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. Pride’s telephone number at such address is (713) 789-1400 or (800) 645-2067.
We are a leading international provider of contract drilling and related services to oil and natural gas companies worldwide, operating offshore and on land. As of February 28, 2007, we owned a global fleet of 272 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, 28 jackup rigs, 16 tender-assisted, barge and platform rigs and 214 land-based drilling and workover rigs.
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, the Mediterranean Sea, West Africa, the Middle East and Asia Pacific. The significant 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, as well as land-based drilling and workover rigs in international land markets. 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
In the third quarter of 2006, we reorganized our operations into three principal reportable segments: Offshore, which includes all of our offshore drilling fleet and operations; Latin America Land, which includes our land-based drilling and workover services in Latin America; and E&P Services, which includes our exploration and production services business in Latin America.
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, total assets, capital expenditures and depreciation and amortization attributable to our segments 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 acquisitions and dispositions of assets set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” in Item 7 and in Notes 2 and 12 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 as of February 28, 2007:
(1)
Owned by a joint venture in which we have a 91% interest; managed by Pride.
(2)
Also known as the Sea Explorer.
(3)
Also known as the Al Baraka I.
(4)
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 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. 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.
Tender-Assisted Rigs. Our tender-assisted rigs are generally barges moored alongside a platform and containing crew quarters, mud tanks, mud pumps and power generation systems. The only equipment transferred to the platform for drilling or workover operations is the derrick equipment set consisting of the substructure, drillfloor, derrick and drawworks. As a result, tender-assisted rigs allow smaller, less costly platforms to be used for
development projects. Self-erecting tender-assisted rigs carry their own derrick equipment and have a crane capable of erecting the derrick on the platform, thereby eliminating the cost associated with a separate derrick barge and related equipment. Tender-assisted rigs generally operate with crews of 15 to 25 persons.
Barge Rigs. We own two lake barge rigs on Lake Maracaibo, Venezuela and one swamp barge in West Africa. Lake barges are designed to work in a floating mode with a cantilever feature and a mooring system that enables the rig to operate in waters up to 150 feet deep. Swamp barge rigs generally operate in marshy areas or in water depths of less than 25 feet. This type of rig is held on location by submerging the hull onto the sea floor before commencement of work. Barge rigs generally operate with crews of 15 to 25 persons.
Platform Rigs. Our platform rigs 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. Fixed offshore platforms are steel, tower-like structures that stand on the ocean floor, with the top portion, or platform, above the water level, providing the foundation upon which the platform rig is placed. Our platform rigs can be used to provide drilling, workover and horizontal reentry services using top drives, enhanced pumps and solids control equipment for drilling fluids. 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.
Managed Rigs. We perform rig management services on a variety of rigs owned by others, consisting of providing technical drilling assistance, personnel, repair and maintenance services, and drilling operation management services.
Contract Labor. We provide contract labor services to two offshore rigs owned and managed by others. We provide the labor on a cost plus or fixed fee basis and do not have any responsibility for the drilling program of the rig owner.
Land-based Rigs
The table below presents information about our land-based rig fleet as of February 28, 2007:
A land-based drilling rig consists of engines, drawworks, a mast, substructure, pumps to circulate the drilling fluid, blowout preventers, drill string and related equipment. The intended well depth and the drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. Our land-based fleet also includes a class of rigs known as workover rigs that are designed to perform maintenance and repair or modification to existing wells, which are referred to as workovers. Maintenance and repair services are required on producing oil and natural gas wells to ensure efficient, continuous operation. These services consist of mechanical repairs necessary to maintain or improve production from the well, such as repairing parted sucker rods, replacing defective downhole pumps in an oil well or replacing defective tubing in a natural gas well. Workover services include the opening of new producing zones in an existing well, recompletion of a well in which production has declined, drilling out plugs and packers and the conversion of a producing well to an injection well during enhanced recovery operations. All of our land-based rigs can be readily moved between well sites and
between geographic areas of operations. Most of our land-based drilling and land-based workover/well service 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, 2006, we had one customer, Petroleo Brasilerio S.A. (“Petrobras”), that accounted for 16.7% of our consolidated revenues. The loss of this significant customer could have a material adverse effect on our results of operations. No other customer accounted for 10% or more of our 2006 consolidated revenues.
Drilling Contracts
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. 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. Substantially all of our contracts with major customers are on a dayrate basis. 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.
Other contracts provide for payment on a footage basis, whereby we are paid a fixed amount 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. 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.
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 or negotiated basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. Rig availability 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, rig location and efficiency. 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 offering a wide range of drilling and other oilfield services 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. Competition for land rigs is generally on a regional basis.
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. In addition, our land rig in Kazakhstan is operating on an artificial island in the Caspian Sea. Because winter ice conditions hinder access and resupply, the rig may be placed in a non-operating standby mode during winter months at a reduced dayrate. Otherwise, our business activities are not significantly affected by seasonal fluctuations. Most of our rigs outside the Gulf of Mexico and Kazakhstan are located in geographical areas that are not subject to severe weather changes that would halt operations for prolonged periods.
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. We have insurance in place covering certain exposures, including physical damage to our drilling rigs and personal injury claims by our drilling crews. Our marine package policy provides coverage for damage to our rigs and loss of hire insurance for certain assets with higher dayrates. In addition, we maintain insurance coverage for cargo, control of well, auto liability, non-owned aviation and similar potential liabilities. Due to losses sustained by the offshore drilling industry as a result of the hurricanes in the Gulf of Mexico in 2004 and 2005, our insurance costs increased significantly as our policies renewed in July 2006. Underwriters have also imposed an aggregate limit of approximately $85.0 million for damage due to named wind storms in the U.S. Gulf of Mexico, with a $10.0 million deductible per named wind storm.
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 2007.
Hurricanes Katrina and Rita damaged a number of the industry’s 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, the Minerals Management Service of the U.S. Department of the Interior (“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, which expired on November 30, 2006, 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 hurricane season, 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 or limit the operational capabilities of our rigs and could materially and adversely affect our operations and financial condition.
Employees
As of December 31, 2006, we employed approximately 14,300 personnel and had approximately 1,000 contractors working for us. Approximately 1,800 of our employees and contractors were located in the United States and 13,500 were located abroad. Hourly rig crews constitute the vast majority of our employees. None of our U.S. employees are represented by a collective bargaining agreement. Many of our international employees are subject to industry-wide labor contracts within their respective countries. We believe that our relations with our employees are good.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to these filings, are available free of charge through our internet website at www.prideinternational.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the Securities and Exchange Commission. These reports also are available at the SEC’s internet website at www.sec.gov. Information contained on or accessible from our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
We have filed the required certifications of our chief executive officer and our chief financial officer under Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits 31.1 and 31.2 to this annual report. In 2006, we submitted to the New York Stock Exchange the chief executive officer certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual.
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:
•
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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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;
•
the ability of OPEC to set and maintain production levels and prices;
•
the level of production by non-OPEC countries;
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domestic and foreign tax policies;
•
the development and exploitation of alternative fuels;
•
the policies of various governments regarding exploration and development of their oil and natural gas reserves; and
•
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.
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. Orders for construction of approximately 65 jackup rigs have been announced with delivery dates ranging from 2007 to 2010. Most of these units are cantilevered units and are considered to be premium units. In the deepwater sector, there have been announcements of approximately 45 new semisubmersible rigs and drillships and the upgrade of approximately five other semisubmersibles to ultra-deepwater units, with delivery forecast to occur from 2007 through 2010. 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 are likely for all classes of rigs pursuant to the exercise of one or more of these options and otherwise. In addition, our competitors’ “cold-stacked” (i.e., minimally crewed with little or no scheduled maintenance being performed) rigs may re-enter the market. 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 exacerbate the negative impacts on 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 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 materially impairs 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 and suppliers, resulting in increased price competition and fewer alternatives for sourcing of key supplies. 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 idle 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.
Failure to attract and retain skilled personnel 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. 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 and 2006, and we expect this trend to continue in 2007. The shortages of qualified personnel or the inability to obtain and retain qualified personnel could negatively affect the quality and timeliness of our work. 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 2006, we derived 81.2% 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 devaluation;
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restrictions on currency repatriation;
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political, social and economic instability, war and civil disturbances;
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seizure, expropriation or nationalization of assets;
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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;
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imposition of trade barriers;
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wage and price controls;
•
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; and
•
acts of terrorism.
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.
In 2006, we derived 6.3% of our revenues from operations in Venezuela, which has been experiencing political, economic and social turmoil, including labor strikes and demonstrations. The implications and results of the political, economic and social instability in Venezuela are uncertain at this time, but the instability could have an adverse effect on our business. The Venezuelan government frequently intervenes in the Venezuelan economy and occasionally makes significant changes in policy. Recently, the government’s actions to control inflation and implement other policies have involved wage and price controls, currency devaluations, capital controls and limits on imports, among other things. Several measures imposed by the Venezuelan government, such as exchange controls and currency transfer restrictions, limit our ability to convert the local currency into U.S. dollars and transfer excess funds out of Venezuela. Although our current drilling contracts in Venezuela call for a significant portion of our dayrates to be paid in U.S. dollars, changes in existing regulations or the interpretation or enforcement of those regulations could further restrict our ability to receive U.S. dollar payments. The exchange controls could also result in an artificially high value being placed on the local currency, which could affect our operating costs, revenues and financial results.
Our international operations are also subject to other risks, including foreign monetary and tax policies and nullification or modification of contracts. Additionally, 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.
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, shortly after and as a result of certain statements that were made by an employee during the investigation, 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 Latin America 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 2003 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 or the movement of personnel through immigration; 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. This review has found evidence suggesting that in 2004 and 2005 payments may have been made to government officials in Saudi Arabia and Kazakhstan, aggregating less than $175,000, in connection with clearing rigs or equipment through customs or resolving outstanding customs issues in those countries. The investigation of the matters related to Saudi Arabia and Kazakhstan 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 Saudi Arabia, Kazakhstan 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. On December 1, 2006, our Vice President - Western Hemisphere Operations resigned. On December 2, 2006, our former Country Manager in Venezuela and Mexico was terminated. We have placed another member of our senior operations management on administrative leave pending the outcome of the investigation.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the U.S. Department of Justice 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. 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.
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.
For the years ended December 31, 2006, 2005 and 2004, our operations in Venezuela provided revenues of approximately $156.9 million, $172.6 million, and $167.1 million, or approximately 6.3%, 8.5% and 9.8% of our total consolidated revenues, respectively. Our Venezuela operations provided earnings (loss) from operations of approximately $6.9 million, $16.8 million, and $(6.7) million or approximately 1.3%, 5.2% and (2.7)% of our total consolidated earnings from operations for 2006, 2005 and 2004, respectively. As of December 31, 2006 and 2005, we had accounts receivable from Petróleos de Venezuela, S.A. totaling $27.6 million and $33.4 million, respectively.
If we are unable to obtain new or favorable contracts for rigs whose contracts are expiring, our revenues and profitability could be materially reduced.
We have a number of contracts that will expire in 2007 and 2008. 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, 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 or in other specified circumstances. 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 or operational problems. 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.
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, lower specification semisubmersible rigs. In addition, the announced construction of new rigs includes approximately 110 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. 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 of managing variable sea floor conditions found in 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, 2006, Petrobras provided 16.7% of our consolidated revenues. Our two next largest customers, none of which individually represented more than 10% of revenues, accounted in the aggregate for 16.3% of our 2006 consolidated revenues. For the year ended December 31, 2005, Petrobras and Petroleos Mexicanos S.A. (“PEMEX”) accounted for 14.4% and 10.7%, respectively, of consolidated revenues. Our two next largest customers, neither of which individually represented more than 10% of revenues, accounted in the aggregate for 13.9% of our 2005 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.
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, 2006, we had $1,386.6 million in long-term debt. 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 reduce our total indebtedness 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.
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 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 and damage from severe weather. 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 in our industry over the last few years, such as the hurricanes in the Gulf of Mexico in 2004 and 2005, insurance underwriters have increased insurance premiums for many of the coverages historically maintained and have 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 increased significantly as our policies renewed in July 2006. In addition, underwriters have also imposed an aggregate limit of approximately $85.0 million for damage due to named wind storms in the U.S. Gulf of Mexico, with a $10.0 million deductible per named wind storm. 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.
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 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 addition, depending on available opportunities, we may construct rigs for our fleet in the future. All of these projects are subject to the risks of delay or cost overruns, including costs or delays resulting from the following:
•
unexpectedly long delivery times for or shortages of key equipment and materials;
•
shortages of skilled labor and other shipyard personnel necessary to perform the work;
•
reliance on third-party equipment vendors;
•
unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
•
unforeseen design or engineering problems;
•
unanticipated actual or purported change orders;
•
disputes with shipyards and suppliers;
•
work stoppages;
•
financial or other difficulties at shipyards;
•
adverse weather conditions; and
•
inability to obtain required permits or approvals.
Significant cost overruns or delays could materially affect our financial condition and results of operations. 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.
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 by extending the economic life of existing rigs, 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.
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 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, 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, which expired on November 30, 2006, 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 hurricane season, 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, 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.
Many of our contracts with our customers for our offshore rigs are long-term fixed dayrate contracts. Increases in our costs, which are unpredictable and fluctuate based on events outside our control, could adversely impact our profitability on those contracts.
A number of our contracts with our customers for our offshore rigs are on a long-term fixed dayrate basis. Generally, costs increase as the business environment for drilling services improves and demand for oilfield equipment and skilled labor increases. Long-term fixed dayrate contracts limit our ability to adjust dayrates in response to increased costs. As a result, substantial increase in our costs associated with these contracts would adversely impact our profitability and this impact could be material.
Our long-term fixed dayrate contracts may limit our ability to benefit from increasing dayrates in an improving market.
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. As a result of a number of our contracts for offshore rigs being on a long-term fixed dayrate basis, our inability to fully benefit from increasing dayrates in an improving market may limit our profitability.
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 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 relating to involuntary terminations arising from our various collective bargaining agreements and from statutory requirements of those countries. 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, outbreaks of which have already occurred in various parts of the world in which we operate, could adversely impact our operations, the operations of our clients and the global economy, 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-based drilling rigs, well servicing rigs and ancillary equipment, most of which we own. We operate some rigs under joint venture arrangements, management agreements and lease agreements. 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 office and operating facilities in Houma, Louisiana and in Algeria, Angola, Argentina, Brazil, Colombia, France, Peru and Venezuela. Additionally, we lease office and operating facilities in Houston, Texas and in several 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 3 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
In August 2004, we were notified that certain of our subsidiaries have been named, along with 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. Additional suits have been filed since August 2004. The complaints allege that certain drilling contractors used products containing asbestos in offshore drilling operations, land-based drilling operations and in
drilling structures, drilling rigs, vessels and other equipment. The plaintiffs assert claims based on, among other things, negligence and strict liability and claims under the Jones Act. The complaints name as defendants numerous other companies that are not affiliated with us, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints. The plaintiffs 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 or one of our affiliates or predecessors. Currently, discovery and investigation is ongoing to determine whether these individuals were employed in our offshore operations during the alleged period of exposure. 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 A. Bragg, our former President and Chief Executive Officer, filed suit against us in State District Court of Harris County, Texas in early October 2005 seeking a declaratory judgment that the non-competition provisions of his employment agreement are unlawful and unenforceable. Shortly thereafter, Mr. Bragg filed a second lawsuit against us alleging that we breached written and oral employment agreements with him and seeking damages aggregating more than $17.0 million. The suits were consolidated.
We filed counterclaims against Mr. Bragg related to his non-competition claim seeking a declaratory judgment that the non-competition provisions of his employment agreement are enforceable and restitution of certain amounts paid to Mr. Bragg should there be a finding that the non-competition provisions of his employment agreement are unenforceable. On February 1, 2007, the trial court granted Mr. Bragg’s motion to dismiss, without prejudice, his declaratory judgment claim related to his covenant not to compete. We, in turn, are seeking to dismiss, without prejudice, our counterclaims in connection with Mr. Bragg’s covenant not to compete declaratory judgment claim.
We filed counterclaims against Mr. Bragg related to his claims for breach of contract claiming, among other things, (i) breach of fiduciary duty seeking disgorgement of certain amounts previously paid to Mr. Bragg stemming from actions that may have been taken by Mr. Bragg relating to his employment compensation claims, (ii) declaratory judgment that we did not breach his contract and (iii) breach of contract. On October 25, 2006, the trial court granted summary judgment in our favor dismissing Mr. Bragg’s claims for damages related to an alleged breach of written and oral employment agreements. On December 20, 2006, the trial court granted summary judgment against us on our counterclaim for breach of fiduciary duty. We subsequently filed a notice of appeal with respect to the trial court’s dismissal of our counterclaim for breach of fiduciary duty. We are seeking to dismiss, without prejudice, our remaining counterclaims, and we have obtained a tolling agreement allowing us to resuscitate these counterclaims at a later date if we so choose.
Currently, the only matter outstanding before the trial court is Mr. Bragg’s motion for reconsideration of the trial court’s order dismissing his breach of contract claims. We intend to defend ourselves vigorously and, based on the information available to us at this time, 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, 2007. 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 of Pride in June 2005. He joined Pride 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 December 2000 until March 2001, he was employed as Executive Vice President, Chief Financial Officer and Chief Operating Officer of JRL Enterprises, Inc. From February 1999 until December 2000, he served as 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 Pride in December 2005 and became 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 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 previously served as Vice President, General Counsel and Secretary since December 2003. He joined Pride 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 Pride, 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 Pride 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.
K. George Wasaff was named Chief Executive Officer for Latin America Land and E&P Services in January 2007. Since 2005, Mr. Wasaff has been employed by Ashmore Energy International as Executive Vice President responsible for worldwide operations and Senior Vice President of Operations and Administration of Prisma Energy. Mr. Wasaff was previously employed by Enron Corp. from 1986 to 2005 in a variety of roles, including Senior Vice President, Wholesale Operations of South America, Vice Chairman and Chief Executive Officer of Transportadora de Gas del Sur S.A., Country Manager and Vice President, Mexico and, most recently, Managing Director, Corporate Services and member of the Management Committee. Prior to that, Mr. Wasaff was a marketing manager for El Paso Natural Gas Company.
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, 2007, there were approximately 1,200 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 do not currently intend to pay any cash dividends on our common stock. In addition, our ability to pay cash dividends is restricted 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, 2006 and 2005, and for the years ended December 31, 2006, 2005 and 2004, 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, 2004, 2003 and 2002, and for the years ended December 31, 2003 and 2002 from consolidated financial information included our annual report on Form 10-K for the year ended December 31, 2005. 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 of this annual report and our audited consolidated financial statements and related notes included in Item 8 of this annual report.
(1)
Other income (expense), net for 2002 includes $24.0 million related to realized and unrealized losses on the fair values of interest rate swap and cap agreements.
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 and Recent Developments
We provide contract drilling and related services to oil and natural gas companies worldwide, operating both offshore and on land. As of February 28, 2007, we owned a global fleet of 272 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, 28 jackup rigs, 16 tender-assisted, barge and platform rigs and 214 land-based drilling and workover rigs. Our customers include the major integrated oil and natural gas companies, independent oil and natural gas companies and state-owned national oil companies. Our competitors range from large international companies offering a wide range of drilling and other oilfield services to smaller, locally owned companies.
In September 2006, we reorganized our operations into three principal reportable segments: Offshore, Latin America Land, and E&P Services. The realignment of our reportable segments was attributable to implementation of a better methodology to manage our business and organizational changes, including the hiring of a Chief Operating Officer responsible for all of our offshore drilling fleet. Our Offshore segment includes all of our offshore drilling fleet and operations. Our Latin America Land segment includes all of our land-based drilling and workover services in Latin America. Our E&P Services segment includes our exploration and production services business in Latin America. All prior year information has been reclassified to conform to the current period presentation of these three segments. See Note 14 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report.
In November 2006, we acquired from our joint venture partner its 70% interest in a joint venture company the principal assets of which are 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 company and the rigs from 30% to 100%. Consideration consisted of $215 million in cash, assumed debt valued at $284 million, and 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 Petrobras, which currently contracts with a 15% bonus opportunity, $256,500). 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.
We funded the purchase price with cash on hand and borrowings under our senior secured revolving credit facility. As a result of the transaction, the joint venture company, which was accounted for as an equity investment, is now consolidated in our financial statements, resulting in the recording of approximately $284 million of debt, net of fair value discount, of the joint venture company to our consolidated balance sheet. The debt, which is guaranteed by the U.S. Maritime Administration, is more fully described under “Liquidity and Capital Resources - Other Outstanding Debt.”
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.
In November 2006, we agreed to contract terms for four of our rigs operating offshore Brazil: the Pride Brazil, the Pride Carlos Walter, the Pride South Atlantic, and the Pride South America. Expected aggregate dayrate revenues under these contracts total approximately $2.1 billion, with approximately $200 million of additional performance bonus opportunities. We expect to commence operations under the new five-year contracts after the current contract commitment for each rig is complete, beginning with the Pride South America during the second quarter 2007, followed by the Pride South Atlantic in the second quarter 2008 and the Pride Brazil and the Pride Carlos Walter in the third quarter 2008. Each of these contracts includes cost escalation provisions that commenced upon the contract award. We also agreed to a three year contract for the Pride North America that includes a dayrate in the mid-$440,000s, with the third year adjusted up or down by a maximum of 10%, according to an index of average contract dayrates for similar rigs during the fourth quarter 2009. This contract, which is expected to begin during the first quarter of 2008, includes cost escalation provisions that commenced upon signing.
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, shortly after and as a result of certain statements that were made by an employee during the investigation, 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 Latin America 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 2003 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 or the movement of personnel through immigration; 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. This review has found evidence suggesting that in 2004 and 2005 payments may have been made to government officials in Saudi Arabia and Kazakhstan, aggregating less than $175,000, in connection with clearing rigs or equipment through customs or resolving outstanding customs issues in those countries. The investigation of the matters related to Saudi Arabia and Kazakhstan 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 Saudi Arabia, Kazakhstan 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. On December 1, 2006, our Vice President - Western Hemisphere Operations resigned. On December 2, 2006, our former Country Manager in Venezuela and Mexico was terminated. We have placed another member of our senior operations management on administrative leave pending the outcome of the investigation.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the U.S. Department of Justice 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. 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.
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. These actions continue a process we had previously commenced. Since late 2003, we have created and filled a legal and ethical compliance function under the supervision of our Senior Vice President, General Counsel and Secretary. We have established an antibribery compliance committee and enhanced our antibribery compliance procedures. We also have developed in-person and online training programs to provide annual instruction on our Code of Business Conduct and Ethical Practices, the FCPA, antitrust law and other key policies as part of our commitment to educate our international workforce.
In 2006, we also (1) continued to enhance our training of management, including our operations managers, to emphasize further the importance of setting the proper tone within their organization to instill an attitude of integrity and control awareness and the use of a thorough and proper analysis of proposed transactions; (2) determined that our bonus-eligible employees complete in-person and online training on the FCPA and our Code of Business Conduct and Ethical Practices as a prerequisite to receiving their bonuses for 2006; (3) required our management, including our operations managers, to reconfirm that they are not aware of any violations of law and confirm with greater specificity that they are not aware of any improper payments to foreign government officials made by us or on our behalf or any other violation of our Code of Business Conduct and Ethical Practices and to recertify their commitment to the Code; (4) established an executive compliance committee, consisting of our executive officers and other management-level employees who are responsible for supervising our antibribery compliance committee, our internal controls steering committee and our compliance efforts in general; and (5) established a separate position of, and appointed, a chief compliance officer.
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.
For the years ended December 31, 2006, 2005 and 2004, our operations in Venezuela provided revenues of approximately $156.9 million, $172.6 million, and $167.1 million, or approximately 6.3%, 8.5% and 9.8% of our total consolidated revenues, respectively. Our Venezuela operations provided earnings (loss) from operations of approximately $6.9 million, $16.8 million, and $(6.7) million or approximately 1.3%, 5.2% and (2.7)% of our total consolidated earnings from operations for 2006, 2005 and 2004, respectively. As of December 31, 2006 and 2005, we had accounts receivable from Petróleos de Venezuela, S.A. totaling $27.6 million and $33.4 million, respectively.
Business Environment
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. Our land-based fleet generally competes on a regional basis. 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 and each contractor’s safety performance record and reputation for quality also can be key factors in the determination. Substantially 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 operating and maintenance expenses. Our customer bears the economic risk relative to the success of the wells.
The markets for our drilling, workover and related E&P services are highly cyclical. Our operating results are significantly impacted 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 and related 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, government regulations and many other factors. 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 and related services. Variations in market conditions during the cycle impact us in different ways depending primarily on the length of drilling contracts in different regions. Contracts in the U.S. Gulf of Mexico, for example, tend to be short-term, so a deterioration or improvement in market conditions tends to impact our operations quickly. Contracts in international offshore markets tend to be longer term due to rig availability, mobilization costs and technical requirements. Accordingly, short-term changes in market conditions in these markets may have little or no short-term impact on our revenues and cash flows from those operations unless the market changes occur during a period when we are attempting to renew a number of those contracts.
Our revenues depend principally upon the number of our available rigs, the number of days these rigs are utilized and the contract day rates received. The number of days our rigs are utilized and the contract day rates received are largely dependent upon the balance of supply and demand for drilling and related services in the different geographic regions in which we operate. The number of available rigs may increase or decrease as a result of the acquisition, relocation 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.
Changes in earnings from operations are primarily affected by revenues, cost of labor and utilization of our drilling fleet. For instance, if a rig is expected to be idle for an extended period of time, we may reduce the size of the rig’s crew and take steps to “cold stack” the rig, which reduces expenses and partially offsets the impact on operating income associated with the loss of revenues.
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.
Business Outlook
Expectations about future oil prices have historically been a key driver for drilling demand; however, the availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments also affect our customers’ drilling programs. We expect
global demand for contract drilling services to continue to increase, driven by increasing worldwide energy demand and demand for oil and natural gas and an increased focus by oil and natural gas companies on offshore prospects.
Our deepwater fleet, which consists of our drillships and our semisubmersibles operating in water depths greater than 4,500 feet, currently operates in West Africa, Brazil and Egypt, and is fully contracted through June 2009, with most of our fleet contracted into 2010. In November 2006, we were awarded five-year contract extensions beginning in 2008 for the Pride Brazil and Pride Carlos Walter and a three-year contract extension for the Pride North America, each at substantially higher dayrates. We have contracted the Pride South Pacific under a two-year contract at a dayrate three times the prior contract rate beginning in March 2007. The balance of our deepwater fleet is contracted through 2007 and our average dayrate is not expected to change materially, other than as a result of cost escalation protection, until contract rollovers occur. 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. We believe that favorable commodity 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 discoveries. In addition, we believe that the need for deepwater rigs will continue to grow for existing offshore development projects in West Africa, the Gulf of Mexico and Brazil.
Prospects for our midwater fleet, which consists of our semisubmersibles operating in water depths from 1,000 feet to 4,500 feet and which currently operates in West Africa, Brazil, the Mediterranean Sea and Mexico, continue to be robust with approximately 83% of our fleet contracted through the end of 2007. At present, increasing demand and limited availability of rigs continues to drive dayrates higher. Contracts for midwater rigs tend to be shorter in duration than deepwater rigs with one to three years as the typical length. We believe increasing demand, a limited ability to increase rig supply in the short term and excess demand for rigs will result in favorable market conditions through 2008. We contracted the Pride South America at a substantially higher dayrate for a five-year term that began in February 2007. The Pride South Seas and Pride South Atlantic will rollover to new contracts at higher dayrates in 2007. We expect our average dayrates for our midwater fleet to continue to improve due to repricing of our fleet in 2007 and 2008. During 2007, three of our rigs are scheduled to be out-of-service for scheduled regulatory inspection and maintenance.
We expect the outlook for the international jackup market to continue to remain strong due to the current jackup rig supply shortage. Demand for jackup rigs in international markets continues to be strong and average dayrates remain high with longer term contracts. However, we continue to monitor the potential effect of the addition of approximately 65 newbuild jackups to the global market, which have scheduled delivery dates from 2007 through 2010. The addition of rig capacity to the market could have an adverse impact on our utilization and dayrates, particularly in international markets. The dayrate environment in the U.S. Gulf of Mexico has been under pressure from lower demand and uncertain natural gas prices due to high storage levels. We anticipate that the market may strengthen in the second half of 2007 as several rigs owned by our competitors are expected to leave the Gulf of Mexico for international markets and the demand for additional rigs by PEMEX and other international clients is expected to increase. Improvement in dayrates in 2007 will largely depend upon natural gas prices and any impact of the 2007 hurricane season on our customers’ drilling programs. The Pride Tennessee completed its shipyard upgrade in February 2007 and is contracted through July 2009. We have 12 rigs currently scheduled for maintenance and upgrade projects in 2007, as compared to 10 rigs that were out of service for maintenance and upgrade projects in 2006. Following the completion of these projects, we expect the number of projects to decline significantly in 2008. The ability to complete the projects on a timely basis could have a significant impact on 2007 results.
We experienced high levels of activity for our Latin America Land and E&P Services operations, which resulted in higher pricing and utilization. The market outlook for Argentina and Colombia remains favorable as economic growth has stimulated demand for oil and natural gas. We currently believe that market conditions in Venezuela will permit us to recover the additional cost associated with recently enacted social programs and do not believe our operations will be materially impacted.
In October 2006, we experienced a two-day strike against our Latin America Land operation in northern Argentina, which temporarily idled approximately 70 of our rigs. During the fourth quarter 2006, our operations in
Argentina experienced additional work stoppages on both local and national levels organized by the unions in protest of various labor and tax laws. The issues were resolved with the unions in December 2006. We believe our relationships with the unions are good and we are not currently aware of any threatened or pending work stoppages. However, industry conditions and changes in the political environments in which we operate have, from time to time, resulted in work stoppages. Such work stoppages may occur in the future and may have a significant impact on our future operations or financial position.
We are actively pursuing options for maximizing the value of our Latin America Land and E&P Services operations. All options are being considered, including sales to strategic buyers and capital market alternatives. We may ultimately decide to pursue a course of action other than a disposition of these operations; however, if we do pursue a disposition, we may be unable to complete a transaction on terms we find acceptable or at all.
Increased activity in the oilfield services industry is increasing competition for experienced oilfield workers resulting in higher labor costs and training costs. The increased activity has also increased demand for oilfield equipment and spare parts and coupled with the consolidation of equipment suppliers, has resulted in longer order lead times to obtain critical spares and higher repair and maintenance costs and increased out-of-service time for repair and upgrade projects. A number of our rigs will be in the shipyard or undergoing repairs during 2007 and may be subject to repair delays. In addition, 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 underwriters have also imposed an aggregate limit of approximately $85.0 million for damage due to named wind storms in the U.S. Gulf of Mexico, with a $10.0 million deductible per named wind storm. However, due to higher dayrates, we expect our growth in revenues to continue to outpace our cost increases throughout 2007.
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.
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, workover and related service industries in which we operate are 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, 2006, 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 2020 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 2007 through 2016.
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 July 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 $41.3 million as of December 31, 2006, 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 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 and potential tax assessments (see “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
In September 2006, based upon changes within our management organization, we changed the composition of our segments to three principal reportable segments: Offshore, which comprises our offshore drilling activity, currently in Africa, the Mediterranean Sea, the Middle East, Southeast Asia, South America and the Gulf of Mexico; Latin America Land, which comprises our land-based drilling and workover services in Latin America, currently in Argentina, Venezuela, Colombia, Bolivia, and Mexico; and E&P Services, which includes exploration and production services in Latin America. “Other” includes revenues and cost for land-based drilling and workover operations outside of Latin America (currently Chad, Kazakhstan and Pakistan), labor contracts and engineering and management consulting services.
The following table presents selected consolidated financial information by reporting segment:
Offshore
We have provided below additional information based on the service capabilities of our offshore fleet. 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. As of February 28, 2007, our Offshore segment comprised two deepwater drillships, 12 semisubmersible rigs, 28 jackup rigs, 10 platform rigs, three tender-assisted rigs, three barge rigs, and
five deepwater rigs managed for other parties. The following table summarizes our revenue and earnings from operations by type of offshore rig in our fleet:
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.
(3)
Excludes rigs managed by us but owned by others.
Deepwater
Revenues increased $120.3 million, or 33%, for the year ended December 31, 2006 over the comparable period in 2005. The increase is 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 and $8.0 million related to the amortization of deferred contract liabilities for the Pride Portland and the Pride Rio de Janeiro, increased dayrates for the Pride North America, and contractual rate escalations. Average daily revenues for the year ended December 31, 2006 increased 8% over the comparable period in 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 $26.2 million, or 25%, for the year ended December 31, 2006 over the comparable period in 2005 due to an increase in revenues partially offset by charges in 2006 for settlement of agency relationships on four of the rigs. The Pride South Pacific, working offshore West Africa, is to begin a new contract at substantially higher rates following the completion of its current contract currently scheduled for April 2007. After completion of repairs to the subsea control system, the Pride North America began operating offshore Egypt in late April 2006 under a contract that expires in January 2008. In October 2006, the Pride North America sustained crane damage as a result of new equipment failure; repairs were completed during the fourth quarter of 2006. The Pride Carlos Walter was in the shipyard for its special periodic survey in the fourth quarter of 2006. In November 2006, the Pride Brazil and Pride Carlos Walter were awarded contract extensions beginning in mid-2008 through 2013 at dayrates approximately 80% higher than current rates.
Utilization remains high, as our deepwater fleet is fully contracted through June 2009. Much of our deepwater fleet is contracted until mid-2010; as a result, we would benefit from increasing dayrates for deepwater rigs only when our fleet is able to rollover to new contract terms.
Revenues increased $43.9 million, or 14%, for the year ended December 31, 2005 over the comparable period in 2004. The increase is due to $47.6 million of revenue from the Pride Portland and the Pride Rio de Janeiro, which commenced operations in April 2005 and October 2005, respectively. Revenues and utilization were impacted by special periodic surveys in 2005 for the Pride Angola and Pride South Pacific, lower dayrates for the Pride North America in 2005 and its mobilization in the fourth quarter of 2005. Average daily revenues for the year ended December 31, 2005 increased 7% over the comparable period in 2004 primarily due to contracted dayrate increases for the Pride South Pacific. Earnings from operations decreased $16.4 million, or 14%, for the year ended December 31, 2005 over the comparable period in 2004 due to lower revenues for the Pride North America and a 9% increase in year-over-year operating costs.
Midwater
Revenues increased $28.3 million, or 18%, for the year ended December 31, 2006 over the comparable period in 2005. The increase is due to higher dayrates for several rigs partially offset by a 4% decline in actual days worked. Average daily revenue for the year ended December 31, 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 increased $20.4 million, or 210%, for the year ended December 31, 2006 over the comparable period in 2005 primarily due to higher dayrates and lower mobilization and repairs and maintenance costs for the Pride Venezuela. The Pride South America began working under a new contract in February 2007 at substantially higher dayrates. The Pride South Seas, which was operating offshore South Africa under a contract that expired in February 2007, is being mobilized to Namibia for work under a contract with an initial term expiring in July 2007 at substantially increased dayrates. After completion of its special periodic survey, the Pride North Sea began working in April 2006 on a series of contracts, with options, in the Mediterranean Sea, which are expected to be completed by mid-to-late 2007. The Pride Venezuela completed its special periodic survey and upgrades in September 2006 and was mobilized to West Africa for an 18-month contract, with a six month option, at substantially higher dayrates. The Pride South Atlantic completed its life enhancement project and is working through February 2008 under contracts with various customers at substantially higher dayrates than in 2005.
Revenues increased $28.7 million, or 23%, for the year ended December 31, 2005 over the comparable period in 2004. The increase is due primarily to increased utilization of the Pride Venezuela partially offset by a decrease in utilization of the Pride South Seas. Average daily revenues for the year ended December 31, 2005 increased 14% over the comparable period in 2004 primarily due to the contracted dayrate increases for the Pride South Seas and Pride South Atlantic. Earnings from operations increased $2.9 million, or 43%, for the year ended December 31, 2005 over the comparable period in 2004 due to higher average daily revenues and utilization.
Jackups
Revenues increased $233.6 million, or 52%, for the year ended December 31, 2006 over the comparable period in 2005. The increase is due to higher dayrates partially offset by a decline in utilization. Average daily revenue for our jackup fleet for year ended December 31, 2006 increased 70% over 2005. Earnings from operations increased $184.4 million, or 123%, for the year ended December 31, 2006 over the comparable period in 2005 due to the increase in average daily revenue. Our jackup fleet has benefited from escalating dayrates due to strong worldwide drilling demand. Contracts for our U.S. Gulf of Mexico fleet tend to be for shorter periods as compared to international jackup contracts and, in certain cases, are indexed to market. The Pride Hawaii began working under a contract with significantly higher dayrates in November 2006. After completing contracts in Southeast Asia that expired in January 2007 and its special periodic survey, the rig is to be mobilized to India to operate under a contract that expires in April 2010. The Pride California and Pride Nevada completed their life enhancement projects and began working under contracts in September 2006 and October 2006, respectively, at substantially higher rates. In November 2006, the Pride Oklahoma completed its life enhancement project and commenced a two well contract with an option for an additional well. The Pride Arkansas completed its maintenance projects and began a two-year contract with a dayrate similar to its previous contract. The Pride New Mexico entered the shipyard near the end of
the third quarter, is currently undergoing survey and assessment and is expected to remain in the shipyard until the second quarter of 2007. A total of 12 jackups are scheduled for planned maintenance and regulatory inspection projects in 2007.
Revenues increased $49.1 million, or 12%, for the year ended December 31, 2005 over the comparable period in 2004. The increase is due primarily to increased dayrates and utilization for our fleet in the U.S. Gulf of Mexico, partially offset by the loss of revenues from rigs sold in 2004 and 2005, principally the Pride West Virginia and Pride Ohio. Average daily revenues for the year ended December 31, 2005 increased 16% over the comparable period in 2004 due to contracted dayrate increases in the U.S. Gulf of Mexico fleet and the Pride California and Pride Texas in Mexico; international fleet dayrates remained flat. Earnings from operations increased $5.2 million, or 4%, for the year ended December 31, 2005 over the comparable period in 2004 primarily due to higher average daily revenues and utilization for the U.S. Gulf of Mexico fleet partially offset by the loss of earnings from rigs sold in 2005 and 2004.
Other Offshore
Revenues decreased $48.3 million, or 16%, for the year ended December 31, 2006 over the comparable period in 2005. Revenues decreased due to the termination of management agreements for GP19 and GP20 in 2006 and the sale of two tender barges in 2005. Average daily revenue for our tender-assisted barges and other offshore assets for the year ended December 31, 2006 increased 5% over 2005. The increase in average daily revenue is primarily due to the contracting of the Barracuda. Earnings from operations decreased $22.9 million, or 68%, due to the sale of the tender barges in 2005 and lower utilization of the Bintang Kalimantan. The Alligator, Pride Ivory Coast and Barracuda are currently working in West Africa under contracts that expire in June 2007, August 2007 and December 2007, respectively. The Bintang Kalimantan completed its contract in March 2006 and is currently stacked. The Pride I and Pride II lake barges in Venezuela are operating on a well-to-well basis. Platform rigs 1002E, 1003E and 1005E are operating in Mexico under contracts that expire in mid-2007. Two of our platform rigs are working in the U.S. Gulf of Mexico under short-term or well-to-well contracts. We also provide drilling management services for five deepwater platform drilling rigs, consisting of two tension leg platforms, two spar units and a semisubmersible rig, under management contracts that expire from 2008 to 2010.
Revenues increased $65.1 million, or 28%, for the year ended December 31, 2005 over the comparable period in 2004. The increase is due primarily to $47.8 million in increased revenues from (1) additional management contract revenues, including the Kizomba B contract commencing in 2005, the Holstein and Mad Dog contracts commencing in 2004 and the Thunderhorse contract commencing in 2005, and (2) higher utilization of the Pride Ivory Coast, which was idle in 2004. Average daily revenues for the year ended December 31, 2005 increased 24% over the comparable period in 2004 primarily due to the 2005 sales of the tender barges, which had lower than average dayrates. Earnings from operations increased $12.7 million, or 61%, for the year ended December 31, 2005 over the comparable period in 2004 due to earnings from the new management contracts, a $3.8 million gain on asset sales in 2005 and a $3.5 million impairment charge in 2004.
Latin America Land
As of February 28, 2007, our Latin America Land segment comprised 206 land drilling and workover rigs, of which 94% were contracted. The following table summarizes our average daily revenues and the number of days worked by type rig in our Latin America Land 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.
(2)
Days worked is calculated as the total days worked by all rigs of each type during the period.
Revenues increased $113.1 million, or 23%, for the year ended December 31, 2006 over the comparable period in 2005. Average daily revenues for our Latin America Land drilling fleet for the year ended December 31, 2006 increased by approximately 21% over 2005. The increase in revenues and average daily revenues is due to strong dayrate increases in Argentina, Colombia and Venezuela and the disposition of the drilling rigs in Brazil in March 2006, which operated at substantially lower daily rates. The average daily revenue for the 2006 period was negatively impacted by three of our drilling rigs in Bolivia being idled following the government’s decision to nationalize the country’s oil and natural gas reserves. We currently anticipate that these rigs will return to work by the end of the first quarter of 2007. In September 2006, we completed the mobilization of a land rig in Kazakhstan to Colombia, where it began a three-year contract in the fourth quarter 2006. The contract is at a rate substantially above our current average daily rate in Latin America, and we recovered the costs of mobilizing the rig in a lump-sum payment from our customer. Average daily revenue for our Latin America Land workover fleet for the year ended December 31, 2006 increased by approximately 24% over 2005. The increase is due to strong daily rate increases in Argentina and Colombia with moderate daily rate increases in Venezuela. The number of days worked and the average daily revenue fluctuate for the workover rigs from period to period based on the location and nature of the wells being worked.
Earnings from operations for our Latin America Land segment increased $47.8 million, or 73%, for the year ended December 31, 2006 over the comparable period in 2005 primarily due to higher dayrates earned in Argentina and Colombia partially offset by higher operating costs in Venezuela.
Revenues increased $105.4 million, or 27%, for the year ended December 31, 2005 over the comparable period in 2004. Average daily revenues for our Latin America Land drilling fleet for the year ended December 31, 2005 increased by approximately 27% over 2004. The increase in revenues is due to increased utilization in Colombia and an increase in dayrates in Argentina, which resulted in higher average daily revenues. Average daily revenue for our Latin America Land workover fleet for the year ended December 31, 2005 increased by approximately 14% over 2004. The increase is due to higher dayrates in Argentina and Colombia. The decline in days worked from 2004 to 2005 is attributable to lower utilization in Venezuela partially offset by higher utilization in Colombia.
Earnings from operations for our Latin America Land segment increased $59.3 million for the year ended December 31, 2005 from $5.8 million over the comparable period in 2004 primarily due to higher dayrates earned in Argentina and an overall increase in business activity in Colombia. In addition, we recorded a $16.8 million charge in 2004 for the impairment of certain rigs and equipment.
E&P Services
We currently provide E&P services in Argentina, Bolivia, Brazil, Ecuador, Peru and Venezuela, consisting primarily of pressure pumping services, integrated services and other exploration and production services.
Revenue of our E&P Services segment for the year ended December 31, 2006 increased $7.5 million, or 4%, over 2005 primarily due to increased revenue from pressure pumping and integrated services in Argentina and directional drilling in Brazil partially offset by downtime resulting from mobilizing equipment between markets. In the first quarter 2006, we moved our E&P Services equipment located in Colombia to Venezuela and Argentina to concentrate on areas with higher margin business. Earnings from operations increased $6.2 million, or 30%, for the year ended December 31, 2006 over the comparable period in 2005 primarily due to increased revenues in Argentina.
Revenue of our E&P Services segment for the year ended December 31, 2005 increased $32.8 million, or 21%, over 2004 primarily due to increased revenue from pressure pumping and integrated services in Argentina and directional drilling in Brazil. Earnings from operations increased $5.7 million, or 38%, for the year ended December 31, 2005 over the comparable period in 2004 primarily due to increased revenues in Argentina and Brazil.
Discontinued Operations
The operations of the Technical Services group were concentrated on completing the final of four rigs pursuant to fixed-fee contracts to design, engineer, manage construction of and commission specialized drilling rigs for two
of our significant customers. The first rig was completed and delivered in 2003, and the other three rigs were completed and delivered in 2004.
We experienced significant cost overruns on these projects, and the total costs on each of the four projects substantially exceeded contract revenues. We 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 in our results of operations. See Note 12 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. Except to the extent that differences between operating segments are material to an understanding of our business taken as a whole, the discussion below is based on our consolidated financial results.
The following table presents selected consolidated financial information:
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Revenues. Revenues for 2006 increased $462.1 million, or 22.7%, compared with 2005. Offshore revenues increased $333.9 million due to overall higher average daily revenues, particularly with respect to our U.S. Gulf of Mexico jackup fleet, higher dayrates for the Pride North America and $49.7 million of additional revenues from the Pride Portland and the Pride Rio de Janeiro, which commenced operations during the third and second quarter of 2005, respectively. Latin America Land revenues increased $113.1 million primarily due to price increases for drilling and workover services in Argentina and Colombia.
Operating Costs. Operating costs for 2006 increased $190.9 million, or 13.8%, compared with 2005, of which $49.0 million is due to the operations of the Pride Portland and the Pride Rio de Janeiro. Offshore operating costs in 2006 include $15.0 million related to termination of our agency agreement 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 63.3% and 68.3% 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 $12.7 million, or 4.9%, compared with 2005 primarily due increased capital expenditures in 2006.
General and Administrative. General and administrative expenses for 2006 increased $31.2 million, or 31.9%, compared with 2005 primarily due to $20.0 million of expenses related to the ongoing investigation described under “- FCPA Investigation” above, an increase of $13.8 million in compensation costs due to increased corporate staffing and stock compensation, and approximately $2.7 million of corporate initiatives related to our Latin America Land and E&P Services businesses. 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 $31.4 million in 2006 primarily due to the sale of the Pride Rotterdam, resulting in a gain of $25.3 million, and the sale of four land rigs. We had net gains on sales of assets of $36.1 million in 2005 primarily due to the sale of one jackup rig, two tender-assisted barge rigs and six land rigs.
Interest Expense. Interest expense for 2006 decreased by $9.7 million, or 11.0%, 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 21/2% convertible senior notes during 2005 described under “- Liquidity and Capital Resources” below. 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.
Other Income, Net. Other income, net for 2006 decreased from $9.5 million for 2005 to $4.5 million for 2006. The decrease was primarily due to a $5.3 million decrease in mark-to-market gains and cash settlements on interest rate swap and cap agreements.
Income Taxes. Our consolidated effective tax rate for 2006 was 37.1% as compared with 40.5% for 2005. The lower rate in 2006 was due to higher profitability in jurisdictions with statutory rates lower than the United States.
Minority Interest. Minority interest in 2006 decreased $15.6 million, or 79.2%, 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.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Revenues. Revenues for 2005 increased $321.1 million, or 18.8%, compared with 2004. Our significant operating segments experienced increased revenues as demand for drilling and related services continued to increase. The commencement of the Pride Portland and the Pride Rio de Janeiro in 2005 resulted in $47.6 million of additional revenues as compared to 2004. Our jackup fleet in the U.S. Gulf of Mexico continued to improve its revenues due to higher revenues from managed rigs and improved dayrates and utilization. Revenues from our Latin America Land segment increased due to stronger demand and higher utilization and increased pricing. Revenues increased in our E&P segment due to increased activity in Mexico, Brazil and Venezuela and a higher level of integrated services work in Argentina and Brazil.
Operating Costs. Operating costs for 2005 increased $241.5 million, or 21.1% compared with 2004, primarily due to increased utilization in our Latin America Land segment driven by stronger demand and increased activity in our E&P services segment. Higher labor costs for oilfield personnel also contributed to the increase in operating costs, as the competition for experienced oilfield workers continued to drive up wages and salaries. Operating costs as a percentage of revenues were 68.3% and 67.0% for 2005 and 2004, respectively. This increase results primarily from an increase in the amount of operations performed on managed rigs, as these contracts typically have lower operating margins.
Operating costs for the offshore fleet increased primarily due to increased utilization of the semisubmersible fleet and increased costs from managed platform rigs, including the Pride Portland and the Pride Rio de Janeiro,
which commenced operations in 2005. Operating costs for our jackup fleet increased primarily due to higher levels of activity.
Depreciation and Amortization. Depreciation and amortization expense for 2005 decreased $8.1 million, or 3.1%, compared with 2004 primarily due a decrease in the number of rigs we own. During 2005, we sold a jackup rig, two tender-assisted barge rigs and six land rigs.
General and Administrative. General and administrative expenses for 2005 increased $22.9 million, or 30.6%, compared with 2004. The increase was primarily due to charges of $10.8 million related to severance in connection with the termination of the employment of various key employees and the retirement of a director, increased audit and professional fees and increased compensation costs due to increased staffing.
Gain on Sale of Assets, Net. We had net gains on sales of assets of $36.1 million in 2005 primarily due to the sale of one jackup rig, two tender-assisted barge rigs and six land rigs. We had net gains on sales of assets of $48.6 million in 2004 primarily due to the sale of three jackup rigs.
Interest Expense. Interest expense for 2005 decreased by $15.2 million, or 14.7%, compared with 2004 primarily due to lower total debt levels resulting from the repayment of debt during 2004 and 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.
Other Income, Net. Other income, net for 2005 increased by $9.0 million from $0.5 million for 2004 to $9.5 million for 2005. The increase was primarily due to a $1.2 million increase in net foreign exchange gains in 2005 compared with 2004, a $4.5 million increase in mark-to-market gains and cash settlements on interest rate swap and cap agreements and a $3.3 million increase in other income.
Income Taxes. Our consolidated effective tax rate for 2005 was 40.5% as compared with 54.3% for 2004. The lower rate in 2005 compared with 2004 was primarily due to debt refinancing charges in 2004 that reduced income without a proportional reduction to income taxes, and an increase in 2005 taxable income in foreign jurisdictions with low or zero effective tax rates. These reductions were partially offset by an increase in 2005 taxable income in high effective tax rate countries, and an increase in U.S. tax on certain foreign earnings.
Minority Interest. Minority interest in 2005 decreased $4.8 million, or 19.6%, compared with 2004 primarily due to lower income from our joint venture that owns the Pride Angola due to it being out of service for approximately 45 days to undergo its special periodic survey and increased interest expense on the joint venture’s debt which was refinanced and increased in 2004, partially offset by an increase in minority interest related to the mark-to-market gains on interest rate swap and cap agreements.
Liquidity and Capital Resources
Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During 2006, cash flows from operations, borrowings under our senior secured revolving credit facility and proceeds from asset sales and stock option exercises were the principal sources of funding. We anticipate that cash on hand and cash flows from operations will be adequate to fund normal ongoing capital expenditures, working capital needs and debt service requirements in 2007. 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.
Our capital allocation process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. In 2006, we used cash for a variety of activities including working capital needs, repayment of indebtedness and purchases of property and equipment.
Sources and Uses of Cash - 2006 Compared with
Cash and cash equivalents, including restricted cash, totaled $65.9 million at December 31, 2006 compared with $46.9 million at December 31, 2005. For 2006, net cash provided by operating activities was $611.7 million as compared with $321.9 million for 2005. The increase in net cash provided from operations was primarily due to the increase in net income.
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. 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.
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.
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.
Debt, including current maturities, totaled $1,386.6 million at December 31, 2006 compared with $1,244.8 million at December 31, 2005.
Sources and Uses of Cash - 2005 Compared with
Cash and cash equivalents, including restricted cash, totaled $46.9 million at December 31, 2005 compared with $47.0 million at December 31, 2004. For 2005, net cash provided by operating activities was $321.9 million as compared with $337.1 million for 2004. The decrease in net cash provided from operations was primarily due to an $83.3 million increase in working capital, primarily driven by an increase in accounts receivable, partially offset by an increase in net income.
Purchases of property and equipment totaled $157.2 million and $136.7 million for 2005 and 2004, respectively. The majority of these expenditures related to capital expenditures incurred in connection with new contracts and other sustaining capital projects. In 2004, we purchased the Pride Ivory Coast tender-assisted drilling rig for $16.0 million.
Proceeds from dispositions of property and equipment were $121.2 million and $73.5 million for 2005 and 2004, respectively. Included in the proceeds for 2005 was $114.5 million related to the sale of one jackup rig, two tender-assisted rigs and six land rigs. Included in the proceeds for 2004 was $71.0 million related to the sale of three jackup rigs.
As described above, in December 2005, we acquired an additional 40% interest in our Angolan joint venture companies for $170.9 million and paid $4.5 million for termination of certain agreements related to the operation of the joint venture.
We received proceeds of $124.9 million and $1.5 million from the issuance of common stock in 2005 and 2004, respectively. We also received proceeds of $91.2 million and $10.1 million from the exercise of stock options in 2005 and 2004, respectively.
Debt, including current maturities, totaled $1,244.8 million at December 31, 2005 compared with $1,725.2 million at December 31, 2004. During 2005, we engaged in the following financing transactions:
•
The holders of our 21/2% Convertible Senior Notes due 2007 converted substantially all of the $300.0 million outstanding principal amount of the notes into approximately 18.2 million shares of our common stock. We redeemed the remaining principal amount of the notes for cash.
•
We completed the repayment of 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.
Working Capital
As of December 31, 2006, we had working capital of $293.1 million compared with $213.8 million as of December 31, 2005. These amounts included an aggregate of short-term borrowings and current portion of long-term debt of $91.9 million and $59.7 million, an aggregate of cash and cash equivalents and restricted cash of $65.9 million and $46.9 million, accounts receivable, net of $505.0 million and $435.5 million and accounts payable of $189.9 million and $159.8 million. The increase in working capital was attributable primarily to the increase in current deferred income taxes relating to reclassification due to our ability to utilize our NOL carryforwards in 2007 and the increase in accounts receivable due to higher dayrates, partially offset by increases in accrued expenses due to the deferred contract liabilities from our joint venture acquisition and increases in accounts payable and accrued expenses due to increased business activity.
Credit Ratings
Our 73/8% Senior Notes due 2014 are rated Ba2 by Moody’s Investor Service, Inc., BB- by both Standard & Poor’s Rating Services and BB by Fitch Ratings. Moody’s, S&P’s and Fitch’s ratings outlooks are stable.
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, 2006, there were $50.0 million of borrowings and $19.2 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 prime rate plus a margin. The interest rate margin varies based on our leverage ratio. As of December 31, 2006, the interest rate on the facility was approximately 5.9% and availability was approximately $430.8 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. We generally 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; distributions, dividends and repurchases of capital stock and other equity interests; acquisitions and investments; asset sales; capital expenditures; 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, 2006, we had $500.0 million principal amount of 73/8% Senior Notes due 2014 outstanding. The notes provide for semiannual interest payments and 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.
As of December 31, 2006, we had $300.0 million principal amount of 31/4% Convertible Senior Notes due 2033 outstanding. The notes 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. 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 common stock, cash or a combination of cash and common stock.
As of December 31, 2006, we had $190.5 million principal amount outstanding under our drillship loan facility due in 2010. Our drillship loan facility is collateralized by the two drillships, 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 is non-recourse to us and the joint owner. The drillship loan bears interest at LIBOR plus 1.50%. As a condition of the loan, we maintain interest rate swap and cap agreements with the lenders. In accordance with the debt agreements, certain cash balances are held in trust to assure that timely interest and principal payments are made. As of December 31, 2006 and 2005, $1.8 million of such cash balances, which amount is included in restricted cash, was held in trust and is not available for our use.
In February 1999, we completed the sale and leaseback of the Pride South America semisubmersible drilling rig with an unaffiliated leasing trust pursuant to which we received $97.0 million. We consolidate the leasing trust’s assets and liabilities, which comprise the Pride South America rig and the associated note payable. As of December 31, 2006 and 2005, the carrying amount of the note payable was approximately $64.2 million and $72.3 million, respectively. The note payable is collateralized by the Pride South America. The note payable bears interest at 9.35% and requires quarterly interest payments. In February 2007, we notified the note holders that we will exercise our right to prepay the semisubmersible loan in August 2007.
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. This transaction resulted in the addition of approximately $284 million of debt, net of fair value discount, (representing 100% of the joint venture entity’s debt) to our consolidated balance sheet. The notes representing the debt were used by the joint venture entity to finance a portion of the cost of construction of these rigs. 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.
Other Sources and Uses of Cash
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 expect our purchases of property and equipment for 2007 to be approximately $400 million. These purchases are expected to be used primarily for various rig upgrades in connection with new contracts as contracts expire during the year and other sustaining capital projects.
We anticipate making income tax payments of approximately $145 million to $165 million in 2007.
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. We are actively pursuing options for maximizing the value of our Latin America Land and E&P Services operations. All options are being considered, including sales to strategic buyers and capital market alternatives. We may ultimately decide to pursue a course of action other than a disposition of these operations; however, if we do pursue a disposition, we may be unable to complete a transaction on terms we find acceptable or at all.
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.
Contractual Obligations
In the table below, we set forth our contractual obligations as of December 31, 2006. 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 the expected cash payments for interest on our long-term debt based on the interest rates in place and amounts outstanding at December 31, 2006.
(3)
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.
(4)
Amounts include committed purchase obligations for major maintenance and upgrade projects and contracts for software maintenance fees.
(5)
Amounts represent other long-term liabilities, including the current portion, related to severance and termination benefits and capital leases.
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 which totaled approximately $223.0 million at December 31, 2006. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions and are not normally called as we typically comply with the underlying performance requirement.
New Accounting Pronouncements
In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 (FIN 48). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 will require companies to determine whether it is more-likely-than-not that a tax position taken or expected to be taken in a tax return will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. FIN 48 also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We adopted FIN 48 on January 1, 2007. We are currently evaluating the potential impact, if any, to our consolidated financial statements. We anticipate that the adoption of FIN 48 could introduce additional volatility into our effective income tax rate in future periods.
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 standard 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 standard requires (or permits) assets or liabilities to be measured at fair value. The standard 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. We are currently evaluating the potential impact, if any, to our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement requires employers to recognize on their balance sheets the obligations associated with single-employer defined benefit pension, retiree healthcare, and other postretirement plans. SFAS No. 158 amends SFAS No. 87, Employers’ Accounting for Pensions, SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, and SFAS No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits, and will require employers to recognize on their balance sheets the funded status of pension and postretirement benefit plans and will require fiscal year end measurements of plan assets and benefit obligations. SFAS No. 158 will not impact most of the measurement and disclosure guidance nor will it change the amounts recognized in the income statement as net periodic benefit cost. As of December 31, 2006, we adopted the recognition of the funded status of plans subject to SFAS No. 158 (see
Note 11 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report). The requirement to measure plan assets and benefit as of fiscal year end is effective for fiscal years ending after December 15, 2008.
In June 2006, the FASB ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on 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 addresses disclosure requirements 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. EITF Issue No. 06-3 concludes that the presentation of taxes on either a gross basis (included in revenues and costs) or a net basis (excluded from revenues) is an accounting policy decision that should be disclosed. In addition, for any such taxes that are reported on a gross basis, a company should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The provisions of EITF Issue No. 06-3 should be applied to financial reports for interim and annual reporting periods beginning after December 15, 2006, with earlier adoption permitted. We adopted EITF Issue No. 06-3 effective January 1, 2007. We are currently evaluating the impact of adopting EITF Issue No. 06-3 but do not expect its adoption to have a significant impact on our results of operations and financial condition.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 requires a registrant to quantify the impact of correcting all misstatements on its current year financial statements using two approaches, the rollover and iron curtain approaches. A registrant is required to adjust its current year financial statements if either approach to accumulate and identify misstatements results in quantifying a misstatement that is material, after considering all relevant quantitative and qualitative factors. SAB 108 is required to be considered for financial statements for fiscal years ending after November 15, 2006. The adoption of SAB 108 had no impact on our consolidated results of operations, financial position or cash flows.
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. We are currently evaluating whether to elect the option provided for in this standard. If elected, SFAS No. 159 would be effective for us as of January 1, 2008. We are currently evaluating the potential impact, if any, to our consolidated financial statements.
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 and future utilization rates and contract rates for rigs;
•
future capital expenditures and investments in the construction, acquisition and refurbishment of rigs (including the amount and nature thereof and the timing of completion thereof);
•
future asset sales and repayment of debt;
•
potential sales of, or other capital market alternatives regarding, our Latin America Land and E&P Services segments;
•
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 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 “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;
•
cost overruns related to our turnkey contracts;
•
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;
•
the limited number of strategic buyers available for our Latin America Land and E&P Services segments;
•
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, 2006 and 2005 was $1,486.8 million and $1,397.1 million, respectively, which was more than its carrying value as of December 31, 2006 and 2005 of $1,386.6 million and $1,244.8 million, respectively. A hypothetical 100 basis point decrease in interest rates relative to market interest rates at December 31, 2006 would increase the fair market value of our long-term debt at December 31, 2006 by approximately $33.9 million.
As of December 31, 2006, 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, 2006, the fair value of the interest rate swap and cap agreements was an asset of $4.0 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 2006 and 2005, but 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, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2006. 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, 2006 and 2005, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in note 1 to the financial statements, 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), the effectiveness of Pride International, Inc.’s internal control over financial reporting as of December 31, 2006, 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, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 28, 2007
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Pride International, Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting for the year ended December 31, 2006, that Pride International, Inc. maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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, management’s assessment that Pride International, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control - Integrated Framework issued by COSO. Also, in our opinion, Pride International, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2006, and our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 28, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Pride International, Inc:
In our opinion, the consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2004 present fairly, in all material respects, the results of operations and cash flows of Pride International, Inc. and its subsidiaries (“the Company”) for the year ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 25, 2005, except for the restatement discussed in the third and fourth paragraphs of Note 2 to the consolidated financial statements included in the 2004 Form 10-K/A (not presented herein) as to which the date is January 24, 2006, and except for the realignment of the Company’s reportable segments described in the fifth paragraph of Note 1 to the consolidated financial statements as to which the date is March 1, 2007.
Pride International, Inc.
Consolidated Balance Sheets
The accompanying notes are an integral part of the consolidated financial statements.
Pride International, Inc.
Consolidated Statements of Operations
The accompanying notes are an integral part of the consolidated financial statements.
Pride International, Inc.
Consolidated Statements of Stockholders’ Equity
The accompanying notes are an integral part of the consolidated financial statements.
Pride International, Inc.
Consolidated Statements of Cash Flows
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 and related services, operating both offshore and on land. We provide contract drilling services to oil and natural gas exploration and production companies through the operation and management of 63 mobile offshore rigs and 214 land-based drilling and workover rigs.
Basis of Presentation
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.
In accordance with Financial Accounting Standards Board Interpretation (“FIN”) No. 46R, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (revised December 2003), we are the primary beneficiary of the unaffiliated trust with which we completed the sale and leaseback of the Pride South America semisubmersible drilling rig in February 1999. Accordingly, the assets and liabilities and revenues and expenses of the trust have been included in the accompanying consolidated financial statements.
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
In September 2006, we reorganized our operations into three principal reportable segments: Offshore, Latin America Land, and E&P Services. The realignment of our reportable segments was attributable to recent organizational changes, including the hiring of a Chief Operating Officer responsible for all of our offshore drilling fleet. Our Offshore segment includes all of our offshore drilling fleet and operations. Our Latin America Land segment includes our all of our land-based drilling and workover services in Latin America. Our E&P Services segment includes our exploration and production services business in Latin America. “Other” includes revenues and cost for land-based drilling and workover operations outside of Latin America (currently Chad, Kazakhstan and Pakistan), labor contracts and engineering and management consulting services. All prior period information has been reclassified to conform to the current period presentation. See Note 14.
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.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
Dollar Amounts
All dollar amounts (except per unit amounts) presented in the tabulations within the notes to our financial statements are stated in million 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.
Rig Construction Contracts
We have historically constructed drilling rigs only for our own use. However, in 2001, at the request of some of our significant customers, we entered into fixed-fee contracts to design, construct and mobilize specialized drilling rigs through our technical services group. We also entered into separate contracts to operate the rigs on behalf of the customers. Construction contract revenues and related costs were recognized under the percentage-of-completion method of accounting using measurements of progress toward completion appropriate for the work performed, such as man hours, costs incurred or physical progress. Accordingly, we reviewed contract price and cost estimates periodically as the work progressed and reflected adjustments in income to recognize income proportionate to the percentage of completion in the case of projects showing an estimated profit at completion and to recognize the entire amount of the loss in the case of projects showing an estimated loss at completion. To the extent these adjustments resulted in an increase in previously reported losses or a reduction in or an elimination of previously reported profits with respect to a project, we recognized a charge against current earnings. We have discontinued our fixed-fee rig construction business. See Note 12.
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.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
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:
Rigs and rig equipment have salvage values not exceeding 20% of the cost of the rig or rig equipment.
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 2006, we recognized an impairment charge of $3.9 million related to two platform rigs and three land workover rigs. In 2005, we recognized an impairment charge of $1.0 million related to damage a platform rig sustained in 2004. In 2004, we recognized an impairment charge of $24.9 million related to retiring 16 stacked land rigs and nine shallow water platform rigs and a loss on impairment of an inactive land rig and other equipment.
Investments and Advances to Affiliates
We periodically assess the recoverability of our investments in affiliates. If an identified event or change in circumstances requires an impairment evaluation, we assess fair value based on valuation methods as appropriate, including discounted cash flows, estimates of sales proceeds and external appraisals, as appropriate.
Goodwill
Goodwill is not amortized. All goodwill is assigned to reporting units, which we have determined are the same as our reporting segments. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, we perform an annual impairment test of goodwill in each of our reporting units as of December 31, or more frequently if circumstances indicate that impairment may exist. Such tests include comparing the fair value of a reporting unit with its carrying value, including goodwill. Impairment assessments are performed using a variety of methodologies, including cash flows analysis and estimates of market value. There were no impairments in 2006, 2005 or 2004 at our reporting units related to the annual impairment test.
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 $22.1 million, $17.2 million and $17.4 million during 2006, 2005 and 2004, respectively, in obtaining and maintaining such certifications. As of December 31, 2006 and 2005, the deferred and unamortized portion of such costs on our balance sheet was $43.8 million and $40.0 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.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
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, 2006, 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 Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). 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
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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. See Note 10 for the impact of the adoption of SFAS No. 123(R).
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 we used in 2005. As a result, expected volatility for the year ended December 31, 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.
New Accounting Pronouncements
In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 (FIN 48). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 will require companies to determine whether it is more-likely-than-not that a tax position taken or expected to be taken in a tax return will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. FIN 48 also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We adopted FIN 48 on January 1, 2007. We are currently evaluating the potential impact, if any, to our consolidated financial statements. We anticipate that the adoption of FIN 48 could introduce additional volatility into our effective income tax rate in future periods.
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 standard 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 standard requires (or permits) assets or liabilities to be measured at fair value. The standard 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. We are currently evaluating the potential impact, if any, to our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement requires employers to recognize on their balance sheets the obligations
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associated with single-employer defined benefit pension, retiree healthcare, and other postretirement plans. SFAS No. 158 amends SFAS No. 87, Employers’ Accounting for Pensions, SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, and SFAS No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits, and will require employers to recognize on their balance sheets the funded status of pension and postretirement benefit plans and will require fiscal year end measurements of plan assets and benefit obligations. SFAS No. 158 will not impact most of the measurement and disclosure guidance nor will it change the amounts recognized in the income statement as net periodic benefit cost. As of December 31, 2006, we adopted the recognition of the funded status of plans subject to SFAS No. 158 (see Note 11). The requirement to measure plan assets and benefit as of fiscal year end is effective for fiscal years ending after December 15, 2008.
In June 2006, the FASB ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on 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 addresses disclosure requirements 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. EITF Issue No. 06-3 concludes that the presentation of taxes on either a gross basis (included in revenues and costs) or a net basis (excluded from revenues) is an accounting policy decision that should be disclosed. In addition, for any such taxes that are reported on a gross basis, a company should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The provisions of EITF Issue No. 06-3 should be applied to financial reports for interim and annual reporting periods beginning after December 15, 2006, with earlier adoption permitted. We adopted EITF Issue No. 06-3 effective January 1, 2007. We are currently evaluating the impact of adopting EITF Issue No. 06-3 but do not expect its adoption to have a significant impact on our results of operations and financial condition.
In September 2006, the United States Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 requires a registrant to quantify the impact of correcting all misstatements on its current year financial statements using two approaches, the rollover and iron curtain approaches. A registrant is required to adjust its current year financial statements if either approach to accumulate and identify misstatements results in quantifying a misstatement that is material, after considering all relevant quantitative and qualitative factors. SAB 108 is required to be considered for financial statements for fiscal years ending after November 15, 2006. The adoption of SAB 108 had no impact on our consolidated results of operations, financial position or cash flows.
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. We are currently evaluating whether to elect the option provided for in this standard. If elected, SFAS No. 159 would be effective for us as of January 1, 2008. We are currently evaluating the potential impact, if any, to our consolidated financial statements.
Reclassifications
Certain reclassifications have been made to the prior years’ consolidated financial statements to conform with the current year presentation.
NOTE 2.
ACQUISITIONS
In December 2005, we acquired an additional 40% interest in the joint venture companies that manage our Angolan operations from our partner Sonangol, the national oil company of Angola, for $170.9 million in cash,
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bringing our total ownership interest to 91%. Prior to the acquisition, we owned a 51% interest in the joint venture companies and fully consolidated the balance sheet and results of operations of the joint venture companies, with a provision for the minority interest for the 49% owned by Sonangol. The principal assets of the joint venture companies 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. In addition, we paid $4.5 million to an affiliate of Sonangol for termination of certain agreements related to the operation of the joint venture.
The purchase price was allocated based on the fair value of the assets acquired and liabilities assumed. As the acquisition cost was less than the fair value of the assets acquired and liabilities assumed, we recorded no goodwill related to the acquisition. We recorded $3.6 million as a contract-based intangible asset related to the management agreements for the Kizomba A and Kizomba B. This intangible asset will be amortized over the lives of the contracts. Additionally, as the current operating contracts for the Pride Africa and Pride Angola were unfavorable compared with current market rates, we recorded a deferred contract liability of $18.7 million which will be amortized to revenues over the remaining lives of the contracts. We increased the carrying values of the drillships and the jackup rig by $77.4 million to the fair values and we decreased our minority interest in the joint venture companies by $108.6 million.
In November 2006, we acquired from our joint venture partner its 70% interest in a joint venture company the principal assets of which are 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 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 to assets acquired and liabilities assumed based upon preliminary fair values is as follows:
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In a related transaction, we cancelled future obligations under certain existing agency relationships related to five offshore rigs we operates 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 3.
PROPERTY AND EQUIPMENT
Property and equipment consisted of the following at December 31:
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.
During 2004, we sold a jackup rig, the Pride West Virginia, for $60.0 million. Additionally, we sold two stacked jackup rigs, the Pride Illinois and the Pride Kentucky, for $11.0 million. Proceeds from these transactions were used to repay debt.
Depreciation and amortization expense of property and equipment for 2006, 2005 and 2004 was $268.7 million, $257.1 million and $265.2 million, respectively.
We capitalize interest applicable to the construction of significant additions to property and equipment. For 2006, 2005 and 2004, we capitalized interest of $2.4 million, $0.5 million and $1.2 million, respectively.
During 2006, 2005 and 2004, maintenance and repair costs included in operating costs on the accompanying consolidated statements of operations were $156.2 million, $140.8 million and $115.7 million, respectively.
NOTE 4.
INVESTMENTS IN AFFILIATES
We have 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, 2006, our investment in UGER was $2.4 million. In addition we had $2.4 million in receivables due from NDSC at December 31, 2006.
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
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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 2). Effective with the acquisition, we eliminated our investment in affiliate as part our purchase accounting.
NOTE 5.
INDEBTEDNESS
Short-Term Borrowings
As of December 31, 2006, we had agreements with several banks for uncollateralized short-term lines of credit totaling $28.6 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, 2006, no borrowings were outstanding under these facilities and $28.6 million was available for borrowings.
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. Proceeds from the term loan and initial borrowings of approximately $95.0 million under the revolving credit facility were used to refinance amounts outstanding under our other credit facilities.
Amounts drawn under the revolving credit facility bear interest at variable rates based on LIBOR plus a margin or prime 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. We generally 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; distributions, dividends and repurchases of capital stock and other equity interests; acquisitions
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and investments; asset sales; capital expenditures; 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, 2006, there were $50.0 million of borrowings and $19.2 million of letters of credit outstanding under the facility. As of December 31, 2006, the interest rate on the senior secured revolving credit facility was 5.9%, and availability was $430.8 million.
73/8% Senior Notes due 2014
In July 2004, we completed an offering of $500.0 million principal amount of 73/8% Senior Notes due 2014. The notes bear interest at 7.375% per annum. The notes contain provisions that limit our ability 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. Prior to July 15, 2007, we may also redeem up to 35% of the notes from the proceeds of certain equity offerings at a specified redemption price. We pay interest semiannually on the notes.
We used the net proceeds from the offering of the notes of $491.1 million (after discounts but before other expenses) to retire $175.0 million aggregate principal amount of our 93/8% Senior Notes due 2007 and $200.0 million aggregate principal amount of our 10% Senior Notes due 2009, together with the applicable prepayment premium and accrued and unpaid interest, and to retire other indebtedness, including $85.9 million of our 9% Senior Convertible Notes due 2004. In connection with the retirement of the 2007 notes and the 2009 notes, we purchased a total of $110.6 million aggregate principal amount of the 2007 notes and $127.6 million aggregate principal amount of the 2009 notes at 37.5 basis points above their respective redemptions prices. The remaining notes were redeemed August 6, 2004 at redemption prices of 101.563% of the principal amount of the 2007 notes and 105.000% of the principal amount of the 2009 notes, in each case plus accrued and unpaid interest to the redemption date.
In connection with the early retirement of the 2007 notes and the 2009 notes, including the redemption of the notes outstanding following completion of the tender offer, we recognized refinancing charges of $30.8 million in 2004, consisting of the tender offer premium, prepayment premiums and the write-off of unamortized deferred financing costs related to the retired debt.
31/4% Convertible Senior Notes Due 2033
In 2003, we issued $300.0 million aggregate principal amount of 31/4% 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. 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
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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.
Drillship Loan Facility
In April 2004, we completed a refinancing of our existing drillship loan facilities through our consolidated joint venture company that owns the Pride Africa and the Pride Angola. The new drillship loan facility is collateralized by the two drillships and the proceeds from the related drilling contracts and provides for a total credit commitment of $301.4 million. Funds at closing, together with $15.4 million of previously restricted cash held by the joint venture, were used to (1) refinance the outstanding principal balance on the prior drillship loans of $172.6 million, (2) repay $103.6 million of loans due to us from the joint venture company, (3) repay $10.0 million of indebtedness of the joint venture company to the joint venture partner, and (4) pay loan transaction costs of $3.1 million. We used the funds paid to us to reduce our other outstanding debt and to improve liquidity. The drillship loan facility matures in September 2010 and amortizes quarterly. The drillship loan facility is non-recourse to us and the joint owner.
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, 2006 was 6.87%. In accordance with the debt agreements, certain cash balances are held in trust to assure that timely interest and principal payments are made. As of December 31, 2006 and 2005, $1.8 million of such cash balances, which amount is included in restricted cash, was held in trust and is not available for our use.
Semisubmersible Loans
In accordance with FIN No. 46R, we consolidate the debt related to the unaffiliated trust with which we completed the sale and leaseback of the Pride South America semisubmersible drilling rig. The loan is collateralized by the Pride South America, which has a carrying value of $81.1 million as of December 31, 2006 and is included in property and equipment on the consolidated balance sheet. The loan bears interest at 9.35% and requires quarterly interest payments. In February 2007, we gave notice that we will exercise our right to prepay the debt in August 2007.
In 2004, we repaid the outstanding aggregate principal amount of $138.5 million due under the semisubmersible loans that had originally financed the construction of the Pride Carlos Walter and Pride Brazil. In connection with the retirement of the semisubmersible loans, we recognized a charge of $5.5 million, including a write-off of deferred finance costs of $1.9 million and $3.6 million for the settlement of related interest rate swap agreements.
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. This transaction resulted in the addition of approximately $284 million of debt, net of fair value discount, (representing 100% of the joint venture entity’s debt) to our consolidated balance sheet. The notes representing the debt were used by the joint venture entity to finance a portion of the cost of construction of these rigs. 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.
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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, 2006 and 2005 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, 2006 and 2005 was $1,486.8 million and $1,397.1 million, respectively, which differs from the carrying amounts of $1,386.6 million and $1,244.8 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, 2006. 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, 2006, we had not designated any of the interest rate swap and cap agreements as hedging instruments as defined by SFAS No. 133. 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 $(1.3) million, $4.0 million and $(0.3) million in our consolidated statements of operations for 2006, 2005 and 2004, respectively. Also included in our consolidated statements of operations is $(0.2) million for 2004 related to the amortization of the SFAS No. 133 transition adjustment. The total aggregate fair value of the interest rate swap and cap agreements at December 31, 2006 and 2005 was an asset of $4.0 million and $5.3 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
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associated with our Euro denominated expenses. We did not enter into any forward exchange or option contracts in 2006 or 2005, but continue to monitor our foreign exchange risk.
NOTE 7.
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 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. In 2004, we had an effective tax rate above the U.S. statutory rate for taxes on foreign earnings due to the following: debt refinancing charges reducing income without a proportional reduction to income taxes; an increase in taxable income in high effective tax rate countries; lower taxable income in foreign jurisdictions with low or zero effective tax rates; and U.S. tax on certain foreign earnings.
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:
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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:
(1)
The change in net deferred tax liability of $51.4 million between December 31, 2006 and 2005 differs by $13.1 million from the deferred tax expense of $64.5 million reported for 2006. This difference is caused primarily by net tax return benefits from the exercise of non-qualified stock options and the tax impact of defined benefit pension plans that were charged to equity accounts.
Applicable U.S. deferred income taxes and related foreign dividend withholding taxes have not been provided on approximately $804.8 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.
In December 2004, the FASB issued FASB Staff Position No. 109-2 (“FSP 109-2”), Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004, which provides guidance under SFAS No. 109, Accounting for Income Taxes, with respect to recording the potential impact of the repatriation provisions of the American Jobs Creation Act of 2004 (the “Jobs Act”) on enterprises’ income tax expense and deferred tax liability. The Jobs Act was enacted on October 22, 2004. FSP 109-2 states that an enterprise is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Jobs Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We have elected not to repatriate capital in this manner.
As of December 31, 2006, we had deferred tax assets of $227.4 million relating to $684.6 million of net operating loss (“NOL”) carryforwards and had $31.5 million of non-expiring Alternative Minimum Tax (“AMT”) credits. The NOL carryforwards and AMT credits can be used to reduce our federal and foreign income taxes payable in future years. Our ability to realize the entire benefit of our deferred tax assets require that we achieve certain future earnings levels prior to the expiration of its NOL carryforwards. Our NOL carryforwards in the United States total $447.8 million and could expire starting in 2020 through 2024. Foreign NOL carryforwards include $89.7 million that do not expire and $147.1 million that could expire starting in 2007 through 2016. We have recognized a $68.1 million valuation allowance on substantially all of these foreign NOL carryforwards due to the uncertainty of realizing certain foreign NOL carryforwards. 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.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
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.
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 July 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, in September 2006, we provided standby letters of credit valued at $41.3 million as of December 31, 2006, to contest these assessments.
NOTE 8.
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, 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 21/2% 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.
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Notes to Consolidated Financial Statements - (Continued)
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 9.
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.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
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 0.6 million, 0.2 million and 4.2 million of common stock issuable pursuant to outstanding stock options for the years ended December 31, 2006, 2005 and 2004, respectively. The calculation of weighted average shares of common stock outstanding, as adjusted, also excludes 32.1 million shares of common stock issuable pursuant to convertible debt for the year ending December 31, 2004. 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 10.
EMPLOYEE STOCK PLANS
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, 2006, only two 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, 2006, a total of approximately 0.2 million shares had been reserved for issuance pursuant to awards granted under the 2004 Directors’ Stock Incentive Plan.
Stock-based compensation expense related to stock options, restricted stock and the ESPP was allocated as follows:
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Notes to Consolidated Financial Statements - (Continued)
The adoption of SFAS No. 123(R) resulted in a change in our method of recognizing the fair value of stock-based compensation and estimating forfeitures for all unvested awards. Specifically, the adoption of SFAS No. 123(R) resulted in our recording compensation expense for employee stock options and our ESPP. The following table shows the effect of adopting SFAS No. 123(R) as of January 1, 2006 on selected financial information for the year ended December 31, 2006:
Under the modified prospective method, stock-based compensation expense for 2006 includes compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provision of SFAS No. 123. 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 and 2004 would have been reduced to the pro forma amounts indicated below:
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Notes to Consolidated Financial Statements - (Continued)
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 2006, 2005 and 2004, we received cash from the exercise of stock options of $50.3 million, $91.2 million and $10.1 million, respectively. Income tax benefits of $14.1 million, $21.2 million, and $1.7 million were realized from the exercise of stock options for 2006, 2005 and 2004, respectively. As of December 31, 2006,
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Notes to Consolidated Financial Statements - (Continued)
there was $8.1 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 1.9 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, 2006, there was $26.8 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 3.0 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
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Notes to Consolidated Financial Statements - (Continued)
incremental compensation cost and will result in the reclassification of the full amount of the recorded liability to equity in the first quarter of 2007.
During 2006, 2005 and 2004, we recognized $0.4 million, $0.6 million and $0.2 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 0.5 million shares remained available for issuance under the plan as of December 31, 2006. Employees purchased approximately 83,000, 82,000 and 83,000 shares in the years ended December 31, 2006, 2005 and 2004, respectively.
NOTE 11.
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 $4.3 million, $3.9 million and $0.4 million related to the SERP in 2006, 2005 and 2004, respectively. As of December 31, 2006 and 2005, the unfunded accrued pension liability was $10.5 million and $4.3 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, 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 $5.8 million, $4.3 million and $3.4 million in 2006, 2005 and 2004, respectively.
In addition, we have a deferred compensation plan that provides our senior officers with the opportunity to participate in an unfunded, non-qualified plan. Eligible employees 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, 2006 and 2005, we have accrued balances of $4.5 million and $4.7 million, respectively.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
NOTE 12.
DISCONTINUED OPERATIONS
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. The first rig was completed and delivered in 2003, and the remaining three rigs were completed and delivered in 2004. 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 13.
COMMITMENTS AND CONTINGENCIES
Leases
At December 31, 2006, 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:
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, shortly after and as a result of certain statements that were made by an employee during the investigation, 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.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
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 Latin America 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 2003 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 or the movement of personnel through immigration; 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. This review has found evidence suggesting that in 2004 and 2005 payments may have been made to government officials in Saudi Arabia and Kazakhstan, aggregating less than $175,000, in connection with clearing rigs or equipment through customs or resolving outstanding customs issues in those countries. The investigation of the matters related to Saudi Arabia and Kazakhstan 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 Saudi Arabia, Kazakhstan 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. On December 1, 2006, our Vice President - Western Hemisphere Operations resigned. On December 2, 2006, our former Country Manager in Venezuela and Mexico was terminated. We have placed another member of our senior operations management on administrative leave pending the outcome of the investigation.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the U.S. Department of Justice 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. 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
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Notes to Consolidated Financial Statements - (Continued)
employees and to access the capital markets. No amounts have been accrued related to any potential fines, sanctions or other penalties.
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.
For the years ended December 31, 2006, 2005 and 2004, our operations in Venezuela provided revenues of approximately $156.9 million, $172.6 million, and $167.1 million, or approximately 6.3%, 8.5% and 9.8% of our total consolidated revenues, respectively. Our Venezuela operations provided earnings (loss) from operations of approximately $6.9 million, $16.8 million, and $(6.7) million or approximately 1.3%, 5.2% and (2.7)% of our total consolidated earnings from operations for 2006, 2005 and 2004, respectively. As of December 31, 2006 and 2005, we had accounts receivable from Petróleos de Venezuela, S.A. totaling $27.6 million and $33.4 million, respectively.
Litigation
In August 2004, we were notified that certain of our subsidiaries have been named, along with 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. Additional suits have been filed since August 2004. The complaints allege that certain drilling contractors used products containing asbestos in offshore drilling operations, land-based drilling operations and in drilling structures, drilling rigs, vessels and other equipment. The plaintiffs assert claims based on, among other things, negligence and strict liability and claims under the Jones Act. The complaints name as defendants numerous other companies that are not affiliated with us, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints. The plaintiffs 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 or one of our affiliates or predecessors. Currently, discovery and investigation is ongoing to determine whether these individuals were employed in our offshore operations during the alleged period of exposure. 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 A. Bragg, our former President and Chief Executive Officer, filed suit against us in State District Court of Harris County, Texas in early October 2005 seeking a declaratory judgment that the non-competition provisions of his employment agreement are unlawful and unenforceable. Shortly thereafter, Mr. Bragg filed a second lawsuit against us alleging that we breached written and oral employment agreements with him and seeking damages aggregating more than $17.0 million. The suits were consolidated.
We filed counterclaims against Mr. Bragg related to his non-competition claim seeking a declaratory judgment that the non-competition provisions of his employment agreement are enforceable and restitution of certain amounts paid to Mr. Bragg should there be a finding that the non-competition provisions of his employment agreement are unenforceable. On February 1, 2007, the trial court granted Mr. Bragg’s motion to dismiss, without prejudice, his declaratory judgment claim related to his covenant not to compete. We, in turn, are seeking to dismiss, without prejudice, our counterclaims in connection with Mr. Bragg’s covenant not to compete declaratory judgment claim.
We filed counterclaims against Mr. Bragg related to his claims for breach of contract claiming, among other things, (i) breach of fiduciary duty seeking disgorgement of certain amounts previously paid to Mr. Bragg stemming from actions that may have been taken by Mr. Bragg relating to his employment compensation claims,
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
(ii) declaratory judgment that we did not breach his contract and (iii) breach of contract. On October 25, 2006, the trial court granted summary judgment in our favor dismissing Mr. Bragg’s claims for damages related to an alleged breach of written and oral employment agreements. On December 20, 2006, the trial court granted summary judgment against us on our counterclaim for breach of fiduciary duty. We subsequently filed a notice of appeal with respect to the trial court’s dismissal of our counterclaim for breach of fiduciary duty. We are seeking to dismiss, without prejudice, our remaining counterclaims, and we have obtained a tolling agreement allowing us to resuscitate these counterclaims at a later date if we so choose.
Currently, the only matter outstanding before the trial court is Mr. Bragg’s motion for reconsideration of the trial court’s order dismissing his breach of contract claims. We intend to defend ourselves vigorously and, based on the information available to us at this time, 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 $223.0 million at December 31, 2006. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions. We also had commitments outstanding for obligations under a software license agreement of approximately $1.2 million at December 31, 2006.
NOTE 14.
SEGMENT AND GEOGRAPHIC INFORMATION
We operate through three principal reporting segments: Offshore, which includes all of our offshore drilling fleet and operations; Latin America Land, which includes all our land-based drilling and workover services in Latin America; and E&P Services, which includes our exploration and production services business in Latin America.
The accounting policies of our segments are the same as those described in Note 1 of our Notes to Consolidated Financial Statements. We evaluate the performance of our segments based on earnings (loss) from operations.
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Notes to Consolidated Financial Statements - (Continued)
Summarized financial information is shown in the following tables. “Other” includes revenues and costs for land-based drilling operations outside of Latin America (currently Chad, Kazakhstan and Pakistan), labor contracts and engineering and management consulting services.
For the year ended December 31, 2006, one customer, Petroleo Brasileiro S.A. (“Petrobras”), accounted for 16.7% of consolidated revenues and is included in the Latin America Land and Offshore segments. For the year ended December 31, 2005, Petrobras accounted for 14.4% of consolidated revenues and is included in the Latin America Land and Offshore segments and an additional customer, Petroleos Mexicanos S.A. (“PEMEX”), accounted for approximately 10.7% of consolidated revenue and is included in the Offshore segment. For the year ended December 31, 2004, Petrobras for 16.6% of consolidated revenues and is included in the Latin America Land and Offshore segments, and PEMEX accounted for 13.9% of consolidated revenue and is included in the Offshore segment.
For the year ended December 31, 2006, we derived 81.2% 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.
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
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:
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Notes to Consolidated Financial Statements - (Continued)
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:
Pride International, Inc.
Notes to Consolidated Financial Statements - (Continued)
NOTE 16.
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
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, 2006 were effective, in all material respects, 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, 2006, 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”). Because of its inherent limitations, 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.
KPMG LLP, our independent registered public accounting firm, has audited management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 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 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
(d)
Material Weakness
In connection with the preparation of our annual report on Form 10-K for the year ended December 31, 2005, management assessed the effectiveness of our internal control over financial reporting as of December 31, 2005. Based on that assessment, management identified a material weakness in our internal controls and concluded that we did not maintain effective internal control over financial reporting as of December 31, 2005 based on criteria set forth in the COSO Framework. The material weakness identified as of December 31, 2005 was that we did not maintain a control environment in which our operations management effectively set a proper ethical tone within our operations organization to instill an attitude of compliance and control awareness. More specifically, these conditions resulted in an environment in which it is likely that certain 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 through collusion by company personnel and outside vendors to circumvent controls designed to prevent the misappropriation of assets. This material weakness resulted in more
than a remote likelihood that a material misstatement of our annual or interim consolidated financial statements would not be prevented or detected.
As described in our 2005 annual report and in our quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2006, June 30, 2006, and September 30, 2006, we implemented certain measures to improve our internal control over financial reporting and to remediate the material weakness described above, including the following:
•
we have terminated one member of our senior operations management and have placed another on administrative leave pending the outcome of the ongoing audit committee investigation described in Item 7 of this annual report;
•
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 ongoing audit committee 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;
•
our Vice President, Western Hemisphere Operations resigned on December 1, 2006;
•
in September 2006, we hired a new Executive Vice President and Chief Operating Officer responsible for our worldwide offshore operations and Eastern Hemisphere land assets;
•
we have continued to enhance our training of management, including our operations managers, to emphasize further the importance of setting the proper tone within their organization to instill an attitude of integrity and control awareness and the use of a thorough and proper analysis of proposed transactions;
•
we have determined that our bonus-eligible employees complete in-person and online training on the Foreign Corrupt Practices Act and our Code of Business Conduct and Ethical Practices as a prerequisite to receiving their bonuses for 2006;
•
we now require our management, including our operations managers, to reconfirm that they are not aware of any violations of law and confirm with greater specificity that they are not aware of any improper payments to foreign government officials made by us or on our behalf or any other violation of our Code of Business Conduct and Ethical Practices and to recertify their commitment to the Code prior to the filing of our annual report on Form 10-K;
•
we have established an executive compliance committee, consisting of our executive officers and other management-level employees who are responsible for supervising our antibribery compliance committee, our internal controls steering committee and our compliance efforts in general; and
•
we have established a separate position of, and appointed, a chief compliance officer.
The actions described above have significantly improved our internal control over financial reporting by creating and maintaining a control environment in our operations management that effectively sets a proper ethical tone within our operations organization to instill an attitude of compliance and control awareness. Our management concluded that, as of December 31, 2006, these changes in our internal control over financial reporting remediated the material weakness identified as of December 31, 2005.
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, 2006. 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, among others, 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, 2006.
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, 2006.
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, 2006.
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, 2006.
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 March 1, 2007.
PRIDE INTERNATIONAL, INC.
/s/ LOUIS A. RASPINO
Louis A. Raspino
President and Chief Executive Officer
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 March 1, 2007.
INDEX TO EXHIBITS
*
Filed herewith.

Management contract or compensatory plan or arrangement.