximately $145 million. As a result of various problems encountered on the project, Rowan exercised its right to take over the rig construction pursuant to the terms of the construction contract, and Signal turned the rig over to the Company in March 2008. The rig was later completed by the Company more than one year behind schedule, and its final cost was approximately 40% over the original estimate. Accordingly, Rowan has declared Signal in breach of contract and initiated court proceedings styled Rowan Companies, Inc. and LeTourneau Technologies, Inc. vs. Signal International LLC in the 269th Judicial District Court of Harris County, Texas, to recover the cost to complete the rig over and above the agreed contract price and other damages, plus interest. Signal filed a separate counterclaim against Rowan styled Signal International LLC vs. LeTourneau, Inc., in the U.S. District Court, Southern District of Texas, Houston Division, alleging breach of contract and claiming unspecified damages for cost overruns. That case has been administratively stayed in favor of the State Court proceeding filed by the Company. Signal reasserted its claimed damages for amounts owed and additional costs incurred, totaling approximately $88 million, as a counterclaim in the State Court suit. The Company intends to vigorously defend its rights under the contract. The Company does not believe that it is probable that Signal will prevail in its claim and has made no accrual for such at December 31, 2009.
On December 9, 2008, the Company received a termination letter from a customer regarding two contracts for the purchase of nine land rigs in the amount of $90.2 million and nine top drives in the amount of $10.3 million. In the letter, the customer alleged that the top drive contract had not become effective because a down payment was never made and further alleged that they had the right to terminate the land rig contract because of late deliveries. The Company firmly believes that both allegations are without merit. Accordingly, the Company initiated court proceedings styled LeTourneau Technologies Drilling Systems, Inc. (“LTDSI”) vs. Nomac Drilling, LLC (“Nomac”) in State District Court, Harris County, Texas, on December 13, 2008, requesting a declaratory judgment and alleging anticipatory repudiation. On January 5, 2009, the case was removed to U.S. District Court, Southern District of Texas, Houston Division. In December 2009, the Company entered into a Compromise Settlement Agreement, including the dismissal of court proceedings, termination of the two contracts for the purchase of drilling equipment, and other terms deemed satisfactory to the Company.
During 2005, the Company learned that the DOJ was conducting an investigation of potential antitrust violations among helicopter transportation providers in the Gulf of Mexico. Rowan's former aviation subsidiary, which was sold effective December 31, 2004, received a subpoena in connection with the investigation. The Company has not been contacted by the DOJ, but the purchaser claimed that Rowan is responsible for any exposure it may have. The Company has disputed that claim. On August 6, 2009, the Company received a letter from the purchaser informing the Company that Rowan’s former aviation subsidiary has been named as a defendant in a purported class action lawsuit alleging antitrust violations and claiming that Rowan is responsible for any exposure the purchaser may have under the lawsuit. The Company disputes that claim, as well.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Rowan is involved in various other legal proceedings incidental to its businesses and is vigorously defending its position in all such matters. The Company believes that there are no other known contingencies, claims or lawsuits that could have a material adverse effect on its financial position, results of operations or cash flows.
NOTE 7 - STOCKHOLDERS’ EQUITY
Stock-Based Incentive Plans
In May 2009, stockholders of the Company approved the adoption of the 2009 Rowan Companies, Inc. Incentive Plan (the “2009 Plan” or “Plan”), which authorizes the Compensation Committee of the Company’s Board of Directors to grant employees and nonemployee directors, through May 2019, incentive awards covering up to 4,500,000 shares of Rowan common stock. The awards may be in the form of stock options, stock appreciation rights, restricted stock awards, restricted stock units, and performance-based awards, in which the number of shares issued is dependent on the achievement of certain long-term market or performance conditions over a specified period. The 2009 Plan replaced the 2005 Rowan Companies, Inc. Long-Term Incentive Plan. All awards outstanding under the 2005 Plan remained outstanding at the effective date of the 2009 Plan. Subsequent grants can only be made under the 2009 Plan.
Shares issued pursuant to the Plan may be treasury shares, authorized but unissued shares, or shares acquired in the open market. The Plan provides that shares not issued as a result of forfeitures or the withholding of shares for the payment of income taxes or exercise price, for example, shall thereafter become available for the grant of additional awards. As of December 31, 2009, there were 3,268,567 shares available for future grant under the Plan.
Generally, restricted stock, stock appreciation rights and options grants awarded by the Company have multiple vesting dates. The Company recognizes compensation cost for such awards on a straight-line basis over the requisite service period for the entire award. Compensation cost under all stock-based incentive awards recognized in income is presented below (in thousands):
Restricted Stock - Restricted stock represents a full share of Rowan common stock issued with a restrictive legend that prevents its sale until the restriction is later removed. In general, the shares vest and the restrictions lapse in one-third increments each year over a three-year service period, or in some cases, cliff vest at the end of a two- or three-year service period. The Company measures compensation related to each share based upon the market price of the common stock on the date of the grant, adjusted for the estimated effect of the restriction. A summary of restricted stock activity for the year ended December 31, 2009, is presented below:
The fair value of shares vested (measured at the vesting date) in 2009, 2008 and 2007 was $3.2 million, $6.4 million, and $5.2 million, respectively. As of December 31, 2009, unrecognized compensation cost related to nonvested restricted stock totaled $14.9 million, which is expected to be recognized over a weighted-average period of 1.9 years.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restricted Stock Units - Restricted stock units (“RSUs”) are rights to receive a specified number of shares of Rowan common stock or an equivalent value in cash. RSUs are typically granted to nonemployee directors and generally cliff vest at the end of a one-year service period; however, shares are not issued until the director terminates service to the Company. The Company measures compensation related to each unit based upon the market price of the underlying common stock on the grant date. Nonemployee directors were awarded 36,000 RSUs in 2009 with a weighted-average grant-date fair value per share of $17.27, compared to 27,000 RSUs granted in each of 2008 and 2007. The Company issued 13,205 shares of stock with a fair value of $0.3 million in 2009 in connection with the settlement of previously vested RSUs. No shares were issued in either 2008 or 2007 in settlement of outstanding RSUs. As of December 31, 2009, unrecognized compensation cost related to nonvested RSUs totaled $0.2 million, which is expected to be recognized over a weighted-average period of 0.3 years.
Performance-Based Awards - The Committee may grant awards in which payment is contingent upon the achievement of certain market or performance-based conditions over a period of time specified by the Committee. Payment of such awards may be in Rowan common stock or cash as determined by the Committee. The number of awards granted is expressed as the number of shares that would be issued in the event the “target” goal is attained. The number of shares actually issued may range from zero to 200% of the target share amount.
Under the total shareholder return (“TSR”) criterion, under which the number of shares that may be issued is based on the Company’s TSR ranking among an industry peer group at the end of the performance period, fair value is estimated using the Monte Carlo simulation model, which considers the probabilities of the Company’s ending TSR at each rank, the number of shares issuable at each rank, and the expected stock price subject to each rank to determine the probability-weighted expected payout. A TSR criterion is deemed a “market condition” under GAAP. Compensation expense for awards with a market condition is reduced only for forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued, if any. The Company recognizes compensation expense on a straight-line basis over the performance period.
The per-share fair value of awards with return-on-investment (“ROI”) or return-on-capital-employed (“ROCE”) criteria is equal to the market price of the stock on the date of grant. The Company initially accrues compensation expense based on the number of shares that would vest in the event the target goal is met, subject to reduction for estimated forfeitures, and the resulting compensation expense is recognized on a straight-line basis over the performance period. ROI and ROCE criteria are deemed “performance conditions” under GAAP. Compensation expense for awards with performance conditions is remeasured annually based on the Company’s progress towards achieving the performance goal and is recognized for only the actual number of shares that vest. In the event that awards do not vest or lapse as a result of the failure to meet the minimum performance criteria, all previously recognized expense, if any, would be reversed.
A summary of performance-based award activity for the year ended December 31, 2009, is presented below:
Performance-based awards outstanding at January 1, 2009, included those for 99,393 shares (net of 16,398 of forfeitures) granted to a group of key employees in 2006, under which as many as 198,786 shares could have been issued in April 2009 in the event the Company had attained certain goals related to TSR and ROI as compared to an industry peer group. At the conclusion of the three-year performance period in April 2009, the Company’s TSR and ROI rank did not result in the issuance of Rowan common stock, and all such 2006 awards lapsed.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Performance-based awards outstanding at December 31, 2009, consisted of (i) 74,401 shares (net of 16,667 of forfeitures) granted in 2007, under which anywhere from zero to 148,802 shares of Rowan common stock will be issued in May 2010 based upon an equal weighting of the Company’s TSR ranking as compared to an industry peer group and its ROCE over the three-year period then ended, and (ii) 85,015 shares (net of 41,985 of forfeitures) granted in 2008, under which from zero to 170,030 shares of Rowan common stock will be issued in April 2011 based upon an equal weighting of the Company’s TSR ranking as compared to an industry peer group and its ROCE over the three-year period then ended.
No shares were issued in 2009, 2008 or 2007 in connection with performance-based awards. As of December 31, 2009, unrecognized compensation cost related to outstanding performance-based awards totaled $1.3 million, which is expected to be recognized over a weighted-average period of 1.1 years.
Stock Options - Stock options granted to employees generally become exercisable in one-third or one-quarter annual increments over a three or four-year service period at a price not less than 100% of the market price of the stock on the date of grant. Any options not exercised expire ten years after the grant date.
Fair values of options granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions (no options were granted in 2009 or 2007):
The weighted-average grant-date per-share fair value of options granted in 2008 was $7.01.
A summary of stock option activity for the year ended December 31, 2009, is presented below:
The total intrinsic value of options exercised was $1.1 million in 2009, $10.7 million in 2008 and $8.6 million in 2007. As of December 31, 2009, unrecognized compensation cost related to stock options totaled $0.5 million, which is expected to be recognized over a weighted-average period of 1.9 years.
Stock Appreciation Rights - Stock appreciation rights (“SARs”) give the holder of the award the right to receive, at no cost to the employee, shares of Rowan common stock, or cash at the discretion of the Committee, equal in value to the excess of (i) the market price of the stock on the date of exercise over (ii) the exercise price, which is the market price of the stock on the date of grant. SARs granted to employees in 2009 become exercisable in one-third annual increments over a three-year service period. Any SARs not exercised expire ten years after the grant date.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Fair values of SARs granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions (no SARs were granted prior to 2009):
The weighted-average grant-date per-share fair value of SARs granted in 2009 was $9.03.
A summary of SARs activity for the year ended December 31, 2009, is presented below:
As of December 31, 2009, unrecognized compensation cost related to SARs totaled $3.5 million, which is expected to be recognized over a weighted-average period of 2.3 years.
Convertible Debenture Incentive Plan
Under the Rowan Companies, Inc. 1998 Convertible Debenture Incentive Plan, as amended, up to $35.0 million principal amount of floating-rate subordinated convertible debentures were authorized for issuance in series from time to time to key employees through April 24, 2008, at a price equal to the higher of (i) the face value plus accrued interest or (ii) the fair value as determined by an independent investment banking firm at the time of purchase. The debentures, to the extent not previously converted or redeemed, are initially convertible into preferred stock, which has no voting rights (except as required by law or the Company’s charter), no dividend and a nominal liquidation preference. The preferred stock is immediately convertible into common stock. From 1998 through 2001, the Company issued convertible debentures with principal amounts aggregating $30.0 million maturing from 2008 through 2011 and convertible into 1,233,719 shares of common stock. As of December 31, 2009, debentures totaling $29.0 million were converted into 1,198,710 shares of common stock, including 992,002 shares in 2008 and 78,707 shares in 2007. No debentures were converted in 2009. The $1.0 million of debentures outstanding at December 31, 2009, are convertible into 35,009 shares of common stock through April 2010.
Stockholder Rights Agreement
In 1992, Rowan adopted a Stockholder Rights Agreement to protect against coercive takeover tactics. The agreement, as amended (the “Rights Agreement”), provided for the distribution to Rowan’s stockholders of one Right for each outstanding share of common stock. Each Right entitled the holder to purchase from the Company one one-hundredth of a share of Series A Junior Preferred Stock of Rowan at an exercise price of $80. The Rights were exercisable only if a person or group knowingly acquired 15% or more of Rowan’s outstanding common stock or made a tender offer for 30% or more of the Company’s outstanding common stock.
On October 30, 2009, Rowan entered into an amendment to the Rights Agreement, pursuant to which the final expiration date for the exercise of Rights was changed to November 2, 2009. The Rights Agreement terminated on November 2, 2009, and ceased to be of any further force and effect.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restrictions on Retained Earnings
Rowan’s debt agreements contain financial covenants that limit the amount the Company may distribute to its stockholders. Under the most restrictive of such covenants, Rowan had approximately $615 million of retained earnings available for distribution at December 31, 2009. Subject to this and other restrictions, the Board of Directors will determine payment, if any, of future dividends or distributions in light of conditions then existing, including the Company’s earnings, financial condition and cash requirements, opportunities for reinvesting earnings, general business conditions and other factors.
NOTE 8 - PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Rowan sponsors defined benefit pension plans covering substantially all of its employees, and provides health care and life insurance benefits upon retirement for certain employees.
The following table presents the changes in benefit obligations and plan assets during the years indicated and the funded status and weighted-average assumptions used to determine the benefit obligation at each year end (in thousands):
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The benefit obligations in the preceding table are the projected benefit obligations (PBO). The PBO, as it relates to pension benefits, is the actuarial present value of benefits accrued based on services rendered to date, and includes the estimated effect of future salary increases. The accumulated benefit obligation (ABO) is also based on services rendered to date, but differs from the PBO in that the ABO is based on actual compensation, excluding the effect of future salary increases. The ABO for all pension plans in the aggregate is presented below (in thousands):
Each of the Company’s pension plans has benefit obligations that exceed the fair value of plan assets.
Rowan expects that the following amounts, which are classified in accumulated other comprehensive loss, a component of stockholders’ equity, will be recognized as net periodic benefits cost in 2010 (in thousands):
Effective July 1, 2009, the Company amended the benefit formula for its largest pension plan for active employees who were earning benefits in the plan prior to January 1, 2008. The effect of the change was to reduce 2009 pension expense by approximately $7.3 million, or $0.04 per share net of tax.
The components of net periodic pension cost and the weighted-average assumptions used to determine net cost were as follows (dollars in thousands):
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The components of net periodic cost of other postretirement benefits and the discount rate used to determine net cost were as follows (dollars in thousands):
The assumed health care cost trend rates used to measure the expected cost of retirement health benefits was 9% for 2010, gradually decreasing to 4.5% for 2029 and thereafter. A one-percentage-point change in the assumed health care cost trend rates would change the reported amounts as follows (in thousands):
The pension plans’ investment objectives for fund assets are: to achieve over the life of the plans a return equal the plans’ expected investment return or the inflation rate plus 3%, whichever is greater; to invest assets in a manner such that contributions are minimized and future assets are available to fund liabilities; to maintain liquidity sufficient to pay benefits when due; and to diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk. Consistent with the investment objectives, the plans have target allocations of 60-80% in equities and 20-40% in fixed income and cash and equivalents. Target allocations within the equity component include the S&P 500 stock index (15-25%), large cap value (5-15%), large cap growth (5-15%), small cap (5-15%), and international (10-30%). The plans will periodically reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses. The plans employ several active managers with proven long-term records in their specific investment discipline.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The fair value of each major category of plan assets as of December 31, 2009, classified by level within the fair value hierarchy (as described in GAAP) is presented below (in thousands):
Assets in the large cap growth, large cap value, small cap growth, and small cap value categories include common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) and include assets invested in separate accounts, commingled funds and an institutional mutual fund. Assets in the international category include a broad range of international equity securities, including both developed and emerging markets, and are invested primarily in a commingled fund. Securities in both the aggregate and “core plus” fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds, and both categories target an average credit rating of “A” or better at all times. Individual securities in the aggregate fixed income category must be investment grade or above at the time of purchase, whereas securities in the core plus category may have a rating of “B” or above. Additionally, the core plus category may invest in foreign securities. Assets in the aggregate and core plus fixed income categories are invested primarily in a commingled fund and an institutional mutual fund, respectively.
To develop the expected long-term rate of return on assets assumption, Rowan considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plans, which was maintained at 8% at December 31, 2009, unchanged from December 31, 2008.
Rowan currently expects to contribute approximately $57.3 million to its pension plans in 2010 and approximately $4.5 million for the direct payment of unfunded other postretirement benefits.
Rowan estimates that the plans will make the following annual payments for pension and other postretirement benefits based upon existing benefit formulas and including amounts attributable to future employee service (in thousands):
Rowan sponsors defined contribution plans covering substantially all employees to which it contributed approximately $9.7 million in 2009, $9.5 million in 2008, and $5.2 million in 2007.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 9 - INCOME TAXES
The detail of income tax provisions is presented below (in thousands):
Rowan’s provision for income taxes differs from that determined by applying the federal income tax rate (statutory rate) to income before income taxes, as follows (in thousands):
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Temporary differences and carryforwards which gave rise to deferred tax assets and liabilities at December 31, 2009 and 2008, were as follows (in thousands):
At December 31, 2009, the Company had approximately $287.4 million of net operating loss carryforwards expiring in 2028 and 2029. Management has determined that no valuation allowances were necessary at December 31, 2009 and 2008, as anticipated future tax benefits relating to all recognized deferred income tax assets are expected to be fully realized when measured against a more likely than not standard.
Undistributed earnings of Rowan’s foreign subsidiaries in the amount of approximately $57.7 million could potentially be subject to additional income taxes of approximately $4 million. The Company has not provided any deferred income taxes on such undistributed foreign earnings because it considers them to be permanently invested abroad.
At December 31, 2009, 2008 and 2007, Rowan had $53.0 million, $3.8 million and $3.4 million, respectively, of net unrecognized tax benefits, all of which would reduce the Company’s income tax provision if recognized. The Company does not expect to recognize significant increases or decreases in unrecognized tax benefits during the next twelve months.
The following table highlights the changes in the Company’s gross unrecognized tax benefits during the years ended December 31 (in thousands):
Interest and penalties relating to income taxes are included in current income tax expense. At December 31, 2009, 2008 and 2007, accrued interest was $0.7 million, $0.8 million and $0.3 million, respectively, and accrued penalties were $0.4 million, $0.3 million and $0.3 million, respectively. To the extent accrued interest and penalties relating to uncertain tax positions are not actually assessed, such accruals will be reversed and the reversals will reduce the Company’s overall income tax provision.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Rowan’s U.S. federal tax returns for 2006 and 2007 are currently under audit by the Internal Revenue Service (“IRS”), and 2002 and later years remain subject to examination. Various state tax returns for 2004 and subsequent years remain open for examination. In the Company’s foreign tax jurisdictions, returns for 2006 and subsequent years remain open for examination. Rowan is undergoing other routine tax examinations in various foreign, U.S. federal, state and local taxing jurisdictions in which the Company has operated. These examinations cover various tax years and are in various stages of finalization. Rowan believes that any income taxes ultimately assessed by any foreign, U.S. federal, state or local taxing authorities will not materially exceed amounts for which the Company has already provided.
In 2009, the Company recognized a $25.4 million tax benefit as a result of applying our facts to a recent third-party tax case that provides a more favorable tax treatment for certain foreign contracts entered into in prior years. The Company has deferred recognition of a remaining $49.2 million estimated benefit in accordance with the accounting guidelines for income tax uncertainties. In connection with the above, the Company has recorded a long-term receivable, which is included in other assets on the Condensed Consolidated Balance Sheet at December 31, 2009, for the gross claim of approximately $74.6 million and a long-term liability of approximately $49.2 million.
Income from continuing operations before income taxes consisted of domestic earnings of $558.3 million, $597.1 million, and $722.4 million in 2009, 2008, and 2007, respectively, a foreign loss of $57.2 million in 2009, and foreign earnings of $56.9 million and $16.7 million in 2008 and 2007, respectively.
NOTE 10 - SEGMENT INFORMATION
Rowan has three principal operating segments - Drilling Services, Drilling Products and Systems, and Mining, Forestry and Steel Products. The Drilling Services segment provides onshore and offshore oil and gas contract drilling services on a daily rate basis. The Drilling Products and Systems segment manufactures equipment and parts for the oil and gas drilling industry featuring jack-up rigs, rig kits and related components and parts, mud pumps, drawworks, top drives, rotary tables, other rig equipment, variable-speed motors, drives and other electrical components. The Mining, Forestry and Steel Products segment manufactures large-wheeled mining and timber equipment and related parts, and carbon and alloy steel and steel plate. The Drilling Products and Systems and Mining, Forestry and Steel Products segments operate under LeTourneau.
Rowan’s reportable segments reflect an aggregation of separately managed, strategic business units for which financial information is separately prepared and monitored based upon qualitative and quantitative factors. The Company evaluates segment performance based upon income from operations.
Prior to 2008, products and services provided by the Drilling Products and Systems segment to the Drilling Services segment were recorded as cost transfers; thus, the Drilling Products and Systems segment did not report intersegment revenues or costs. Effective January 1, 2008, such intersegment transactions were recorded as sales based on the terms and conditions and rates of compensation which approximated those that were customarily included in third-party contracts for similar items. During 2007, Rowan’s Drilling Products and Systems segment provided approximately $263 million of products and services to Drilling Services at cost. Certain administrative costs are allocated between segments generally based upon revenues. Refer to Note 2 for further information with regard to significant accounting policies applicable to the Company’s operating segments.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Certain information by operating segment is set forth below (in thousands):
_____________________________________
1 See Note 11 of “Notes to Consolidated Financial Statements” for an analysis of material charges.
One customer provided 10% or more of consolidated revenues in any of the last three years. Saudi Aramco accounted for 15% of consolidated revenues in 2009 and 2008, and 13% in 2007.
The classifications of revenues and assets among geographic areas in the tables which follow were determined based on the physical location of assets. Because the Company’s offshore drilling rigs are mobile, classifications by area are dependent on the rigs’ location at the time revenues are earned, and may vary from one period to the next.
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Revenues by geographic area are set forth below (in thousands):
Long-lived assets by geographic area are set forth below (in thousands):
NOTE 11 - MATERIAL CHARGES AND OTHER OPERATING EXPENSES
Operating expenses for the fourth quarter of 2008 included the following adjustments, by operating segment (in thousands):
Rowan Companies, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 12 - RELATED PARTY TRANSACTIONS
In 2008, Rowan paid an investment bank, in which a Rowan director served as managing director until March 2009, $4.1 million for services provided to the Company. In 2009, Rowan paid the investment bank $1.8 million for services provided in connection with the Company’s July 2009 public offering of $500 million Senior Notes, though the transaction occurred several months following his departure.
Another Rowan director serves as “of counsel” to a law firm that represents Rowan on certain matters and to which the Company paid approximately $0.6 million, $1.6 million and $0.3 million for legal fees and expenses in 2009, 2008 and 2007, respectively.
In each case, the director’s services were approved by the Company’s Board of Directors, and compensation from his employer was not tied to amounts received from the Company. Rowan believes that the fees paid for services reflected market rates.
NOTE 13 - SUPPLEMENTAL CASH FLOW INFORMATION
Noncash investing and financing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information follows (dollars in thousands):
Interest capitalized in 2009 exceeded the amount of interest payments due to the timing of the first interest payment on the 7.875% Senior Notes, which were issued in July 2009. Interest on the Senior Notes is payable each February and August beginning February 2010.
NOTE 14 - SUBSEQUENT EVENTS
There were no events or transactions that occurred subsequent to December 31, 2009 requiring recognition or disclosure in the financial statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Rowan Companies, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Rowan Companies, Inc. and subsidiaries (the "Company") as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2009. 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 the standards of the Public Company Accounting Oversight Board (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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010, expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 1,
Rowan Companies, Inc.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
PURSUANT TO SECTION 404 OF THE SARBANES-OXLEY ACT OF 2002
The management of Rowan is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition.
Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to assess the effectiveness of our internal controls relative to a suitable framework. The Committee of Sponsoring Organizations of the Treadway Commission (COSO) developed a formalized, organization-wide framework that embodies five interrelated components - the control environment, risk assessment, control activities, information and communication and monitoring, as they relate to three internal control objectives - operating effectiveness and efficiency, financial reporting reliability and compliance with laws and regulations.
Our assessment included an evaluation of the design of our internal control over financial reporting relative to COSO and testing of the operational effectiveness of our internal control over financial reporting. Based upon our assessment, we have concluded that our internal controls over financial reporting were effective as of December 31, 2009.
The registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements included in our 2009 Annual Report on Form 10-K and has issued an attestation report on the Company’s internal control over financial reporting.
/s/ W. MATT RALLS
/s/ W. H. WELLS
W. Matt Ralls
W. H. Wells
President and Chief Executive Officer
Vice President, Finance and Chief Financial Officer
March 1, 2010
March 1, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Rowan Companies, Inc.
Houston, Texas
We have audited the internal control over financial reporting of Rowan Companies, Inc. and subsidiaries (the "Company") 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. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2009 of the Company and our report dated March 1, 2010, expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 1,
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Unaudited quarterly financial data for each full quarter within the two most recent fiscal years follows (in thousands except per share amounts):
The sum of the per-share amounts for the quarters may not equal the per-share amounts for the full year since the quarterly and full year per share computations are made independently.
The fourth quarter of 2008 includes certain year-end adjustments and other material items, which are described in Note 11 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
The Company’s management has evaluated, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, the effectiveness of the Company’s disclosure controls and procedures, as of the end of the period covered by this report, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Company’s Chief Executive Officer, along with the Company’s Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2009.
Our management is responsible for establishing and maintaining internal control over financial reporting (ICFR). Our internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations, and therefore can only provide reasonable assurance with respect to financial statement preparation and presentation.
Our management’s assessment is that the Company did maintain effective ICFR as of December 31, 2009, within the context of the framework established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and that the Company did not have a material change in ICFR during the fourth quarter of 2009.
See “Management’s Report on Internal Control over Financial Reporting” included in Item 8 of this Form 10-K.
ITEM 9B. OTHER INFORMATION
Not applicable
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning our directors will appear in our Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2010, under the caption “Election of Directors.” Such information is incorporated herein by reference.
Information concerning our executive officers appears in Part 1 under the caption “Executive Officers of the Registrant” of this Form 10-K.
Information concerning our Audit Committee will appear in our Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2010, under the caption “Committees of the Board of Directors.” Such information is incorporated herein by reference.
Information concerning compliance with Section 16(a) of the Securities Exchange Act will appear in our Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A of the Exchange Act (“Regulation 14A”) on or before March 15, 2010, under the caption “Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance.” Such information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning director and executive compensation will appear in our Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2010, under the captions “Director Compensation and Attendance,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” and “Executive Compensation.” Such information is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information concerning the security ownership of management will appear in our Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2010, under the caption “Security Ownership of Certain Beneficial Owners and Management.” Such information is incorporated herein by reference.
The business address of all directors is the principal executive offices of the Company as set forth on the cover page of this Form 10-K.
Equity Compensation Plan Information
The following table provides information about our common stock that may be issued under equity compensation plans as of December 31, 2009.
(1)
The number of securities to be issued includes (i) 1,836,250 options and 119,153 shares issuable under outstanding SARs (see note (2) below), (ii) 159,416 contingent shares in connection with performance-based stock awards, and (iii) 35,009 shares issuable under the 1998 Convertible Debenture Incentive Plan. The exact number of shares to be issued under performance-based awards is dependent on meeting certain market-based or performance-based criteria and can range between zero and 318,832 shares (see Note 7 of Notes to Consolidated Financial Statements for a further discussion of performance-based stock awards and the 1998 Convertible Debenture Incentive Plan).
(2)
The weighted-average exercise price in column (b) is based on (i) 1,836,250 shares under outstanding options with a weighted average exercise price of $22.50 per share, and (ii) 119,153 shares of stock that would be issuable in connection with 513,834 stock appreciation rights (SARs) outstanding at December 31, 2009. The number of shares issuable under SARs is equal in value to the excess of the Rowan stock price on the date of exercise over the exercise price. The number of shares under SARs included in column (a) was based on a December 31, 2009 closing stock price of $22.64 and an exercise price of $17.39 per share.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information concerning director and executive related party transactions will appear in our Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2010, within the section and under the captions “Director Independence” and “Related Party Transactions.” Such information is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information concerning principal account fees and services will appear in our Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2010, in the last paragraph under the caption “Fees of Audit Firm.” Such information is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements
See Item 8, “Financial Statements and Supplementary Data,” beginning on page 41 of this Form 10-K for a list of financial statements filed as a part of this report.
(2) Financial Statement Schedules
Financial Statement Schedules I, II, III, IV, and V are not included in this Form 10-K because such schedules are not required, the required information is not significant, or the information is presented elsewhere in the financial statements.
(3) Exhibits
Unless otherwise indicated below as being incorporated by reference to another filing of the Company with the Securities and Exchange Commission, each of the following exhibits is filed herewith:
3.1
Restated Certificate of Incorporation of the Company, dated February 17, 1984 (incorporated by reference to Exhibit 4.1 to Registration Statement No. 333-84369 on Form S-8) and the Certificates of Designation for the Company’s Series A Preferred Stock (and Certificate of Correction related thereto) (incorporated by reference to Exhibit 4.8 to Registration Statement No. 333-84369 on Form S-8), Series B Preferred Stock (incorporated by reference to Exhibit 4d to Form 10-K for the year ended December 31, 1999), Series D Preferred Stock (incorporated by reference to Exhibit 4.11 to Registration Statement No. 333-82804 on Form S-3 filed on February 14, 2002), and Series E Preferred Stock (incorporated by reference to Exhibit 4.12 to Registration Statement No. 333-82804 on Form S-3 filed on February 14, 2002).
3.2
Amended and Restated Bylaws of Rowan Companies, Inc., effective as of October 29, 2009, incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated November 2, 2009 (File No. 1-5491).
4.1
Certificate of Change of Address of Registered Office and of Registered Agent dated July 25, 1984, incorporated by reference to Exhibit 4.4 to Registration Statement No. 333-84369 on Form S-8 (File No. 1-5491).
4.2
Certificate of Amendment of Certificate of Incorporation dated April 24, 1987, incorporated by reference to Exhibit 4.5 to Registration Statement No. 333-84369 on Form S-8 (File No. 1-5491).
4.3
Certificate of Designation of the Series A Junior Preferred Stock dated March 2, 1992, incorporated by reference to Exhibit 4.2 to Registration Statement on Form 8-A/A filed on February 12, 2002 (File No. 1-5491).
4.4
Certificate of Designation of the Series C Preferred Stock dated July 28, 2000, incorporated by reference to Exhibit 4.10 to Registration Statement No. 333-44874 on Form S-8 (File No. 1-5491).
4.5
Specimen Common Stock certificate, incorporated by reference to Exhibit 4k to Form 10-K for the year ended December 31, 2001 (File No. 1-5491).
4.6
Form of Promissory Note date April 27, 2000 between purchasers of Series C Floating Rate Subordinated Convertible Debentures due 2010 and Rowan, incorporated by reference to Exhibit 4n to Form 10-K for the year ended December 31, 2000 (File No. 1-5491).
4.7
Indenture for Senior Debt Securities dated as of July 21, 2009, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated July 21, 2009 (File No. 1-5491).
4.8
First Supplemental Indenture dated as of July 21, 2009, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated July 21, 2009 (File No. 1-5491).
10.1
Restated 1988 Nonqualified Stock Option Plan, incorporated by reference to Appendix C to the Notice of Annual Meeting and Proxy Statement dated March 20, 2002 (File No. 1-5491) and Form of Stock Option Agreement related thereto, incorporated by reference to Exhibit 10c to Form 10-K for the year ended December 31, 2004 (File No. 1-5491).
10.2
Nonemployee Director Stock Option Plan, incorporated by reference to Exhibit 10b of Form 10-Q for the quarter ended March 31, 1998 (File No. 1-5491) and Form of Stock Option Agreement related thereto, incorporated by reference to Exhibit 10c to Form 10-K for the year ended December 31, 2004 (File No. 1-5491).
10.3
Convertible Debenture Incentive Plan, incorporated by reference to Appendix B to the Notice of Annual Meeting and Proxy Statement dated March 20, 2002 (File No. 1-5491) and Form of Debenture related thereto, incorporated by reference to Exhibit 10c to Form 10-K for the year ended December 31, 2004 (File No. 1-5491).
10.4
Rowan Companies, Inc. Incentive Plan, incorporated by reference to Appendix A of the Company’s definitive proxy statement dated March 19, 2009 (File No. 1-5491) and Form of 2009 Stock Appreciation Right Agreement, Form of 2009 Restricted Stock Agreement, and Form of Non-Employee Director 2009 Restricted Stock Unit Agreement under the 2009 Rowan Companies, Inc. Incentive Plan, incorporated by reference to Exhibits 10.2, 10.3 and 10.4, respectively, of the Company’s Quarterly Report on Form 10-Q dated August 10, 2009 (File No. 1-5491).
10.5
Pension Restoration Plan of LeTourneau Technologies, Inc., a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 10j to Form 10-K for the year ended December 31, 1994 (File No. 1-5491).
10.6
Participation Agreement dated December 1, 1984 between Rowan and Textron Financial Corporation et al. and Bareboat Charter dated December 1, 1984 between Rowan and Textron Financial Corporation et al., incorporated by reference to Exhibit 10c to Form 10-K for the year ended December 31, 1985 (File No. 1-5491).
10.7
Participation Agreement dated December 1, 1985 between Rowan and Eaton Leasing Corporation et. al. and Bareboat Charter dated December 1, 1985 between Rowan and Eaton Leasing Corporation et. al., incorporated by reference to Exhibit 10d to Form 10-K for the year ended December 31, 1985 (File No. 1-5491).
10.8
Election and acceptance letters with respect to the exercise of the Fixed Rate Renewal Option set forth in the Bareboat Charter dated December 1, 1984 between Rowan and Textron Financial Corporation et al, incorporated by reference to Exhibit 10j to Form 10-K for the year ended December 31, 1999 (File No. 1-5491).
10.9
Election and acceptance letters with respect to the exercise of the Fixed Rate Renewal Option set forth in the Bareboat Charter dated December 1, 1985 between Rowan and Eaton Leasing Corporation et. al, incorporated by reference to Exhibit 10k to Form 10-K for the year ended December 31, 1999 (File No. 1-5491).
10.10
Commitment to Guarantee Obligations dated December 17, 1996 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla V), incorporated by reference to Exhibit 10t to Form 10-K for year ended December 31, 1996 (File No. 1-5491).
10.11
Amendment No. 1 dated June 30, 1997 to Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla V), incorporated by reference to Exhibit 10p to 10-K for the year ended December 31, 1997 (File No. 1-5491).
10.12
Amendment No. 2 dated July 1, 1998 to Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla V), incorporated by reference to Exhibit 10o to Form 10-K for the year ended December 31, 1998 (File No. 1-5491).
10.13
Credit Agreement and Trust Indenture both dated December 17, 1996 between Rowan and Citibank, N.A. (relating to Gorilla V), incorporated by reference to Exhibit 10u to Form 10-K for the year ended December 31, 1996 (File No. 1-5491).
10.14
Amendment No. 1 to the Credit Agreement and Supplement No. 1 to Trust Indenture both dated July 1, 1997 between Rowan and Citibank, N.A. (relating to Gorilla V), incorporated by reference to Exhibit 10r to Form 10-K for the year ended December 31, 1997 (File No. 1-5491).
10.15
Supplement No. 2 dated July 1, 1998 to Trust Indenture between Rowan and Citibank, N.A. (relating to Gorilla V), incorporated by reference to Exhibit 10r to Form 10-K for the year ended December 31, 1998 (File No. 1-5491).
10.16
Commitment to Guarantee Obligations dated September 29, 1998 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VI), incorporated by reference to Exhibit 10a to Form 10-Q for quarter ended September 30, 1998 (File No. 1-5491).
10.17
Credit Agreement and Trust Indenture both dated September 29, 1998 between Rowan and Citibank, N.A. (relating to Gorilla VI), incorporated by reference to Exhibit 10b to Form 10-Q for the quarter ended September 30, 1998 (File No. 1-5491).
10.18
Amendment No. 1 dated March 15, 2001 to Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VI), incorporated by reference to Exhibit 10v to Form 10-K for the year ended December 31, 2000 (File No. 1-5491).
10.19
Supplement No. 1 dated March 15, 2001 to Trust Indenture between Rowan and Citibank, N.A. (relating to Gorilla VI), incorporated by reference to Exhibit 10v to Form 10-K for the year ended December 31, 2000 (File No. 1-5491).
10.20
Commitment to Guarantee Obligations dated October 29, 1999 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VII), incorporated by reference to Exhibit 10v to Form 10-K for the year ended December 31, 1999 (File No. 1-5491).
10.21
Credit Agreement and Trust Indenture both dated October 29, 1999 between Rowan and Citibank, N.A. (relating to Gorilla VII), incorporated by reference to Exhibit 10w to Form 10-K for the year ended December 31, 1999 (File No. 1-5491).
10.22
Amendment No. 1 dated June 30, 2003 to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VII), incorporated by reference to Exhibit 10x to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.23
Supplement No. 1 dated June 30, 2003 to Trust Indenture between Rowan and Citibank, N.A. (relating to Gorilla VII), incorporated by reference to Exhibit 10y to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.24
Commitment to Guarantee Obligations dated May 23, 2001 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Palmer, formerly Gorilla VIII), incorporated by reference to Exhibit 10y to Form 10-K for the year ended December 31, 2001 (File No. 1-5491).
10.25
Credit Agreement and Trust Indenture both dated May 23, 2001 between Rowan and Citibank, N.A. (relating to the Bob Palmer, formerly Gorilla VIII), incorporated by reference to Exhibit 10z to Form 10-K for the year ended December 31, 2001 (File No. 1-5491).
10.26
Commitment to Guarantee Obligations dated May 28, 2003 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10bb to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.27
Credit Agreement and Trust Indenture both dated May 28, 2003 between Rowan and Citibank, N.A. (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10cc to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.28
Amendment No. 1 dated June 15, 2005 to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10a to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
10.29
Supplement No. 1 dated June 15, 2005 to Trust Indenture between Rowan and Citibank, N.A. (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10b to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
10.30
Commitment to Guarantee Obligations dated May 28, 2003 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10dd to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.31
Credit Agreement and Trust Indenture both dated May 28, 2003 between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10ee to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.32
Amendment No. 1 dated March 28, 2005 to Credit Agreement between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10a to Form 10-Q for the quarterly period ended March 31, 2005 (File No. 1-5491).
10.33
Amendment No. 2 dated May 4, 2005 to Credit Agreement between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10b to Form 10-Q for the quarterly period ended March 31, 2005 (File No. 1-5491).
10.34
Memorandum Agreement dated January 26, 2006 between Rowan and C. R. Palmer, incorporated by reference to Exhibit 10jj to Form 10-K for year ended December 31, 2005 (File No. 1-5491).
10.35
Rowan Companies, Inc. Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed May 10, 2005 (File No. 1-5491) and Form of Non-Employee Director 2005 Restricted Stock Unit Grant, Form of Non-Employee Director 2006 Restricted Stock Unit Grant, Form of 2005 Restricted Stock Grant Agreement, Form of 2005 Nonqualified Stock Option Agreement, Form of 2005 Performance Share Award Agreement related thereto, each incorporated by reference to Exhibits 10c, 10d, 10e, 10f and 10g, respectively, to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
10.36
Change in Control Agreement and Change in Control Supplement, incorporated by reference to Exhibits 10.1 and 10.2 to Form 8-K filed December 20, 2007 (File 1-5491).
10.37
Credit Agreement dated as of June 23, 2008 among Rowan, as Borrower, the Lenders Party thereto, Wells Fargo Bank, NA, as Administrative Agent, Issuing Lender and Swingline Lender, Bayerische Hypo-Und Vereinsbank AG, as Syndication Agent, and Amegy Bank NA, as Documentation Agent, incorporated by reference to Form 8-K filed June 25, 2008 (File 1-5491).
10.38
Amendment No. 1 dated August 4, 2009, to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q filed August 10, 2009 (File No. 1-5491).
10.39
Supplement No. 2 dated August 4, 2009, to Trust Indenture between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed August 10, 2009 (File No. 1-5491).
10.40
Form of Indemnification Agreement between Rowan Companies, Inc. and each of its directors and certain officers, incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 2, 2009 (File No. 1-5491).
10.41
Amendment No. 1 dated November 24, 2009, to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Palmer, formerly Gorilla VIII), incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 24, 2009 (File No. 1-5491).
10.42
Supplement No. 2 dated November 24, 2009, to Trust Indenture between Rowan and Manufacturers and Traders Trust Company (relating to the Bob Palmer, formerly Gorilla VII), incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated November 24, 2009 (File No. 1-5491).
10.43
Restoration Plan of Rowan Companies, Inc. (As Restated Effective July 1, 2009).
Code of Business Conduct for Senior Financial Officers of the Company, incorporated by reference to Exhibit 14 to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
Subsidiaries of the Registrant as of February 24, 2010.
Consent of Independent Registered Public Accounting Firm.
Powers of Attorney pursuant to which names were affixed to this Form 10-K for the year ended December 31, 2009.
31.1
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Annual CEO Certification to the New York Stock Exchange.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
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Only portions specifically incorporated herein are deemed to be filed.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
Compensatory plans in which Rowan’s directors and executive officers participate are listed as follows:
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Restated 1988 Nonqualified Stock Option Plan, incorporated by reference to Appendix C to the Notice of Annual Meeting and Proxy Statement dated March 20, 2002 (File No. 1-5491).
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Nonemployee Director Stock Option Plan, incorporated by reference to Exhibit 10b of Form 10-Q for the quarter ended March 31, 1998 (File No. 1-5491).
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Convertible Debenture Incentive Plan, incorporated by reference to Appendix B to the Notice of Annual Meeting and Proxy Statement dated March 20, 2002 (File No. 1-5491).
•
Restoration Plan of Rowan Companies, Inc. (As Restated Effective July 1, 2009).
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Pension Restoration Plan of LeTourneau, Inc., a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 10j to Form 10-K for the year ended December 31, 1994 (File No. 1-5491).
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Profit Sharing Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed May 4, 2006 (File No. 1-5491).
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Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed May 10, 2005 (File No. 1-5491).
•
Change in Control Agreement and Change in Control Supplement for the Rowan Companies, Inc. Restated 1988 Nonqualified Stock Option Plan and the 2005 Rowan Companies, Inc. Long-Term Incentive Plan incorporated by reference to Exhibits 10.1 and 10.2 to Form 8-K filed December 20, 2007 (File 1-5491).
•
Rowan Companies, Inc. Incentive Plan, incorporated by reference to Appendix A of the Company’s definitive proxy statement dated March 19, 2009 (File No. 1-5491).
Rowan agrees to furnish to the Commission upon request a copy of all instruments defining the rights of holders of long-term debt of the Company and its subsidiaries.
For the purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into Registrant’s Registration Statements on Form S-8 Nos. 2-58700, as amended by Post-Effective Amendment No. 4 (filed June 11, 1980), 33-33755, as amended by Amendment No. 1 (filed March 29, 1990), 33-61444 (filed April 23, 1993), 333-84369 (filed August 3, 1999), 333-84405 (filed August 3, 1999), 333-101914 (filed December 17, 2002), 333-132762 (filed March 28, 2006), and 333-158985 (filed May 5, 2009):
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the act and will be governed by the final adjudication of such issue.
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.
ROWAN COMPANIES, INC.
(Registrant)
By: /s/ W. MATT RALLS
W. Matt Ralls
President and Chief Executive officer
Date: March 1, 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 date indicated.
Signature
Title
Date
/s/ W. MATT RALLS
President, Chief Executive Officer and Director
March 1, 2010
(W. Matt Ralls)
/s/ W. H. WELLS
Principal Financial Officer
March 1, 2010
(W. H. Wells)
/s/ GREGORY M. HATFIELD
Principal Accounting Officer
March 1, 2010
(Gregory M. Hatfield)
/s/ *R. G. CROYLE
Director
March 1, 2010
(R. G. Croyle)
/s/ *WILLIAM T. FOX III
Director
March 1, 2010
(William T. Fox III)
/s/ *SIR GRAHAM HEARNE
Director
March 1, 2010
(Sir Graham Hearne)
/s/ *THOMAS R. HIX
Director
March 1, 2010
(Thomas R. Hix)
/s/ *ROBERT E. KRAMEK
Director
March 1, 2010
(Robert E. Kramek)
/s/ *FREDERICK R. LAUSEN
Director
March 1, 2010
(Frederick R. Lausen)
/s/ *H. E. LENTZ
Chairman of the Board
March 1, 2010
(H. E. Lentz)
/s/ *LORD MOYNIHAN
Director
March 1, 2010
(Lord Moynihan)
/s/ *P. DEXTER PEACOCK
Director
March 1, 2010
(P. Dexter Peacock)
/s/ *JOHN J. QUICKE
Director
March 1, 2010
(John J. Quicke)
*By:
/s/ W. MATT RALLS
(W. Matt Ralls,
Attorney-in-Fact)