ITEM 1. BUSINESS
In this Annual Report on Form 10-K, “we,” the “Company” and “Pride” are references to Pride International, Inc. and its subsidiaries, unless the context clearly indicates otherwise. Pride International, Inc. is a Delaware corporation with its principal executive offices located at 5847 San Felipe, Suite 3300, Houston, Texas 77057. Our telephone number at such address is (713) 789-1400 or (800) 645-2067.
We are one of the world’s largest offshore drilling contractors operating, as of February 27, 2008, a fleet of 64 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, 28 jackups, 10 platform rigs, five managed deepwater drilling rigs and seven Eastern Hemisphere-based land drilling rigs. We have three ultra-deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.
Our operations are conducted in many of the most active oil and natural gas basins of the world, including South America, the Gulf of Mexico, West Africa, the Mediterranean Sea, the Middle East and Asia Pacific. The diversity of our rig fleet and areas of operation enables us to provide a broad range of services and to take advantage of market upturns while reducing our exposure to sharp downturns in any particular market sector or geographic region.
We provide contract drilling services to oil and natural gas exploration and production companies through the use of mobile offshore drilling rigs in U.S. and international waters. We provide the rigs and drilling crews and are responsible for the payment of operating and maintenance expenses. In addition, we also provide rig management services on a variety of rigs, consisting of technical drilling assistance, personnel, repair and maintenance services and drilling operation management services.
Segment Information
Subsequent to the disposition of our Latin America Land and E&P Services segments in August 2007, our operations consist of one reportable segment, Offshore Drilling Services, which includes all of our offshore drilling fleet and operations.
We incorporate by reference in response to this item the segment information for the last three years set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Segment Review” in Item 7 of this annual report and the information for the last three fiscal years with respect to revenues, earnings from operations, attributable to our asset classes and revenues and long-lived assets by geographic areas of operations in Note 14 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report. We also incorporate by reference in response to this item the information with respect to backlog and acquisitions and dispositions of assets set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Recent Developments” and “- Liquidity and Capital Resources” in Item 7 and in Notes 2 and 3 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report.
Rig Fleet
Offshore Rigs
The table below presents information about our offshore rig fleet, excluding our 10 platform rigs, as of February 27, 2008:
(1)
Also known as the Sea Explorer.
(2)
Managed by us, but owned by others.
Drillships. The Pride Africa and Pride Angola are deepwater, self-propelled drillships that can be positioned over a drill site through the use of a computer-controlled thruster (dynamic positioning) system. Drillships are suitable for deepwater drilling in remote locations because of their mobility and large load-carrying capacity. Generally, these drillships operate with crews of approximately 100 persons.
Semisubmersible Rigs. Our semisubmersible rigs, which consist of all of our deepwater and midwater fleet other than our two drillships, are floating platforms that, by means of a water ballasting system, can be submerged to a predetermined depth so that a substantial portion of the lower hulls, or pontoons, is below the water surface during drilling operations. The rig is “semisubmerged,” remaining afloat in a position, off the sea bottom, where the lower hull is about 60 to 80 feet below the water line and the upper deck protrudes well above the surface. This type of rig maintains its position over the well through the use of either an anchoring system or a computer-controlled thruster system similar to that used by our drillships. Semisubmersible rigs generally operate with crews of 60 to 75 persons.
Jackup Rigs. The jackup rigs we operate are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. The rig legs may have a lower hull or mat attached to the bottom to provide a more stable foundation in soft bottom areas. Independent leg rigs are better suited for harsher drilling conditions or uneven seabed conditions. Our jackup rigs are generally subject to a maximum water depth of approximately 200 to 300 feet. The length of the rig’s legs and the operating environment determine the water depth limit of a particular rig. A cantilever jackup rig has a feature that allows the drilling platform to be extended out from the hull, enabling the rig to perform drilling or workover operations over a pre-existing platform or structure. Slot-type jackup rigs are configured for drilling operations to take place through a slot in the hull. Slot-type rigs are usually used for exploratory drilling because their configuration makes them difficult to position over existing platforms or structures. Jackups generally operate with crews of 15 to 40 persons.
Managed Deepwater Rigs. We perform rig management services for drilling operations for five deepwater rigs, located offshore Angola and in the U.S. Gulf of Mexico, under contracts that expire in 2011 and 2012. Our services consist of providing technical assistance, personnel, repair and maintenance services, and drilling operation management services. The drilling equipment, which we operate on behalf of our customers, is installed on a variety of supporting structures, including tension-leg platform, spar and semisubmersible hull designs. Due to the similar drilling equipment specifications and operation among our managed deepwater rigs and our owned deepwater rigs, our managed rig personnel and the rig crews on our owned rigs require similar experience and training.
Other Operations
Platform Rigs. Our 10 platform rigs, which operate in the Gulf of Mexico, generally consist of drilling equipment and machinery arranged in modular packages that are transported to, assembled and installed on fixed offshore platforms owned by the customer. The crew operating on a platform rig can vary significantly depending upon the size of the platform and the nature of the operations being performed.
Land Rigs. We also own seven land rigs in three countries. Our land drilling and land workover rigs operate under short-term or well-to-well contracts.
Customers
We provide contract drilling and related services to a customer base that includes large multinational oil and natural gas companies, government-owned oil and natural gas companies and independent oil and natural gas producers. For the year ended December 31, 2007, Petroleos Mexicanos S.A., Petroleo Brasilerio S.A., ExxonMobil Corporation and Total S.A. accounted for 21%, 13%, 12%, and 8%, respectively, of our consolidated revenues. The loss of any of these significant customers could have a material adverse effect on our results of operations.
Drilling Contracts
Overview
Our drilling contracts are awarded through competitive bidding or on a negotiated basis. The contract terms and rates vary depending on competitive conditions, geographical area, geological formation to be drilled, equipment and services to be supplied, on-site drilling conditions and anticipated duration of the work to be performed.
Oil and natural gas well drilling contracts are carried out on a dayrate, footage or turnkey basis. Currently, all of our offshore drilling services contracts are on a dayrate basis. Under dayrate contracts, we charge the customer a fixed amount per day regardless of the number of days needed to drill the well. In addition, dayrate contracts usually provide for a reduced dayrate (or lump-sum amount) for mobilizing the rig to the well location or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. A dayrate drilling contract generally covers either the drilling of a single well or group of wells or has a stated term. These contracts may generally be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for a period of time as a result of a breakdown of equipment or, in some cases, due to other events beyond the control of either party. In addition, drilling contracts with certain customers are cancelable, without cause, upon little or no prior notice and without penalty or early termination payments. In some instances, the dayrate contract term may be extended by the customer exercising options for the drilling of additional wells or for an additional length of time at fixed or mutually agreed terms, including dayrates.
Another type of contract provides for payment on a footage basis, whereby a fixed amount is paid for each foot drilled regardless of the time required or the problems encountered in drilling the well. We may also enter into turnkey contracts, whereby we agree to drill a well to a specific depth for a fixed price and to bear some of the well equipment costs. Compared with dayrate contracts, footage and turnkey contracts involve a higher degree of risk to us.
Our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime or operational problems above a contractual limit, if the rig is a total loss or in other specified circumstances. Many of our contracts include termination provisions that require the customer to pay the remaining amounts due on the contract less stipulated operating expenses. Our contracts also generally include cost escalation provisions that allow us to increase the amounts billed to our customers when our operating costs increase. A customer is more likely to seek to cancel or renegotiate its contract during periods of depressed market conditions. We could be required to pay penalties if some of our contracts with our customers are canceled due to downtime or operational problems. Suspension of drilling contracts results in the reduction in or loss of dayrates for the period of the suspension. If our customers cancel some of our significant contracts and we are unable to secure new contracts on substantially similar terms, or if contracts are suspended for an extended period of time, it could adversely affect our consolidated financial statements.
Deepwater
The Pride Africa is currently operating under a contract expiring in December 2011. The current contract for the Pride Angola expires in July 2008, and we are working with our client to obtain regulatory approvals for a multi-year contract. In November 2006, we were awarded five-year contract extensions that begin in mid-2008 for the Pride Brazil and the Pride Carlos Walter and a three-year contract extension that began in early 2008 for the Pride North America. In February 2008, the Pride Portland and the Pride Rio de Janeiro were awarded contract extensions into 2017 in direct continuation of their current contracts. The Pride South Pacific commenced a two-year contract in March 2007.
Midwater
The Pride South America is operating under a five-year contract expiring in February 2012. The Pride Mexico is expected to leave the shipyard in March 2008 and commence a five-year contract in June 2008. The current contract for the Pride South Atlantic expires in April 2008 and, following a brief shipyard stay and transit, is expected to commence its new five-year contract in May 2008. The Pride Venezuela commences a new six-month contract in March 2008 following the expiration of its current contract, and the Pride North Sea is expected to commence a new one-year contract in May 2008 following the completion of its existing contract in March 2008 and a brief shipyard
stay and transit to its new location. The Pride South Seas is expected to commence its new 16-month contract in March 2008.
Jackups
Eight of our jackup rigs operating in the U.S. Gulf of Mexico are operating under short-term contracts expiring in 2008. The Pride Texas, the Pride Tennessee and the Pride Louisiana are operating in the Mexican sector of the Gulf of Mexico under contracts expiring in September 2009, August 2009 and April 2009, respectively. The other nine rigs operating in Mexico are working under contracts expiring in 2008. Of our five jackup rigs operating outside the Gulf of Mexico, the Pride Cabinda is under contract to January 2009, the Pride Hawaii to May 2010, the Pride Pennsylvania to October 2009, the Pride Montana to June 2011 and the Pride North Dakota to May 2010.
Competition
The contract drilling industry is highly competitive. Demand for contract drilling and related services is influenced by a number of factors, including the current and expected prices of oil and natural gas and the expenditures of oil and natural gas companies for exploration and development of oil and natural gas. In addition, demand for drilling services remains dependent on a variety of political and economic factors beyond our control, including worldwide demand for oil and natural gas, the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and pricing, the level of production of non-OPEC countries and the policies of the various governments regarding exploration and development of their oil and natural gas reserves.
Drilling contracts are generally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. Rig availability, location and technical ability and each contractor’s safety performance record and reputation for quality also can be key factors in the determination. Operators also may consider crew experience and efficiency. Some of our contracts are on a negotiated basis. We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future. Certain competitors may have greater financial resources than we do, which may better enable them to withstand periods of low utilization, compete more effectively on the basis of price, build new rigs or acquire existing rigs.
Our competition ranges from large international companies to smaller, locally owned companies. We believe we are competitive in terms of safety, pricing, performance, equipment, availability of equipment to meet customer needs and availability of experienced, skilled personnel; however, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business can occur. Competition for offshore rigs is usually on a global basis, as these rigs are highly mobile and may be moved, at a cost that is sometimes substantial, from one region to another in response to demand.
Seasonality
Our rigs in the Gulf of Mexico are subject to severe weather during certain periods of the year, particularly hurricane season, which extends from June through November, which could halt operations for prolonged periods or limit contract opportunities during that period. Otherwise, our business activities are not significantly affected by seasonal fluctuations.
Insurance
Our operations are subject to hazards inherent in the drilling of oil and natural gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, or seriously damage or destroy the equipment involved. Offshore drilling operations are also subject to hazards particular to marine operations including capsizing, grounding, collision and loss or damage from severe weather. Our marine package policy provides insurance coverage for physical damage to our rigs, liability due to control-of-well events and loss of hire insurance for certain assets with higher dayrates. This insurance policy has a $16 million aggregate deductible. In addition, the marine package policy has a sub-limit of $110 million for physical damage claims due to a named windstorm in the U.S. Gulf of Mexico. We also maintain insurance coverage for cargo, auto liability, non-owned aviation, personal injury and similar liabilities. Those policies have significantly lower deductibles than the marine package policy.
Environmental and Other Regulatory Matters
Our operations include activities that are subject to numerous international, federal, state and local laws and regulations, including the U.S. Oil Pollution Act of 1990, the U.S. Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation and Liability Act and the International Convention for the Prevention of Pollution from Ships, governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect our consolidated financial statements. While we believe that we are in substantial compliance with the current laws and regulations, there is no assurance that compliance can be maintained in the future. We do not presently anticipate that compliance with currently applicable environmental laws and regulations will have a material adverse effect on our consolidated financial statements during 2008.
The Minerals Management Service of the U.S. Department of the Interior (“MMS”) may issue guidelines for jackup rig fitness requirements in the U.S. Gulf of Mexico for future hurricane seasons and may take other steps that could increase the cost of operations or reduce the area of operations for our jackup rigs, thus reducing their marketability. Implementation of new MMS guidelines or regulations may subject us to increased costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations and financial condition. Please read “Risk Factors-Our ability to operate our rigs in the U.S. Gulf of Mexico could be restricted or made more costly by government regulation” in Item 1A
ITEM 1A. RISK FACTORS
A material or extended decline in expenditures by oil and natural gas companies due to a decline or volatility in oil and natural gas prices, a decrease in demand for oil and natural gas or other factors may reduce demand for our services and substantially reduce our profitability or result in our incurring losses.
The profitability of our operations depends upon conditions in the oil and natural gas industry and, specifically, the level of exploration, development and production activity by oil and natural gas companies. Oil and natural gas prices and market expectations regarding potential changes in these prices significantly affect this level of activity. However, higher commodity prices do not necessarily translate into increased drilling activity since our customers’ expectations of future commodity prices typically drive demand for our rigs. Oil and natural gas prices are volatile. Commodity prices are directly influenced by many factors beyond our control, including:
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the demand for oil and natural gas;
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the cost of exploring for, developing, producing and delivering oil and natural gas;
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expectations regarding future energy prices;
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advances in exploration, development and production technology;
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government regulations;
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local and international political, economic and weather conditions;
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the ability of OPEC to set and maintain production levels and prices;
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the level of production in non-OPEC countries;
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domestic and foreign tax policies;
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the development and exploitation of alternative fuels;
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the policies of various governments regarding exploration and development of their oil and natural gas reserves;
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acts of terrorism in the United States or elsewhere; and
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the worldwide military and political environment and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East and other oil and natural gas producing regions.
Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks against the United States or other countries could cause a downturn in the economies of the United States and those of other countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. More specifically, these risks could lead to increased volatility in prices for oil and natural gas and could affect the markets for our drilling services. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain insurance coverages that we consider adequate or are otherwise required by our contracts.
Depending on the market prices of oil and natural gas, and even during periods of high commodity prices, companies exploring for and producing oil and natural gas may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of
success in exploration efforts. Such a reduction in demand may decrease daily rates and utilization of our rigs. Any significant decrease in daily rates or utilization of our rigs, particularly our high-specification drillships, semisubmersible rigs or jackup rigs, could materially reduce our revenues and profitability.
Rig upgrade, refurbishment, repair and construction projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.
We have expended, and will continue to expend, significant amounts of capital to complete the construction of our three drillships currently under construction. Depending on available opportunities, we may construct additional rigs for our fleet in the future. In addition, we make significant upgrade, refurbishment and repair expenditures for our fleet from time to time, particularly in light of the aging nature of our rigs. Some of these expenditures are unplanned. In 2008, we expect to spend approximately $610 million with respect to the construction of our three drillships and an additional approximately $385 million with respect to the refurbishment and upgrade of other rigs. All of these projects are subject to the risks of delay or cost overruns, including costs or delays resulting from the following:
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unexpectedly long delivery times for or shortages of key equipment, parts and materials;
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shortages of skilled labor and other shipyard personnel necessary to perform the work;
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failure or delay of third-party equipment vendors or service providers;
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unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
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unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment;
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unanticipated actual or purported change orders;
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client acceptance delays;
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disputes with shipyards and suppliers;
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work stoppages and other labor disputes;
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latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
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financial or other difficulties at shipyards;
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adverse weather conditions; and
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inability to obtain required permits or approvals.
Significant cost overruns or delays could materially affect our financial condition and results of operations. Some of our risks are concentrated because our three drillships currently under construction are located at one shipyard in South Korea. Delays in the delivery of rigs being constructed or undergoing upgrade, refurbishment or repair may, in many cases, result in delay in contract commencement, resulting in a loss of revenue to us, and may also cause our customer to renegotiate the drilling contract for the rig or terminate or shorten the term of the contract under applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms. Additionally, capital expenditures for rig upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our rigs undergoing upgrade, refurbishment and repair may not earn a dayrate during the period they are out of service.
An oversupply of comparable or higher specification rigs in the markets in which we compete could depress the demand and contract prices for our rigs and materially reduce our revenues and profitability.
Demand and contract prices customers pay for our rigs also are affected by the total supply of comparable rigs available for service in the markets in which we compete. During prior periods of high utilization and dayrates, industry participants have increased the supply of rigs by ordering the construction of new units. This has often created an oversupply of drilling units and has caused a decline in utilization and dayrates when the rigs enter the market, sometimes for extended periods of time as rigs have been absorbed into the active fleet. Approximately 13 new jackup rigs entered the market in 2007, and approximately 83 jackup rigs are on order or under construction with delivery dates ranging from 2008 to 2011. Most of these units are cantilevered units and are considered to be premium units. In the deepwater sector, one new semi-submersible rig entered the market in 2007, and there have been announcements of approximately 70 new semisubmersible rigs and drillships, including our three drillship construction projects, with delivery forecasted to occur from 2008 through 2011. A number of the contracts for units currently under construction provide for options for the construction of additional units, and we believe further new construction announcements may occur for all classes of rigs pursuant to the exercise of one or more of these options and otherwise. In addition, our competitors’ “stacked” (i.e., minimally crewed with little or no scheduled maintenance being performed) rigs may re-enter the market. Not all of the rigs currently under construction have been contracted for future work, which may intensify price competition as scheduled delivery dates occur. The entry into service of newly constructed, upgraded or reactivated units will increase marketed supply and could curtail a further strengthening of dayrates, or reduce them, in the affected markets as rigs are absorbed into the active fleet. Any further increase in construction of new drilling units may negatively affect utilization and dayrates. In addition, the new construction of high specification rigs, as well as changes in our competitors’ drilling rig fleets, could require us to make material additional capital investments to keep our rig fleet competitive.
Our industry is highly competitive and cyclical, with intense price competition.
Our industry is highly competitive. Our contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. Rig availability, location and technical ability and each contractor’s safety performance record and reputation for quality also can be key factors in the determination. Some of our competitors in the drilling industry are larger than we are and have more diverse fleets, or fleets with generally higher specifications, and greater resources than we have. Some of these competitors also are incorporated in tax-haven countries outside the United States, which provides them with significant tax advantages that are not available to us as a U.S. company and which may materially impair our ability to compete with them for many projects that would be beneficial to our company. In addition, recent mergers within the oil and natural gas industry have reduced the number of available customers, resulting in increased competition for projects. We may not be able to maintain our competitive position, and we believe that competition for contracts will continue to be intense in the foreseeable future. Our inability to compete successfully may reduce our revenues and profitability.
Historically, the offshore service industry has been highly cyclical, with periods of high demand, limited rig supply and high dayrates often followed by periods of low demand, excess rig supply and low dayrates. Periods of low demand and excess rig supply intensify the competition in the industry and often result in rigs, particularly lower specification rigs like a large portion of our fleet, being idle for long periods of time. We may be required to stack rigs or enter into lower dayrate contracts in response to market conditions in the future. Prolonged periods of low utilization and dayrates could result in the recognition of impairment charges on certain of our rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.
Consolidation of suppliers may limit our ability to obtain supplies and services at an acceptable cost, on our schedule or at all.
We rely on certain third parties to provide supplies and services necessary for our operations. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing of key supplies. We may not be able to obtain supplies and services at an acceptable cost, at the times we need them or at all. These cost increases or delays could have a material adverse affect on our results of operations and financial position.
Failure to attract and retain skilled personnel or an increase in labor costs could hurt our operations.
We require highly skilled personnel to operate and provide technical services and support for our business. Competition for the skilled and other labor required for our operations intensifies as the number of rigs activated or added to worldwide fleets or under construction increases, creating upward pressure on wages. In periods of high
utilization, such as the current period, we have found it more difficult to find and retain qualified individuals. We have experienced tightening in the relevant labor markets since 2005 and have recently sustained the loss of experienced personnel to our customers and competitors. Our labor costs increased significantly in 2005, 2006 and 2007, and we expect this trend to continue in 2008. The shortages of qualified personnel or the inability to obtain and retain qualified personnel could negatively affect the quality, safety and timeliness of our work. In addition, our ability to crew our three new drillships and to expand our deepwater operations depends in part upon our ability to increase the size of our skilled labor force. We have intensified our recruitment and training programs in an effort to meet our anticipated personnel needs. These efforts may be unsuccessful, and competition for skilled personnel could materially impact our business by limiting or affecting the quality and safety of our operations or further increasing our costs.
Our international operations involve additional risks not generally associated with domestic operations, which may hurt our operations materially.
In 2007, we derived 83% of our revenues from countries outside the United States. Our operations in these areas are subject to the following risks, among others:
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foreign currency fluctuations and devaluations;
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restrictions on currency or capital repatriation;
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political, social and economic instability, war and civil disturbances;
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seizure, expropriation or nationalization of assets or confiscatory taxation;
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significant governmental influence over many aspects of local economies;
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unexpected changes in regulatory requirements;
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work stoppages;
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damage to our equipment or violence directed at our employees, including kidnappings;
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complications associated with repairing and replacing equipment in remote locations;
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repudiation, nullification, modification or renegotiation of contracts;
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limitations on insurance coverage, such as war risk coverage, in certain areas;
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piracy;
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imposition of trade barriers;
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wage and price controls;
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import-export quotas;
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uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate;
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acts of terrorism; and
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other forms of government regulation and economic conditions that are beyond our control.
We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not take protective measures against exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We
attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment in U.S. dollars or freely convertible foreign currency. To the extent possible, we seek to limit our exposure to local currencies by matching the acceptance of local currencies to our expense requirements in those currencies. Although we have done this in the past, we may not be able to take these actions in the future, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate materially.
Our ability to compete in international contract drilling markets may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, our foreign subsidiaries may face governmentally imposed restrictions from time to time on their ability to transfer funds to us. Finally, governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems which are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.
The laws and regulations concerning import activity, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
Although we implement policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate, our employees, contractors and agents may take actions in violation of our policies and such laws. Any such violation, even if prohibited by our policies, could materially and adversely affect our business.
We are conducting an investigation into allegations of improper payments to foreign government officials, as well as corresponding accounting entries and internal control issues. The outcome and impact of this investigation are unknown at this time.
During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.
The investigation, which is continuing, has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig
and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.
The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations. In addition, the U.S. Department of Justice has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria. The Audit Committee is reviewing the issues raised by the request, and we are cooperating with the DOJ in connection with its request.
This review has found evidence suggesting that during the period from 2001 through 2005 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola, and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2 million. We are also reviewing certain agent payments related to Malaysia.
The investigation of the matters described in the prior paragraph and the Audit Committee’s compliance review are ongoing. Accordingly, there can be no assurances that evidence of additional potential FCPA violations may not be uncovered in those or other countries.
Our management and the Audit Committee of our Board of Directors believe it likely that members of our senior operations management either were aware, or should have been aware, that improper payments to foreign government officials were made or proposed to be made. Our former Chief Operating Officer resigned as Chief Operating Officer effective on May 31, 2006 and has elected to retire from the company, although he will remain an employee, but not an officer, during the pendency of the investigation to assist us with the investigation and to be available for consultation and to answer questions relating to our business. His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the Securities and Exchange Commission and are cooperating with these authorities as the investigation and compliance reviews continue and as they review the matter. If violations of the FCPA occurred, we could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.
We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets. No amounts have been accrued related to any potential fines, sanctions or other penalties, which could be material individually or in the aggregate.
We cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, the applicable government or other authorities or our customers or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.
If we are unable to renew or obtain new and favorable contracts for rigs whose contracts are expiring or are terminated, our revenues and profitability could be materially reduced.
We have a number of contracts that will expire in 2008 and 2009. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the dayrates under any new contracts may be substantially below the existing dayrates, which could materially reduce our revenues and profitability.
Our customers may seek to cancel or renegotiate some of our drilling contracts during periods of depressed market conditions or if we experience downtime, operational difficulties, or safety-related issues.
Substantially all our contracts with major customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well. During depressed market conditions, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime, operational problems above the contractual limit or safety-related issues, if the rig is a total loss, if the rig is not delivered to the customer within the period specified in the contract or in other specified circumstances, which include events beyond the control of either party. Some of our contracts with our customers include terms allowing them to terminate contracts without cause, with little or no prior notice and without penalty or early termination payments. In addition, we could be required to pay penalties, which could be material, if some of our contracts with our customers are terminated due to downtime, operational problems or failure to deliver. Some of our other contracts with customers may be cancelable at the option of the customer upon payment of a penalty, which may not fully compensate us for the loss of the contract. Early termination of a contract may result in a rig being idle for an extended period of time. The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. If our customers cancel some of our significant contracts and we are unable to secure new contracts on substantially similar terms, our revenues and profitability could be materially reduced.
Many of our contracts with our customers for our offshore rigs are long-term dayrate contracts. Increases in our costs, which are unpredictable and fluctuate based on events outside our control, could adversely impact our profitability.
In periods of rising demand for offshore rigs, a drilling contractor generally would prefer to enter into well-to-well or other shorter term contracts that would allow the contractor to profit from increasing dayrates, while customers with reasonably definite drilling programs would typically prefer longer term contracts in order to maintain dayrates at a consistent level. Conversely, in periods of decreasing demand for offshore rigs, a drilling contractor generally would prefer longer term contracts to preserve dayrates and utilization, while customers generally would prefer well-to-well contracts or other shorter term contracts that would allow the customer to benefit from the decreasing dayrates. In 2007, a majority of our revenue was derived from long-term dayrate contracts, and substantially all of our backlog as of December 31, 2007 was attributable to long-term dayrate contracts. As a result, our inability to fully benefit from increasing dayrates in an improving market may limit our profitability.
In general, our costs increase as the business environment for drilling services improves and demand for oilfield equipment and skilled labor increases. While many of our contracts include escalation provisions that allow us to increase the dayrate based on stipulated costs increases, the timing and amount earned from these dayrate increases may differ from our actual increase in costs. Additionally, if our rigs incur idle time between contracts, we typically do not de-man those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary
significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.
We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.
As of December 31, 2007, our contract drilling backlog was approximately $4.9 billion for future revenues under firm commitments. We may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, including those described above. Our inability to perform under our contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.
Our jackup rigs and some of our lower specification semisubmersible rigs are at a relative disadvantage to higher specification jackup and semisubmersible rigs. These higher specification rigs may be more likely to obtain contracts than our lower specification rigs, particularly during market downturns.
Many of our competitors have jackup fleets with generally higher specification rigs than those in our jackup fleet, and our fleet includes a number of older and/or lower specification semisubmersible rigs. In addition, the announced construction of approximately 153 new rigs includes jackup rigs, semisubmersible rigs and ultra-deepwater drillships. Particularly during market downturns when there is decreased rig demand, higher specification rigs may be more likely to obtain contracts than lower specification rigs. Some of our significant customers may also begin to require higher specification rigs for the types of projects that currently utilize our lower specification rigs, which could materially affect their utilization. In the past, our lower specification rigs have been stacked earlier in the cycle of decreased rig demand than many of our competitors’ higher specification rigs and have been reactivated later in the cycle, which has adversely impacted our business and could be repeated in the future. In addition, higher specification rigs may be more adaptable to different operating conditions and have greater flexibility to move to areas of demand in response to changes in market conditions. Furthermore, in recent years, an increasing amount of exploration and production expenditures have been concentrated in deeper water drilling programs and deeper formations, including deep natural gas prospects, requiring higher specification rigs. This trend is expected to continue and could result in a material decline in demand for the lower specification rigs in our fleet.
Our ability to move some of our rigs to other regions is limited.
Most jackup and submersible rigs can be moved from one region to another, and in this sense the contract drilling market is a global market. The supply and demand balance for jackup and semisubmersible rigs may vary somewhat from region to region, because the cost to move a rig is significant, there is limited availability of rig-moving vessels and some rigs are designed to work in specific regions. However, significant variations between regions tend not to exist on a long-term basis due to the ability to move rigs. Our mat-supported jackup rigs are less capable than independent leg jackup rigs of managing variable sea floor conditions found in most areas outside the Gulf of Mexico. As a result, our ability to move these rigs to other regions in response to changes in market conditions is limited.
We rely heavily on a small number of customers and the loss of a significant customer could have a material adverse impact on our financial results.
Our contract drilling business is subject to the usual risks associated with having a limited number of customers for our services. For the year ended December 31, 2007, our four largest customers provided approximately 54% of our consolidated revenues. Our results of operations could be materially adversely affected if any of our major customers terminates its contracts with us, fails to renew its existing contracts or refuses to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates.
Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2007, we had $1,191.5 million in long-term debt. This debt represents approximately 26% of our total capitalization. Our current indebtedness may have several important effects on our future operations, including:
•
a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes;
•
covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities; and
•
our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited.
Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our three drillship construction projects, will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings.
We are subject to a number of operating hazards, including those specific to marine operations. We may not have insurance to cover all these hazards.
Our operations are subject to hazards customary in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punchthroughs, craterings, fires, explosions and pollution. Contract drilling and well servicing require the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages. We customarily provide contract indemnity to our customers for:
•
claims that could be asserted by us relating to damage to or loss of our equipment, including rigs;
•
claims that could be asserted by us or our employees relating to personal injury or loss of life; and
•
legal and financial consequences of spills of industrial waste and other liquids, but only to the extent (1) that the waste or other liquids were in our control at the time of the spill, (2) that our level of culpability is greater than mere negligence or (3) of specified monetary limits.
Certain areas in and near the Gulf of Mexico are subject to hurricanes and other extreme weather conditions on a relatively frequent basis. Our drilling rigs in the Gulf of Mexico may be located in areas that could cause them to be susceptible to damage or total loss by these storms. In addition, damage caused by high winds and turbulent seas to our rigs, our shorebases and our corporate infrastructure could potentially cause us to curtail operations for significant periods of time until the damages can be repaired.
We maintain insurance for injuries to our employees, damage to or loss of our equipment and other insurance coverage for normal business risks, including general liability insurance. Any insurance protection may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. For example, pollution, reservoir damage and environmental risks generally are not fully insurable. Except for a portion of our deepwater fleet, we generally do not maintain business interruption or loss of hire insurance. In addition, some of our primary insurance policies have substantial per occurrence or annual deductibles and/or self-insured aggregate amounts.
As a result of a number of catastrophic events over the last few years, such as the hurricanes in the Gulf of Mexico in 2004 and 2005, insurance underwriters increased insurance premiums for many of the coverages
historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry in the Gulf of Mexico suffered extensive damage from those hurricanes. As a result, our insurance costs and our deductibles increased significantly when our policies renewed in July 2006. Our insurance policy has a $16 million aggregate deductible. In addition, the marine package policy has a sub-limit of $110 million for physical damage claims due to a named windstorm in the U.S. Gulf of Mexico. A number of our customers that produce oil and natural gas in the Gulf of Mexico have maintained business interruption insurance for their production. This insurance may cease to be available in the future, which could adversely impact our customers’ business prospects in the Gulf of Mexico and reduce demand for our services.
The occurrence of a significant event against which we are not fully insured, or of a number of lesser events against which we are insured but are subject to substantial deductibles, aggregate limits, and/or self-insured amounts, could materially increase our costs and impair our profitability and financial condition. We may not be able to maintain adequate insurance at rates or on terms that we consider reasonable or acceptable or be able to obtain insurance against certain risks.
We may not be able to maintain or replace our rigs as they age.
The capital associated with the repair and maintenance of our fleet increases with age. We may not be able to maintain our fleet of existing rigs to compete effectively in the market, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement rigs.
Failure to secure a drilling contract prior to deployment of the uncontracted drillship under construction or any other rigs we may construct in the future prior to their deployment could adversely affect our future results of operations.
Two of our three drillships under construction have long-term drilling contracts. The drillship remaining to be contracted is scheduled for delivery in the second quarter of 2010. We have not yet obtained a drilling contract for this drillship. In addition, we may commence the construction of additional rigs for our fleet from time to time without first obtaining a drilling contract covering any such rig. Our failure to secure a drilling contract for any rig under construction, including our remaining uncontracted drillship construction project, prior to its deployment could adversely affect our results of operations and financial condition.
New technologies may cause our current drilling methods to become obsolete, resulting in an adverse effect on our business.
The offshore contract drilling industry is subject to the introduction of new drilling techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies, we may be placed at a competitive disadvantage and competitive pressures may force us to implement new technologies at substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to benefit from technological advantages and implement new technologies before we can. We may not be able to implement technologies on a timely basis or at a cost that is acceptable to us.
Our customers may be unable or unwilling to indemnify us.
Consistent with standard industry practice, our clients generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These risks are those associated with the loss of control of a well, such as blowout or cratering, the cost to regain control or redrill the well and associated pollution. There can be no assurance, however, that these clients will necessarily be willing or financially able to indemnify us against all these risks. Also, we may be effectively prevented from enforcing these indemnities because of the nature of our relationship with some of our larger clients.
We are subject to numerous governmental laws and regulations, including those that may impose significant costs and liability on us for environmental and natural resource damages.
Many aspects of our operations are affected by governmental laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring us to obtain and maintain specified permits or other governmental approvals and to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. Our operations and activities in the United States are
subject to numerous environmental laws and regulations, including the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation and Liability Act and the International Convention for the Prevention of Pollution from Ships. Additionally, other countries where we operate have environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment in connection with operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, the denial or revocation of permits or other authorizations and the issuance of injunctions that may limit or prohibit our operations. Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and natural gas could materially limit future contract drilling opportunities or materially increase our costs or both. In addition, we may be required to make significant capital expenditures to comply with laws and regulations or materially increase our costs or both.
Our ability to operate our rigs in the U.S. Gulf of Mexico could be restricted or made more costly by government regulation.
Hurricanes Katrina and Rita in 2005 caused damage to a number of rigs in the Gulf of Mexico fleet, and rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. In May 2006 and April 2007, the MMS issued interim guidelines for jackup rig fitness requirements for the 2006 hurricane season, effectively imposing new requirements on the offshore oil and natural gas industry in an attempt to increase the likelihood of survival of jackup rigs and other offshore drilling units during a hurricane. These MMS interim guidelines, the latest of which expired on November 30, 2007, resulted in our jackup rigs operating in the U.S. Gulf of Mexico being required to operate with a higher air gap during the 2006 and 2007 hurricane seasons, effectively reducing the water depth in which they can operate. The guidelines also provided for enhanced information and data requirements from oil and natural gas companies operating properties in the U.S. Gulf of Mexico. The MMS may issue similar guidelines for future hurricane seasons and may take other steps that could increase the cost of operations or reduce the area of operations for our jackup rigs, thus reducing their marketability. Implementation of new MMS guidelines or regulations may subject us to increased costs and limit the operational capabilities of our rigs.
A change in tax laws of any country in which we operate could result in a higher tax expense or a higher effective tax rate on our worldwide earnings.
We conduct our worldwide operations through various subsidiaries. Tax laws and regulations are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, treaties and regulations in and between countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, treaties or regulations, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings.
As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We are currently contesting several tax assessments that could be material and may contest future assessments where we believe the assessments are in error. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees in international markets are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs or limit our flexibility.
Certain legal obligations require us to contribute certain amounts to retirement funds and pension plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our business, financial condition and results of operation.
We may incur substantial costs associated with workforce reductions.
In many of the countries in which we operate, our workforce has certain compensation and other rights arising from our various collective bargaining agreements and from statutory requirements of those countries relating to involuntary terminations. If we choose to cease operations in one of those countries or if market conditions reduce the demand for our drilling services in such a country, we could incur costs, which may be material, associated with workforce reductions.
Public health threats could have a material adverse effect on our operations and our financial results.
Public health threats, such as the bird flu, Severe Acute Respiratory Syndrome (SARS) and other highly communicable diseases, could adversely impact our operations, the operations of our clients and the global economy in general, including the worldwide demand for oil and natural gas and the level of demand for our services. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may materially impact operations and adversely affect our financial results.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Our property consists primarily of mobile offshore and land drilling rigs, well servicing rigs and ancillary equipment, most of which we own. Some of our rigs are pledged to collateralize our secured credit facilities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” in Item 7 of this annual report. We also own and operate transport and heavy duty trucks and other ancillary equipment.
We own or lease office and operating facilities in Houston, Texas, Houma, Louisiana and in Angola, Brazil, Mexico, France and several additional international locations.
We incorporate by reference in response to this item the information set forth in Item 1 and Item 7 of this annual report and the information set forth in Notes 4 and 5 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
FCPA Investigation
We incorporate by reference in response to this item the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - FCPA Investigation” in Item 7 of this annual report.
Other Legal Proceedings
Since 2004, certain of our subsidiaries have been named, along with numerous other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi by several hundred individuals that allege that they were employed by some of the named defendants between approximately 1965 and 1986. The complaints allege that certain drilling contractors used products containing asbestos in their operations and seek, among other things, an award of unspecified compensatory and punitive damages. Eight individuals of the many plaintiffs in these suits have been identified as allegedly having worked for us. We intend to defend ourselves
vigorously and, based on the information available to us at this time, we do not expect the outcome of these lawsuits to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits.
Paul Bragg, our former President and Chief Executive Officer, filed suit against us in the State District Court of Harris County, Texas in October 2005 seeking declaratory relief to set aside his non-competition agreement and damages for breach of contract in excess of $17 million. We and Mr. Bragg litigated his claims as well as a number of counterclaims we filed against Mr. Bragg, including a claim for breach of fiduciary duty. In late 2006 and early 2007, the trial court granted summary judgment in our favor against Mr. Bragg with respect to his breach of contract claims and in Mr. Bragg’s favor against our breach of fiduciary duty counterclaim. Mr. Bragg’s two-year contractual commitment to not compete with us ended in June 2007, according to the terms of his employment agreement. We and Mr. Bragg have each appealed the summary dismissal of our respective claims, and the appeals are currently pending. We intend to continue our vigorous defense against Mr. Bragg’s breach of contract claims on appeal. Similarly, we intend to pursue diligently on appeal our breach of fiduciary duty counterclaim against Mr. Bragg. We do not expect the outcome of this lawsuit to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this lawsuit.
We are routinely involved in other litigation, claims and disputes incidental to our business, which at times involve claims for significant monetary amounts, some of which would not be covered by insurance. In the opinion of management, none of the existing litigation will have a material adverse effect on our financial position, results of operations or cash flows. However, a substantial settlement payment or judgment in excess of our accruals could have a material adverse effect on our financial position, results of operations or cash flows.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
Executive Officers of Registrant
We have presented below information about our executive officers as of February 28, 2008. Officers are appointed annually by the Board of Directors and serve until their successors are chosen or until their resignation or removal.
Louis A. Raspino was named President, Chief Executive Officer and a Director in June 2005. He joined us in December 2003 as Executive Vice President and Chief Financial Officer. From July 2001 until December 2003, he served as Senior Vice President, Finance and Chief Financial Officer of Grant Prideco, Inc. From February 1999 until March 2001, he held various senior financial positions, including Vice President of Finance for Halliburton Company. From October 1997 until July 1998, he was a Senior Vice President at Burlington Resources, Inc. From 1978 until its merger with Burlington Resources, Inc. in 1997, he held a variety of increasingly responsible positions at Louisiana Land and Exploration Company, most recently as Senior Vice President, Finance and Administration and Chief Financial Officer. Mr. Raspino also is a Director of Dresser-Rand Group Inc.
Rodney W. Eads was named Executive Vice President, Chief Operating Officer in September 2006. Since 1997, he served as Senior Vice President, Worldwide Operations for Diamond Offshore, where he was responsible for their offshore drilling fleet. From 1980 through 1997 he served in several executive and operations management positions with Exxon Corporation, primarily in international assignments and including Drilling Manager, Exxon Company International. Prior to joining Exxon, Mr. Eads served as a Senior Drilling Engineer for ARAMCO and a Petroleum Engineer with Cities Services Corporation.
Brian C. Voegele joined us in December 2005 and became our Senior Vice President and Chief Financial Officer in January 2006. From June 2005 through November 2005, he served as Senior Vice President, Chief Financial Officer, Treasurer and Secretary of Bristow Group (formerly Offshore Logistics, Inc.). From July 1989 until January 2005, he held various senior management positions at Transocean Inc. Mr. Voegele began his career at Arthur Young & Co., where he ultimately served as Tax Manager.
Lonnie D. Bane was named Senior Vice President, Human Resources in January 2005. He previously served as Vice President, Human Resources since June 2004. From July 2000 until May 2003, he served as Senior Vice President, Human Resources of America West Airlines, Inc. From July 1998 until July 2000, he held various senior management positions, including Senior Vice President, Human Resources at Corporate Express, Inc. From February 1996 until July 1998, Mr. Bane served as Senior Vice President, Human Resources for CEMEX, S.A. de C.V. From 1994 until 1996, he was a Vice President, Human Resources at Allied Signal Corporation. From 1987 until 1994, he held various management positions at Mobil Oil Corporation.
W. Gregory Looser was named Senior Vice President, General Counsel and Secretary in January 2005. He had previously served as Vice President, General Counsel and Secretary since December 2003. He joined us in May 1999 as Assistant General Counsel. Prior to that time, Mr. Looser was with the law firm of Bracewell & Guiliani, L.L.P. in Houston, Texas.
Kevin C. Robert was named Vice President, Marketing in March 2005 and became Senior Vice President, Marketing and Business Development in May 2006. Prior to joining us, from June 2002 to February 2005, Mr. Robert worked for Samsung Heavy Industries as the Vice President, EPIC Contracts. From January 2001 through September 2001, Mr. Robert was employed by Marine Drilling Companies, Inc. as the Vice President, Marketing. When we acquired Marine in September 2001, he became our Director of Business Development, where he served until June 2002. From November 1997 through December 2000, Mr. Robert was Managing Member of Maverick Offshore L.L.C. From January 1981 to November 1997, Mr. Robert was employed by Conoco Inc.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange under the symbol “PDE.” As of February 27, 2008, there were approximately 1,350 stockholders of record. The following table presents the range of high and low sales prices of our common stock on the NYSE for the periods shown:
We have not paid any cash dividends on our common stock since becoming a publicly held corporation in September 1988. We currently do not have any plans to pay cash dividends on our common stock. In addition, in the event we elect to pay cash dividends in the future, our ability to pay such dividends would be limited by our existing financing arrangements.
Unregistered Sales of Equity Securities
None.
Issuer Purchases of Equity Securities
None.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
We have derived the following selected consolidated financial information as of December 31, 2007 and 2006, and for the years ended December 31, 2007, 2006 and 2005, from our audited consolidated financial statements included in Item 8 of this annual report. We have derived the selected consolidated financial information as of December 31, 2005, 2004 and 2003 and for the years ended December 31, 2004 and 2003 from consolidated financial information included our annual report on Form 10-K for the year ended December 31, 2006. During 2007, we reclassified the results of operations of our Latin America Land and E&P Services segments and three tender-assist barge rigs to discontinued operations for all periods reported. See Note 2 to Notes to the Consolidated Financial Statements in Item 8 of this annual report. The selected consolidated financial information below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Financial Statement and Supplementary Data” in Item 8 of this annual report. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A and elsewhere in this annual report. See “Forward-Looking Statements” below.
Overview
We are one of the world’s largest offshore drilling contractors operating, as of February 27, 2008, a fleet of 64 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, 28 jackups, 10 platform rigs, five managed deepwater drilling rigs and seven Eastern Hemisphere-based land drilling rigs. We have three ultra-deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.
We operate in many of the significant deepwater oil and natural gas basins throughout the world, including Brazil, West Africa and the Gulf of Mexico. In addition to our owned deepwater fleet, we also manage the drilling operations for five deepwater rigs owned by our customers. With our combined owned and managed fleet, we believe that we are the second largest operator of deepwater rigs and that our deepwater fleet is among the youngest in the industry, with seven of our eight deepwater rigs having been placed into service since 1999. We believe our deepwater experience and the age of our fleet gives us a competitive advantage for contract opportunities, including newbuild prospects, over our competitors with older, lower specification rigs or competitors with less operating and engineering experience in deepwater.
We are increasing our emphasis on deepwater and other high specification drilling solutions. We believe that customer demands to explore and develop deepwater fields will exceed the capacity of the existing deepwater drilling rig fleet for the next several years. In line with this belief, since 2005 we have invested or committed to invest over $2.8 billion in the expansion of our deepwater fleet. Our accomplishments include our acquisition of the remaining 49% outside joint venture interests in our two existing drillships, acquiring the remaining 70% interests in two of our deepwater semisubmersible rigs in Brazil, and expanding our drillship fleet through our three ultra-deepwater drillships under construction, two of which have drilling contracts for periods of at least five years after delivery. As part of our focus on deepwater and premium offshore services, we have sought opportunities to dispose of non-core assets to enable us to reinvest our financial and human capital to develop our growth strategy. Most notably, in 2007, we sold our Latin America Land and E&P Services business for approximately $1 billion in cash and completed the sale of our three tender-assist barges for $213 million in cash in the first quarter of 2008.
Recent Developments
Investments in Deepwater Fleet
In June 2007, we entered into an agreement with Samsung Heavy Industries Co., Ltd. to construct an advanced-capability ultra-deepwater drillship. The agreement provides for an aggregate fixed purchase price of approximately $612 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before June 30, 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. We expect the total project cost, including commissioning and testing, to be approximately $680 million, excluding capitalized interest. In connection with the construction contract, we entered into a license agreement with the holder of certain patents, which are expected to expire in 2016, related to the drillship’s dual-activity capabilities. Under the license agreement, we paid the holder a fee of $10 million for the initial drillship and we will pay an additional $15 million for any additional drilling units that use the patented technology, plus five percent of the revenue earned by the drillship and any additional units (reduced by a $5 million credit per unit for any of the additional units) in jurisdictions where the license is applicable. Although we currently do not have a drilling contract for this drillship, we expect that the anticipated demand resulting from the continuing expansion of
customer requirements for deepwater drilling capacity should provide us with a number of opportunities to contract the rig prior to its delivery date.
In July 2007, we acquired from Lexton Shipping Ltd. an advanced-capability ultra-deepwater drillship being constructed by Samsung. As consideration for our acquisition of Lexton’s rights under the drillship construction contract with Samsung, we paid Lexton $108.5 million in cash and assumed its obligations under the construction contract, including remaining scheduled payments of approximately $540 million. The construction contract provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before February 28, 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. In January 2008, we entered into a five-year contract with respect to the drillship for drilling operations in the U.S. Gulf of Mexico, which is expected to commence during the third quarter of 2010 following the completion of shipyard construction, mobilization of the rig to the U.S. Gulf of Mexico and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to improve its off-line operational capabilities. Including these modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $730 million, excluding capitalized interest.
In August 2007, we acquired the remaining nine percent interest in our Angolan joint venture company for $45 million in cash from a subsidiary of Sonangol, the national oil company of Angola. The joint venture owned the two deepwater drillships Pride Africa and Pride Angola and the 300 foot independent-leg jackup rig Pride Cabinda, and held management agreements for the deepwater platform rigs Kizomba A and Kizomba B.
In January 2008, we entered into an agreement with Samsung to construct an advanced-capability ultra-deepwater drillship. The agreement provides for an aggregate fixed purchase price of approximately $635 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before March 31, 2011. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. We have entered into a multi-year drilling contract with respect to the drillship, which is expected to commence during the first quarter of 2011 following the completion of shipyard construction, mobilization of the rig and customer acceptance testing. Under the drilling contract, the customer may elect, by January 31, 2010, a firm contract term of at least five years and up to seven years in duration. We expect the total project cost, including commissioning and testing, to be approximately $720 million, excluding capitalized interest.
Dispositions
In August 2007, we completed the sale to GP Investments Ltd., a private equity firm based in Brazil, of all of the issued and outstanding capital stock of our subsidiaries through which we conducted the business of our Latin America Land and E&P Services segments. The purchase price paid at closing of $1.0 billion in cash is subject to adjustment based on the working capital of the business at the closing date. We have agreed not to compete with the land drilling and E&P services business in Mexico, Central America and South America or solicit employees of the business for a period of three years following the closing. We and the buyer have agreed, subject to certain limitations, to indemnify each other against various matters, which could be material.
In August 2007, we also entered into an agreement to sell our fleet of three self-erecting, tender-assist rigs to Ferncliff TIH AS of Norway for $213 million in cash. We completed the sale the rigs in the first quarter of 2008. In connection with the sale, we entered into an agreement to operate one of the rigs until its current contract is completed, which is anticipated to be in December 2008.
We have reclassified all of our historical operations of the Latin America Land and E&P Services segments and our three tender-assist rigs to discontinued operations. Unless noted otherwise, our discussion and analysis that follows relates to our continuing operations only. Subsequent to the disposition of our Latin America Land and E&P Services segments, our operations consist of one reportable segment, Offshore Drilling Services.
FCPA Investigation
During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the
investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.
The investigation, which is continuing, has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.
The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations. In addition, the U.S. Department of Justice has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria. The Audit Committee is reviewing the issues raised by the request, and we are cooperating with the DOJ in connection with its request.
This review has found evidence suggesting that during the period from 2001 through 2005 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola, and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2 million. We are also reviewing certain agent payments related to Malaysia.
The investigation of the matters described in the prior paragraph and the Audit Committee’s compliance review are ongoing. Accordingly, there can be no assurances that evidence of additional potential FCPA violations may not be uncovered in those or other countries.
Our management and the Audit Committee of our Board of Directors believe it likely that members of our senior operations management either were aware, or should have been aware, that improper payments to foreign government officials were made or proposed to be made. Our former Chief Operating Officer resigned as Chief Operating Officer effective on May 31, 2006 and has elected to retire from the company, although he will remain an employee, but not an officer, during the pendency of the investigation to assist us with the investigation and to be available for consultation and to answer questions relating to our business. His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the Securities and Exchange Commission and are cooperating with these authorities as the investigation and compliance reviews continue and as they review the matter. If violations of the FCPA occurred, we could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time
may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.
We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets. No amounts have been accrued related to any potential fines, sanctions or other penalties, which could be material individually or in the aggregate.
We cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, the applicable government or other authorities or our customers or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.
Our Business
We provide contract drilling services to major integrated, government-owned and independent oil and natural gas companies throughout the world. Our offshore drilling fleet competes on a global basis, as offshore rigs generally are highly mobile and may be moved from one region to another in response to demand. While the cost of moving a rig and the availability of rig-moving vessels may cause the supply and demand balance to vary somewhat between regions, significant variations between regions do not tend to persist long-term because of rig mobility. Pricing is often the primary factor in determining which qualified contractor is awarded a job. Rig availability, location and technical ability and each contractor’s safety performance record and reputation for quality also can be key factors in the determination. All of our drilling contracts with major customers are on a dayrate basis, where we charge the customer a fixed amount per day regardless of the number of days needed to drill the well. We provide the rigs and drilling crews and are responsible for the payment of rig operating and maintenance expenses. Our customer bears the economic risk and benefit relative to the geologic success of the wells.
The markets for our drilling services are highly cyclical. Our operating results are significantly affected by the level of energy industry spending for the exploration and development of oil and natural gas reserves. Oil and natural gas companies’ exploration and development drilling programs drive the demand for drilling services. These drilling programs are affected by oil and natural gas companies’ expectations about oil and natural gas prices, anticipated production levels, demand for crude oil and natural gas products and many other factors. The availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect our customers’ drilling programs. Oil and natural gas prices are volatile, which has historically led to significant fluctuations in expenditures by our customers for oil and natural gas drilling services. Variations in market conditions during the cycle impact us in different ways depending primarily on the length of drilling contracts in different regions. For example, contracts in the U.S. Gulf of Mexico tend to be shorter term, so a deterioration or improvement in market conditions tends to quickly impact revenues and cash flows from those operations. Contracts in international offshore markets tend to be longer term, so a change in market conditions tends to have a delayed impact. Accordingly, short-term changes in market conditions may have minimal short-term impact on revenues and cash flows from those operations unless the timing of contract renewals takes place during the short-term changes in the market.
Generally, we expect global demand for offshore contract drilling services to remain strong, driven by increasing worldwide demand for oil and natural gas, an increased focus by oil and natural gas companies on offshore prospects and increased global participation by national oil companies. Customer requirements for deepwater drilling capacity continue to expand, as successful results in exploration drilling have led to prolonged field development programs around the world, placing deepwater assets in limited supply beyond the end of the decade. We believe that long-term market conditions for deepwater drilling services are favorable and that demand for deepwater rigs will continue to exceed supply for the next several years, producing attractive opportunities for deepwater drilling rigs, including ultra-deepwater rigs like ours under construction. We believe that higher prices for oil, geological successes in exploratory markets and, in general, more favorable political conditions will continue to encourage the development of new projects by exploration and production companies on a number of major
deepwater discoveries. In addition, we believe that the need for deepwater rigs will continue to grow for existing offshore development projects.
Our revenues depend principally upon the number of our available rigs, the number of days these rigs are utilized and the contract dayrates received. The number of days our rigs are utilized and the contract dayrates received are largely dependent upon the balance of supply of drilling rigs and demand for drilling services for the different rig classes we operate, as well as our rigs’ operational performance, including mechanical efficiency. The number of rigs we have available may increase or decrease as a result of the acquisition or disposal of rigs, the construction of new rigs and the number of rigs being upgraded or repaired or undergoing periodic surveys or routine maintenance at any time. In order to improve utilization or realize higher contract day rates, we may mobilize our rigs from one geographic region to another for which we may receive a mobilization fee. Mobilization fees are deferred and recognized as revenue over the term of the contract.
Our earnings from operations are primarily affected by revenues, cost of labor, repairs and maintenance and utilization of our drilling fleet. Many of our drilling contracts allow us to increase the dayrates charged to our customer based on increases in operating costs, such as increases in labor costs, maintenance and repair costs, and insurance costs. Some of our costs are fixed in nature or do not vary at the same time or to the same degree as changes in revenue. For instance, if a rig is expected to be idle between contracts and earn no revenue, we will still maintain our rig crew, which reduces our earnings as we cannot fully offset the impact of the lost revenues with reductions in operating costs.
Our industry is being affected by shortages of, and increased competition for, skilled rig crew personnel due to the level of activity in the drilling industry. As a result, the costs to attract and retain personnel continue to increase. To better retain and attract skilled rig personnel, we offer competitive compensation programs and have increased our focus on training and management development programs. We believe that labor costs will continue to increase in 2008. In addition, increased demand for contract drilling operations has increased demand for oilfield equipment and spare parts, which, when coupled with the consolidation of equipment suppliers, has resulted in longer order lead times to obtain critical spares and other critical equipment components essential to our business, higher repair and maintenance costs and longer out-of-service time for major repair and upgrade projects. We anticipate maintaining higher levels of critical spares to minimize unplanned downtime. With the current level of business activity, we do not expect these trends to moderate in the near term. However, due to higher market dayrates and our ability to increase dayrates for higher costs, we expect our growth in revenues to continue to outpace our cost increases throughout 2008.
Our operations and activities are subject to numerous environmental laws and regulations, including the U.S. Oil Pollution Act of 1990, the U.S. Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation and Liability Act and the International Convention for the Prevention of Pollution from Ships. Additionally, other countries where we operate have similar laws and regulations covering the discharge of oil and other contaminants in connection with drilling operations.
As a result of the significant insurance losses incurred by the drilling industry during the 2004 and 2005 hurricane seasons, our insurance costs increased significantly when our policies renewed in July 2006. Our insurance policy has a $16 million aggregate deductible. In addition, the marine package policy has a sub-limit of $110 million for physical damage claims due to a named windstorm in the U.S. Gulf of Mexico.
We operate in one reportable segment, Offshore Drilling Services, with a global fleet of offshore rigs. We consider our drillships and our semisubmersible rigs operating in water depths greater than 4,500 feet as deepwater and our semisubmersible rigs operating in water depths from 1,000 feet to 4,500 feet as midwater. Our jackups operate in water depths up to 300 feet.
Our deepwater fleet currently operates in West Africa, Brazil and the Mediterranean Sea, and is fully contracted through mid-2008, with most of the fleet contracted into 2010 and beyond. As a result, we would benefit from potential dayrate increases for deepwater rigs only when our deepwater fleet can operate under new contracts or as our uncontracted ultra-deepwater drillship becomes available. Based on our recent contracts for two of our ultra-deepwater rigs under construction and inquiries received from our clients, we believe our customer needs for deepwater drilling rigs are extending five to ten years into the future. Contracts for deepwater rigs tend to be longer term, with some contracts being five or more years in length, reflecting the demand for drilling rigs and our customers’ long-term commitment to deepwater exploration and development. Based on limited rig availability and
the geologic success in deepwater, we expect dayrates for deepwater rigs to remain strong for the next several years.
Our midwater fleet currently operates in West Africa, Brazil and the Mediterranean Sea. We currently have half of our midwater fleet contracted through 2013. At present, strong demand and limited availability of rigs continues to sustain the high dayrates for the midwater fleet. Contracts for midwater rigs tend to be shorter in duration than contracts for deepwater rigs, with one to three years as the typical length. We believe strong demand and a limited ability to increase semisubmersible rig supply in the short term will result in favorable market conditions through 2009.
Our jackup fleet operates in the U.S. Gulf of Mexico and internationally in Mexico, the Middle East, Asia Pacific and West Africa. Contracts for our U.S. Gulf of Mexico jackup fleet tend to be for shorter periods as compared to international jackup contracts. Also, contracts for our Mexico jackup fleet are impacted by dayrate levels in the U.S. Gulf of Mexico. We continue to benefit from the current contract dayrates and high utilization in the international jackup market; however, we are beginning to observe indications of the potential negative effect on our dayrates due to worldwide newbuild rig fleet additions over the next three years. Currently, approximately 36 newbuild jackups are expected to be added to the global market with scheduled delivery by the end of 2008 and approximately 47 additional newbuild jackups have scheduled delivery dates from 2009 through 2011. We believe the addition of this rig capacity to the market is likely to result in increased volatility of and downward trends in international jackup dayrates and utilization. Since mid-2006, the dayrate environment in the U.S. Gulf of Mexico has been under pressure from lower demand for rigs. We expect our competitors to continue to seek opportunities to relocate rigs from the U.S. Gulf of Mexico to international markets, including the relocation of additional independent leg jackup rigs to Mexico. While dayrates in the U.S. Gulf of Mexico have stabilized due to recent increases in fleet utilization, any improvement in dayrates in the U.S. Gulf of Mexico will largely depend upon changes affecting natural gas storage levels and prices that drive increased activity levels, access to capital for small to medium sized exploration and production companies, seasonality in the market driven by recurring hurricane seasons, and the number and timing of rigs moving from the U.S. Gulf of Mexico to Mexico and other international markets. As dayrates in Mexico are based on U.S. Gulf of Mexico rates, we expect that dayrates for our Mexican fleet will adjust lower in 2008. In addition, we will likely be unable to compete for some of the growth opportunities in the Mexican jackup market due to the technical limits of some of our rigs.
We incurred approximately 1,350 unavailable days for shipyard maintenance and upgrade projects in 2007 for our existing fleet. For 2008, we expect the number of shipyard days to be approximately 725. These shipyard projects may be subject to repair delays. For our ultra-deepwater drillships under construction, we have attempted to mitigate risks of delay by selecting the same shipyard for all three construction projects with fixed-fee contracts, although some of our other risks with respect to these construction projects, such as work stoppages, disputes with the shipyard, shipyard financial and other difficulties and adverse weather conditions, are more concentrated.
Backlog
Our backlog at December 31, 2007, totaled approximately $4.9 billion for our executed contracts. Approximately $1.8 billion of this backlog is expected to be realized in 2008. Our backlog at December 31, 2006, was approximately $5.7 billion. We calculate our backlog, or future contracted revenue for our offshore fleet, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation, customer reimbursables and performance bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the amount disclosed or expected due to various factors. Downtime due to various operating factors, including unscheduled repairs, maintenance, weather and other factors, may result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances.
Subsequent to December 31, 2007, we were awarded firm drilling contracts for two of our ultra-deepwater drillships under construction. In addition, we received new contracts or contract extensions for several rigs in our fleet, including the Pride North Sea, the Pride Rio de Janeiro and the Pride Portland. In total, these contracts added approximately $3.1 billion to our backlog and resulted in our total backlog increasing to approximately $7.7 billion as of February 28, 2008.
Critical Accounting Estimates
The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.
Our critical accounting estimates are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. We would report different amounts in our consolidated financial statements, which could be material, if we used different assumptions or estimates. We have discussed the development and selection of our critical accounting estimates with the Audit Committee of our Board of Directors and the Audit Committee has reviewed the disclosure presented below. During the past three fiscal years, we have not made any material changes in accounting methodology used to establish the critical accounting estimates for property and equipment, income taxes and contingent liabilities discussed below; however, as previously disclosed, we made a material change in accounting methodology used to establish the critical accounting estimates for certain interest rate swap and cap agreements.
We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimation.
Property and Equipment
Property and equipment comprise a significant amount of our total assets. We determine the carrying value of these assets based on property and equipment policies that incorporate our estimates, assumptions and judgments relative to the carrying value, remaining useful lives and salvage value of our rigs.
We depreciate our property and equipment over their estimated useful lives using the straight-line method. The assumptions and judgments we use in determining the estimated useful lives of our rigs reflect both historical experience and expectations regarding future operations, utilization and performance. The use of different estimates, assumptions and judgments in the establishment of estimated useful lives, especially those involving our rigs, would likely result in materially different net book values of our property and equipment and results of operations.
Useful lives of rigs and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs when certain events occur that directly impact our assessment of the remaining useful lives of the rig and include changes in operating condition, functional capability and market and economic factors. We also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives of individual rigs. During the three months ended September 30, 2007, we completed a technical evaluation of our offshore fleet. As a result of this evaluation, remaining useful lives and estimated salvage values were adjusted on certain rigs in the fleet. These changes were primarily a result of changing market conditions, the significant capital investment in certain rigs and revisions to, and standardization of, maintenance practices. As a result of our evaluation, effective July 1, 2007, we increased our estimates of the remaining lives of certain semisubmersible and jackup rigs in our fleet between four and eight years, increased the expected useful lives of our drillships from 25 years to 35 years and our semisubmersibles from 25 years to 30 years, and updated our estimated salvage value for all of our offshore drilling rig fleet to 10% of the historical cost of the rigs. The effect of these changes in estimates was a reduction to depreciation expense of approximately $28.5 million and an after-tax increase to diluted earnings per share of $0.13 for the six-month period ended December 31, 2007.
We review our property and equipment for impairment whenever events or changes in circumstances indicate the carrying value of such assets or asset groups may not be recoverable. Indicators of possible impairment include extended periods of idle time and/or an inability to contract specific assets or groups of assets, such as a specific type of drilling rig, or assets in a specific geographical region. However, the drilling and workover industry in which
we operate is highly cyclical and it is not unusual to find that assets that were idle, under-utilized or contracted at sub-economic rates for significant periods of time resume activity at economic rates when market conditions improve. Additionally, most of our assets are mobile, and we may mobilize rigs from one market to another to improve utilization or realize higher dayrates.
Asset impairment evaluations are based on estimated future undiscounted cash flows of the assets being evaluated to determine the recoverability of carrying amounts. In general, analyses are based on expected costs, utilization and dayrates for the estimated remaining useful lives of the asset or group of assets being assessed. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not recoverable.
Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets and could materially affect our results of operations.
Income Taxes
Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. The income tax rates and methods of computing taxable income vary substantially in each jurisdiction. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates.
The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined.
Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as returns are filed, or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as of the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where the rigs are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances as discussed below.
As of December 31, 2007, we have U.S. net operating loss (“NOL”) carryforwards. Due to our acquisition of Marine Drilling Companies in September 2001, certain NOL carryforwards are subject to limitations under Sections 382 and 383 of the U.S. Internal Revenue Code. The U.S. NOL carryforwards could expire starting in 2021 through 2024. We have foreign NOL carryforwards, and we have recognized a valuation allowance on substantially all of these foreign NOL carryforwards. Certain foreign NOL carryforwards do not expire and some could expire starting in 2008 through 2017.
We have not provided for U.S. deferred taxes on the unremitted earnings of our foreign controlled subsidiaries that are permanently reinvested. If a distribution is made to us from the unremitted earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these unremitted earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.
As required by law, we file periodic tax returns that are subject to review and examination by various tax authorities within the jurisdictions in which we operate. We are currently contesting several tax assessments and may contest future assessments where we believe the assessments are in error. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments; however, we believe the ultimate
resolution of outstanding tax assessments will not have a material adverse effect on our consolidated financial statements.
In 2006, we received tax assessments from the Mexican government related to our operations for the tax years 2002 and 2003. These assessments contest our right to claim certain deductions in our tax returns for those years. We anticipate that the Mexican government will make additional assessments contesting similar deductions for other tax years. While we intend to contest these assessments vigorously, we cannot predict or provide assurance as to the ultimate outcome, which may take several years. However, we do not believe that the ultimate outcome of these assessments will have a material impact on our consolidated financial statements. As required by local statutory requirements, we have provided standby letters of credit, which totaled $45 million as of December 31, 2007, to contest these assessments.
We do not believe that it is possible to reasonably estimate the potential impact of changes to the assumptions and estimates identified because the resulting change to our tax liability, if any, is dependent on numerous underlying factors which cannot be reasonably estimated. These include, among other things, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have been appropriate; however, past experience is only a guide and the tax resulting from the resolution of current and potential future tax controversies may have a material adverse effect on our consolidated financial statements.
Contingent Liabilities
We establish reserves for estimated loss contingencies when we believe a loss is probable and the amount of the loss can be reasonably estimated. Our contingent liability reserves relate primarily to litigation, personal injury claims, indemnities and potential income and other tax assessments (see also “Income Taxes” above). Revisions to contingent liability reserves are reflected in income in the period in which different facts or information become known or circumstances change that affect our previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon our assumptions and estimates regarding the probable outcome of the matter. Should the outcome differ from our assumptions and estimates or other events result in a material adjustment to the accrued estimated reserves, revisions to the estimated reserves for contingent liabilities would be required and would be recognized in the period the new information becomes known.
Accounting for Interest Rate Swap and Cap Agreements
We currently use derivatives in the normal course of business to manage our exposure to fluctuations in interest rates. We have not designated our interest rate swap and cap agreements as hedging instruments in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities. Accordingly, we must determine the fair value of these agreements and record any changes to the fair value in our consolidated statements of operations. The determination of the fair value is complex and requires significant judgments and estimates, including the methodology of building a forward yield curve, the basis of discounting projected future cash flows and varying conventions in contract terms. The use of different estimates and assumptions could result in materially different fair values and could materially affect our results of operations.
Segment Review
Subsequent to the disposition of our Latin America Land and E&P Services segments in August 2007, our operations consist of one reportable segment, Offshore Drilling Services. All periods presented have been revised to reflect our Latin America Land and E&P Services segments and our three tender-assist rigs as discontinued operations. See Note 2 of our Notes to Consolidated Financial Statements in Item 8 of this annual report for additional information regarding discontinued operations. As a result of our disposal of the Latin America Land and E&P Services segments, certain operating and administrative costs were reallocated for all periods presented to our remaining continuing operating segments.
The following table summarizes our revenue and earnings from continuing operations by asset class of Offshore Drilling Services and our other continuing operations. We have included our seven land rigs and other operations in Other.
The following table summarizes our average daily revenues and percentage utilization by type of offshore rig in our fleet:
(1)
Average daily revenues are based on total revenues for each type of rig divided by actual days worked by all rigs of that type. Average daily revenues will differ from average contract dayrate due to billing adjustments for any non-productive time, mobilization fees, demobilization fees, performance bonuses and charges to the customer for ancillary services.
(2)
Utilization is calculated as the total days worked divided by the total days in the period.
Deepwater
Revenues increased $165.3 million, or 35%, for 2007 over 2006 as we continue to benefit from the strong demand for our deepwater rigs, which has resulted in higher dayrates and continued high utilization levels across much of the fleet. This strong performance was led by the Pride South Pacific, which contributed approximately $70 million of incremental revenue as a result of the commencement of a new contract in March 2007 with a dayrate approximately three times higher than its previous contract. The improvement was also due to increased utilization
from the Pride North America, which had non-revenue maintenance and repair downtime in 2006, and an increase of $47.7 million in revenue from the non-cash amortization of deferred revenue related to the Pride Portland and Pride Rio de Janeiro. Average daily revenues in 2007 increased 28% over 2006 primarily due to contract dayrate increases. Operating days increased 5% in 2007 over 2006 due to increased utilization from the Pride North America. Earnings from operations increased $150.7 million, or 121%, in 2007 over 2006 due to an increase in revenues and a decrease in rental expenses resulting from our acquisition in November 2006 of the remaining 70% interest in a joint venture company, the principal assets of which were the Pride Rio de Janeiro and the Pride Portland. Utilization increased to 96% for 2007 from 91% in 2006 due to the Pride North America, which had non-revenue maintenance repair and downtime in 2006. These favorable conditions were offset partially by a 19% increase in total labor costs resulting primarily from increased wages for our rig crews. In November 2006, we were awarded five-year contract extensions that begin in mid-2008 for the Pride Brazil and the Pride Carlos Walter and a three-year contract extension that began in early 2008 for the Pride North America, each at substantially higher dayrates from their previous contract dayrates. In June 2007, our customer for both the Pride Africa and the Pride Angola exercised two one-year options to extend the existing contract for the Pride Africa through December 2011. In late October 2007, the Pride Rio de Janeiro experienced a water ingress, which required us to suspend rig operations for approximately 68 days to complete the necessary repairs. The rig returned to service in January 2008. We are in the process of finalizing a multi-year contract for our deepwater drillship the Pride Angola. The contract is subject to regulatory approval, which we are working with our client to obtain. We can give no assurance that such approval will be obtained in a timely manner or at all.
Revenues increased $119.2 million, or 33%, for 2006 over 2005. The increase was due to a 24% increase in actual days worked in 2006 as compared to 2005 primarily due to a full year of operations in 2006 for the Pride Portland and the Pride Rio de Janeiro and $8.0 million related to the amortization of deferred contract liabilities for these two rigs, increased dayrates for the Pride North America, and contractual rate escalations. Average daily revenues for 2006 increased 7% over 2005 due to contracted dayrate increases for the Pride North America and moderate contractual dayrate escalations in 2006 for several of our deepwater rigs. Earnings from operations increased $25.3 million, or 25%, for 2006 over 2005 due to an increase in revenues partially offset by charges in 2006 for settlement of agency relationships on four of the rigs.
Midwater
Revenues increased $153.1 million, or 84%, in 2007 over 2006 due primarily to higher dayrates. Average daily revenue for 2007 increased 88% over 2006 as a result of the Pride South America, the Pride South Atlantic, the Pride South Seas and the Pride Venezuela commencing new contracts with substantially higher dayrates. Earnings from operations in 2007 increased $117.4 million over 2006 due to higher dayrates for most of our midwater fleet. Overall, utilization of our midwater fleet decreased to 79% in 2007 from 81% in 2006. The decline in utilization in 2007 is primarily due to the Pride Mexico entering the shipyard in May 2007 for upgrade and maintenance in preparation for its new contract beginning in mid-2008. In addition, the Pride South Seas entered the shipyard in September 2007 for upgrade and maintenance, lowering its utilization for 2007 as compared to 2006.
Revenues increased $28.3 million, or 18%, in 2006 over 2005. The increase was due to higher dayrates for several rigs partially offset by a 4% decline in actual days worked. Average daily revenue for 2006 increased 23% over 2005 as a result of the Pride Venezuela rolling over to a market rate contract, contract escalations and performance bonuses earned. Earnings from operations in 2006 increased $20.3 million, or 251%, over 2005 primarily due to higher dayrates and lower mobilization and repairs and maintenance costs for the Pride Venezuela.
Jackups - U.S.
Revenues decreased $136.9 million, or 36%, in 2007 over 2006. The decrease was primarily due to the softening demand in the U.S. Gulf of Mexico, which has resulted in lower dayrates and utilization across much of the fleet. Reflecting the relative market softness, average daily revenue for our jackup fleet for 2007 decreased 19% over 2006. Earnings from operations in 2007 decreased $138.7 million, or 63%, over 2006 due to lower dayrates and operating costs incurred while rigs are idle between contracts. Overall, utilization of our U.S. jackup fleet decreased to 68% for 2007 from 79% for 2006. During the third quarter of 2007, the Pride Oklahoma and Pride Mississippi departed the U.S. Gulf of Mexico to Mexico for one-year contracts. At the end of September 2007, we elected to cold stack the Pride Utah, and we do not expect to operate the rig in 2008.
Revenues increased $210.2 million, or 124%, in 2006 over 2005. The increase was due to the historically high dayrates in 2006 partially offset by a decline in utilization. Average daily revenue for our U.S. jackup fleet in 2006
increased 99% over 2005. Earnings from operations increased $153.8 million, or 238%, in 2006 over 2005 due to the increase in average daily revenue without corresponding increases in operating costs. Utilization of our U.S. jackup fleet decreased to 79% in 2006 from 84% in 2005. The decline of utilization is primarily due to shipyard upgrade and maintenance projects.
Jackups - International
Revenues increased $229.4 million, or 76%, in 2007 over 2006 primarily due to dayrate increases in Mexico, to the Pride Tennessee operating in Mexico for much of 2007 after its being out of service from the beginning of 2006 through early 2007 for a planned shipyard upgrade project, and to the relocation of two rigs from the U.S. Gulf of Mexico to Mexico. Average daily revenue for our international jackup fleet for 2007 increased 65% over 2006 as our rigs in Mexico recontracted at higher dayrates. Earnings from operations in 2007 increased $132.4 million, or 118%, over 2006 due to higher dayrates without corresponding increases in operating costs, partially offset by a $25.3 million gain on the sale of the Pride Rotterdam in 2006. In October 2007, the Pride Alabama experienced a lightening strike from severe storms in Mexico and required 10 days to repair. Overall, utilization of our international jackup fleet increased 1% to 87% for 2007 over 2006. After the completion of its contract in 2007, the Pride Nevada was mobilized from Mexico to the U.S. Gulf of Mexico and currently is without a contract.
Revenues increased $23.3 million, or 8%, in 2006 over the 2005. The increase was due to higher dayrates partially offset by a decline in utilization. Average daily revenue for our international jackup fleet for 2006 increased 40% over 2005. Earnings from operations in 2006 increased $30.4 million, or 37%, over 2005 due to the increase in average daily revenue. Utilization of our international jackup fleet decreased to 86% for 2006 from 94% in 2005. The decline of utilization is primarily due to shipyard upgrade and maintenance projects.
Other Offshore
Other offshore includes our 10 platform rigs, as well as the drilling management services we provide for five deepwater drilling rigs under management contracts that expire from 2011 to 2012.
Revenues increased $8.8 million, or 5%, in 2007 over 2006 primarily as a result of higher dayrates and utilization for our platform rigs and higher rates for our managed rigs, partially offset by our reduction in shallow-water management contracts and swamp barge rig operations. In December 2007, we sold the Bintang Kalimantan, which had been idle since early 2006, resulting in a gain on sale of $20 million. Average daily revenue for our other offshore assets for 2007 increased 9% over 2006. The increase in average daily revenue was primarily due to higher dayrates for platform rigs in the U.S. Gulf of Mexico. Earnings from operations increased $37.0 million, or 712%, for 2007 over 2006 due to the gain on the sale of the Bintang Kalimantan and higher dayrates for our managed rigs. Utilization of our other offshore assets increased to 60% for 2007 from 53% in 2006 due to higher activity levels in the U.S. Gulf of Mexico platform rig market.
Revenues decreased $60.0 million, or 27%, in 2006 over 2005 due to the termination of management agreements in 2006 and the sale of two tender barges in 2005. Average daily revenue for our other offshore assets for 2006 increased 2% over 2005. Earnings from operations in 2006 decreased $20.5 million, or 80%, due to gains on asset sales in 2005 and lower utilization. Utilization of our other offshore assets decreased to 53% in 2006 from 58% in 2005 due to lower platform rig utilization.
Discontinued Operations
In August 2007, we completed the sale of all of the issued and outstanding capital stock of our subsidiaries through which we conducted the business of our Latin America Land and E&P Services segments, and we entered into an agreement to sell our fleet of three self-erecting, tender-assist rigs. We have reclassified all of our historical operations of the Latin America Land and E&P Services segments and our three tender-assist rigs to discontinued operations.
Additionally in 2004, we discontinued our fixed-fee rig construction business, which designed, engineered, managed the construction of and commissioned four deepwater platform drilling rigs for installation on spars and tension leg platforms under fixed-fee contracts. We do not currently intend to enter into additional business of this nature. Our activity in 2006 consisted primarily of resolving commercial disputes and warranty claims, while in 2005 we revised our estimates for other cost items.
See Note 2 of our Notes to Consolidated Financial Statements in Item 8 of this annual report for additional information regarding discontinued operations.
Results of Operations
The discussion below relating to significant line items represents our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items.
The following table presents selected consolidated financial information for our continuing operations:
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues. Revenues for 2007 increased $433.0 million, or 27%, compared with 2006. For additional information about our revenues, please read “- Segment Review” above.
Operating Costs. Operating costs for 2007 increased $90.7 million, or 10%, compared with 2006 primarily due to higher labor costs and higher repair and maintenance costs. In addition, we incurred $2.8 million in the third and fourth quarters of 2007 to compensate certain non-U.S. employees for the negative impact on their wages due to U.S. dollar fluctuations against their home country currencies. Operating costs in 2006 include $15.0 million of expenses for the termination of agency fee agreements in Brazil in connection with our buyout of the remaining 70% interest in the former joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro in November 2006. Operating costs as a percentage of revenues were 51% and 58% for 2007 and 2006, respectively. The decrease as a percentage of revenue was primarily driven by the increase in dayrates.
Depreciation and Amortization. Depreciation expense for 2007 increased $25.3 million, or 13%, compared with 2006. This increase relates to additional depreciation expense as a result of the acquisition of the remaining 70% interest in the former joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro in November 2006 and the completion of a number of capitalized shipyard projects during 2006 and 2007, partially offset by a $28.5 million reduction in depreciation expense for 2007 as a result of the change in useful life estimates for several of our rigs.
General and Administrative. General and administrative expenses for 2007 increased $30.8 million, or 29%, compared with 2006, primarily due to an increase of $7.4 million of expenses related to the ongoing investigation described under “- FCPA Investigation” above, $6.7 million expensed for upgrades to our information technology infrastructure and a $5.3 million increase in stock-based compensation and termination and retirement benefits in 2007. The remainder of the increase is due to increased staffing and related wages and benefits.
Gain on Sale of Assets, Net. We had net gains on sales of assets of $30.4 million in 2007 primarily due to the sale of one of our barge rigs, the Bintang Kalimantan, and one Eastern Hemisphere land rig. We had net gains on sales of assets of $29.8 million in 2006 primarily due to the sale of the Pride Rotterdam.
Interest Expense. Interest expense for 2007 decreased by $4.9 million, or 6%, compared with 2006 primarily due to a $7.9 million increase in capitalized interest and a reduction in interest expense for our senior secured revolving credit facility, partially offset by the addition of interest expense on the debt acquired as part of our buyout of the remaining 70% interest in the former joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro in November 2006.
Interest Income. Interest income for 2007 increased by $10.2 million, or 243%, compared with 2006 primarily due to investment of cash received from the third quarter 2007 sale of our Latin America Land and E&P Services segments.
Other Income (Expense), Net. Other expense, net for 2007 increased by $5.5 million compared with 2006 primarily due to a $2.6 million increase in losses in 2007 for realized and unrealized gains and losses on our interest rate swap and cap agreements as compared to 2006, and a $2.3 million decrease from 2007 to 2006 in equity earnings from unconsolidated subsidiaries. In addition, in 2007 we had a $5.8 million foreign exchange loss as compared to a $4.6 million loss for 2006.
Income Taxes. Our consolidated effective income tax rate for continuing operations for 2007 was 29.2% compared with 39.4% for 2006. The lower rate for 2007 was principally the result of higher profitability in lower taxed foreign jurisdictions coupled with the recognition of benefits derived from previously unrecognized foreign tax credits, which offset taxable income in the U.S.
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Revenues. Revenues for 2006 increased $329.2 million, or 26%, compared with 2005. For additional information about our revenues, please read “- Segment Review” above.
Operating Costs. Operating costs for 2006 increased $114.9 million, or 14%, compared with 2005, of which $49.0 million is due to the operations of the Pride Portland and the Pride Rio de Janeiro for the full year of 2006, compared with a partial year in 2005. Offshore operating costs in 2006 include $15.0 million related to the termination of our agency agreement in Brazil in connection with the buyout of our joint venture operating in Brazil. Labor costs, rental expenses and amortization of deferred mobilization costs were the other primary reasons for overall increases in operating costs. Operating costs as a percentage of revenues were 58% and 64% for 2006 and 2005, respectively. The decrease as a percentage of revenue was primarily driven by the increase in dayrates.
Depreciation and Amortization. Depreciation and amortization expense for 2006 increased $13.4 million, or 7%, compared with 2005 primarily due increased capital expenditures in 2006.
General and Administrative. General and administrative expenses for 2006 increased $26.1 million, or 32%, compared with 2005 primarily due to $20.0 million of expenses related to the ongoing investigation described under “- FCPA Investigation” above, a $7.2 million increase in stock-based compensation costs due to the implementation of SFAS No. 123(R), and a $1.7 million increase in expense for employee benefits. The remainder of the increase is due to increased staffing and related wages and benefits. General and administrative expenses for 2005 include approximately $10.8 million of severance in connection with the termination of the employment of various key employees and the retirement of a director.
Gain on Sale of Assets, Net. We had net gains on sales of assets of $29.8 million in 2006 primarily due to the sale of the Pride Rotterdam, resulting in a gain of $25.3 million. We had net gains on sales of assets of $31.5 million in 2005 primarily due to the sale of one jackup rig and two barge rigs.
Interest Expense. Interest expense for 2006 decreased by $9.5 million, or 11%, compared with 2005 primarily due to lower total debt levels resulting from the repayment of our senior secured term loan and the conversion and retirement of our 2 1/2% convertible senior notes during 2005. Included in 2005 are charges of $3.6 million related to the write-off of deferred financing costs as a result of the prepayment of our senior secured term loan.
Interest Income. Interest income for 2006 increased by $2.4 million, or 133%, compared with 2005 primarily due to an increase in cash balances for 2006.
Other Income (Expense), Net. Other expense, net decreased from $2.7 million of income for 2005 to $0.4 million of income for 2006 primarily due to a $1.6 million gain for 2006 from realized and unrealized gains and losses on interest rate swap and cap agreements as compared to a $3.7 million gain for 2005, and a $4.6 million foreign exchange loss for 2006 as compared to a $4.5 million loss for 2005, partially offset by a $1.7 million increase from 2006 to 2005 in equity earnings from unconsolidated subsidiaries.
Income Taxes. Our consolidated effective tax rate for 2006 was 39.4% as compared with 41.2% for 2005. The lower rate in 2006 was due to higher profitability in jurisdictions with statutory rates lower than the United States. Both effective tax rates are above the U.S. statutory tax rate primarily due to non-deductible expenses and U.S. tax on certain foreign earnings.
Minority Interest. Minority interest in 2006 decreased $15.6 million, or 79%, compared with 2005 primarily due to the purchase of an additional 40% interest in our drillship joint venture in December 2005 described under “- Liquidity and Capital Resources” below.
Liquidity and Capital Resources
Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. Our $500.0 million senior secured revolving credit facility provides back-up liquidity in the event of an unanticipated significant demand on cash that would not be funded by operations. At December 31, 2007, we had $486.7 million of availability under this facility.
During 2007, we used cash flows generated from operations as our primary source of liquidity, including for working capital needs, repayment of debt and capital expenditures. We believe that our cash on hand, cash flows from operations and availability under our revolving credit facility will be sufficient for 2008 to fund our working capital needs, scheduled debt repayments and anticipated capital expenditures. In addition, we will continue to pursue opportunities to expand or upgrade our fleet, which could result in additional capital investment. Subject to the limitations imposed by our existing debt arrangements, we may in the future elect to return capital to our stockholders by share repurchases or the payment of dividends.
In August 2007, we completed the sale of our Latin America Land and E&P Services segments and received approximately $947.1 million of net proceeds. The covenants contained in the indenture governing our 7 3/8% senior notes due 2014 require that we use the net proceeds to acquire assets that are used or useful in our business or to repay senior debt. If the net proceeds not used for these purposes within one year following the closing, referred to as “excess proceeds,” are greater than $50 million, we are required to make a pro rata offer to purchase the maximum amount of senior notes at par value that can be purchased with the excess proceeds. Upon completion of the offer, we may use any remaining net proceeds for general corporate purposes.
We may review from time to time possible expansion and acquisition opportunities relating to our business, which may include the construction or acquisition of rigs or acquisitions of other business in addition to those described in this annual report. Any determination to construct additional rigs for our fleet will be based on market conditions and opportunities existing at the time, including the availability of long-term contracts with sufficient dayrates for the rigs and the relative costs of building new rigs with advanced capabilities compared with the costs of retrofitting or converting existing rigs to provide similar capabilities. The timing, size or success of any additional acquisition or construction effort and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may
not; however, be available to us at that time due to a variety of events, including, among others, credit rating agency downgrades of our debt, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry.
Sources and Uses of Cash - 2007 Compared with 2006
Cash flows provided by operating activities
Cash flows from operations were $685.0 million for 2007 compared with $611.7 for 2006. The increase in cash flows from operations was primarily due to the increase in our income from continuing operations partially offset by increased use of cash for working capital items.
Cash flows provided by (used in) investing activities
Cash flows provided by investing activities were $299.1 million for 2007 compared with cash flow used in investing activities of $513.6 for 2006. The increase in cash flows from investing activities was primarily due to $947.1 million of proceeds received from the sale of our Latin America Land and E&P Services segments, net of cash disposed of and cash selling costs. The final net proceeds will differ as a result of settlement of the final working capital adjustment, post-closing indemnities, and payment of transaction costs. In addition, we received $213 million in cash upon the closing of the sale of our three tender-assist rigs in the first quarter of 2008.
Purchases of property and equipment totaled $656.4 million and $356.2 million for 2007 and 2006, respectively. With respect to our recent drillship construction contracts, we had capital expenditures of approximately $309 million in 2007 towards the construction of the rigs. We also spent $45 million for the acquisition of the remaining nine percent interest in our Angolan joint venture in August 2007. The majority of the remaining expenditures were incurred in connection with life enhancements and other upgrades and sustaining capital projects.
Proceeds from dispositions of property and equipment were $53.4 million and $60.5 million for 2007 and 2006, respectively. Included in the proceeds for 2007 was $34.0 million related to the sale of one of our barge rigs, the Bintang Kalimantan, and $17.3 million related to the sale of one land rig in the Eastern Hemisphere. Included in the proceeds for 2006 was $51.3 million related to the sale of the Pride Rotterdam and four land rigs that were part of our former Latin America Land segment.
Cash flows used in financing activities
Cash flows used in financing activities were $157.8 million for 2007 compared with $79.1 million for 2006. Our net cash used for debt repayments included $58.4 million paid in August 2007 to repay in full the outstanding amounts under our 9.35% semisubmersible loan, a net reduction of our revolving credit facility of $50.0 million and $88.1 million in scheduled debt repayments. We received proceeds of $2.1 million and $1.4 million from the issuance of common stock under our employee stock purchase plan in 2007 and 2006, respectively. We also received proceeds of $27.6 million and $50.3 million from the exercise of stock options in 2007 and 2006, respectively.
Cash flows from discontinued operations
Our discontinued operations were largely dependent on us for funding of capital expenditures, strategic investments and acquisitions. The discontinued operations would periodically distribute to us available cash through intercompany invoices or capital dividends or require us to fund their operations through intercompany working capital or capital investments. For 2007, we received net cash of $9.9 million from discontinued operations as compared to $39.4 million for 2006.
Our cash flows from operating activities of discontinued operations for 2007 were $56.1 million compared with $118.8 million for 2006. The decrease in cash flows from operations was primarily due to 2007 including eight months of operations of our Latin America Land and E&P Services segments prior to the disposal compared with a full year of operations in 2006. An increase in net working capital in 2007 also negatively effected cash flow from operations in 2007.
Purchases of property and equipment were $48.6 million for 2007 compared with $50.6 million for 2006.
We do not believe that, in the future, the loss of the cash flows from our discontinued operations will significantly affect our liquidity or ability to fund our capital expenditures.
Sources and Uses of Cash - 2006 Compared with 2005
Cash flows provided by operating activities
Cash flows from operations were $611.7 million for 2006 compared with $321.9 million for 2005. The increase in cash flows from operations was primarily due to the increase in our income from continuing operations.
Cash flows provided by (used in) investing activities
Cash flows used in investing activities were $513.6 million for 2006 compared with $226.3 million for 2005. Purchases of property and equipment totaled $356.2 million and $157.2 million for 2006 and 2005, respectively. The majority of these expenditures related to capital expenditures incurred in connection with new contracts and other sustaining capital projects.
Proceeds from dispositions of property and equipment were $60.5 million and $121.2 million for 2006 and 2005, respectively. Included in the proceeds for 2006 was $51.3 million related to the sale of the Pride Rotterdam and four land rigs that were part of our former Latin America Land segment. Included in the proceeds for 2005 was $40.0 million related to the sale of the Pride Ohio by one of our foreign subsidiaries, $49.5 million related to the sale of the Piranha and the Ile de Sein and $23.0 million related to three land rigs that were part of our former Latin America Land segment.
Cash flows used in financing activities
Cash flows used in financing activities were $79.1 million for 2006 compared with $87.6 million for 2005. In November 2006, we acquired the remaining 70% interest in the joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro for $215.0 million in cash, plus earn-out payments, if any, to be made during the six-year period (subject to certain extensions for non-operating periods) following the expiration of the existing drilling contracts for the rigs. The transaction also resulted in the recording of approximately $284 million of debt, net of the fair value discount, of the joint venture companies to our consolidated balance sheet. In addition, we paid $15 million to an affiliate of our partner for the cancellation of future obligations under certain existing agency relationships related to five offshore rigs we operate in Brazil. We funded the purchase price and cancellation payment with available cash and borrowings under our revolving credit facility.
In December 2005, we acquired an additional 40% interest in our joint venture companies that manage our Angolan operations from our partner, the national oil company of Angola, for $170.9 million in cash. In addition, we paid $4.5 million to an affiliate of our partner for termination of certain agreements related to the operation of the joint venture. We funded the purchase price and the termination payment with borrowings under our senior secured revolving credit facility.
During 2005, we repaid the remaining $279 million balance on our senior secured term loan and recognized charges of $3.6 million to write off the unamortized portion of the deferred finance costs at the time of the early repayment.
We received proceeds of $1.4 million and $124.9 million from the issuance of common stock in 2006 and 2005, respectively. The proceeds for 2005 included $123.6 million (before offering costs) related to the public offering of 6.0 million shares of common stock. We used the net proceeds from the offering to purchase an equal number of shares of our common stock from three affiliated investment funds at a price per share equal to the proceeds per share that we received from the offering. The shares repurchased from the funds were subsequently retired. We also received proceeds of $50.3 million and $91.2 million from the exercise of stock options in 2006 and 2005, respectively.
Cash flows from discontinued operations
For 2006, we received net cash of $39.4 million from discontinued operations as compared to $26.0 million for 2005.
Our cash flows from operating activities of discontinued operations for 2006 were $118.8 million compared with $55.7 million for 2005. The increase in cash flows from operations was primarily due to the increase in net earnings of our Latin America Land and E&P Services segments.
Purchases of property and equipment were $50.6 million in 2006 compared with $35.6 million for 2005.
Working Capital
As of December 31, 2007, we had working capital of $888.0 million compared with $293.1 million as of December 31, 2006. The increase in working capital is due primarily to the cash received upon the disposition of our Latin America Land and E&P Services segments in August 2007, partially offset by the reduction in our working capital disposed of in the divestiture of our Latin America Land and E&P Services segments.
Credit Ratings
Our 7 3/8% Senior Notes due 2014 are rated Ba2 by Moody’s Investor Service, Inc., BB+ by Standard & Poor’s Rating Services and BB by Fitch Ratings. Each of the rating agencies report a stable outlook for the Company.
Available Credit Facilities
We currently have a $500.0 million senior secured revolving credit facility with a group of banks maturing in July 2009. Borrowings under the facility are available for general corporate purposes. We may obtain up to $100.0 million of letters of credit under the revolving credit facility. As of December 31, 2007, there were no outstanding borrowings and $13.3 million of letters of credit outstanding under the facility. Amounts drawn under the facility bear interest at variable rates based on LIBOR plus a margin or the base rate plus a margin. The interest rate margin varies based on our leverage ratio. As of December 31, 2007, the interest rate on the facility would have been approximately 5.1% had we had any borrowings outstanding, and availability was $486.7 million.
The facility is secured by first priority liens on certain of the existing and future rigs, accounts receivable, inventory and related insurance of our subsidiary Pride Offshore, Inc. (the borrower under the facility) and its subsidiaries, all of the equity of Pride Offshore and its domestic subsidiaries and 65% of the equity of certain of our foreign subsidiaries. We and certain of our domestic subsidiaries have guaranteed the obligations of Pride Offshore under the facility. In certain circumstances, we are required to repay the revolving loans, with a permanent reduction in availability under the revolving credit facility, with proceeds from a sale of or a casualty event with respect to collateral. The facility contains a number of covenants restricting, among other things, redemption and repurchase of our indebtedness; acquisitions and investments; asset sales; indebtedness; liens; and affiliate transactions. The facility also contains customary events of default, including with respect to a change of control.
Other Outstanding Debt
As of December 31, 2007, in addition to our credit facility, we had the following long-term debt, including current maturities, outstanding:
Our 7 3/8% senior notes contain provisions that limit our ability and the ability of our subsidiaries to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt or issue preferred stock; incur dividend or other payment restrictions affecting our subsidiaries; sell assets; engage in sale and leaseback transactions; create liens; and consolidate, merge or transfer all or substantially all of our assets. Many of these restrictions will terminate if the notes are rated investment grade by either S&P or Moody’s and, in either case, the notes have a specified minimum rating by the other rating agency. We are required to offer to repurchase the notes in connection with specified change in control events that result in a ratings decline.
Our 3 1/4% Convertible Senior Notes due 2033 provide for semiannual interest payments and for the payment of contingent interest during any six-month interest period commencing on or after May 1, 2008 for which the trading price of the notes for each of the five trading days immediately preceding such period equals or exceeds 120% of the
principal amount of the notes. During any interest period when contingent interest is payable, the contingent interest payable per note will equal 0.25% of the average trading price of the notes during the five trading days immediately preceding the first day of the applicable six-month interest period. Beginning May 5, 2008, we may redeem any of the notes at a redemption price of 100% of the principal amount redeemed plus accrued and unpaid interest. In addition, noteholders may require us to repurchase the notes on May 1 of 2008, 2010, 2013, 2018, 2023 and 2028 at a repurchase price of 100% of the principal amount redeemed plus accrued and unpaid interest. We may elect to pay all or a portion of the repurchase price in common stock instead of cash, subject to certain conditions. Based on current market prices, we believe that we likely will not be required to purchase the notes on their initial put date. The notes are convertible under specified circumstances into shares of our common stock at a conversion rate of 38.9045 shares per $1,000 principal amount of notes (which is equal to a conversion price of $25.704), subject to adjustment. The notes are currently convertible. Upon conversion, we will have the right to deliver, in lieu of shares of common stock, cash or a combination of cash and common stock. If we choose to deliver cash upon conversion, we may incur a loss for extinguishment of debt. The closing price of our common stock on December 31, 2007 was $33.90 per share. At this price, if note holders were to convert the entire issue and we chose to deliver cash in lieu of shares, we would pay approximately $396 million to settle the conversion and incur an approximately $96 million debt extinguishment loss. For each $1 change in our stock price, the incurred debt extinguishment loss for a cash settled conversion would change by approximately $12 million.
Our drillship loan facility is collateralized by the Pride Africa and the Pride Angola, and the proceeds from the related drilling contracts. The drillship loan facility matures in September 2010 and amortizes quarterly. The drillship loan bears interest at LIBOR plus 1.50%. The effective rate at December 31, 2007 was 6.33%. As a condition of the loan, we maintain interest rate swap and cap agreements with the lenders. In accordance with the debt agreements, we have posted letters of credit to assure that timely interest and principal payments are made.
Our notes guaranteed by the United States Maritime Administration were used to finance a portion of the cost of construction of the Pride Portland and Pride Rio de Janeiro. The notes bear interest at a weighted average fixed rate of 4.33%, mature in 2016 and are prepayable, in whole or in part, at any time, subject to a make-whole premium. The notes are collateralized by the two rigs and the net proceeds received by subsidiary project companies chartering the rigs.
Although we do not expect that our level of total indebtedness will have a material adverse impact on our financial position, results of operations or liquidity in future periods, it may limit our flexibility in certain areas. Please read “Risk Factors - Our significant debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities” in Item 1A of this annual report.
Other Sources and Uses of Cash
We expect our purchases of property and equipment for 2008, excluding our new drillship commitments, to be approximately $385 million. These purchases are expected to be used primarily for various rig upgrades in connection with new contracts as contracts expire during the year along with other sustaining capital projects. With respect to our three ultra-deepwater drillships currently under construction, the total estimated remaining costs are approximately $1.8 billion. We anticipate making additional payments for the construction of these drillships of approximately $610 million in 2008, approximately $380 million in 2009, approximately $640 million in 2010, and approximately $175 million in 2011. We expect to fund construction of these rigs through available cash, cash flow from operations and borrowing under our revolving credit facility.
We anticipate making income tax payments of approximately $120 million to $130 million in 2008.
Mobilization fees received from customers and the costs incurred to mobilize a rig from one geographic area to another, as well as up-front fees to modify a rig to meet a customer’s specifications, are deferred and amortized over the term of the related drilling contracts. These up-front fees and costs impact liquidity in the period in which the fees are received or the costs incurred, whereas they will impact our statement of operations in the periods during which the deferred revenues and costs are amortized. The amount of up-front fees received and the related costs vary from period to period depending upon the nature of new contracts entered into and market conditions then prevailing. Generally, contracts for drilling services in remote locations or contracts that require specialized equipment will provide for higher up-front fees than contracts for readily available equipment in major markets.
Additionally, we defer costs associated with obtaining in-class certification from various regulatory bodies in order to operate our offshore rigs. We amortize these costs over the period of validity of the related certificate.
We may redeploy additional assets to more active regions if we have the opportunity to do so on attractive terms. We frequently bid for or negotiate with customers regarding multi-year contracts that could require significant capital expenditures and mobilization costs. We expect to fund project opportunities primarily through a combination of working capital, cash flow from operations and borrowings under our senior secured revolving credit facility.
We may review from time to time possible expansion and acquisition opportunities relating to our business segments, which may include the construction of rigs for our fleet and acquisitions of rigs and other business. While we have no definitive agreements to acquire or construct additional equipment or to acquire any businesses, suitable opportunities may arise in the future. Any determination to construct additional rigs for our fleet will be based on market conditions and opportunities existing at the time, including the availability of long-term contracts with sufficient dayrates for the rigs and the relative costs of building new rigs with advanced capabilities compared with the costs of retrofitting or converting existing rigs to provide similar capabilities. The timing, size or success of any acquisition or construction effort and the associated potential capital commitments are unpredictable. We may fund all or part of any such efforts with proceeds from debt and/or equity issuances.
We consider from time to time opportunities to dispose of certain assets or groups of assets when we believe the capital could be more effectively deployed.
In addition to the matters described in this “- Liquidity and Capital Resources” section, please read “- Business Outlook” and “- Segment Review” for additional matters that may have a material impact on our liquidity.
Letters of Credit
We are contingently liable as of December 31, 2007 in the aggregate amount of $239.5 million under certain performance, bid and custom bonds and letters of credit, including $13.3 million in letters of credit issued under our revolving credit facility. As of December 31, 2007, we had not been required to make any collateral deposits with respect to these agreements.
Contractual Obligations
In the table below, we set forth our contractual obligations as of December 31, 2007. Some of the figures we include in this table are based on our estimates and assumptions about these obligations, including their duration and other factors. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.
(1)
Amounts represent the expected cash payments for our total long-term debt and do not reflect any unamortized discount.
(2)
Amounts represent other long-term liabilities, including current portion, related to severance and termination benefits and capital leases.
(3)
Amounts represent the expected cash payments for interest on our long-term debt based on the interest rates in place and amounts outstanding at December 31, 2007.
(4)
We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the leases. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements.
(5)
Includes approximately $69.3 million in purchase obligations related to drillship construction projects.
(6)
Includes shipyard payments under drillship construction agreements for two drillship construction projects initiated in 2007. Excludes the drillship construction project executed in January 2008, the construction contract for which requires total payments of $636 million from 2008-2011.
On January 1, 2007, we adopted the recognition and disclosure provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109. As of December 31, 2007, we have approximately $44.4 million of unrecognized tax benefits, including penalties and interest. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.
Pending Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurement, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement also responds to investors’ requests for more information about (1) the extent to which companies measure assets and liabilities at fair value, (2) the information used to measure fair value, and (3) the effect that fair-value measurements have on earnings. SFAS No. 157 will apply whenever another statement requires (or permits) assets or liabilities to be measured at fair value. SFAS No. 157 does not expand the use of fair value to any new circumstances. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, which was effective upon issuance. The FSP delays the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. We are currently evaluating the potential impact of the provisions of SFAS No. 157, if any, to our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits companies to choose to measure, on an instrument-by-instrument basis, financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The
effective date for us is January 1, 2008. We are evaluating the impact of the provisions of SFAS No. 159 on our consolidated financial statements.
In December 2007, the FASB issued the revised SFAS No. 141(R), Business Combinations. Under SFAS No. 141(R), all business combinations will be accounted for by applying the acquisition method and an acquirer is required to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any noncontrolling interest at their fair values as of the acquisition date. SFAS No. 141(R) also requires transaction costs and restructuring charges to be expensed. We will begin applying this statement prospectively to business combinations occurring in fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which is an amendment of Accounting Research Bulletin No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, SFAS No. 160 requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This statement is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We are currently evaluating the potential impact of adopting SFAS No. 160 but do not expect its adoption to have a significant impact on our results of operations and financial condition.
FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this annual report that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future are forward-looking statements. These include such matters as:
•
market conditions, expansion and other development trends in the contract drilling industry;
•
our ability to enter into new contracts for our rigs, commencement dates for new contracts and future utilization rates and contract rates for rigs;
•
customer requirements for drilling capacity and customer drilling plans;
•
contract backlog and the amounts expected to be realized within one year;
•
future capital expenditures and investments in the construction, acquisition and refurbishment of rigs (including the amount and nature thereof and the timing of completion and delivery thereof);
•
future asset sales and repayment of debt;
•
expected use of proceeds from the sale of our Latin America Land and E&P Services segments and other assets;
•
adequacy of funds for capital expenditures, working capital and debt service requirements;
•
future income tax payments and the utilization of net operating loss carryforwards;
•
business strategies;
•
expansion and growth of operations;
•
future exposure to currency devaluations or exchange rate fluctuations;
•
expected outcomes of legal, tax and administrative proceedings, including our ongoing investigation into improper payments to foreign government officials, and their expected effects on our financial position, results of operations and cash flows;
•
future operating results and financial condition; and
•
the effectiveness of our disclosure controls and procedures and internal control over financial reporting.
We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.
These statements are subject to a number of assumptions, risks and uncertainties, including those described in “- FCPA Investigation” above and in “Risk Factors” in Item 1A of this annual report and the following:
•
general economic and business conditions;
•
prices of oil and natural gas and industry expectations about future prices;
•
ability to adequately staff our rigs;
•
foreign exchange controls and currency fluctuations;
•
political stability in the countries in which we operate;
•
the business opportunities (or lack thereof) that may be presented to and pursued by us;
•
cancellation or renegotiation of our drilling contracts;
•
changes in laws or regulations; and
•
the validity of the assumptions used in the design of our disclosure controls and procedures.
Most of these factors are beyond our control. We caution you that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in these statements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. These risks arise primarily as a result of potential changes in the fair market value of financial instruments that would result from adverse fluctuations in interest rates and foreign currency exchange rates as discussed below. We may enter into derivative financial instrument transactions to manage or reduce market risk, but do not enter into derivative financial instrument transactions for speculative purposes.
Interest Rate Risk. We are exposed to changes in interest rates through our fixed rate long-term debt. Typically, the fair market value of fixed rate long-term debt will increase as prevailing interest rates decrease and will decrease as prevailing interest rates increase. The fair value of our long-term debt is estimated based on quoted market prices where applicable, or based on the present value of expected cash flows relating to the debt discounted at rates currently available to us for long-term borrowings with similar terms and maturities. The estimated fair value of our long-term debt as of December 31, 2007 and 2006 was $1,331.9 million and $1,486.8 million, respectively, which was more than its carrying value as of December 31, 2007 and 2006 of $1191.5 million and $1,386.6 million, respectively. A hypothetical 100 basis point decrease in interest rates relative to market interest rates at December 31, 2007 would increase the fair market value of our long-term debt at December 31, 2007 by approximately $36.0 million.
As of December 31, 2007, we held interest rate swap and cap agreements relating to the drillship loan facility as required by the lenders. We have not designated these interest rate swap and cap agreements as hedging instruments
in accordance with SFAS No. 133. Accordingly, the interest rate swap and cap agreements are marked-to-market with realized and unrealized gains and losses recorded in our consolidated statements of operations. As of December 31, 2007, the fair value of the interest rate swap and cap agreements was an asset of $0.2 million.
Foreign Currency Exchange Rate Risk. We operate in a number of international areas and are involved in transactions denominated in currencies other than the U.S. dollar, which expose us to foreign currency exchange rate risk. We utilize local currency borrowings and the payment structure of customer contracts to selectively reduce our exposure to exchange rate fluctuations in connection with monetary assets, liabilities and cash flows denominated in certain foreign currencies. We did not enter into any forward exchange or option contracts in 2007 and 2006; however, we may elect to enter into contracts in the future as we continue to monitor our exposure to foreign currency exchange risk. We do not hold or issue foreign currency forward contracts, option contracts or other derivative financial instruments for speculative purposes.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Pride International, Inc.:
We have audited the accompanying consolidated balance sheets of Pride International, Inc. as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pride International, Inc. as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in note 1 to the financial statements, in 2007 the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes. As discussed in note 1 and 13, in 2006 the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, and Statement of Financial Accounting Standards No. 123(R), Share-Based Payment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pride International, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 28, 2008
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Pride International, Inc.:
We have audited Pride International, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pride International, Inc.’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 for the year ended December 31, 2007. 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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pride International, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pride International, Inc. as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 28, 2008 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 28, 2008
Pride International, Inc.
Consolidated Balance Sheets
(In millions, except par value)
The accompanying notes are an integral part of the consolidated financial statements.
Pride International, Inc.
Consolidated Statements of Operations
(In millions, except per share amounts)
The accompanying notes are an integral part of the consolidated financial statements.
Pride International, Inc.
Consolidated Statements of Stockholders’ Equity
(In millions)
The accompanying notes are an integral part of the consolidated financial statements.
Pride International, Inc.
Consolidated Statements of Cash Flows
(In millions)
The accompanying notes are an integral part of the consolidated financial statements.
Pride International, Inc.
Notes to Consolidated Financial Statements
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Pride International, Inc. (“Pride,” “we,” “our,” or “us”) is a leading international provider of contract drilling services. We provide contract drilling services to oil and natural gas exploration and production companies through the operation and management of 57 offshore rigs and seven land drilling rigs. We also have three ultra-deepwater drillships under construction.
Basis of Presentation
In August 2007, we completed the sale of our Latin America Land and E&P Services segments. In August 2007, we also agreed to sell our three tender-assist rigs, which are classified as assets held for sale. The results of operations for all periods presented of the assets disposed or to be disposed of in both of these transactions have been reclassified to income from discontinued operations. Except where noted, the discussions in the following notes relate to our continuing operations only. (See Note 2).
The consolidated financial statements include the accounts of Pride and all entities that we control by ownership of a majority voting interest as well as variable interest entities for which we are the primary beneficiary. All significant intercompany transactions and balances have been eliminated in consolidation. Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. Investments in which we do not exercise significant influence are accounted for using the cost method of accounting.
Management Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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.
Segment Information
Subsequent to the disposition of our Latin America Land and E&P Services segments in August 2007, our operations consist of one reportable segment, Offshore Drilling Services. As a result of our disposal of the Latin America Land and E&P Services segments, certain operating and administrative costs were reallocated for all periods presented to our remaining continuing operating segments.
Conditions Affecting Ongoing Operations
Our current business and operations are substantially dependent upon conditions in the oil and natural gas industry and, specifically, the exploration and production expenditures of oil and natural gas companies. The demand for contract drilling and related services is influenced by, among other things, oil and natural gas prices, expectations about future prices, the cost of producing and delivering oil and natural gas, government regulations and local and international political and economic conditions. There can be no assurance that current levels of exploration and production expenditures of oil and natural gas companies will be maintained or that demand for our services will reflect the level of such activities.
Dollar Amounts
All dollar amounts (except per share amounts) presented in the tabulations within the notes to our financial statements are stated in millions of dollars, unless otherwise indicated.
Revenue Recognition
We recognize revenue as services are performed based upon contracted dayrates and the number of operating days during the period. Revenue from turnkey contracts is based on percentage of completion. Mobilization fees received and costs incurred in connection with a customer contract to mobilize a rig from one geographic area to another are deferred and recognized on a straight-line basis over the term of such contract, excluding any option periods. Costs incurred to mobilize a rig without a contract are expensed as incurred. Fees received for capital improvements to rigs are deferred and recognized on a straight-line basis over the period of the related drilling contract. The costs of such capital improvements are capitalized and depreciated over the useful lives of the assets.
Effective January 1, 2007, we adopted the provisions of Emerging Issues Task Force (“EITF”) Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation). EITF Issue No. 06-3 requires disclosure of the accounting policy applied for any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value-added and some excise taxes. We record all taxes imposed directly on revenue-producing transactions on a net basis. The adoption of EITF Issue No. 06-3 had no impact on our financial statements for any period.
Cash and Cash Equivalents
We consider all highly liquid debt instruments having maturities of three months or less at the date of purchase to be cash equivalents.
Parts and Supplies
Parts and supplies consist of spare rig parts and supplies held in warehouses for use in operations and are valued at weighted average cost.
Property and Equipment
Property and equipment are carried at original cost or adjusted net realizable value, as applicable. Major renewals and improvements are capitalized and depreciated over the respective asset’s remaining useful life. Maintenance and repair costs are charged to expense as incurred. When assets are sold or retired, the remaining costs and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in results of operations.
We evaluate our estimates of remaining useful lives and salvage value for our rigs when changes in market or economic conditions occur that may impact our estimates of the carrying value of these assets. During the quarter ended September 30, 2007, we completed a technical evaluation of our offshore fleet. As a result of this evaluation, remaining useful lives and estimated salvage values were adjusted on certain rigs in the fleet. These changes were primarily a result of changing market conditions, the significant capital investment in certain rigs and revisions to, and standardization of, maintenance practices. As a result of our evaluation, effective July 1, 2007, we increased our estimates of the remaining lives of certain semisubmersible and jackup rigs in our fleet between four and eight years, increased the expected useful lives of our drillships from 25 years to 35 years and our semisubmersibles from 25 years to 30 years, and updated our estimated salvage value for all of our offshore drilling rig fleet to 10% of the historical cost of the rigs. The effect of these changes in estimates was a reduction to depreciation expense of approximately $28.5 million and an after-tax increase to diluted earnings per share of $0.13 for the six-month period ended December 31, 2007.
For financial reporting purposes, depreciation of property and equipment is provided using the straight-line method based upon expected useful lives of each class of assets. Expected useful lives of the assets for financial reporting purposes are as follows:
Interest is capitalized on construction-in-progress at the weighted average cost of debt outstanding during the period of construction or at the interest rate on debt incurred for construction.
We assess the recoverability of the carrying amount of property and equipment if certain events or changes occur, such as significant decrease in market value of the assets or a significant change in the business conditions in a particular market. In 2007, we recognized no impairment charges. In 2006, we recognized an impairment charge of $0.5 million related to two platform rigs. In 2005, we recognized an impairment charge of $1.0 million related to damage to a platform rig sustained in 2004.
Goodwill
Goodwill is not amortized. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, we perform an annual impairment test of goodwill as of December 31, or more frequently if circumstances indicate that impairment may exist. Impairment assessments are performed using a variety of methodologies, including cash flows analysis and estimates of market value. There were no impairments in 2007, 2006 or 2005.
Rig Certifications
We are required to obtain certifications from various regulatory bodies in order to operate our offshore drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs associated with obtaining and maintaining such certifications, including inspections and surveys, and drydock costs to the rigs are deferred and amortized over the corresponding certification periods.
We expended $8.1 million, $22.1 million and $15.8 million during 2007, 2006 and 2005, respectively, in obtaining and maintaining such certifications. As of December 31, 2007 and 2006, the deferred and unamortized portion of such costs on our balance sheet was $32.9 million and $39.7 million, respectively. The portion of the costs that are expected to be amortized in the 12 month periods following each balance sheet date are included in other current assets on the balance sheet and the costs expected to be amortized after more than 12 months from each balance sheet date are included in other assets. The costs are amortized on a straight-line basis over the period of validity of the certifications obtained. These certifications are typically for five years, but in some cases are for shorter periods. Accordingly, the remaining useful lives for these deferred costs are up to five years.
Derivative Financial Instruments
We have entered into derivative financial instruments to economically limit our exposure to changes in interest rates. Our policies do not permit the use of derivative financial instruments for speculative purposes. As of December 31, 2007, we had not designated any of our derivative financial instruments as hedging instruments as defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended). Accordingly, the changes in fair value of the derivative financial instruments are recorded in “Other income, net” in our consolidated statement of operations.
Income Taxes
We recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Deferred tax liabilities and assets are determined based on the difference between the financial statement and the tax basis of assets and liabilities using enacted tax rates in effect for the year in which the asset is recovered or the liability is settled. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Because of tax jurisdictions in which we operate, some of which are revenue based tax regimes, changes in earnings before taxes and minority interest do not directly correlate to changes in our provision for income tax.
Foreign Currency Translation
We have designated the U.S. dollar as the functional currency for most of our operations in international locations because we contract with customers, purchase equipment and finance capital using the U.S. dollar. In those countries where we have designated the U.S. dollar as the functional currency, certain assets and liabilities of foreign operations are translated at historical exchange rates, revenues and expenses in these countries are translated at the average rate of exchange for the period, and all translation gains or losses are reflected in the period’s results of operations. In those countries where the U.S. dollar is not designated as the functional currency, revenues and expenses are translated at the average rate of exchange for the period, assets and liabilities are translated at end of period exchange rates and all translation gains and losses are included in accumulated other comprehensive income (loss) within stockholders’ equity.
Concentration of Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. We place our cash and cash equivalents in other high quality financial instruments. We limit the amount of credit exposure to any one financial institution or issuer. Our customer base consists primarily of major integrated and government-owned international oil companies, as well as smaller independent oil and gas producers. Management believes the credit quality of our customers is generally high. We provide allowances for potential credit losses when necessary.
Stock-Based Compensation
On January 1, 2006, we adopted the revised SFAS No. 123(R), Share-Based Payment, using the modified prospective method. SFAS No. 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. SFAS No. 123(R) requires that companies recognize compensation expense for awards of equity instruments to employees based on the grant-date fair value of those awards. That cost is to be recognized over the period during which an employee is required to provide service in exchange for the award. The fair value is to be estimated using an option pricing model. SFAS No. 123(R) also requires that companies measure the cost of liability-classified awards based on current fair value. The fair value of these awards will be remeasured at each reporting date through the settlement date. Changes in fair value during the requisite service period will be recognized as compensation cost over that period. With respect to the determination of the pool of windfall tax benefits, we elected to use the transition election of SFAS No. 123(R)-3 (the “short-cut method”) as of the adoption of SFAS No. 123(R). Under the “short-cut method” the windfall tax benefits recognized for fully vested awards, as defined in SFAS No. 123(R)-3, are recognized as an addition to paid-in capital and are required to be reported as a financing cash flow and an operating cash outflow within the statement of cash flows. Windfall tax benefits for partially vested awards should be recognized as if we had always followed the fair-value method of recognizing compensation cost in our financial statements and would be included as a financing cash flow and an operating cash outflow within the statement of cash flows.
Prior to January 1, 2006, we accounted for stock-based compensation under APB No. 25 and provided pro forma disclosure amounts in accordance with SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure, as if the fair value method defined by SFAS No. 123 had been applied to our stock-based compensation. Under APB No. 25, no compensation expense was recognized for stock options or for our employee stock purchase plan (“ESPP”). Compensation expense was, however, recognized for our restricted stock awards. Under APB No. 25, we established an accounting policy to use the tax ordering rules for the excess tax benefits of stock-based compensation and we continue to use this accounting policy under SFAS No. 123(R).
In 2006, we reevaluated our assumptions used in estimating the fair value of stock options granted. As part of this assessment, we determined that implied volatility calculated based on actively traded options on our common stock is a better indicator of expected volatility and future stock price trends than one year historical volatility, which we used in 2005. As a result, expected volatility for 2007 and 2006 was based on a market-based implied volatility. We used the Black-Scholes option pricing model to value the stock options. The expected life computation is based on historical exercise patterns and post-vesting termination behavior over the past 12 years. The risk-free interest rate is
based on the implied yield currently available on U.S. Treasury zero coupon issues with a remaining term equal to the expected life. Expected dividend yield is based on historical dividend payments.
Pending Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurement, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement also responds to investors’ requests for more information about (1) the extent to which companies measure assets and liabilities at fair value, (2) the information used to measure fair value, and (3) the effect that fair-value measurements have on earnings. SFAS No. 157 will apply whenever another statement requires (or permits) assets or liabilities to be measured at fair value. SFAS No. 157 does not expand the use of fair value to any new circumstances. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, which was effective upon issuance. The FSP delays the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. We are currently evaluating the potential impact of the provisions of SFAS No. 157, if any, to our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits companies to choose to measure, on an instrument-by-instrument basis, financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The effective date for us is January 1, 2008. We are evaluating the impact of the provisions of SFAS No. 159 on our consolidated financial statements.
In December 2007, the FASB issued the revised SFAS No. 141(R), Business Combinations. Under SFAS No. 141(R), all business combinations will be accounted for by applying the acquisition method and an acquirer is required to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any noncontrolling interest at their fair values as of the acquisition date. SFAS No. 141(R) also requires transaction costs and restructuring charges to be expensed. We will begin applying this statement prospectively to business combinations occurring in fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which is an amendment of Accounting Research Bulletin No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, SFAS No. 160 requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This statement is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We are currently evaluating the potential impact of adopting SFAS No. 160 but do not expect its adoption to have a significant impact on our results of operations and financial condition.
Reclassifications
Certain reclassifications have been made to the prior years’ consolidated financial statements to conform with the current year presentation.
NOTE 2. DISCONTINUED OPERATIONS
We report discontinued operations in accordance with the guidance of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. For the disposition of any asset group accounted for as discontinued operations under SFAS No. 144, we have reclassified the results of operations as discontinued operations for all periods presented. Such reclassifications had no effect on our net income or stockholders’ equity.
Sale of Latin America Land and E&P Services Segments
During the third quarter of 2007, we completed the disposition of our Latin America Land and E&P Services segments for $1.0 billion in cash. The purchase price is subject to certain post-closing adjustments for working capital and other indemnities. The following table presents selected information regarding the results of operations of our Latin America Land and E&P Services segments:
The gain on disposal of assets includes certain estimates for the settlement of closing date working capital, valuation adjustments for tax and other indemnities provided to the buyer, and selling costs incurred by us. We have indemnified the purchaser for certain obligations that may arise or be incurred in the future by the purchaser with respect to the business. We believe it is probable that some of these liabilities will be settled with the purchaser in cash. Included within the estimated gain on disposal of assets is a $88.3 million liability based on our fair value estimates for the indemnities. The expected settlement dates for these indemnities varies from within one year to several years for pre-closing tax matters. The final gain may differ from the amount recorded as of December 31, 2007.
Sale of Tender-Assist Rigs
In August 2007, we entered into an agreement to sell our three tender-assist rigs, the Barracuda, Alligator and Al Baraka I, for $213 million in cash. We completed the sale of the rigs in the first quarter of 2008. In connection with the sale, we entered into an agreement to operate the Alligator until its current contract is completed, which is anticipated to be in December 2008. The following table presents selected information regarding the results of operations of this asset group:
We have reclassified the net book value of property and equipment and a deferred mobilization contract payment for the tender-assist rigs to assets held for sale as of September 30, 2007. There are no other significant assets to be sold or liabilities to be assumed as part of the agreement.
Disposition of Fixed-fee Rig Construction Business
In 2001 and 2002, our Technical Services group entered into fixed-fee contracts to design, engineer, manage construction of and commission four deepwater platform drilling rigs for installation on spars and tension leg platforms. In 2004, we discontinued this business and do not currently intend to enter into additional business of this
nature. Accordingly, we have reported our fixed-fee rig construction business as discontinued operations on our consolidated statements of operations. We recorded loss provisions of $27.3 million in 2004 relating to the construction of the rigs. The loss provision principally consisted of additional provisions for higher commissioning costs for the rigs, the costs of settling certain commercial disputes and renegotiations of commercial terms with shipyards, equipment vendors and other subcontractors, completion issues at the shipyard constructing the final two rigs and revised estimates for other cost items. In 2006 and 2005, we reduced our estimates for other cost items and recognized a gain of $1.9 million and $0.5 million, respectively.
The operating results of the discontinued fixed-fee construction business were as follows for the years ended December 31:
NOTE 3. ACQUISITIONS
In August 2007, we acquired the remaining nine percent interest in the joint venture company that manages our Angolan operations from our partner Sonangol, the national oil company of Angola, for $45.0 million in cash, bringing our total ownership interest to 100%. Prior to this acquisition, we owned a 91% interest in the joint venture company and fully consolidated the balance sheet and results of operations of the joint venture company. The principal assets of the joint venture company include the two ultra-deepwater drillships Pride Africa and Pride Angola, the jackup rig Pride Cabinda and management agreements for the deepwater platform rigs Kizomba A and Kizomba B.
We allocated the purchase price by increasing the carrying values of the drillships and the jackup rig by $36.7 million and eliminated the remaining minority interest in the joint venture company of $31.7 million. As the current operating contracts for the Pride Africa and the Pride Angola were unfavorable compared with current market rates, we recorded a non-cash deferred contract liability of $23.4 million to record the difference between stated values of the non-cancelable contracts and the current fair value of contracts with similar terms. The deferred contract liability will be amortized to revenues over the remaining lives of the contracts of approximately one to four years.
In November 2006, we acquired from our joint venture partner its 70% interest in a joint venture company that owned two deepwater semi-submersible drilling rigs, the Pride Portland and the Pride Rio de Janeiro. The acquisition increased our ownership interest in the joint venture entity and the rigs from 30% to 100%. Consideration consisted of $215.0 million in cash, plus earn-out payments, if any, to be made during the six-year period (subject to certain extensions for non-operating periods) following the expiration of the existing drilling contracts for the rigs. Such earn-out payments will equal 30% of the amount, if any, by which the standard operating dayrate, excluding bonuses, for a rig (less adjustments to reflect certain capital additions and certain increases in operating costs) exceeds $294,975 (or, in the case of Petroleo Brasileiro S.A. (“Petrobras”), which currently contracts with a 15% bonus opportunity, $256,500). As a result of the transaction, the joint venture company, which was accounted for as an equity investment, is consolidated in our financial statements, resulting in the addition of approximately $284 million of debt, net of the fair value discount of $3.9 million, of the joint venture company to our consolidated balance sheet. Due to the termination of lease agreements between us and the joint venture company and because the related operating contracts for the Pride Portland and the Pride Rio de Janeiro at the time of acquisition were unfavorable compared with current market rates, we recorded a non-cash deferred contract liability of $191.6 million to record the difference between stated values of the non-cancelable contracts and the current fair value of contracts with similar terms. The deferred contract liability will be amortized to revenues over the remaining lives of the contracts of approximately four years. The allocation of fair value to the assets acquired and liabilities assumed was as follows:
In a related transaction, we cancelled future obligations under certain existing agency relationships related to five offshore rigs we operate in Brazil, including the Pride Portland and the Pride Rio de Janeiro. For this cancellation, we paid $15 million in cash, which we expensed during the fourth quarter 2006.
NOTE 4. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following at December 31:
Depreciation and amortization expense of property and equipment for 2007, 2006 and 2005 was $222.9 million, $198.0 million and $186.3 million, respectively.
During 2007, 2006 and 2005, maintenance and repair costs included in operating costs on the accompanying consolidated statements of operations were $119.2 million, $99.7 million and $110.8 million, respectively.
Newbuild Projects and Construction-in-progress
In June 2007, we entered into an agreement with Samsung Heavy Industries Co., Ltd. to construct an advanced-capability ultra-deepwater drillship. The agreement provides for an aggregate fixed purchase price of approximately $612 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before June 30, 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. We expect the total project cost, including commissioning and testing, to be approximately $680 million, excluding capitalized interest.
In July 2007, we acquired from Lexton Shipping Ltd. an advanced-capability ultra-deepwater drillship being constructed by Samsung. As consideration for our acquisition of Lexton’s rights under the drillship construction contract with Samsung, we paid Lexton $108.5 million in cash and assumed its obligations under the construction contract, including remaining scheduled payments of approximately $540 million. The construction contract provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before February 28, 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. In January 2008, we entered into a five-year contract with respect to the drillship for drilling operations in the U.S. Gulf of Mexico, which is expected to
commence during the third quarter of 2010 following the completion of shipyard construction, mobilization of the rig to the U.S. Gulf of Mexico and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to improve its off-line operational capabilities. Including these modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $730 million, excluding capitalized interest.
In January 2008, we entered into a construction agreement and drilling contract for a third ultra-deepwater drillship (See Note 17).
As of December 31, 2007, construction-in-progress related to these two drillship construction contracts was $315.9 million, excluding $6.8 million of capitalized interest.
We capitalize interest applicable to the construction of significant additions to property and equipment. For 2007, 2006 and 2005, we capitalized interest of $10.3 million, $2.4 million and $0.5 million, respectively.
Sale of assets
In December 2007, we sold the Bintang Kalimantan for $34.0 million, resulting in a pre-tax gain of $20.0 million. In the second quarter of 2007, we completed the sale of one land rig from our Eastern Hemisphere fleet for $17.3 million, resulting in a pre-tax gain on the sale of $8.5 million.
During 2006, we sold the Pride Rotterdam for $53.2 million, resulting in a pre-tax gain on the sale of $25.3 million. The proceeds from this sale were used to repay debt.
During 2005, one of our foreign subsidiaries sold the jackup rig Pride Ohio and received $37.9 million in net proceeds, resulting in a pre-tax gain on the sale of $11.2 million. We also sold two tender-assisted barge rigs, the Piranha and the Ile de Sein, for total net proceeds of $45.6 million, resulting in a net pre-tax gain of $3.8 million. In addition, we sold six land rigs for net proceeds of $31.0 million and recognized a pre-tax gain of $18.8 million. The proceeds from these sales were used to repay debt.
NOTE 5. INDEBTEDNESS
Short-Term Borrowings
As of December 31, 2007, we had agreements with several banks for uncollateralized short-term lines of credit totaling $14.0 million (substantially all of which are uncommitted), primarily denominated in U.S. dollars. These facilities renew periodically and bear interest at variable rates based on LIBOR. As of December 31, 2007, there was no outstanding balance under any of these facilities.
Long-Term Debt
Long-term debt consisted of the following at December 31:
Senior Secured Credit Facilities
In July 2004, we entered into senior secured credit facilities consisting of a $300.0 million term loan and a $500.0 million revolving credit facility. Amounts drawn under the senior secured revolving credit facility bear interest at variable rates based on LIBOR plus a margin or the base rate plus a margin. The interest rate margin varies based on our leverage ratio. The revolving credit facility expires in July 2009.
The facility is secured by first priority liens on certain of the existing and future rigs, accounts receivable, inventory and related insurance of our subsidiary Pride Offshore, Inc. (“Pride Offshore”) (the borrower under the facility) and its subsidiaries, all of the equity of Pride Offshore and its domestic subsidiaries and 65% of the equity of certain of our foreign subsidiaries. We and certain of our domestic subsidiaries have guaranteed the obligations of Pride Offshore under the facility. In certain circumstances, we are required to repay the revolving loans, with a permanent reduction in availability under the revolving credit facility, with proceeds from a sale of or a casualty event with respect to collateral. The facility contains a number of covenants restricting, among other things, redemption and repurchase of our indebtedness; acquisitions and investments; asset sales; indebtedness; liens and affiliate transactions. The facility also contains customary events of default, including with respect to a change of control.
During 2005, we repaid the senior secured term loan in full and recognized charges of $3.6 million to write off the unamortized portion of the deferred finance costs at the time of the early repayment.
Borrowings under the revolving credit facility are available for general corporate purposes. We may obtain up to $100.0 million of letters of credit under the facility. As of December 31, 2007, there were no outstanding borrowings and $13.3 million of letters of credit outstanding under the facility. As of December 31, 2007, the interest rate on the senior secured revolving credit facility would have been approximately 5.1% had we had any borrowings outstanding, and availability was $486.7 million.
7 3/8% Senior Notes due 2014
In July 2004, we completed an offering of $500.0 million principal amount of 7 3/8% Senior Notes due 2014. The notes bear interest at 7.375% per annum, payable semiannually. The notes contain provisions that limit our ability and the ability of our subsidiaries to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt or issue preferred stock; incur dividend or other payment restrictions affecting our subsidiaries; sell assets; engage in sale and leaseback transactions; create liens; and consolidate, merge or transfer all or substantially all of our assets. Many of these restrictions will terminate if the notes are rated investment grade by either Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. and, in either case, the notes have a specified minimum rating by the other rating agency. We are required to offer to repurchase the notes in connection with specified change in control events that result in a ratings decline. The notes are subject to redemption, in whole or in part, at our option at any time on or after July 15, 2009 at redemption prices starting at 103.688% of the principal amount redeemed and declining to 100% by July 15, 2012. Prior to July 15, 2009, we may redeem some or all of the notes at 100% of the principal amount plus a make-whole premium.
3 1/4% Convertible Senior Notes Due 2033
In 2003, we issued $300.0 million aggregate principal amount of 3 1/4% Convertible Senior Notes due 2033. The notes bear interest at a rate of 3.25% per annum. We also will pay contingent interest during any six-month interest period commencing on or after May 1, 2008 for which the trading price of the notes for each of the five trading days immediately preceding such period equals or exceeds 120% of the principal amount of the notes. During any interest period when contingent interest is payable, the contingent interest payable per note will equal 0.25% of the average trading price of the notes during the five trading days immediately preceding the first day of the applicable six-month interest period. Beginning May 5, 2008, we may redeem any of the notes at a redemption price of 100% of the principal amount redeemed plus accrued and unpaid interest. In addition, noteholders may require us to repurchase the notes on May 1 of 2008, 2010, 2013, 2018, 2023 and 2028 at a repurchase price of 100% of the principal amount redeemed plus accrued and unpaid interest. We may elect to pay all or a portion of the repurchase price in common stock instead of cash, subject to certain conditions. The notes are convertible under specified circumstances into shares of our common stock at a conversion rate of 38.9045 shares per $1,000 principal amount of notes (which is equal to a conversion price of $25.704), subject to adjustment. Upon conversion, we will
have the right to deliver, in lieu of shares of our common stock, cash or a combination of cash and common stock. The notes are currently convertible by the note holders. Upon conversion, we will have the right to deliver, in lieu of shares of common stock, cash or a combination of cash and common stock. If we choose to deliver cash upon conversion, we may incur a loss for extinguishment of debt. The closing price of our common stock on December 31, 2007 was $33.90 per share. At this price, if note holders were to convert the entire issue and we chose to deliver cash in lieu of shares, we would pay approximately $396 million to settle the conversion and incur an approximately $96 million debt extinguishment loss. For each $1 increase in our stock price, the incurred debt extinguishment loss for a cash settled conversion would increase by approximately $12 million.
MARAD Notes
In November 2006, we completed the purchase of the remaining 70% interest in the joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro, which resulted in the addition of approximately $284 million of debt, net of fair value discount, to our consolidated balance sheet. Repayment of the notes is guaranteed by the United States Maritime Administration (“MARAD”). The notes bear interest at a weighted average fixed rate of 4.33%, mature in 2016 and are prepayable, in whole or in part, at any time, subject to a make-whole premium. The notes are collateralized by the two rigs and the net proceeds received by subsidiary project companies chartering the rigs.
Drillship Loan Facility
In April 2004, we completed a refinancing of the drillship loan facility collateralized by the Pride Africa and the Pride Angola and the proceeds from the related drilling contracts. The drillship loan facility matures in September 2010 and amortizes quarterly. The drillship loan facility bears interest at LIBOR plus 1.50%. As a condition of the loan, we maintain interest rate swap and cap agreements with the lenders. The effective rate at December 31, 2007 was 6.33%. In accordance with the debt agreements, we have posted letters of credit to assure that timely interest and principal payments are made. Prior to our purchase of the remaining nine percent in our Angolan joint venture company, certain cash balances were held in trust to assure that timely interest and principal payments were made. As of December 31, 2006, $1.8 million of such cash balances, which amount is included in restricted cash, was held in trust and was not available for our use.
Semisubmersible Loan
In August 2007, we repaid in full the outstanding aggregate principal amount of $58.4 million due under the semisubmersible loan collateralized by the Pride South America. The loan facility had an interest rate of 9.35% and required quarterly interest payments. We did not incur any charges in connection with the retirement of the loan.
Future Maturities
Future maturities of long-term debt were as follows at December 31:
NOTE 6. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
Our financial instruments include cash, receivables, payables and debt. Except as described below, the estimated fair value of such financial instruments at December 31, 2007 and 2006 approximate their carrying value as
reflected in our consolidated balance sheets. The fair value of our debt has been estimated based on year-end quoted market prices.
The estimated fair value of our debt at December 31, 2007 and 2006 was $1,331.9 million and $1,486.8 million, respectively, which differs from the carrying amounts of $1,191.5 million and $1,386.6 million, respectively, included in our consolidated balance sheets.
Interest Rate Swap and Cap Agreements
We are subject to the risk of variability in interest payments on our floating rate debt, which includes the senior secured revolving credit facility and the drillship loan facility at December 31, 2007. The drillship loan facility requires us to maintain interest rate swap and cap agreements. The drillship loan facility generally restricts our ability to transfer, settle, sell, offset or amend the interest rate swap and cap agreements without the consent of the lenders.
As of December 31, 2007, we had not designated any of the interest rate swap and cap agreements as hedging instruments as defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Accordingly, the changes in fair value of the interest rate swap and cap agreements are recorded currently in earnings. We included the changes in the fair value on our interest rate swap and cap agreements of $(3.9) million, $(1.3) million and $4.0 million in our consolidated statements of operations for 2007, 2006 and 2005, respectively. The total aggregate fair value of the interest rate swap and cap agreements at December 31, 2007 and 2006 was an asset of $0.2 million and $4.0 million, respectively.
Foreign Exchange Risks
Our operations are subject to foreign exchange risks, including the risks of adverse foreign currency fluctuations and devaluations and of restrictions on currency repatriation. We attempt to limit the risks of adverse currency fluctuations and restrictions on currency repatriation by obtaining contracts providing for payment in U.S. dollars or freely convertible foreign currency. To the extent possible, we seek to limit our exposure to local currencies by matching its acceptance thereof to its expense requirements in such currencies. Prior to 2004, we entered into forward exchange contracts and option contracts to manage foreign currency exchange risk principally associated with our Euro denominated expenses. We did not enter into any forward exchange or option contracts in 2007, 2006 or 2005, but continue to monitor our foreign exchange risk.
NOTE 7. INVESTMENTS IN AFFILIATES
As of December 31, 2007, we had a 30% interest in United Gulf Energy Resource Co. SAOC-Sultanate of Oman (“UGER”), which owns 99.9% of National Drilling and Services Co. LLC (“NDSC”), an Omani company. NDSC owns and operates four land drilling rigs. As of December 31, 2007, our investment in UGER was $3.4 million. In February 2008, we sold our interest in UGER for approximately $15 million.
In 2005, investment in affiliates included our 30% interest in a joint venture entity that owned the Pride Portland and the Pride Rio de Janeiro. We operated the rigs under lease agreements with the joint venture companies that required all revenues from the operations of the rigs, less operating costs and a management fee of $5,000 per day for each rig, to be paid to the joint venture companies in the form of lease payments. The lease agreements also required the joint venture companies to provide us with working capital necessary to operate the rigs, to fund capital improvements to the rigs and to fund any cash deficits incurred. In November 2006, we acquired our partner’s interest in the joint venture companies, increasing our ownership to 100% (see Note 3).
NOTE 8. INCOME TAXES
The provision for income taxes on income from continuing operations is comprised of the following for the years ended December 31:
A reconciliation of the differences between our income taxes computed at the U.S. statutory rate and our income taxes from continuing operations before income taxes and minority interest as reported is summarized as follows for the years ended December 31:
The 2007 effective tax rate is below the U.S. statutory rate due to the recording of a U.S. foreign tax credit benefit for a prior period and the impact of increased taxable income in low tax jurisdictions. The 2006 and 2005 effective tax rates are above the U.S. statutory rate due to non deductible expenses and U.S. tax on certain foreign earnings offset by the impact of taxable income in low tax jurisdictions.
The domestic and foreign components of income from continuing operations before income taxes and minority interest were as follows for the years ended December 31:
The tax effects of temporary differences that give rise to significant portions of the deferred tax liabilities and deferred tax assets were as follows at December 31:
Applicable U.S. deferred income taxes and related foreign dividend withholding taxes have not been provided on approximately $1,254.5 million of undistributed earnings and profits of our foreign subsidiaries. We consider such earnings to be permanently reinvested outside the United States. It is not practicable to estimate the amount of deferred income taxes associated with these unremitted earnings.
As of December 31, 2007, we had deferred tax assets of $71.7 million relating to $235.3 million of net operating loss (“NOL”) carryforwards, $38.6 million of non-expiring Alternative Minimum Tax (“AMT”) credits, and $98.7 million of U.S. foreign tax credits (“FTC”). The NOL carryforwards and tax credits can be used to reduce our federal and foreign income taxes payable in future years. Our NOL carryforwards in the United States total $64.9 million and could expire starting in 2021 through 2024. Foreign NOL carryforwards include $41.0 million that do not expire and $129.4 million that could expire starting in 2008 through 2017. We have recognized a $49.0 million valuation allowance on all of these foreign NOL carryforwards due to the uncertainty of realizing certain foreign NOL carryforwards. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized. We have not recorded a valuation allowance against our FTC and AMT credit deferred tax assets, since we believe that future profitability will allow us to fully utilize these tax attributes. Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings prior to the expiration of the carryforwards. The foreign tax credits begin to expire in 2017 and the AMT credits do not expire. We could be required to record an additional valuation allowance against certain or all of our remaining deferred tax assets if market conditions deteriorate or future earnings are below current estimates.
In connection with the acquisition of Marine Drilling Companies, Inc. in September 2001, we determined that certain NOL carryforwards and AMT credits are subject to limitation under Sections 382 and 383 of the U.S. Internal Revenue Code as a result of the greater than 50% cumulative change in our ownership. Although the timing of when we can utilize NOL carryforwards may be limited, we have determined that such limitations should not affect our ability to realize the benefits of the deferred tax assets associated with such NOL carryforwards and AMT credits.
Uncertain Tax Positions
We adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), on January 1, 2007. As a result of the implementation of FIN 48, we recognized an increase of approximately $18.4 million in the liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007, balance of retained earnings. As of December 31, 2007, we have approximately $44.4 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate.
We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2007, we have approximately $9.8 million of accrued interest and penalties related to uncertain tax positions on the consolidated balance sheet. During 2007, we recorded interest and penalties of $2.9 million through the consolidated statement of operations.
For jurisdictions other than the United States, tax years 1995 through 2007 remain open to examination by the major taxing jurisdictions. With regard to the United States, tax years 2004 through 2007 remain open to examination. The 2005 tax year is currently under examination by the Internal Revenue Service.
The following table presents the reconciliation of the total amounts of unrecognized tax benefits from January 1, 2007 to December 31, 2007:
(1)
Amount represents the liabilities decreased due to the sale of the Latin America Land & E&P business.
From time to time, our periodic tax returns are subject to review and examination by various tax authorities within the jurisdictions in which we operate. We are currently contesting several tax assessments and may contest future assessments where we believe the assessments are in error. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments; however, we believe the ultimate resolution of outstanding tax assessments will not have a material adverse effect on our consolidated financial statements.
In 2006, we received tax assessments from the Mexican government related to our operations for the tax years 2002 and 2003. These assessments contest our right to claim certain deductions in our tax returns for those years. We anticipate that the Mexican government will make additional assessments contesting similar deductions for other tax years. While we intend to contest these assessments vigorously, we cannot predict or provide assurance as to the ultimate outcome, which may take several years. However, we do not believe that the ultimate outcome of these assessments will have a material impact on our consolidated financial statements. As required by local statutory requirements, we have provided standby letters of credit valued at $45 million as of December 31, 2007, to contest these assessments.
NOTE 9. STOCKHOLDERS’ EQUITY
Preferred Stock
We are authorized to issue 50.0 million shares of preferred stock with a par value $0.01 per share. Our Board of Directors has the authority to issue shares of preferred stock in one or more series and to fix the number of shares, designations and other terms of each series. The Board of Directors has designated 4.0 million shares of preferred stock to constitute the Series A Junior Participating Preferred Stock in connection with our stockholders’ rights plan. As of December 31, 2007 and 2006, no shares of preferred stock were outstanding.
Common Stock
In May 2005, we completed a public offering of approximately 6.0 million shares of our common stock. We used the net proceeds of approximately $123.6 million (before offering expenses) to purchase an equal number of shares of our common stock from three affiliated investment funds at a price per share equal to the proceeds per share that we received from the offering. The shares repurchased from the funds were subsequently retired. There was no increase in the total number of shares outstanding of our common stock resulting from the transactions.
In March and April 2005, the noteholders converted substantially all of the $300.0 million principal amount of our 2 1/2% Convertible Senior Notes due 2007 into approximately 18.2 million shares of our common stock, with the remaining principal amount redeemed for cash.
Stockholders’ Rights Plan
We have a preferred share purchase rights plan. Under the plan, each share of common stock includes one right to purchase preferred stock. The rights will separate from the common stock and become exercisable (1) ten days after public announcement that a person or group of affiliated or associated persons has acquired, or obtained the right to acquire, beneficial ownership of 15% of our outstanding common stock or (2) ten business days following the start of a tender offer or exchange offer that would result in a person’s acquiring beneficial ownership of 15% of our outstanding common stock. A 15% beneficial owner is referred to as an “acquiring person” under the plan.
Our Board of Directors can elect to delay the separation of the rights from the common stock beyond the ten-day periods referred to above. The plan also confers on the board the discretion to increase or decrease the level of ownership that causes a person to become an acquiring person. Until the rights are separately distributed, the rights will be evidenced by the common stock certificates and will be transferred with and only with the common stock certificates.
After the rights are separately distributed, each right will entitle the holder to purchase from us one one-hundredth of a share of Series A Junior Participating Preferred Stock for a purchase price of $50. The rights will expire at the close of business on September 30, 2011, unless we redeem or exchange them earlier as described below.
If a person becomes an acquiring person, the rights will become rights to purchase shares of our common stock for one-half the current market price, as defined in the rights agreement, of the common stock. This occurrence is referred to as a “flip-in event” under the plan. After any flip-in event, all rights that are beneficially owned by an acquiring person, or by certain related parties, will be null and void. Our Board of Directors has the power to decide that a particular tender or exchange offer for all outstanding shares of our common stock is fair to and otherwise in the best interests of our stockholders. If the board makes this determination, the purchase of shares under the offer will not be a flip-in event.
If, after there is an acquiring person, we are acquired in a merger or other business combination transaction or 50% or more of our assets, earning power or cash flow are sold or transferred, each holder of a right will have the right to purchase shares of the common stock of the acquiring company at a price of one-half the current market price of that stock. This occurrence is referred to as a “flip-over event” under the plan. An acquiring person will not be entitled to exercise its rights, which will have become void.
Until ten days after the announcement that a person has become an acquiring person, our Board of Directors may decide to redeem the rights at a price of $0.01 per right, payable in cash, shares of common stock or other consideration. The rights will not be exercisable after a flip-in event until the rights are no longer redeemable.
At any time after a flip-in event and prior to either a person’s becoming the beneficial owner of 50% or more of the shares of common stock or a flip-over event, our Board of Directors may decide to exchange the rights for shares of common stock on a one-for-one basis. Rights owned by an acquiring person, which will have become void, will not be exchanged.
NOTE 10. EARNINGS PER SHARE
Basic earnings per share from continuing operations has been computed based on the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per share from continuing operations has been computed based on the weighted average number of shares of common stock and common stock equivalents outstanding during the applicable period, as if stock options, convertible debentures and other convertible debt were converted into common stock, after giving retroactive effect to the elimination of interest expense, net of income taxes.
The following table presents information necessary to calculate basic and diluted earnings per share from continuing operations for the years ended December 31:
The calculation of weighted average shares of common stock outstanding, as adjusted, excludes 1.1 million, 0.6 million and 0.2 million of common stock issuable pursuant to outstanding stock options for the years ended December 31, 2007, 2006 and 2005, respectively. The calculation of weighted average shares of common stock outstanding, as adjusted, also excludes 11.7 million shares of common stock issuable pursuant to convertible debt for the year ended December 31, 2005. These shares were excluded from the calculation because their effect was antidilutive or the exercise price of stock options exceeded the average price of our common stock for the applicable period.
NOTE 11. STOCK-BASED COMPENSATION
Our employee stock-based compensation plans provide for the granting or awarding of stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards and cash awards to directors, officers and other key employees. As of December 31, 2007, three of our plans had shares available for future option grants or other awards. The number of shares authorized and reserved for future issuance under the 1998 Long-Term Incentive Plan is limited to 10% of total issued and outstanding shares, subject to adjustment in the event of certain changes in our corporate structure or capital stock. No new awards may be made under the plan after May 12, 2008. As of December 31, 2007, we had a total of approximately 0.1 million shares available for award under the 2004 Directors’ Stock Incentive Plan. In May 2007, our stockholders approved the 2007 Long-Term Incentive Plan, which allows for up to eight million shares to be awarded to our employees. The maximum number of shares of common stock that may be issued with respect to awards other than options and stock appreciation rights is four million shares. As of December 31, 2007, no awards had been granted under the 2007 plan.
Stock-based compensation expense related to stock options, restricted stock and the ESPP was allocated as follows:
Stock-based compensation expense for all stock-based compensation awards granted after January 1, 2006 is based on the grant date fair value estimated in accordance with SFAS No. 123(R). We recognize these compensation costs net of a forfeiture rate and recognize the compensation costs for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. Had compensation expense for stock options been determined based on fair value at the grant date consistent with SFAS No. 123, our net income and earnings per share for 2005 would have been reduced to the pro forma amounts indicated below:
The fair value of stock-based awards is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:
The following table summarizes activity in our stock options:
The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between our closing stock price on the last trading day of the year and the exercise price, multiplied by the number of in-the-money stock options) that would have been received by the stock option holders had all the holders exercised their stock options on the last day of the year. This amount changes based on the fair market value of our stock.
The exercise price of stock options is equal to the fair market value of our common stock on the option grant date. The stock options generally vest over periods ranging from two years to four years and have a contractual term of 10 years. Vested options may be exercised in whole or in part at any time prior to the expiration date of the grant. Awards of restricted stock and of restricted stock units consist of awards of our common stock, or awards denominated in common stock, that are subject to restrictions on transferability. Such awards are subject to forfeiture if employment terminates in certain circumstances prior to the release of the restrictions and vest two to four years from the date of grant.
Other information pertaining to option activity was as follows:
During 2007, 2006 and 2005, we received cash from the exercise of stock options of $27.6 million, $50.3 million and $91.2 million, respectively. Income tax benefits of $7.7 million, $14.1 million, and $21.2 million were realized from the exercise of stock options for 2007, 2006 and 2005, respectively. As of December 31, 2007, there was $8.4 million of total stock option compensation expense related to nonvested stock options not yet recognized, which is expected to be recognized over a weighted average period of 2.4 years.
We have awarded restricted stock and restricted stock units (collectively, “restricted stock awards”) to certain key employees and directors. We record unearned compensation as a reduction of stockholders’ equity based on the closing price of our common stock on the date of grant. The unearned compensation is being recognized ratably over the applicable vesting period. The following table summarizes the restricted stock awarded during the years ended December 31:
The following table summarizes activity in our nonvested restricted stock awards:
As of December 31, 2007, there was $31.6 million of unrecognized stock-based compensation expense related to nonvested restricted stock awards. That cost is expected to be recognized over a weighted average period of 2.7 years. Prior to the January 1, 2006 adoption of SFAS 123(R), we accounted for restricted stock awards under APB No. 25. APB No. 25 required the full value of restricted stock awards to be recorded in stockholders’ equity with a deferred compensation balance recorded within equity for the unrecognized compensation cost. SFAS 123(R) does not consider the equity to be issued until the stock award vests. Accordingly, the deferred compensation balance of $5.1 million at December 31, 2005 was reclassified to additional paid in capital on January 1, 2006.
In December 2006, we changed the procedures regarding personal income tax withholding with respect to outstanding restricted stock awards held by our officers, including all of our executive officers. The changes permitted such officers to request that, for purposes of satisfying the federal income tax withholding obligations with respect to certain taxes required to be withheld with respect to the vesting of the awards, the amount withheld be greater than the statutory minimum with respect to federal income tax withholding but no more than the highest federal marginal income tax rate applicable to ordinary income at the time of vesting. For restricted stock awards that vested through February 14, 2007, the withholding of the statutory minimum and the increased amount was net settled by the plan administrator’s delivery of share of common stock to us with a fair market value equal to the amount of the withholding, with the remaining shares delivered to the officer. As a result of the change in procedures and the net settlement feature, these awards were reclassified from equity to liability awards under SFAS No. 123(R) in the fourth quarter of 2006. We reclassified $4.0 million from stockholders’ equity and accrued a total of $5.2 million in accrued expenses and other long-term liabilities for the fair value of the share-based payment liabilities at December 31, 2006. Expense of $1.2 million was recognized in 2006 in connection with the modification of these awards. As of February 15, 2007, we further amended our procedures for additional
withholding and settlement of vested awards, which resulted in the reclassification of the affected restricted stock awards back to equity classified awards. The February 15, 2007, modification did not result in any material incremental compensation cost and resulted in the reclassification of the full amount of the recorded liability to equity in the first quarter of 2007.
During 2007, 2006 and 2005, we recognized $0.1 million, $0.4 million and $0.6 million, respectively, of stock-based compensation in connection with the modification of the terms of certain key employees’ stock options and restricted stock.
Our ESPP permits eligible employees to purchase shares of our common stock at a price equal to 85% of the lower of the closing price of our common stock on the first or last trading day of the calendar year. A total of 0.4 million shares remained available for issuance under the plan as of December 31, 2007. Employees purchased approximately 95,000, 83,000 and 82,000 shares in the years ended December 31, 2007, 2006 and 2005, respectively.
NOTE 12. EMPLOYEE BENEFIT PLANS
Defined Benefit Pension Plans
We have a non-qualified Supplemental Executive Retirement Plan (the “SERP”) that provides for benefits, to the extent vested, to be paid to participating executive officers upon the officer’s termination or retirement. No assets are held with respect to the SERP; therefore, benefits will be funded when paid to the participants. We account for the SERP in accordance with SFAS No. 87, Employers Accounting for Pensions. We recorded expenses of $5.6 million, $4.3 million and $3.9 million related to the SERP in 2007, 2006 and 2005, respectively. As of December 31, 2007 and 2006, the unfunded accrued pension liability was $13.6 million and $10.5 million, respectively.
We adopted the recognition provisions of SFAS No. 158 as of December 31, 2006, which requires that the funded status of defined benefit pension plan and other postretirement plans be fully recognized in the balance sheet. Based on the funded status of our plans as of December 31, 2007, total assets for overfunded plans were approximately $1.1 million and the unfunded accrued liability was approximately $14.3 million. Based on the funded status of our plans as of December 31, 2006, the adoption of SFAS 158 increased total assets by approximately $1.1 million, increased the unfunded accrued liability by approximately $1.9 million and reduced total shareholders’ equity by approximately $0.5 million, net of taxes. The adoption of SFAS 158 did not affect our results of operations.
Defined Contribution Plan
We have a 401(k) defined contribution plan for generally all of our U.S. employees that allows eligible employees to defer up to 50% of their eligible annual compensation, with certain limitations. At our discretion, we may match up to 100% of the first 6% of compensation deferred by participants. Our contributions to the plan amounted to $6.4 million, $4.8 million and $3.7 million in 2007, 2006 and 2005, respectively.
In addition, we have a deferred compensation plan that allows senior managers and other highly compensated employees, as defined in the plan, to participate in an unfunded, non-qualified plan. Participants may defer up to 100% of compensation, including bonuses and net proceeds from the exercise of stock options.
Other
In 2004, we applied to the French Labor Ministry for a Progressive Retirement Plan (the “PRP”). The PRP was approved by the French Labor Ministry in 2005. Pursuant to the PRP, 56 employees of our subsidiary in France have elected to accelerate their retirement with us funding a portion of the benefits. The cost of the PRP will be recognized over the estimated remaining service period of the employees. As of December 31, 2007 and 2006, we have accrued balances of $3.3 million and $2.3 million, respectively.
NOTE 13. COMMITMENTS AND CONTINGENCIES
Leases
At December 31, 2007, we had entered into long-term non-cancelable operating leases covering certain facilities and equipment. The minimum annual rental commitments are as follows for the years ending December 31:
Purchase Obligations
At December 31, 2007, our purchase obligations as defined by SFAS No. 47, Disclosure of Long-Term Obligations, related to our two newbuild drillship construction projects as of such date are as follows:
FCPA Investigation
During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.
The investigation, which is continuing, has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.
The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations. In addition, the U.S. Department of Justice has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria. The Audit Committee is reviewing the issues raised by the request, and we are cooperating with the DOJ in connection with its request.
This review has found evidence suggesting that during the period from 2001 through 2005 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola, and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2 million. We are also reviewing certain agent payments related to Malaysia.
The investigation of the matters described in the prior paragraph and the Audit Committee’s compliance review are ongoing. Accordingly, there can be no assurances that evidence of additional potential FCPA violations may not be uncovered in those or other countries.
Our management and the Audit Committee of our Board of Directors believe it likely that members of our senior operations management either were aware, or should have been aware, that improper payments to foreign government officials were made or proposed to be made. Our former Chief Operating Officer resigned as Chief Operating Officer effective on May 31, 2006 and has elected to retire from the company, although he will remain an employee, but not an officer, during the pendency of the investigation to assist us with the investigation and to be available for consultation and to answer questions relating to our business. His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the Securities and Exchange Commission and are cooperating with these authorities as the investigation and compliance reviews continue and as they review the matter. If violations of the FCPA occurred, we could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.
We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets. No amounts have been accrued related to any potential fines, sanctions or other penalties, which could be material individually or in the aggregate.
We cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, the applicable government or other authorities or our customers or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.
Litigation
Since 2004, certain of our subsidiaries have been named, along with numerous other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi by several hundred individuals that allege that they were employed by some of the named defendants between approximately 1965 and 1986. The
complaints allege that certain drilling contractors used products containing asbestos in their operations and seek, among other things, an award of unspecified compensatory and punitive damages. Eight individuals of the many plaintiffs in these suits have been identified as allegedly having worked for us. We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of these lawsuits to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits.
Paul Bragg, our former President and Chief Executive Officer, filed suit against us in the State District Court of Harris County, Texas in October 2005 seeking declaratory relief to set aside his non-competition agreement and damages for breach of contract in excess of $17 million. We and Mr. Bragg litigated his claims as well as a number of counterclaims we filed against Mr. Bragg, including a claim for breach of fiduciary duty. In late 2006 and early 2007, the trial court granted summary judgment in our favor against Mr. Bragg with respect to his breach of contract claims and in Mr. Bragg’s favor against our breach of fiduciary duty counterclaim. Mr. Bragg’s two-year contractual commitment to not compete with us ended in June 2007, according to the terms of his employment agreement. We and Mr. Bragg each have appealed the summary dismissal of our respective claims, and the appeals are currently pending. We intend to continue our vigorous defense against Mr. Bragg’s breach of contract claims on appeal. Similarly, we intend to pursue diligently on appeal our breach of fiduciary duty counterclaim against Mr. Bragg. We do not expect the outcome of this lawsuit to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this lawsuit.
We are routinely involved in other litigation, claims and disputes incidental to our business, which at times involve claims for significant monetary amounts, some of which would not be covered by insurance. In the opinion of management, none of the existing litigation will have a material adverse effect on our financial position, results of operations or cash flows. However, a substantial settlement payment or judgment in excess of our accruals could have a material adverse effect on our financial position, results of operations or cash flows.
Other
In the normal course of business with customers, vendors and others, we have entered into letters of credit and surety bonds as security for certain performance obligations that totaled approximately $239.5 million at December 31, 2007. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions.
NOTE 14. SEGMENT AND GEOGRAPHIC INFORMATION
Subsequent to the disposition of our Latin America Land and E&P Services segments in August 2007, our operations consist of one reportable segment, Offshore Drilling Services. All periods presented have been revised to reflect our Latin America Land and E&P Services segments and our three tender-assist rigs as discontinued operations (See Note 2). As a result of our reportable segment changes, certain operating and administrative costs were reallocated for all periods presented to our continuing operating segments.
Revenues for Offshore Drilling Services by asset class are listed below. We consider our drillships and our semisubmersible rigs operating in water depths greater than 4,500 feet as deepwater and our semisubmersible rigs operating in water depths from 1,000 feet to 4,500 feet as midwater. Our jackups operate in water depths up to 300 feet. We have included our seven land rigs and other operations in Other.
Our significant customers for the years ended 2005, 2006 and 2007, were as follows:
For the year ended December 31, 2007, we derived 83% of our revenues from countries outside of the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in foreign operations. Revenues by geographic area are presented by attributing revenues to the individual country where the services were performed.
Revenues by geographic area where the services are performed are as follows for years ended December 31:
Long-lived assets by geographic area as presented in the following table were attributed to countries based on the physical location of the assets. A substantial portion of our assets is mobile. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the revenues generated by such assets during the periods.
Long-lived assets, which include property and equipment and goodwill, by geographic area are as follows at December 31:
NOTE 15. OTHER SUPPLEMENTAL INFORMATION
Prepaid expenses and other current assets consisted of the following at December 31:
Accrued expenses and other current liabilities consisted of the following at December 31:
Supplemental consolidated statement of operations information is as follows for the years ended December 31:
Supplemental cash flows and non-cash transactions were as follows for the years ended December 31:
NOTE 16. SELECTED QUARTERLY FINANCIAL DATA (1) (UNAUDITED)
(1) All periods presented reflect the reclassification of our Latin America Land and E&P Services segments and three tender-assist barge rigs to discontinued operations. Also, reported in discontinued operations for all periods presented is our fixed-fee rig construction business.
NOTE 17. SUBSEQUENT EVENT
In January 2008, we entered into an agreement with Samsung to construct an advanced-capability ultra-deepwater drillship. The agreement provides for an aggregate fixed purchase price of approximately $636 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before March 31, 2011. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. We have entered into a multi-year drilling contract with respect to the drillship, which is expected to commence during the first quarter of 2011 following the completion of shipyard construction, mobilization of the rig and customer acceptance testing. Under the drilling contract, the customer may elect, by January 31, 2010, a firm contract term of at least five years and up to seven years in duration. We expect the total project cost, including commissioning and testing, to be approximately $720 million, excluding capitalized interest.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this annual report. Based upon that evaluation, our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2007 were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
(b) Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined under Rule 13a-15(f) promulgated under the Exchange Act. In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2007, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, using the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (the “COSO Framework”). The inherent limitations of internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management concluded that our internal control over financial reporting was effective based on the criteria set forth in the COSO Framework as of December 31, 2007.
KPMG LLP, our independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2007 as stated in their report, which appears in “Item 8. Financial Statements and Supplementary Data” contained herein.
(c) Changes in Our Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, or the Exchange Act, within 120 days of the end of our fiscal year on December 31, 2007. Information with respect to our executive officers is set forth under the caption “Executive Officers of the Registrant” in Part I of this annual report.
Code of Business Conduct and Ethical Practices
We have adopted a Code of Business Conduct and Ethical Practices, which applies to all employees, including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of the code under “Corporate Governance” in the “Investor Relations” section of our internet website at www.prideinternational.com. Copies of the code may be obtained free of charge on our website or by requesting a copy in writing from our Chief Compliance Officer at 5847 San Felipe, Suite 3300, Houston, Texas 77057. Any waivers of the code must be approved by our Board of Directors or a designated board committee. Any amendments to, or waivers from, the code that apply to our executive officers and directors will be posted under “Corporate Governance” in the “Investor Relations” section of our internet website at www.prideinternational.com.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2007.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2007.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2007.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2007.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this annual report:
(1) Financial Statements
All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.
(2) Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or not required, or the information required thereby is included in the consolidated financial statements or the notes thereto included in this annual report.
(3) Exhibits
Each exhibit identified below is filed with this annual report. Exhibits designated with an "*” are filed herewith. Exhibits designated with a “” are management contracts or compensatory plans or arrangements.
*
Filed herewith.

Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on February 28, 2008.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 28, 2008.
INDEX TO EXHIBITS
*
Filed herewith.

Management contract or compensatory plan or arrangement.