UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2008
Commission file number: 1-13289
_______________
Pride International, Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 76-0069030 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
| 5847 San Felipe, Suite 3300 | 77057 |
| Houston, Texas | (Zip Code) |
| (Address of principal executive offices) |
Registrant’s telephone number, including area code:
(713) 789-1400
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Name of Each Exchange on Which Registered |
| Common Stock, $.01 par value | New York Stock Exchange |
| Rights to Purchase Preferred Stock | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
| (Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2008, based on the closing price on the New York Stock Exchange on such date, was approximately $8.1 billion. (The current executive officers and directors of the registrant are considered affiliates for the purposes of this calculation.)
The number of shares of the registrant’s common stock outstanding on February 23, 2009 was 173,575,849.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the Annual Meeting of Stockholders to be held in May 2009 are incorporated by reference into Part III of this annual report.
TABLE OF CONTENTS
2
ITEM 1. BUSINESS
In this Annual Report on Form 10-K, “we,” the “Company” and “Pride” are references to Pride International, Inc. and its subsidiaries, unless the context clearly indicates otherwise. Pride International, Inc. is a Delaware corporation with its principal executive offices located at 5847 San Felipe, Suite 3300, Houston, Texas 77057. Our telephone number at such address is (713) 789-1400 or (800) 645-2067.
We are one of the world’s largest offshore drilling contractors operating, as of February 2, 2009, a fleet of 44 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, 27 jackups and three managed deepwater drilling rigs. We have four deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.
Our operations are conducted in many of the most active crude oil and natural gas basins of the world, including South America, the Gulf of Mexico, West Africa, the Mediterranean Sea, the Middle East and Asia Pacific. We are focused on increasing our deepwater and other high specification drilling solutions and, since 2005, have invested or committed to invest over $3.6 billion in the expansion of our deepwater fleet. Since 2005, we have completed sales of non-core assets totaling approximately $1.6 billion, enabling us to invest capital in our deepwater business.
Consistent with our strategy to focus on deepwater drilling, we have filed a Form 10 registration statement with the Securities and Exchange Commission with respect to the distribution to our stockholders of all of the shares of common stock of a subsidiary that would hold, directly or indirectly, the assets and liabilities of our 20-rig mat-supported jackup business. We believe that the spin-off has the potential to facilitate our growth strategies and reduce our cost of capital, and to allow us to refine our focus and further enhance our reputation as a provider of deepwater drilling services. The spin-off, which we expect to complete in 2009, is contingent upon approval of the final plan by the board of directors, a favorable ruling from the Internal Revenue Service, the effectiveness of the Form 10 registration statement, compliance with covenants under our existing debt agreements and other conditions. There can be no assurance that we will complete the spin-off within that time period or at all.
We provide contract drilling services to oil and natural gas exploration and production companies through the use of mobile offshore drilling rigs in U.S. and international waters. We provide the rigs and drilling crews and are responsible for the payment of operating and maintenance expenses. In addition, we also provide rig management services on a variety of rigs, consisting of technical drilling assistance, personnel, repair and maintenance services and drilling operation management services.
Segment Information
During the fourth quarter of 2008, we reorganized our reportable segments to reflect the general asset class of our drilling rigs. We believe that this change reflects how we manage our business. Our new reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths greater than 4,500 feet, and Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,500 feet or less. Our jackup fleet, which operates in water depths up to 300 feet, is reported as two segments, Independent Leg Jackups and Mat-Supported Jackups, based on rig design as well as our intention to separate the mat-supported jackup business. We also manage the drilling operations for three deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations.
We incorporate by reference in response to this item the segment information for the last three years set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Segment Review” in Item 7 of this annual report and Note 14 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report. We also incorporate by reference in response to this item the information with respect to backlog and acquisitions and dispositions of assets set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” and “— Liquidity and Capital Resources” in Item 7 and in Notes 2 and 3 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report.
3
Rig Fleet
The table below presents information about our rig fleet as of February 2, 2009:
| Rig Name | Rig Type / Design | Built / Upgraded | Water Depth Rating (In Feet) | Drilling Depth Rating (In Feet) | Location | Status | ||||||
| Deepwater | ||||||||||||
| Drillships Under Construction — 4 | ||||||||||||
| PS1 | Samsung, DP3 Single Activity | Exp Q1 2010 | 12,000 | 40,000 | S. Korea | Shipyard | ||||||
| PS2 | Samsung, DP3 Single Activity | Exp Q3 2010 | 12,000 | 40,000 | S. Korea | Shipyard | ||||||
| PS3 | Samsung, DP3 Single Activity | Exp Q1 2011 | 12,000 | 40,000 | S. Korea | Shipyard | ||||||
| PS4 | Samsung, DP3 Single Activity | Exp Q4 2011 | 12,000 | 40,000 | S. Korea | Shipyard | ||||||
| Drillships — 2 | ||||||||||||
| Pride Africa | Gusto 10,000, DP | 1999 | 10,000 | 30,000 | Angola | Working | ||||||
| Pride Angola | Gusto 10,000, DP | 1999 | 10,000 | 30,000 | Angola | Working | ||||||
| Semisubmersibles — 6 | ||||||||||||
| Pride North America | Bingo 8000 | 1999 | 7,500 | 25,000 | Egypt | Working | ||||||
| Pride South Pacific | Sonat Offshore /Aker | 1974/1999 | 6,500 | 25,000 | Angola | Working | ||||||
| Pride Portland | Amethyst 2 Class, DP | 2004 | 5,700 | 25,000 | Brazil | Working | ||||||
| Pride Rio de Janeiro | Amethyst 2 Class, DP | 2004 | 5,700 | 25,000 | Brazil | Working | ||||||
| Pride Brazil | Megathyst, DP | 2001 | 5,000 | 25,000 | Brazil | Shipyard | ||||||
| Pride Carlos Walter | Megathyst, DP | 2000 | 5,000 | 25,000 | Brazil | Working | ||||||
| Midwater — 6 | ||||||||||||
| Pride South America | Amethyst, DP | 1987/1996 | 4,000 | 12,000 | Brazil | Working | ||||||
| Pride Mexico | Neptune Pentagon | 1973/1995 | 2,650 | 25,000 | Brazil | Working | ||||||
| Pride South Atlantic | F&G Enhanced Pacesetter | 1982 | 1,500 | 25,000 | Brazil | Working | ||||||
| Pride Venezuela | F&G Enhanced Pacesetter | 1982/2001 | 1,500 | 25,000 | Angola | Working | ||||||
| Sea Explorer | Aker H-3 | 1975/2001 | 1,000 | 25,000 | Tunisia | Working | ||||||
| Pride South Seas | Aker H-3 | 1977/1997 | 1,000 | 20,000 | Namibia | Working | ||||||
| Jackup Rigs | ||||||||||||
| Independent leg - 7 | ||||||||||||
| Pride Cabinda | Independent leg, cantilever | 1983 | 300 | 25,000 | Gabon | Working | ||||||
| Pride Hawaii | Independent leg, cantilever | 1975/1997 | 300 | 21,000 | India | Working | ||||||
| Pride Pennsylvania | Independent leg, cantilever | 1973/1998 | 300 | 20,000 | India | Working | ||||||
| Pride Tennessee | Independent leg, cantilever | 1981/2007 | 300 | 20,000 | Mexico | Working | ||||||
| Pride Wisconsin | Independent leg, slot | 1976/2002 | 300 | 20,000 | Mexico | Working | ||||||
| Pride Montana | Independent leg, cantilever | 1980/2001 | 270 | 20,000 | Mid-East | Working | ||||||
| Pride North Dakota | Independent leg, cantilever | 1981/2002 | 250 | 30,000 | Mid-East | Working | ||||||
4
| Mat-supported - 20 | ||||||||||||
| Pride Texas | Mat-supported, cantilever | 1974/1999 | 300 | 25,000 | Mexico | Working | ||||||
| Pride Kansas | Mat-supported, cantilever | 1976/1999 | 250 | 25,000 | USA | Shipyard | ||||||
| Pride Alaska | Mat-supported, cantilever | 1982/2002 | 250 | 20,000 | USA | Idle | ||||||
| Pride Arizona | Mat-supported, slot | 1981/1996 | 250 | 20,000 | USA | Idle | ||||||
| Pride California | Mat-supported, slot | 1975/2002 | 250 | 20,000 | Mexico | Working | ||||||
| Pride Georgia | Mat-supported, slot | 1981/1995 | 250 | 20,000 | USA | Working | ||||||
| Pride Louisiana | Mat-supported, slot | 1981/2002 | 250 | 20,000 | Mexico | Working | ||||||
| Pride Michigan | Mat-supported, slot | 1975/2002 | 250 | 20,000 | USA | Working | ||||||
| Pride Missouri | Mat-supported, cantilever | 1981 | 250 | 20,000 | USA | Working | ||||||
| Pride Oklahoma | Mat-supported, slot | 1975/2002 | 250 | 20,000 | Mexico | Working | ||||||
| Pride Alabama | Mat-supported, cantilever | 1982 | 200 | 20,000 | USA | Stacked | ||||||
| Pride Arkansas | Mat-supported, cantilever | 1982 | 200 | 20,000 | Mexico | Working | ||||||
| Pride Colorado | Mat-supported, cantilever | 1982 | 200 | 20,000 | USA | Stacked | ||||||
| Pride Florida | Mat-supported, cantilever | 1981 | 200 | 20,000 | USA | Working | ||||||
| Pride Mississippi | Mat-supported, cantilever | 1981/2002 | 200 | 20,000 | USA | Working | ||||||
| Pride Nebraska | Mat-supported, cantilever | 1981/2002 | 200 | 20,000 | Mexico | Working | ||||||
| Pride Nevada | Mat-supported, cantilever | 1981/2002 | 200 | 20,000 | USA | Stacked | ||||||
| Pride New Mexico | Mat-supported, cantilever | 1982 | 200 | 20,000 | USA | Working | ||||||
| Pride South Carolina | Mat-supported, cantilever | 1980/2002 | 200 | 20,000 | USA | Stacked | ||||||
| Pride Utah | Mat-supported, cantilever | 1978/2002 | 80 | 15,000 | USA | Stacked | ||||||
| Managed Rigs — 3 | ||||||||||||
| Thunder Horse | Moored Semisubmersible Drilling Rig | 2004 | N/A | 25,000 | USA | Working | ||||||
| Kizomba B | Tension Leg Platform Rig | 2004 | N/A | 20,000 | Angola | Working | ||||||
| Holstein | Moored Spar Platform Rig | 2004 | N/A | 20,000 | USA | Working | ||||||
Drillships. Our drillships, including the four under construction, are deepwater, self-propelled drillships that can be positioned over a drill site through the use of a computer-controlled thruster (dynamic positioning) system. Drillships are suitable for deepwater drilling in remote locations because of their mobility and large load-carrying capacity. Generally, these drillships operate with crews of approximately 100 persons.
Semisubmersible Rigs. Our semisubmersible rigs, which consist of all of our deepwater and midwater fleet other than our drillships, are floating platforms that, by means of a water ballasting system, can be submerged to a predetermined depth so that a substantial portion of the lower hulls, or pontoons, is below the water surface during drilling operations. The rig is “semisubmerged,” remaining afloat in a position, off the sea bottom, where the lower hull is about 60 to 80 feet below the water line and the upper deck protrudes well above the surface. This type of rig maintains its position over the well through the use of either an anchoring system or a computer-controlled thruster system similar to that used by our drillships. Semisubmersible rigs generally operate with crews of 60 to 75 persons.
Jackup Rigs. The jackup rigs we operate are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. Mat-supported rigs have a lower hull, or mat, that provides a more stable foundation in soft seabed areas. Independent leg rigs are better suited for harsher drilling conditions or uneven seabed conditions. Our jackup rigs are generally subject to a maximum water depth of approximately 200 to 300 feet, while some of our competitors’ jackup rigs may drill in water depths exceeding 400 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 40 to 60 persons.
Managed Deepwater Rigs. We perform rig management services for drilling operations for three deepwater rigs owned by others, located offshore Angola and in the U.S. Gulf of Mexico. Our services consist of providing technical assistance, personnel, repair and maintenance services and drilling operation management services. The drilling equipment, which we operate on behalf of our customers, is installed on a variety of supporting structures,
5
including tension-leg platform, spar and semisubmersible hull designs. Due to the similar drilling equipment specifications and operations among our managed deepwater rigs and our owned deepwater rigs, our managed rig personnel and the rig crews on our owned rigs require similar experience and training.
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, 2008, Petroleos Mexicanos S.A., Petroleo Brasilerio S.A. and BP America and affiliates accounted for 20%, 19% and 10%, respectively, of our consolidated revenues. The loss of any of these significant customers could have a material adverse effect on our results of operations.
Drilling Contracts
Overview
Our drilling contracts are awarded through competitive bidding or on a negotiated basis. The contract terms and rates vary depending on competitive conditions, geographical area, geological formation to be drilled, equipment and services to be supplied, on-site drilling conditions and anticipated duration of the work to be performed.
Oil and natural gas well drilling contracts are carried out on a dayrate, footage or turnkey basis. Currently, all of our offshore drilling services contracts are on a dayrate basis. Under dayrate contracts, we charge the customer a fixed amount per day regardless of the number of days needed to drill the well. In addition, dayrate contracts usually provide for a reduced dayrate (or lump-sum amount) for mobilizing the rig to the well location or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. Our dayrate contracts also generally include cost escalation provisions that allow us to increase the amounts billed to our customers when our operating costs increase. A dayrate drilling contract generally covers either the drilling of a single well or group of wells or has a stated term. In some instances, the dayrate contract term may be extended by the customer exercising options for the drilling of additional wells or for an additional length of time at fixed or mutually agreed terms, including dayrates.
Another type of contract provides for payment on a footage basis, whereby a fixed amount is paid for each foot drilled regardless of the time required or the problems encountered in drilling the well. We may also enter into turnkey contracts, whereby we agree to drill a well to a specific depth for a fixed price and to bear some of the well equipment costs. Compared with dayrate contracts, footage and turnkey contracts involve a higher degree of risk to us.
Our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime or operational problems above a contractual limit or specified safety-related issues, if the rig is a total loss, if the rig is not delivered to the customer or, in certain circumstances, does not pass acceptance testing within the period specified in the contract or in other specified circumstances. In addition, a number of our long-term drilling contracts are cancelable by the customer for convenience upon the payment of a termination fee. The termination fees vary from contract to contract and range from (1) the remaining revenue under the contract to (2) the present value of the cash margin for the remaining term to (3) a reduced dayrate for the remaining term. For some contracts, the termination fee includes the payment of mobilization and demobilization fees and may be reduced to the extent of the dayrate obtained for the rig on another contract. For our Independent Leg Jackup and Mat-Supported Jackup segments, long-term drilling contracts with certain customers are cancelable, without cause, upon little or no prior notice and without penalty or early termination payments. 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, operational problems or failure to deliver. Suspension of drilling contracts results in the reduction in or loss of dayrate 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 at all, or if contracts are suspended for an extended period of time, it could materially adversely affect our consolidated financial statements.
6
Deepwater
The Pride Africa is currently operating under a contract expiring in December 2011. In 2008, the Pride Angola obtained a five-year contract expiring in July 2013. In February 2008, the Pride Portland and the Pride Rio de Janeiro were awarded contract extensions into 2017 in direct continuation of their current contracts. The Pride South Pacific commenced a two-year contract in March 2007 and was awarded a three-month contract in 2008 to commence after the current contract. In November 2006, we were awarded five-year contract extensions that began in mid-2008 for the Pride Brazil and the Pride Carlos Walter and a three-year contract extension that began in early 2008 for the Pride North America. For information about the contract status of our four drillships under construction, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments — Investments in Deepwater Fleet” in Item 7 of this annual report.
Midwater
The Pride South America is operating under a five-year contract expiring in February 2012. The Pride Mexico commenced a five-year contract in Brazil in July 2008. The Pride South Atlantic commenced its new five-year contract in April 2008. The Pride Venezuela received contracts extending it to March 2010. The Sea Explorer commenced a new one-year contract in August 2008 and was awarded a two-year contract in Brazil that is expected to commence in October 2009. The Pride South Seas commenced an eight well contract in March 2008, which is expected to conclude in the third quarter of 2009.
Independent Leg Jackups
The Pride Tennessee and Pride Wisconsin are operating in the Mexican sector of the Gulf of Mexico under contracts expiring throughout 2009. Of our five independent leg jackup rigs operating outside the Gulf of Mexico, the Pride Cabinda is under contract to August 2009, the Pride Hawaii to May 2010, the Pride Pennsylvania to October 2009, the Pride Montana to June 2011 and the Pride North Dakota, inclusive of an unexercised priced option, to May 2010.
Mat-Supported Jackups
As of February 2, 2009, six of our mat-supported jackup rigs operating in the U.S. Gulf of Mexico were operating under short-term contracts expiring in 2009, and we had six rigs operating in the Mexican sector of the Gulf of Mexico under contracts expiring throughout 2009. We also have two rigs currently available for contracts in the United States and five stacked rigs that we are not actively marketing. We also expect the Pride Arkansas to be released by PEMEX at the completion of its contract and we intend to stack the rig when it returns to the United States.
Other Operations
We operate three deepwater drilling rigs under management contracts. In September 2008, our management contract for drilling operations of Kizomba A expired. In December 2008, we were notified that our management services contract for the Mad Dog deepwater spar platform was terminated as result of damage to the drilling package from Hurricane Ike. In January 2009, we received notification that our management contract for the Holstein will be terminated by the fourth quarter of 2009. Our other two management contracts expire in 2010 and 2012 (with early termination permitted in certain cases).
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 crude 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 prices and demand for crude 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.
7
Drilling contracts are generally awarded on a competitive bid basis. Pricing, safety record and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical ability also can be significant factors in the determination. Operators also may consider crew experience and efficiency. Some of our contracts are on a negotiated basis. We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future. Certain competitors may have greater financial resources than we do, which may better enable them to withstand periods of low utilization, compete more effectively on the basis of price, build new rigs or acquire existing rigs.
Our competition ranges from large international companies to smaller, locally owned companies. We believe we are competitive in terms of safety, pricing, performance, equipment, availability of equipment to meet customer needs and availability of experienced, skilled personnel; however, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business can occur. Competition for offshore rigs is usually on a global basis, as these rigs are highly mobile and may be moved, at a cost that is sometimes substantial, from one region to another in response to demand.
Seasonality
Our rigs in the Gulf of Mexico are subject to severe weather during certain periods of the year, particularly during hurricane season from June through November, which could halt operations for prolonged periods or limit contract opportunities during that period. Otherwise, our business activities are not significantly affected by seasonal fluctuations.
Insurance
Our operations are subject to hazards inherent in the drilling of oil and natural gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, or seriously damage or destroy the equipment involved. Offshore drilling operations are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our marine package policy provides insurance coverage for physical damage to our rigs, liability due to control-of-well events and loss of hire insurance for certain assets with higher dayrates. This insurance policy has a $10 million aggregate deductible and $10 million per occurrence deductible. In addition, the marine package policy has a sub-limit of $110 million for physical damage claims due to a named windstorm in the U.S. Gulf of Mexico. We also maintain insurance coverage for cargo, automobile liability, non-owned aviation, personal injury and similar liabilities. Those policies have significantly lower deductibles than the marine package policy, which are generally less than $1 million.
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. In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. 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 or limit contract drilling opportunities 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 2009.
The Minerals Management Service of the U.S. Department of the Interior (“MMS”) has issued guidelines for jackup rig fitness requirements in the U.S. Gulf of Mexico for future hurricane seasons through 2013 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
8
costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations and financial condition. Please read “Risk Factors — Our ability to operate our rigs in the U.S. Gulf of Mexico could be restricted or made more costly by government regulation” in Item 1A of this annual report.
The United States Clean Water Act prohibits the discharge of oil or hazardous substances in U.S. navigable waters and imposes strict liability in the form of penalties for unauthorized discharges. Pursuant to regulations promulgated by the EPA in the early 1970s, the discharge of sewage from vessels and effluent from properly functioning marine engines was exempted from the permit requirements of the National Pollution Discharge Elimination System. This exemption allowed vessels in U.S. waters to discharge certain substances incidental to the normal operation of a vessel, including ballast water, without obtaining a permit to do so. In September 2006, in response to a challenge by certain environmental groups and U.S. states, a U.S. District Court issued an order invalidating the exemption. As a result of this ruling, as of December 19, 2008, EPA requires a permit for such discharges. EPA issued a general permit available to vessel owners to cover the discharges, which includes effluent limits, specific corrective actions, inspections and monitoring, recordkeeping and reporting requirements. As a result, like others in our industry, we are subject to this new permit requirement. However, we do not presently anticipate that compliance with this requirement will have a material adverse effect on our operations.
Our international operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling rigs and equipment, currency conversions and repatriation, oil and natural gas exploration and development, environmental protection, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling rigs and other equipment. New environmental or safety laws and regulations could be enacted, which could adversely affect our ability to operate in certain jurisdictions. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
Employees
As of December 31, 2008, we employed approximately 5,700 personnel and had approximately 700 contract personnel working for us. Approximately 1,500 of our employees and contractors were located in the United States and 4,900 were located outside the United States. 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.
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 2008, 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.
9
ITEM 1A. RISK FACTORS
Risk Factors About Our Business
A material or extended decline in expenditures by oil and natural gas companies due to a decline or volatility in crude oil and natural gas prices, a decrease in demand for crude 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. Crude 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 because our customers’ expectations of future commodity prices typically drive demand for our rigs. Crude oil and natural gas prices are volatile. Commodity prices are directly influenced by many factors beyond our control, including:
| • | the demand for crude oil and natural gas; |
| • | the cost of exploring for, developing, producing and delivering crude oil and natural gas; |
| • | expectations regarding future energy prices; |
| • | advances in exploration, development and production technology; |
| • | government regulations; |
| • | local and international political, economic and weather conditions; |
| • | the ability of OPEC to set and maintain production levels and prices; |
| • | the level of production in non-OPEC countries; |
| • | 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; |
| • | acts of terrorism in the United States or elsewhere; 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. |
The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession or depression. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks against the United States or other countries could further the downturn in the economies of the United States and those of other countries. A slowdown in economic activity would likely reduce worldwide demand for energy and result in an extended period of lower crude oil and natural gas prices. Any prolonged reduction in crude oil and natural gas prices will depress the levels of exploration, development and production activity. Moreover, even during periods of high commodity prices, customers 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. These factors could cause our revenues and margins to decline, decrease daily rates and
10
utilization of our rigs and limit our future growth prospects. 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. 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.
The global financial and credit crisis may have impacts on our business and financial condition that we currently cannot predict.
The continued credit crisis and related instability in the global financial system has had, and may continue to have, an impact on our business and our financial condition. We may face significant challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions. The financial and credit crisis could have an impact on the lenders under our credit facility, on our customers, on our vendors or on the counterparties to our derivative contracts, causing them to fail to meet their obligations to us. Such crisis may also adversely affect the ability of shipyards to meet scheduled deliveries of our newbuild and other shipyard projects.
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.
Currently, our contracts with 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 or operational problems above the contractual limit or specified safety-related issues, if the rig is a total loss, if the rig is not delivered to the customer or, in certain circumstances, does not pass acceptance testing within the period specified in the contract or in other specified circumstances, which include events beyond the control of either party. Some of our contracts with our customers include terms allowing them to terminate contracts without cause, with little or no prior notice and without penalty or early termination payments. In addition, we could be required to pay penalties, which could be material, if some of our contracts with our customers are terminated due to downtime, operational problems or failure to deliver. Some of our other contracts with customers may be cancelable at the option of the customer upon payment of a penalty, which may not fully compensate us for the loss of the contract. In addition, a customer that is the subject of a bankruptcy filing may elect to reject its drilling 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, or at all, our revenues and profitability could be materially reduced.
Rig upgrade, refurbishment, repair and construction projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.
We have expended, and will continue to expend, significant amounts of capital to complete the construction of our four drillships currently under construction. Depending on available opportunities, we may construct additional rigs for our fleet in the future. In addition, we make significant upgrade, refurbishment and repair expenditures for our fleet from time to time, particularly in light of the aging nature of our rigs. Some of these expenditures are unplanned. In 2009, we expect to spend approximately $735 million with respect to the construction of our four drillships and an additional approximately $350 million with respect to the refurbishment and upgrade of other rigs.
All of these projects are subject to the risks of delay or cost overruns, including costs or delays resulting from the following:
| • | unexpectedly long delivery times for or shortages of key equipment, parts and materials; |
| • | shortages of skilled labor and other shipyard personnel necessary to perform the work; |
11
| • | failure or delay of third-party equipment vendors or service providers; |
| • | unforeseen increases in the cost of equipment, labor and raw materials, particularly steel; |
| • | unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment; |
| • | unanticipated actual or purported change orders; |
| • | client acceptance delays; |
| • | disputes with shipyards and suppliers; |
| • | work stoppages and other labor disputes; |
| • | latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions; |
| • | financial or other difficulties at shipyards and suppliers; |
| • | acts of war; |
| • | 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. Some of our risks are concentrated because our four drillships currently under construction are located at one shipyard in South Korea. Delays in the delivery of rigs being constructed or undergoing upgrade, refurbishment or repair may, in many cases, result in delay in contract commencement, resulting in a loss of revenue to us, and may also cause our customer to renegotiate the drilling contract for the rig or terminate or shorten the term of the contract under applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms, if at all. Additionally, capital expenditures for rig upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our rigs undergoing upgrade, refurbishment and repair may not earn a dayrate during the period they are out of service.
An oversupply of comparable or higher specification rigs in the markets in which we compete could depress the demand and contract prices for our rigs and materially reduce our revenues and profitability.
Demand and contract prices customers pay for our rigs also are affected by the total supply of comparable rigs available for service in the markets in which we compete. During prior periods of high utilization and dayrates, industry participants have increased the supply of rigs by ordering the construction of new units. This has often created an oversupply of drilling units and has caused a decline in utilization and dayrates when the rigs enter the market, sometimes for extended periods of time as rigs have been absorbed into the active fleet. A total of approximately 45 new jackup rigs entered the market in 2007 and 2008, and approximately 73 jackup rigs are on order or under construction with delivery dates ranging from 2009 to 2011. Most of these units are cantilevered units and are considered to be of a higher specification than our jackup rig fleet, because they generally are larger, have greater deckloads and have water depth ratings of 300 feet or greater. In addition, independent leg rigs are more commonly accepted by exploration and production companies outside the United States. In the deepwater sector, four drillships and five new semi-submersible rigs entered the market in 2007 and 2008, and there have been announcements of approximately 92 new semisubmersible rigs and drillships, including our four drillship construction projects, with delivery forecasted to occur from 2009 through 2012. A number of the contracts for units currently under construction provide for options for the construction of additional units, and further new construction announcements may occur for all classes of rigs pursuant to the exercise of one or more of these options and otherwise. Not all of the rigs currently under construction have been contracted for future work, which may intensify price competition as scheduled delivery dates occur. In addition, our and our competitors’ rigs that are “stacked” (i.e., minimally crewed with little or no scheduled maintenance being performed) may re-enter the
12
market. The entry into service of newly constructed, upgraded or reactivated units will increase marketed supply and could reduce, or curtail a strengthening of, dayrates in the affected markets as rigs are absorbed into the active fleet. Any further increase in construction of new drilling units may negatively affect utilization and dayrates. In addition, the new construction of high specification rigs, as well as changes in our competitors’ drilling rig fleets, could require us to make material additional capital investments to keep our rig fleet competitive.
Our industry is highly competitive and cyclical, with intense price competition.
Our industry is highly competitive. Our contracts are traditionally awarded on a competitive bid basis. Pricing, safety record and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical ability also can be significant factors in the determination. Some of our competitors in the drilling industry are larger than we are and have more diverse fleets, or fleets with generally higher specifications, and greater resources than we have. Some of these competitors also are incorporated in tax-haven countries outside the United States, which provides them with significant tax advantages that are not available to us as a U.S. company and which may materially impair our ability to compete with them for many projects that would be beneficial to our company. In addition, recent mergers within the oil and natural gas industry have reduced the number of available customers, resulting in increased competition for projects. We may not be able to maintain our competitive position, and we believe that competition for contracts will continue to be intense in the foreseeable future. Our inability to compete successfully may reduce our revenues and profitability.
Historically, the offshore service industry has been highly cyclical, with periods of high demand, limited rig supply and high dayrates often followed by periods of low demand, excess rig supply and low dayrates. Periods of low demand and excess rig supply intensify the competition in the industry and often result in rigs, particularly lower specification rigs like a large portion of our fleet, being idle for long periods of time. We may be required to stack rigs or enter into lower dayrate contracts in response to market conditions. Prolonged periods of low utilization and dayrates could result in the recognition of impairment charges on certain of our rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.
Consolidation of suppliers may limit our ability to obtain supplies and services at an acceptable cost, on our schedule or at all.
Our operations rely on a significant supply of capital and consumable spare parts and equipment to maintain and repair our fleet. We also rely on the supply of ancillary services, including supply boats and helicopters. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing of key supplies and services. We may not be able to obtain supplies and services at an acceptable cost, at the times we need them or at all. These cost increases, delays or unavailability could negatively impact our future operations and result in increases in rig downtime, and delays in the repair and maintenance of our fleet.
Failure to attract and retain skilled personnel or an increase in labor costs could hurt our operations.
We require highly skilled personnel to operate and provide technical services and support for our business. Competition for the skilled and other labor required for our operations intensifies as the number of rigs activated or added to worldwide fleets or under construction increases, creating upward pressure on wages. In periods of high utilization, 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 since 2005 and, while we expect this trend to moderate in 2009, shortages of certain skilled positions and in certain geographic locations may continue. The shortages of qualified personnel or the inability to obtain and retain qualified personnel could negatively affect the quality, safety and timeliness of our work. In addition, our ability to crew our four new drillships and to expand our deepwater operations depends in part upon our ability to increase the size of our skilled labor force. We have intensified our recruitment and training programs in an effort to meet our anticipated personnel needs. These efforts may be unsuccessful, and competition for skilled personnel could materially impact our business by limiting or affecting the quality and safety of our operations or further increasing our costs.
13
Our international operations involve additional risks not generally associated with domestic operations, which may hurt our operations materially.
In 2008, we derived 86% of our revenues from countries outside the United States. Our operations in these areas are subject to the following risks, among others:
| • | foreign currency fluctuations and devaluations; |
| • | restrictions on currency or capital repatriation; |
| • | political, social and economic instability, war and civil disturbances; |
| • | seizure, expropriation or nationalization of assets or confiscatory taxation; |
| • | significant governmental influence over many aspects of local economies; |
| • | unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws; |
| • | work stoppages; |
| • | damage to our equipment or violence directed at our employees, including kidnappings; |
| • | complications associated with repairing and replacing equipment in remote locations; |
| • | repudiation, nullification, modification or renegotiation of contracts; |
| • | limitations on insurance coverage, such as war risk coverage, in certain areas; |
| • | piracy; |
| • | imposition of trade barriers; |
| • | wage and price controls; |
| • | import-export quotas; |
| • | 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; |
| • | acts of terrorism; and |
| • | other forms of government regulation and economic conditions that are beyond our control. |
We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not take protective measures against exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment in U.S. dollars or freely convertible foreign currency. To the extent possible, we seek to limit our exposure to local currencies by matching the acceptance of local currencies to our expense requirements in those currencies. Although we have done this in the past, we may not be able to take these actions in the future, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate materially.
14
Our ability to compete in international contract drilling markets may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, our foreign subsidiaries may face governmentally imposed restrictions from time to time on their ability to transfer funds to us. Finally, governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems which are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
Although we implement policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate, our employees, contractors and agents may take actions in violation of our policies and such laws. Any such violation, even if prohibited by our policies, could materially and adversely affect our business.
We are conducting an investigation into allegations of improper payments to foreign government officials, as well as corresponding accounting entries and internal control issues. The outcome and impact of this investigation are unknown at this time.
During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.
The investigation, which is continuing, has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.
15
The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations. In addition, the U.S. Department of Justice has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria. The Audit Committee is reviewing the issues raised by the request, and we are cooperating with the DOJ in connection with its request.
This review has found evidence suggesting that during the period from 2001 through 2006 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola, and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2.5 million. We are also reviewing certain agent payments related to Malaysia.
The investigation of the matters described in the prior paragraph and the Audit Committee’s compliance review are ongoing. Accordingly, there can be no assurances that evidence of additional potential FCPA violations may not be uncovered in those or other countries.
Our management and the Audit Committee of our Board of Directors believe it likely that then members of our senior operations management either were aware, or should have been aware, that improper payments to foreign government officials were made or proposed to be made. Our former Chief Operating Officer resigned as Chief Operating Officer effective on May 31, 2006 and has elected to retire from the company, although he will remain an employee, but not an officer, during the pendency of the investigation to assist us with the investigation and to be available for consultation and to answer questions relating to our business. His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the Securities and Exchange Commission and are cooperating with these authorities as the investigation and compliance reviews continue and as they review the matter. If violations of the FCPA occurred, we could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.
We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company. 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, claims or other penalties, which could be material individually or in the aggregate.
We cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, any other applicable government or other authorities or our customers or other third parties or the effect the actions may have on our results of operations,
16
financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.
If we are unable to renew or obtain new and favorable contracts for rigs whose contracts are expiring or are terminated, our revenues and profitability could be materially reduced.
We have a number of contracts that will expire in 2009 and 2010. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the dayrates under any new contracts may be substantially below the existing dayrates, which could materially reduce our revenues and profitability.
Many of our contracts with our customers for our offshore rigs are long-term dayrate contracts. Increases in our costs, which are unpredictable and fluctuate based on events outside our control, could adversely impact our profitability.
In periods of rising demand for offshore rigs, a drilling contractor generally would prefer to enter into well-to-well or other shorter term contracts that would allow the contractor to profit from increasing dayrates, while customers with reasonably definite drilling programs would typically prefer longer term contracts in order to maintain dayrates at a consistent level. Conversely, in periods of decreasing demand for offshore rigs, a drilling contractor generally would prefer longer term contracts to preserve dayrates and utilization, while customers generally would prefer well-to-well or other shorter term contracts that would allow the customer to benefit from the decreasing dayrates. In 2008, a majority of our revenue was derived from long-term dayrate contracts, and substantially all of our backlog as of December 31, 2008 was attributable to long-term dayrate contracts. As a result, our inability to fully benefit from increasing dayrates in an improving market may limit our profitability.
In general, our costs increase as the business environment for drilling services improves and demand for oilfield equipment and skilled labor increases. While many of our contracts include escalation provisions that allow us to increase the dayrate based on stipulated costs increases, the timing and amount earned from these dayrate increases may differ from our actual increase in costs. Additionally, if our rigs incur idle time between contracts, we typically do not remove personnel from those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.
Our current backlog of contract drilling revenue may not be ultimately realized.
As of December 31, 2008, our contract drilling backlog was approximately $8.6 billion for future revenues under firm commitments. We may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, including those described above or in connection with the ongoing financial crisis. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.
Our jackup rigs and some of our lower specification semisubmersible rigs are at a relative disadvantage to higher specification jackup and semisubmersible rigs. These higher specification rigs may be more likely to obtain contracts than our lower specification rigs, particularly during market downturns.
Some of our competitors have jackup fleets with generally higher specification rigs than those in our jackup fleet, and our fleet includes a number of older and/or lower specification semisubmersible rigs. In addition, the
17
announced construction of approximately 165 new rigs includes jackup rigs, semisubmersible rigs and deepwater drillships. Particularly during market downturns when there is decreased rig demand, higher specification rigs may be more likely to obtain contracts than lower specification rigs. Some of our significant customers may also begin to require higher specification rigs for the types of projects that currently utilize our lower specification rigs, which could materially affect their utilization. In the past, our lower specification rigs have been stacked earlier in the cycle of decreased rig demand than many of our competitors’ higher specification rigs and have been reactivated later in the cycle, which has adversely impacted our business and could be repeated in the future. In addition, higher specification rigs may be more adaptable to different operating conditions and have greater flexibility to move to areas of demand in response to changes in market conditions. Furthermore, in recent years, an increasing amount of exploration and production expenditures have been concentrated in deeper water drilling programs and deeper formations, including deep natural gas prospects, requiring higher specification rigs. This trend is expected to continue and could result in a material decline in demand for the lower specification rigs in our fleet.
Our ability to move some of our rigs to other regions is limited.
Most jackup and semisubmersible rigs and drillships 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 these rigs may vary somewhat from region to region because the cost to move a rig is significant, there is limited availability of rig-moving vessels and some rigs are designed to work in specific regions. However, significant variations between regions tend not to exist on a long-term basis due to the ability to move rigs. Our mat-supported jackup rigs are less capable than independent leg jackup rigs of managing variable sea floor conditions found in most areas outside the Gulf of Mexico. As a result, our ability to move these rigs to other regions in response to changes in market conditions is limited.
We rely heavily on a small number of customers. 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, 2008, our four largest customers provided approximately 58% of our consolidated revenues. Our results of operations could be materially adversely affected if any of our major customers terminates its contracts with us, fails to renew its existing contracts or refuses to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates.
Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2008, we had $723.2 million in debt. This debt represented approximately 14% of our total capitalization. Our current indebtedness may have several important effects on our future operations, including:
| • | a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes; |
| • | covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities; and |
| • | our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited. |
Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our four drillship construction projects, will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations
18
and contractual commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings.
We are subject to a number of operating hazards, including those specific to marine operations. We may not have insurance to cover all these hazards.
Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punchthroughs, craterings, fires, explosions and pollution. Contract drilling and well servicing require the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages. We customarily provide contract indemnity to our customers for:
| • | claims that could be asserted by us relating to damage to or loss of our equipment, including rigs; |
| • | claims that could be asserted by us or our employees relating to personal injury or loss of life; and |
| • | legal and financial consequences of spills of industrial waste and other liquids, but generally 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. For example, in September 2008, one of our mat-supported jackup rigs operating in the U.S. Gulf of Mexico, the Pride Wyoming, was lost as a result of Hurricane Ike. In addition, damage caused by high winds and turbulent seas to our rigs, our shorebases and our corporate infrastructure could potentially cause us to curtail operations for significant periods of time until the damages can be repaired.
We maintain insurance for injuries to our employees, damage to or loss of our equipment and other insurance coverage for normal business risks, including general liability insurance. Any insurance protection may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. For example, pollution, reservoir damage and environmental risks generally are not fully insurable. Except for a portion of our deepwater fleet, we generally do not maintain business interruption or loss of hire insurance. In addition, some of our primary insurance policies have substantial per occurrence or annual deductibles and/or self-insured aggregate amounts.
As a result of a number of catastrophic events over the last few years, such as the hurricanes in the Gulf of Mexico, insurance underwriters have increased insurance premiums for many of the coverages historically maintained and made significant changes to a wide variety of insurance coverages. The oil and natural gas industry in the Gulf of Mexico suffered extensive damage from those hurricanes. As a result, our insurance costs and our deductibles have increased significantly. Our insurance policy has a $10 million aggregate deductible, and a $10 million per occurrence deductible. In addition, the marine package policy has a sub-limit of $110 million for physical damage claims due to a named windstorm in the U.S. Gulf of Mexico. A number of our customers that produce oil and natural gas in the Gulf of Mexico have maintained business interruption insurance for their production. This insurance may cease to be available in the future, which could adversely impact our customers’ business prospects in the Gulf of Mexico and reduce demand for our services. It is unclear what actions insurance underwriters will take as a result of the 2008 hurricane season.
19
The occurrence of a significant event against which we are not fully insured, or of a number of lesser events against which we are insured but are subject to substantial deductibles, aggregate limits, and/or self-insured amounts, could materially increase our costs and impair our profitability and financial condition. We may not be able to maintain adequate insurance at rates or on terms that we consider reasonable or acceptable or be able to obtain insurance against certain risks.
We are responsible for costs and awards relating to the loss of the Pride Wyoming that are not covered by our insurance.
In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig operating in the U.S. Gulf of Mexico, was deemed a total loss for insurance purposes after it was severely damaged and sank as a result of Hurricane Ike. We expect to incur costs of approximately $48.6 million for removal of the wreckage and salvage operations, not including any costs arising from damage to offshore structures owned by third parties. These costs for removal of the wreckage and salvage operations in excess of a $1 million retention are expected to be covered by our insurance. We will be responsible for payment of the $1 million retention, $2.5 million in premium payments for a removal of wreckage claim and for any costs not covered by our insurance.
The owners of two pipelines on which parts of the Pride Wyoming settled have requested that we pay for all costs, expenses and other losses associated with the damage, including loss of revenue. Each owner has claimed damages in excess of $40 million. Other pieces of the rig may have also caused damage to certain other offshore structures. In October 2008, we filed a complaint in the U.S. Federal District Court pursuant to the Limitation of Liability Act, which has the potential to statutorily limit our exposure for claims arising out of third-party damages caused by the loss of the Pride Wyoming. We will be responsible for any awards not covered by our insurance.
We may not be able to maintain or replace our rigs as they age.
The capital associated with the repair and maintenance of our fleet increases with age. We may not be able to maintain our fleet of existing rigs to compete effectively in the market, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement rigs.
We may incur substantial costs associated with workforce reductions.
In many of the countries in which we operate, our workforce has certain compensation and other rights arising from our various collective bargaining agreements and from statutory requirements of those countries relating to involuntary terminations. If we choose to cease operations in one of those countries or if market conditions reduce the demand for our drilling services in such a country, we could incur costs, which may be material, associated with workforce reductions.
Failure to secure a drilling contract prior to deployment of the uncontracted drillship under construction or any other rigs we may construct in the future prior to their deployment could adversely affect our future results of operations.
Three of our four drillships under construction have long-term drilling contracts. The drillship remaining to be contracted is scheduled for delivery in the fourth quarter of 2011. We have not yet obtained a drilling contract for this drillship. In addition, we may commence the construction of additional rigs for our fleet from time to time without first obtaining a drilling contract covering any such rig. Our failure to secure a drilling contract for any rig under construction, including our remaining uncontracted drillship construction project, prior to its deployment could adversely affect our results of operations and financial condition.
New technologies may cause our current drilling methods to become obsolete, resulting in an adverse effect on our business.
The offshore contract drilling industry is subject to the introduction of new drilling techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies, we may be placed at a competitive disadvantage and competitive pressures may force us to implement new technologies at substantial cost. In addition, competitors may have greater financial, technical and
20
personnel resources that allow them to benefit from technological advantages and implement new technologies before we can. We may not be able to implement technologies on a timely basis or at a cost that is acceptable to us.
Our customers may be unable or unwilling to indemnify us.
Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These risks are those associated with the loss of control of a well, such as blowout or cratering, the cost to regain control or redrill the well and associated pollution. There can be no assurance, however, that these customers will necessarily be willing or financially able to indemnify us against all these risks. Also, we may choose not to enforce these indemnities because of the nature of our relationship with some of our larger customers.
We are subject to numerous governmental laws and regulations, including those that may impose significant costs and liability on us for environmental and natural resource damages.
Many aspects of our operations are affected by governmental laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring us to obtain and maintain specified permits or other governmental approvals and to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. Our operations and activities in the United States are subject to numerous environmental laws and regulations, including the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation, and Liability Act and the International Convention for the Prevention of Pollution from Ships. Additionally, other countries where we operate have adopted, and could in the future adopt additional, environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment that could be applicable to our 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 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. In May 2006 and April 2007, the MMS issued interim guidelines for jackup rig fitness requirements for the 2006 and 2007 hurricane seasons, 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. Effective June 2008, the MMS issued longer-term guidelines, generally consistent with the interim guidelines, for jackup rig fitness requirements during hurricane seasons. The June 2008 guidelines are scheduled to be effective through the 2013 hurricane season. As a result of these MMS guidelines, our jackup rigs operating in the U.S. Gulf of Mexico are being required to operate with a higher air gap (the space between the water level and the bottom of the rig’s hull) during the hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and natural gas companies operating properties in the U.S. Gulf of Mexico. The MMS 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 the MMS guidelines or regulations may subject us to increased costs and limit the operational capabilities of our rigs.
21
A change in tax laws of any country in which we operate could result in a higher tax expense or a higher effective tax rate on our worldwide earnings.
We conduct our worldwide operations through various subsidiaries. Tax laws and regulations are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, treaties and regulations in and between countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, treaties or regulations, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings.
As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We are currently contesting several tax assessments that could be material and may contest future assessments where we believe the assessments are in error. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.
We have received and are contesting tax assessments from the Mexican government, and we could receive additional assessments in the future.
In 2006, we received tax assessments from the Mexican government related to the operations of certain entities for the tax years 2001 through 2003. As required by statutory requirements, we have provided bonds totaling approximately 555 million pesos, or approximately $40 million, as of December 31, 2008 to contest these assessments. In February 2009, we received additional tax assessments for the tax years 2003 and 2004 in the amount of 1,097 million pesos, or approximately $74 million. Bonds for these assessments are to be provided later in 2009. These assessments contest our right to claim certain deductions. While we intend to contest these assessments vigorously, we cannot predict or provide assurance as to the ultimate outcome, which may take several years. Additional bonds will need to be provided to the extent future assessments are contested. We anticipate that the Mexican government will make additional assessments contesting similar deductions for other tax years or entities.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees in international markets are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues 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.
Public health threats could have a material adverse effect on our operations and our financial results.
Public health threats, such as the bird flu, Severe Acute Respiratory Syndrome (SARS) and other highly communicable diseases, could adversely impact our operations, the operations of our clients and the global economy in general, including the worldwide demand for crude 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.
22
Risk Factors About Our Proposed Spin-Off
The planned spin-off of our mat-supported jackup rig business is contingent upon the satisfaction of a number of conditions, may require significant time and attention of our management and may not achieve the intended results.
We have filed a Form 10 registration statement with the Securities and Exchange Commission with respect to the distribution to our stockholders of all of the shares of common stock of a subsidiary that would hold, directly or indirectly, the assets and liabilities of our 20-rig mat-supported jackup business. The spin-off is contingent upon approval of the final plan by the board of directors, a favorable ruling from the Internal Revenue Service, the effectiveness of the Form 10 registration statement, compliance with covenants under our existing debt agreements and other conditions. For these and other reasons, the spin-off may not be completed. Additionally, execution of the proposed spin-off will likely continue to require significant time and attention of our management, which could distract management from the operation of our business and the execution of our other strategic initiatives. Further, if the spin-off is completed, it may not achieve the intended results.
In connection with the spin-off of our mat-supported jackup rig business, the spin-off company will indemnify us for certain liabilities. However, the indemnity may not be sufficient to insure us against the full amount of such liabilities, and the spin-off company’s ability to satisfy its indemnification obligations may be impaired in the future.
Pursuant to a separation agreement we will enter into with the spin-off company, that company will agree to indemnify us from certain liabilities after the spin-off. However, third parties could seek to hold us responsible for any of the liabilities that the spin-off company has agreed to assume. In addition, the indemnity may not be sufficient to protect us against the full amount of such liabilities, and the spin-off company may not be able to fully satisfy its indemnification obligations to us. Moreover, even if we ultimately succeed in recovering from the spin-off company any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks could adversely affect our business, results of operations and financial condition.
If certain internal restructuring transactions and the spin-off of our mat-supported jackup rig business are determined to be taxable for U.S. federal income tax purposes, we and our stockholders that are subject to U.S. federal income tax could incur significant U.S. federal income tax liabilities.
We anticipate that certain internal restructuring transactions will be undertaken in preparation for the spin-off of our mat-supported jackup rig business. These transactions are complex and could cause us to incur significant tax liabilities. We intend to request a ruling from the Internal Revenue Service that these transactions and the spin-off qualify for favorable tax treatment. In addition, we expect to obtain an opinion of tax counsel confirming the favorable tax treatment of these transactions and the spin-off. The ruling and the opinion will rely on certain facts, assumptions, representations and undertakings from us regarding the past and future conduct of our businesses and other matters. If any of these are incorrect or not otherwise satisfied, then we and our stockholders may not be able to rely on the ruling or the opinion and could be subject to significant tax liabilities. Notwithstanding the ruling and the opinion, the Internal Revenue Service could determine on audit that the spin-off or the internal restructuring transactions should be treated as taxable transactions if it determines that any of these facts, assumptions, representations or undertakings are not correct or have been violated, or if the spin-off should become taxable for other reasons, including as a result of significant changes in stock ownership after the spin-off.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
Our property consists primarily of mobile offshore drilling rigs and ancillary equipment, most of which we own. Two of our rigs are pledged with respect to our notes guaranteed by the United States Maritime Administration. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in Item 7 of this annual report.
23
We own or lease office and operating facilities in Houston, Texas, Houma, Louisiana and in Angola, Brazil, Mexico, France, Dubai and several additional international locations.
We incorporate by reference in response to this item the information set forth in Item 1 and Item 7 of this annual report and the information set forth in Notes 4 and 5 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report.
FCPA Investigation
We incorporate by reference in response to this item the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — FCPA Investigation” in Item 7 of this annual report.
Other Legal Proceedings
Since 2004, certain of our subsidiaries have been named, along with numerous other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi by several hundred individuals that allege that they were employed by some of the named defendants between approximately 1965 and 1986. The complaints allege that certain drilling contractors used products containing asbestos in their operations and seek, among other things, an award of unspecified compensatory and punitive damages. Nine individuals of the many plaintiffs in these suits have been identified as allegedly having worked for us. A trial is set for one of the claimants in October 2009. 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.
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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
We have presented below information about our executive officers as of February 23, 2009. Officers are appointed annually by the Board of Directors and serve until their successors are chosen or until their resignation or removal.
| Name | Age | Position |
| Louis A. Raspino | 56 | President, Chief Executive Officer |
| Rodney W. Eads | 57 | Executive Vice President, Chief Operating Officer |
| Brian C. Voegele | 49 | Senior Vice President and Chief Financial Officer |
| Lonnie D. Bane | 50 | Senior Vice President, Human Resources and Administration |
| W. Gregory Looser | 39 | Senior Vice President – Legal, Information Strategy, General Counsel and Secretary |
| Kevin C. Robert | 50 | Senior Vice President, Marketing and Business Development |
| Randall D. Stilley | 55 | Chief Executive Officer – Seahawk Drilling Division |
Louis A. Raspino was named President, Chief Executive Officer and a Director in June 2005. He joined us in December 2003 as Executive Vice President and Chief Financial Officer. From July 2001 until December 2003, he served as Senior Vice President, Finance and Chief Financial Officer of Grant Prideco, Inc. From February 1999
24
until March 2001, he held various senior financial positions, including Vice President of Finance for Halliburton Company. From October 1997 until July 1998, he was a Senior Vice President at Burlington Resources, Inc. From 1978 until its merger with Burlington Resources, Inc. in 1997, he held a variety of increasingly responsible positions at Louisiana Land and Exploration Company, most recently as Senior Vice President, Finance and Administration and Chief Financial Officer. Mr. Raspino also is a Director of Dresser-Rand Group Inc.
Rodney W. Eads was named Executive Vice President, Chief Operating Officer in September 2006. Since 1997, he served as Senior Vice President, Worldwide Operations for Diamond Offshore, where he was responsible for their offshore drilling fleet. From 1980 through 1997 he served in several executive and operations management positions with Exxon Corporation, primarily in international assignments and including Drilling Manager, Exxon Company International. Prior to joining Exxon, Mr. Eads served as a Senior Drilling Engineer for ARAMCO and a Petroleum Engineer with Cities Services Corporation.
Brian C. Voegele joined us in December 2005 and became our Senior Vice President and Chief Financial Officer in January 2006. From June 2005 through November 2005, he served as Senior Vice President, Chief Financial Officer, Treasurer and Secretary of Bristow Group (formerly Offshore Logistics, Inc.). From July 1989 until January 2005, he held various senior management positions at Transocean Inc. Mr. Voegele began his career at Arthur Young & Co., where he ultimately served as Tax Manager.
Lonnie D. Bane was named Senior Vice President, Human Resources and Administration 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 became our Senior Vice President—Legal, Information Strategy, General Counsel and Secretary in June 2008. Since January 2005, he was Senior Vice President, General Counsel and Secretary, and since December 2003 he was Vice President, General Counsel and Secretary. He joined us in May 1999 as Assistant General Counsel. Prior to that time, Mr. Looser was with the law firm of Bracewell & Guiliani LLP in Houston, Texas.
Kevin C. Robert was named Vice President, Marketing in March 2005 and became Senior Vice President, Marketing and Business Development in May 2006. Prior to joining us, from June 2002 to February 2005, Mr. Robert worked for Samsung Heavy Industries as the Vice President, EPIC Contracts. From January 2001 through September 2001, Mr. Robert was employed by Marine Drilling Companies, Inc. as the Vice President, Marketing. When we acquired Marine in September 2001, he became our Director of Business Development, where he served until June 2002. From November 1997 through December 2000, Mr. Robert was Managing Member of Maverick Offshore L.L.C. From January 1981 to November 1997, Mr. Robert was employed by Conoco Inc.
Randall D. Stilley has served as our Chief Executive Officer — Seahawk Drilling Division (which consists of the operations in our mat-supported jackup business) since September 2008. Prior to joining us, from October 2004 to June 2008, Mr. Stilley was President and Chief Executive Officer of Hercules Offshore, Inc., an oilfield services company. From January 2004 to October 2004, Mr. Stilley was Chief Executive Officer of Seitel, Inc., an oilfield services company. From June 2008 to September 2008 and from 2000 until January 2004, Mr. Stilley was an independent business consultant and managed private investments. From 1997 until 2000, Mr. Stilley was President of the Oilfield Services Division at Weatherford International, Inc., an oilfield services company. Prior to joining Weatherford in 1997, Mr. Stilley served in a variety of positions at Halliburton Company, an oilfield services company. He is a registered professional engineer in the state of Texas and a member of the Society of Petroleum Engineers.
25
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 23, 2009, there were approximately 1,300 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:
| Price | ||||||||
| High | Low | |||||||
| 2007 | ||||||||
| First Quarter | $ | 31.58 | $ | 26.31 | ||||
| Second Quarter | 38.00 | 30.21 | ||||||
| Third Quarter | 40.44 | 31.04 | ||||||
| Fourth Quarter | 37.45 | 30.46 | ||||||
| 2008 | ||||||||
| First Quarter | $ | 37.24 | $ | 28.35 | ||||
| Second Quarter | 48.86 | 34.36 | ||||||
| Third Quarter | 47.00 | 27.18 | ||||||
| Fourth Quarter | 29.48 | 11.38 | ||||||
We have not paid any cash dividends on our common stock since becoming a publicly held corporation in September 1988. We currently do not have any plans to pay cash dividends on our common stock. In addition, in the event we elect to pay cash dividends in the future, our ability to pay such dividends could be limited by our existing financing arrangements.
Unregistered Sales of Equity Securities
None.
Issuer Purchases of Equity Securities
| Period | Total Number of Shares Purchased (1) | Average Price Paid Per Share | Total Number of Shares Purchased as Part of a Publicly Announced Plan (2) | Maximum Number of Shares That May Yet Be Purchased Under the Plan (2) | ||||||||||||
| October 1-31, 2008 | - | N/A | N/A | N/A | ||||||||||||
| November 1-30, 2008 | - | N/A | N/A | N/A | ||||||||||||
| December 1-31, 2008 | 3,077 | $ | 15.97 | N/A | N/A | |||||||||||
| Total | 3,077 | $ | 15.97 | N/A | N/A | |||||||||||
_____________
| (1) | Represents the surrender of shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock awards issued to employees under our stockholder-approved long-term incentive plan. |
| (2) | We did not have at any time during the quarter, and currently do not have, a share repurchase program in place. |
26
We have derived the following selected consolidated financial information as of December 31, 2008 and 2007, and for the years ended December 31, 2008, 2007 and 2006, 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, 2006, 2005 and 2004 and for the years ended December 31, 2005 and 2004 from consolidated financial information included our annual report on Form 10-K for the year ended December 31, 2007. During 2008, we reclassified the results of operations of our Eastern Hemisphere land rig operations to discontinued operations for all periods reported. See Note 2 to Notes to the Consolidated Financial Statements in Item 8 of this annual report. The selected consolidated financial information below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report and our audited consolidated financial statements and related notes included in Item 8 of this annual report.
| Year Ended December 31, | ||||||||||||||||||||
| 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||
| Statement of Operations Data: | ||||||||||||||||||||
| Revenues | $ | 2,310.4 | $ | 1,951.5 | $ | 1,518.8 | $ | 1,201.0 | $ | 1,057.1 | ||||||||||
| Operating costs, excluding depreciation and amortization | 1,127.9 | 966.7 | 887.9 | 779.9 | 641.6 | |||||||||||||||
| Depreciation and amortization | 206.5 | 215.3 | 188.0 | 174.3 | 181.0 | |||||||||||||||
General and administrative, excluding depreciation and amortization amortization | 130.6 | 138.1 | 105.8 | 81.2 | 60.2 | |||||||||||||||
| Impairment charges | - | - | 0.5 | 1.0 | 8.1 | |||||||||||||||
| Gain on sales of assets, net | (24.1 | ) | (30.5 | ) | (28.6 | ) | (31.5 | ) | (48.2 | ) | ||||||||||
| Earnings from operations | 869.5 | 661.9 | 365.2 | 196.1 | 214.4 | |||||||||||||||
| Interest expense | (18.5 | ) | (73.3 | ) | (78.2 | ) | (87.7 | ) | (102.3 | ) | ||||||||||
| Refinancing charges | (2.3 | ) | - | - | - | (36.3 | ) | |||||||||||||
| Interest income | 17.5 | 14.4 | 4.2 | 1.8 | 1.8 | |||||||||||||||
| Other income (expense), net | 17.4 | (3.4 | ) | 0.9 | 1.9 | 1.6 | ||||||||||||||
Income from continuing operations before income taxes and minority interest | 883.6 | 599.6 | 292.1 | 112.1 | 79.2 | |||||||||||||||
| Income taxes | (217.2 | ) | (172.3 | ) | (117.4 | ) | (45.6 | ) | (35.2 | ) | ||||||||||
| Minority interest | - | (3.5 | ) | (4.1 | ) | (19.6 | ) | (24.5 | ) | |||||||||||
| Income from continuing operations, net of tax | $ | 666.4 | $ | 423.8 | $ | 170.6 | $ | 46.9 | $ | 19.5 | ||||||||||
| Income from continuing operations per share: | ||||||||||||||||||||
| Basic | $ | 3.91 | $ | 2.56 | $ | 1.05 | $ | 0.31 | $ | 0.14 | ||||||||||
| Diluted | $ | 3.81 | $ | 2.41 | $ | 1.01 | $ | 0.30 | $ | 0.14 | ||||||||||
| Shares used in per share calculations: | ||||||||||||||||||||
| Basic | 170.6 | 165.6 | 162.8 | 152.5 | 135.8 | |||||||||||||||
| Diluted | 175.6 | 178.5 | 176.5 | 160.9 | 137.3 | |||||||||||||||
| December 31, | ||||||||||||||||||||
| 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Balance Sheet Data: | ||||||||||||||||||||
| Working capital | $ | 849.6 | $ | 888.0 | $ | 293.1 | $ | 213.8 | $ | 130.5 | ||||||||||
| Property and equipment, net | 4,588.9 | 4,019.7 | 4,000.1 | 3,181.7 | 3,281.8 | |||||||||||||||
| Total assets | 6,065.0 | 5,613.9 | 5,097.5 | 4,086.5 | 4,042.0 | |||||||||||||||
| Long-term debt, net of current portion | 692.9 | 1,115.7 | 1,294.7 | 1,187.3 | 1,685.9 | |||||||||||||||
| Stockholders’ equity | 4,397.4 | 3,470.4 | 2,633.9 | 2,259.4 | 1,716.3 | |||||||||||||||
27
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Financial Statement and Supplementary Data” in Item 8 of this annual report. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A and elsewhere in this annual report. See “Forward-Looking Statements” below.
Overview
We are one of the world’s largest offshore drilling contractors operating, as of February 2, 2009, a fleet of 44 rigs, consisting of two ultra-deepwater drillships, 12 semisubmersible rigs, 27 jackups and three managed deepwater drilling rigs. We also have four ultra-deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.
We are continuing to increase our emphasis on deepwater drilling. Although crude oil demand and prices have declined recently, we believe the long-term prospects for deepwater drilling are positive given that the expected growth in oil consumption from developing nations, limited growth in crude oil supplies and high depletion rates of mature oil fields, together with geologic successes, improving access to promising offshore areas and new, more efficient technologies, will continue to be catalysts for the exploration and development of deepwater fields. Since 2005, we have invested or committed to invest over $3.6 billion in the expansion of our deepwater fleet, including four new ultra-deepwater drillships under construction. Three of the drillships have multiyear contracts at favorable rates, with two scheduled to work in the strategically important deepwater U.S. Gulf of Mexico, which in addition to our operations in Brazil and West Africa, provides us with exposure to all three of the world’s most active deepwater basins. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, to enable us to reinvest our financial and human capital to deepwater drilling. Our transition to a pure offshore focused company is essentially complete.
We expect that our customers will lower exploration and development spending in 2009 due to the current economic downturn. However, we anticipate that deepwater activity will outperform other drilling sectors due to the long-term field development activities of our customers and more favorable drilling economics. Our contract backlog at December 31, 2008 totals $8.6 billion and is comprised primarily of contracts with large integrated oil and national oil companies with long-term development plans. With our low debt levels relative to our total capitalization, we believe that we have sufficient financial resources to sustain our focus through this economic downturn.
Recent Developments
Investments in Deepwater Fleet
In June 2007, we entered into an agreement with Samsung Heavy Industries Co., Ltd. to construct an advanced-capability ultra-deepwater drillship. The agreement provides for an aggregate fixed purchase price of approximately $612 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before June 30, 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. We have entered into a five-year contract with respect to the drillship, which is expected to commence during the fourth quarter of 2010 following the completion of shipyard construction, mobilization of the rig to an initial operating location and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to provide enhanced capabilities designed to allow our clients to conduct subsea construction activities and other simultaneous activities, while drilling or completing the well. Including these modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $725 million, excluding capitalized interest. In addition, while we have previously purchased a license to equip the rig for dual-activity
28
use, the rig will not initially be functional as a dual-activity rig, but can be modified to add this functionality in the future.
In July 2007, we acquired from Lexton Shipping Ltd. an advanced-capability ultra-deepwater drillship being constructed by Samsung. As consideration for our acquisition of Lexton’s rights under the drillship construction contract with Samsung, we paid Lexton $108.5 million in cash and assumed its obligations under the construction contract, including remaining scheduled payments of approximately $540 million. The construction contract provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before February 28, 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. We have entered into a five-year contract with respect to the drillship, which is expected to commence during the third quarter of 2010 following the completion of shipyard construction, mobilization of the rig to the U.S. Gulf of Mexico and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to provide enhanced capabilities designed to allow our clients to conduct subsea construction activities and other simultaneous activities, while drilling or completing the well. Including these modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $730 million, excluding capitalized interest.
In August 2007, we acquired the remaining nine percent interest in our Angolan joint venture company for $45 million in cash from a subsidiary of Sonangol, the national oil company of Angola. The joint venture owned the two ultra-deepwater drillships Pride Africa and Pride Angola and the 300 foot independent-leg jackup rig Pride Cabinda, and held management agreements for the deepwater platform rigs Kizomba A and Kizomba B.
In January 2008, we entered into an agreement with Samsung to construct an advanced-capability ultra-deepwater drillship. The agreement provides for an aggregate fixed purchase price of approximately $635 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before March 31, 2011. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from Samsung for delays during certain periods. We have entered into a multi-year drilling contract with respect to the drillship, which is expected to commence during the second quarter of 2011 following the completion of shipyard construction, mobilization of the rig and customer acceptance testing. Under the drilling contract, the customer may elect, by January 31, 2010, a firm contract term of at least five years and up to seven years in duration. We expect the total project cost, including commissioning and testing, to be approximately $720 million, excluding capitalized interest.
In August 2008, we entered into an agreement for the construction of a fourth ultra-deepwater drillship. The agreement provides for an aggregate fixed purchase price of approximately $655 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before the fourth quarter of 2011. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages for delays during certain periods. We expect the total project cost, including commissioning and testing, to be approximately $745 million, excluding capitalized interest. Although we currently do not have a drilling contract for this drillship, we expect that the anticipated long-term demand for deepwater drilling capacity should provide us with a number of opportunities to contract the rig prior to its delivery date.
Separation of Our Mat-Supported Jackup Business
We have filed a Form 10 registration statement with the Securities and Exchange Commission with respect to the distribution to our stockholders of all of the shares of common stock of a subsidiary that would hold, directly or indirectly, the assets and liabilities of our 20-rig mat-supported jackup business. We believe that the spin-off has the potential to facilitate our growth strategies and reduce our cost of capital, and to allow us to refine our focus and further enhance our reputation as a provider of deepwater drilling services. The spin-off, which we expect to complete in 2009, is contingent upon approval of the final plan by our board of directors, a favorable ruling from the Internal Revenue Service, the effectiveness of the Form 10 registration statement, compliance with covenants under our existing debt agreements and other conditions. There can be no assurance that we will complete the spin-off within that time period or at all. Following the spin-off, we will be focused on deepwater opportunities with a concentration of high-specification deepwater rigs, and the subsidiary will be focused on shallow water drilling in the Gulf of Mexico.
29
Dispositions
In February 2008, we completed the sale of our fleet of three self-erecting, tender-assist rigs for $213 million in cash. In connection with the sale, we are operating one of the rigs until its current contract is completed, which is anticipated to be in first quarter of 2009.
In May 2008, we sold our entire fleet of platform rigs and related land, buildings and equipment for $66 million in cash. In connection with the sale, we entered into lease agreements with the buyer to operate two platform rigs until their current contracts are completed, which is expected to occur in the second quarter of 2009. The leases require us to pay to the buyer all revenues from the operation of the rigs, less operating costs and a small per day management fee, which we retain.
In July 2008, we entered into agreements to sell our Eastern Hemisphere land rig business, which constituted our only remaining land drilling operations, for $95 million in cash. The sale of all but one of the rigs closed in the fourth quarter of 2008. We are leasing the remaining rig to the buyer until the sale of that rig is completed, which is expected to occur in the first half of 2009.
We have reclassified the historical results of operations of our former Latin America Land and E&P Services segments, which we sold for $1.0 billion in 2007, our three tender-assist rigs and our Eastern Hemisphere land rig operations to discontinued operations. Unless noted otherwise, the discussion and analysis that follows relates to our continuing operations only.
Loss of Pride Wyoming
In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig operating in the U.S. Gulf of Mexico, was deemed a total loss for insurance purposes after it was severely damaged and sank as a result of Hurricane Ike. The rig had a net book value of approximately $14 million and was insured for $45 million. We have collected a total of $25 million through October 2008 for the insured value of the rig, which is net of our loss retention of $20 million. We expect to incur costs of approximately $48.6 million for removal of the wreckage and salvage operations, not including any costs arising from damage to offshore structures owned by third parties. These costs for removal of the wreckage and salvage operations in excess of a $1 million retention are expected to be covered by our insurance. We will be responsible for payment of the $1 million retention, $2.5 million in premium payments for a removal of wreckage claim and for any costs not covered by our insurance.
The owners of two pipelines on which parts of the Pride Wyoming settled have requested that we pay for all costs, expenses and other losses associated with the damage, including loss of revenue. Each owner has claimed damages in excess of $40 million. Other pieces of the rig may have also caused damage to certain other offshore structures. In October 2008, we filed a complaint in the U.S. Federal District Court pursuant to the Limitation of Liability Act, which has the potential to statutorily limit our exposure for claims arising out of third-party damages caused by the loss of the Pride Wyoming. Based on information available to us at this time, we do not expect the outcome of this potential claim 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 potential claim. Although we believe we have adequate insurance, we will be responsible for any awards not covered by our insurance.
Redemption of Convertible Notes
In April 2008, we called for redemption all of the outstanding 3 1/4% Convertible Senior Notes Due 2033. The notes entitled the holders to elect to convert the notes into our common stock at a rate of 38.9045 shares of common stock per $1,000 principal amount of the notes (or approximately 11.7 million shares in the aggregate) prior to the redemption date. In accordance with the indenture governing the notes, we elected to retire our obligation on the notes tendered for conversion using a combination of cash and common stock. In connection with the retirement of the notes, we delivered to holders an aggregate of approximately $300.0 million in cash and approximately 5.0 million shares of common stock. With our common stock trading above the conversion price of $25.70 during the redemption period, our potential obligation to issue common stock upon conversion of the notes resulted in the inclusion of the full 11.7 million shares in our fully diluted share count. However, our delivery of approximately
30
$300.0 million in connection with the retirement of the principal amount of the notes reduced the number of shares delivered and essentially had the same effect as a share repurchase.
Drillship Loan Repayment
In March 2008, we repaid the outstanding aggregate principal amount of $138.9 million due under the drillship loan facility collaterized by the Pride Africa and Pride Angola. In connection with the retirement of the drillship loan facility, we recognized a charge of $1.2 million related to the write-off of unamortized debt issuance costs. We also settled all of the related interest rate swap and cap agreements.
FCPA Investigation
During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.
The investigation, which is continuing, has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.
The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations. In addition, the U.S. Department of Justice has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria. The Audit Committee is reviewing the issues raised by the request, and we are cooperating with the DOJ in connection with its request.
This review has found evidence suggesting that during the period from 2001 through 2006 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola, and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2.5 million. We are also reviewing certain agent payments related to Malaysia.
The investigation of the matters described in the prior paragraph and the Audit Committee’s compliance review are ongoing. Accordingly, there can be no assurances that evidence of additional potential FCPA violations may not be uncovered in those or other countries.
Our management and the Audit Committee of our Board of Directors believe it likely that then 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
31
available for consultation and to answer questions relating to our business. His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the Securities and Exchange Commission and are cooperating with these authorities as the investigation and compliance reviews continue and as they review the matter. If violations of the FCPA occurred, we could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.
We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company. 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, claims or other penalties, which could be material individually or in the aggregate.
We cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, any other applicable government or other authorities or our customers or other third parties or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.
Our Business
We provide contract drilling services to major integrated, government-owned and independent oil and natural gas companies throughout the world. Our drilling fleet competes on a global basis, as offshore rigs generally are highly mobile and may be moved from one region to another in response to demand. While the cost of moving a rig and the availability of rig-moving vessels may cause the supply and demand balance to vary somewhat between regions, significant variations between regions do not tend to persist long-term because of rig mobility. Key factors in determining which qualified contractor is awarded a contract include pricing, safety record and competency. Rig availability, location and technical ability can also be key factors in the determination. Currently, all of our drilling contracts with our customers are on a dayrate basis, where we charge the customer a fixed amount per day regardless of the number of days needed to drill the well. We provide the rigs and drilling crews and are responsible for the payment of rig operating and maintenance expenses. Our customer bears the economic risk and benefit relative to the geologic success of the wells.
The markets for our drilling services are highly cyclical. Our operating results are significantly affected by the level of energy industry spending for the exploration and development of crude oil and natural gas reserves. Oil and natural gas companies’ exploration and development drilling programs drive the demand for drilling services. These drilling programs are affected by oil and natural gas companies’ expectations regarding crude oil and natural gas prices, anticipated production levels, worldwide demand for crude oil and natural gas products and many other factors. The availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect our customers’ drilling
32
programs. Crude oil and natural gas prices are volatile, which has historically led to significant fluctuations in expenditures by our customers for oil and natural gas drilling services. Variations in market conditions during the cycle impact us in different ways depending primarily on the length of drilling contracts in different regions. For example, contracts in the shallow water U.S. Gulf of Mexico are shorter term, so a deterioration or improvement in market conditions tends to quickly impact revenues and cash flows from those operations. Contracts in deepwater and other international offshore markets tend to be longer term, so a change in market conditions tends to have a delayed impact. Accordingly, short-term changes in market conditions may have minimal short-term impact on revenues and cash flows from those operations unless the timing of contract renewals takes place during the short-term changes in the market.
Our revenues depend principally upon the number of our available rigs, the number of days these rigs are utilized and the contract dayrates received. The number of days our rigs are utilized and the contract dayrates received are largely dependent upon the balance of supply of drilling rigs and demand for drilling services for the different rig classes we operate, as well as our rigs’ operational performance, including mechanical efficiency. The number of rigs we have available may increase or decrease as a result of the acquisition or disposal of rigs, the construction of new rigs, the number of rigs being upgraded or repaired or undergoing periodic surveys or routine maintenance at any time and the number of rigs idled during periods of oversupply in the market or when we are unable to contract our rigs at economical rates. In order to improve utilization or realize higher contract day rates, we may mobilize our rigs from one geographic region to another for which we may receive a mobilization fee. Mobilization fees are deferred and recognized as revenue over the term of the contract.
Our earnings from operations are primarily affected by revenues, cost of labor, repairs and maintenance and utilization of our drilling fleet. Many of our drilling contracts allow us to adjust the dayrates charged to our customer based on changes in operating costs, such as increases in labor costs, maintenance and repair costs, and insurance costs. Some of our costs are fixed in nature or do not vary at the same time or to the same degree as changes in revenue. For instance, if a rig is expected to be idle between contracts and earn no revenue, we may maintain our rig crew, which reduces our earnings as we cannot fully offset the impact of the lost revenues with reductions in operating costs.
Our industry has been affected by shortages of, and competition for, skilled rig crew personnel due to the level of activity in the drilling industry, the aging workforce and the training and skill set of applicants. As a result, the costs to attract and retain certain skilled personnel may continue to increase. To better retain and attract skilled rig personnel, we offer competitive compensation programs and have increased our focus on training and management development programs. We believe that labor costs may continue to increase in 2009 for skilled personnel and in certain geographic locations. In addition, increased demand for contract drilling operations has increased demand for oilfield equipment and spare parts, which, when coupled with the consolidation of equipment suppliers, has resulted in longer order lead times to obtain critical spares and other critical equipment components essential to our business, higher repair and maintenance costs and longer out-of-service time for major repair and upgrade projects. We anticipate maintaining higher levels of critical spares to minimize unplanned downtime. With the decline in prices for steel and other key inputs and the decline in level of business activity, we believe that some softening of lead times and pricing for spare parts and equipment is likely to occur. The amount and timing of moderation of costs will be affected by our suppliers’ level of backlog and the number of remaining newbuilds.
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.
The decline in crude oil prices that began in late 2008, following the onset of the global financial crisis, deteriorating global economic fundamentals and the resulting decline in crude oil demand in a number of the world’s largest oil consuming nations, is expected to have a negative impact on 2009 offshore activity. Lower average crude oil prices resulting from declining global demand have resulted in some of our customers reducing 2009 planned expenditures for drilling activity, with this decline expected to be more pronounced in exploration activities, which are characterized by shorter term projects. However, deepwater drilling activity is expected to display more resilience relative to other offshore drilling activities, especially for projects currently in development. Typically,
33
utilization for the industry’s deepwater fleet has remained high even during market downturns due to the advanced technical features of the rigs and the limited supply of rigs capable of addressing the increasingly complex drilling projects of our clients. However, some clients could engage in subletting of rigs to other parties in an effort to reduce their capital commitments, which could drive lower the dayrates paid for deepwater rigs in 2009.
We believe that long-term market conditions for offshore drilling services are generally favorable and that demand for offshore rigs could continue to exceed supply for the next several years, producing attractive opportunities for offshore drilling rigs, including deepwater rigs such as ours under construction. We expect the long-term global demand for deepwater offshore contract drilling services to remain strong, driven by increasing worldwide demand for crude oil and natural gas when economic recovery begins, an increased focus by oil and natural gas companies on offshore prospects and increased global participation by national oil companies. Customer requirements for deepwater drilling capacity is steady, as successful results in exploration drilling have led to prolonged field development programs around the world, placing deepwater assets in limited supply beyond the end of the decade. We believe that long-term economic factors and demand for crude oil will lead to higher prices for crude oil in the future. With geological successes in exploratory markets, such as the Tupi field offshore Brazil, and, in general, more favorable conditions allowing international oil companies access to new field development, we believe exploration and production companies will continue to pursue the development of new deepwater projects and discoveries. In addition, we believe that the need for deepwater rigs will continue to grow for existing offshore development projects.
We organize our reportable segments based on the general asset class of our drilling rigs. Our reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths greater than 4,500 feet, and Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,500 feet or less. Our jackup fleet, which operates in water depths up to 300 feet, is reported as two segments, Independent Leg Jackups and Mat-Supported Jackups. We also manage the drilling operations for three deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations.
Our deepwater fleet currently operates in West Africa, Brazil and the Mediterranean Sea and we expect to expand into the strategically important U.S. Gulf of Mexico region in 2010 following the delivery of two of our four deepwater drillships currently under construction. Including rig days for our drillships under construction, based upon their scheduled delivery dates, we have 96% of our available rig days for our deepwater fleet contracted in 2009, 87% in 2010, 81% in 2011 and 67% in 2012. Customer demand for deepwater drilling rigs has increased steadily since 2005, with the industry’s fleet of 97 units experiencing full utilization through 2008 and deepwater rig shortages apparent since 2006. The high customer demand has led to a steep rise in deepwater rig dayrates, reaching $650,000 per day for some multi-year contracts agreed to during late 2008. The deepwater drilling business has been supported by strong geologic success, especially in Brazil and West Africa, and the emergence of new, promising deepwater regions, such as India, Libya and Mexico, along with advances in seismic gathering and interpretation and well completion technologies. These developments have contributed to record backlog levels and contracted rig utilization at or near 100% through the end of 2009, although we expect our revenues for the segment to be negatively impacted by approximately 14 days of unplanned downtime for the Pride North America in the first quarter of 2009. In addition, deepwater drilling economics have been aided in recent years by higher average crude oil prices, and an increased number of deepwater discoveries. These improving factors associated with deepwater activity have produced a growing base of development programs requiring multiple years to complete and resulting in long-term contract awards by our customers, especially for projects in Brazil, West Africa and the U.S. Gulf of Mexico, and represents a significant portion of our revenue backlog that currently extends into 2016.
Our midwater fleet currently operates offshore Africa and Brazil, and we expect this geographic presence to remain unchanged through 2009. We currently have 97% of our available rig days for our midwater fleet contracted in 2009, 70% in 2010, 64% in 2011 and 35% in 2012. Recently, demand for midwater rigs has been supported by increased customer needs in Brazil and in emerging locations such as Libya. We expect there will be an increase in subletting of rig time in 2009 following the decline in crude oil prices, which could affect contract renewals due to the increased rig availability. Many of the industry’s midwater rigs are utilized in mature offshore regions that are sensitive to crude oil price volatility, such as the North Sea. With the average remaining contract duration on a midwater rig at approximately two years, customers in some regions, such as the U.K. North Sea, and others with limited capital resources, are increasingly subletting rig time in an effort to reduce capital spending during 2009, contributing to a more challenging near- to intermediate-term pricing environment.
34
Our independent leg jackup rig fleet currently operates in Mexico, the Middle East, Asia Pacific and West Africa. We currently have 76% of our available rig days for our independent leg jackup fleet contracted in 2009, 25% in 2010, 7% in 2011 and none in 2012. Since 2007, 45 jackup rigs have been added to the global fleet, with another 73 expected to be added in 2009 to 2011. The global financial crisis, which has created a difficult environment to obtain needed funding for fleet expansion, could result in some of the expected rig deliveries to be delayed significantly or cancelled. Customer demand is not expected to match or exceed the supply of international jackup rigs in 2009. Therefore, utilization and dayrates are expected to decline from 2008 levels. Contract durations have begun to shorten throughout the existing fleet of jackup rigs, and the majority of rigs being delivered in 2009 and beyond are without contracts. Dayrates for standard international-class jackup rigs peaked during 2008 and are expected to continue to decline as utilization in 2009 declines. We continue to expect jackup needs in Mexico to increase during 2009, as PEMEX attempts to reverse substantial crude oil production declines. Recently, PEMEX has indicated a shifting focus toward geologic prospects in deeper water and, therefore, an increased emphasis on rigs with a water depth rating of 250 feet or greater, especially independent leg cantilever rigs.
Our mat-supported jackup fleet operates in the United States and Mexico. The shallow water U.S. Gulf of Mexico is one of the most mature offshore basins in the world. We currently have 21% of our available rig days, which includes rigs that are currently stacked, for our mat-supported jackup fleet contracted in 2009, and none in 2010, 2011 and 2012. Drilling activity in the region is typically conducted by small independent exploration and production companies with the level of activity heavily influenced by the price of natural gas. Production prospects are typically small with high depletion rates and jackup rigs are employed by clients for short-term, well-to-well programs. Throughout most of 2008, utilization and dayrates for the U.S. Gulf of Mexico based jackup rigs improved steadily due in part to higher natural gas prices and a reduction in the supply of jackup rigs following the continued relocation of rigs to international markets and the industry’s loss of four units during Hurricane Ike. Also, with the historically high crude oil price experienced into mid 2008, a number of clients employed jackup rigs to drill small accumulations of crude oil, constraining further the supply of rigs in the region. Recently, the aggregate fleet utilization for U.S. jackup rigs has declined to approximately 75%, as natural gas prices fell following the onset of the global financial crisis and deteriorating economic conditions in the United States. The inability of some clients to access credit markets to fund their exploration and production programs also contributed to the decline in activity. Jackup rig activity is expected to decline further in 2009 due to the expected continuation of the unfavorable commodity price trend and the inability for some of our customers to gain access to capital to fund exploration and production spending. Typically, when fleet utilization declines below 90%, rig dayrates begin to fall. Some jackup rig capacity is expected to be removed from active service due to the weaker business environment, which is expected to keep rig dayrates above the cash cost to operate the rigs. As PEMEX changes its focus toward new field exploration and development prospects that increasingly require the use of rigs with greater water depth capability, we expect that demand in Mexico for our ten mat-supported jackup rigs with water depth ratings of 200 feet or less could decline and the future contracting opportunities for such rigs in Mexico could diminish. Our mat-supported jackup rig fleet in Mexico declined during 2008 from 11 units at the start of the year to six units as of February 2, 2009. A total of five units were relocated to the U.S. Gulf of Mexico region, with all of these units stacked until market conditions improve. We also expect the Pride Arkansas to be released by PEMEX at the completion of its contract and we intend to stack the rig when it returns to the United States.
We experienced approximately 655 out-of-service days for shipyard maintenance and upgrade projects in 2008, including 20 days for deepwater rigs, 305 days for midwater rigs, 230 days for independent leg jackups and 100 days for mat-supported jackups, for our existing fleet as compared to 1,350 days for 2007. For 2009, we expect the number of out-of-service days to be approximately 595 days, including 275 days for deepwater rigs, 35 days for midwater rigs, 210 days for independent leg rigs and 75 days for mat-supported rigs. Shipyard projects may be subject to delays. For our ultra-deepwater drillships under construction, we have attempted to mitigate risks of delay by selecting the same shipyard for all four construction projects with fixed-fee contracts, although some of our other risks with respect to these construction projects, such as work stoppages, disputes with the shipyard, shipyard financial and other difficulties and adverse weather conditions, are more concentrated.
Backlog
Our backlog at December 31, 2008, totaled approximately $8.6 billion for our executed contracts, with $2.6 billion attributable to our deepwater drillships under construction. We expect approximately $1.8 billion of our total backlog to be realized in 2009. Our backlog at December 31, 2007 was approximately $4.9 billion. We calculate our
35
backlog, or future contracted revenue for our offshore fleet, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation, customer reimbursables and performance bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the amount disclosed or expected due to various factors. Downtime due to various operating factors, including unscheduled repairs, maintenance, weather and other factors, may result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances.
The following table reflects the percentage of rig days committed by year as of December 31, 2008. The percentage of rig days committed is calculated as the ratio of total days committed under firm contracts, as well as scheduled shipyard, survey and mobilization days, to total available days in the period. Total available days have been calculated based on the expected delivery dates for our four deepwater rigs under construction.
| For the Years Ending December 31, | |||||||||||||||
| 2009 | 2010 | 2011 | 2012 | ||||||||||||
| Rig Days Committed | |||||||||||||||
| Deepwater | 96% | 87% | 81% | 67% | |||||||||||
| Midwater | 97% | 70% | 64% | 35% | |||||||||||
| Jackups - Independent Leg | 76% | 25% | 7% | 0% | |||||||||||
| Jackups - Mat-Supported | 21% | 0% | 0% | 0% | |||||||||||
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.
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 the 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.
36
Useful lives of rigs and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs when certain events occur that directly impact our assessment of the remaining useful lives of the rig and include changes in operating condition, functional capability and market and economic factors. We also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives of individual rigs. During 2008, we reviewed the useful lives of certain rigs upon completion of shipyard projects, which resulted in extending the useful lives of the rigs, and as a result reduced depreciation expense by $2.9 million and increased after-tax diluted earnings per share by $0.01. During 2007, we completed a technical evaluation of our offshore fleet. As a result of our evaluation, we increased our estimates of the remaining lives of certain semisubmersible and jackup rigs in our fleet between four and eight years, increased the expected useful lives of our drillships from 25 years to 35 years and our semisubmersibles from 25 years to 30 years, and updated our estimated salvage value for all of our offshore drilling rig fleet to 10% of the historical cost of the rigs. The effect for 2007 of these changes in estimates was a reduction to depreciation expense of approximately $28.5 million and an after-tax increase to diluted earnings per share of $0.13.
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 (i) extended periods of idle time and/or an inability to contract specific assets or groups of assets, (ii) a significant adverse change in business climate, such as a decline in our market value or fleet utilization, or (iii) an adverse change in the manner or physical condition of a group of assets or a specific asset. However, the drilling industry is highly cyclical and it is not unusual to find that assets that were idle, under-utilized or contracted at sub-economic rates for significant periods of time resume activity at economic rates when market conditions improve. Additionally, our rigs are mobile, and we may mobilize rigs from one market to another to improve utilization or realize higher dayrates. Due to the decline in our share price since mid-2008 and recent impairment announcements by other companies in our industry, we reviewed our recorded asset values and determined that no impairment was required.
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.
37
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, 2008, we have foreign net operating loss (“NOL”) carryforwards, with respect to all of which we have recognized a valuation allowance. Certain foreign NOL carryforwards do not expire while others could expire starting in 2009 through 2018.
We have not provided for U.S. deferred taxes on the unremitted earnings of our foreign controlled subsidiaries that are permanently reinvested. If a distribution is made to us from the unremitted earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these unremitted earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.
As required by law, we file periodic tax returns that are subject to review and examination by various tax authorities within the jurisdictions in which we operate. We are currently contesting several tax assessments and may contest future assessments where we believe the assessments are in error. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments; however, we believe the ultimate resolution of outstanding tax assessments will not have a material adverse effect on our consolidated financial statements.
In 2006, we received tax assessments from the Mexican government related to the operations of certain entities for the tax years 2001 through 2003. As required by statutory requirements, we have provided bonds, which totaled 555 million Mexican pesos, or approximately $40 million, as of December 31, 2008, to contest these assessments. In February 2009, we received additional tax assessments for the tax years 2003 and 2004 in the amount of 1,097 million pesos, or approximately $74 million. Bonds for these assessments are to be provided later in 2009. These assessments contest our right to claim certain deductions. 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. Additional bonds will need to be provided to the extent future assessments are contested. We anticipate that the Mexican government will make additional assessments contesting similar deductions for other tax years or entities.
We do not believe that it is possible to reasonably estimate the potential impact of changes to the assumptions and estimates identified because the resulting change to our tax liability, if any, is dependent on numerous underlying factors which cannot be reasonably estimated. These include, among other things, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have been appropriate; however, past experience is only a guide and the tax resulting from the resolution of current and potential future tax controversies may have a material adverse effect on our consolidated financial statements.
Contingencies
We establish reserves for estimated loss contingencies when we believe a loss is probable and the amount of the loss can be reasonably estimated. Our contingent liability reserves relate primarily to litigation, personal injury claims, indemnities and potential income and other tax assessments (see also “Income Taxes” above). Revisions to
38
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 and include our costs to defend. In situations where we expect insurance proceeds to offset contingent liabilities, we record a receivable for all probable recoveries until the net loss is zero. We recognize contingent gains when the contingency is resolved and the gain has been realized. Should the outcome differ from our assumptions and estimates or other events result in a material adjustment to the accrued estimated contingencies, revisions to the estimated contingency amounts would be required and would be recognized in the period the new information becomes known.
Segment Review
During the fourth quarter of 2008, we reorganized our reportable segments to reflect the general asset class of our drilling rigs. We believe that this change reflects how we manage our business. Our new reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths greater than 4,500 feet, and Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,500 feet or less. Our jackup fleet, which operates in water depths up to 300 feet, is reported as two segments, Independent Leg Jackups and Mat-Supported Jackups, based on rig design as well as our intention to separate the mat-supported jackup business. We also manage the drilling operations for three deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations. For all periods presented, we have excluded the results of operations of our discontinued operations. See Note 2 of our Notes to Consolidated Financial Statements in Item 8 of this annual report for additional information regarding discontinued operations. As a result of our disposal of these operations, certain operating and administrative costs were reallocated for all periods presented to our remaining continuing operating segments.
The following table summarizes our revenues and earnings from continuing operations by our reportable segments:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Revenues: | (In millions) | |||||||||||
| Deepwater | $ | 882.2 | $ | 643.9 | $ | 479.0 | ||||||
| Midwater | 425.2 | 334.5 | 181.2 | |||||||||
| Jackups - Independent Leg | 275.2 | 221.7 | 125.6 | |||||||||
| Jackups - Mat-Supported | 553.1 | 551.7 | 550.9 | |||||||||
| Other | 174.2 | 198.7 | 182.2 | |||||||||
| Corporate | 0.5 | 1.0 | (0.1 | ) | ||||||||
| Total | $ | 2,310.4 | $ | 1,951.5 | $ | 1,518.8 | ||||||
| Earnings from continuing operations: | ||||||||||||
| Deepwater | $ | 463.0 | $ | 274.2 | $ | 123.4 | ||||||
| Midwater | 168.7 | 145.0 | 27.8 | |||||||||
| Jackups - Independent Leg | 135.7 | 94.9 | 34.0 | |||||||||
| Jackups - Mat-Supported | 197.1 | 227.8 | 269.1 | |||||||||
| Other | 39.9 | 62.6 | 31.9 | |||||||||
| Corporate | (134.9 | ) | (142.6 | ) | (121.0 | ) | ||||||
| Total | $ | 869.5 | $ | 661.9 | $ | 365.2 | ||||||
39
The following table summarizes our average daily revenues and utilization percentage by segment:
| 2008 | 2007 | 2006 | |||||||||||||||||||||
| Average Daily Revenues (1) | Utilization (2) | Average Daily Revenues (1) | Utilization (2) | Average Daily Revenues (1) | Utilization (2) | ||||||||||||||||||
| Deepwater | $ | 310,100 | 97% | $ | 230,800 | 96% | $ | 180,100 | 91% | ||||||||||||||
| Midwater | $ | 249,200 | 78% | $ | 192,200 | 79% | $ | 102,300 | 81% | ||||||||||||||
| Jackups - Independent Leg | $ | 121,100 | 89% | $ | 100,600 | 86% | $ | 58,700 | 93% | ||||||||||||||
| Jackups - Mat-Supported | $ | 90,300 | 81% | $ | 93,500 | 77% | $ | 87,100 | 89% | ||||||||||||||
____________
| (1) | Average daily revenues are based on total revenues for each type of rig divided by actual days worked by all rigs of that type. Average daily revenues will differ from average contract dayrate due to billing adjustments for any non-productive time, mobilization fees, demobilization fees, performance bonuses and charges to the customer for ancillary services. |
| (2) | Utilization is calculated as the total days worked divided by the total days in the period. |
Deepwater
Revenues increased $238.3 million, or 37%, for 2008 over 2007 as our deepwater units earned higher dayrates, reflecting the strong worldwide demand for deepwater rigs. The increase in revenues is primarily due to four of our rigs commencing new contracts at higher dayrates, which contributed approximately $180 million of incremental revenues in 2008 over 2007. The strong performance was also due to the increased utilization of the Pride Rio de Janeiro, which had a 21% increase in days worked in 2008 over 2007. Average daily revenues increased 34% for 2008 over 2007 primarily due to higher dayrates. Earnings from operations increased $188.8 million, or 69%, for 2008 over 2007 due to the increase in revenues and a decrease in depreciation expense from the change in estimate of useful lives effective July 2007. The increase in earnings from operations was partially offset by a 26% increase in overall labor costs for our rig crews, and an increase in repair and maintenance costs. Utilization remained relatively unchanged at 97% for 2008 as compared to 96% for 2007.
Revenues increased $164.9 million, or 34%, for 2007 over 2006 as we benefited from the strong demand for our deepwater rigs, which resulted in higher dayrates and high utilization levels across much of the fleet. This strong performance was led by the Pride South Pacific, which contributed approximately $70 million of incremental revenue as a result of an increase in dayrate from $140,000 to $425,000 with the commencement of a new contract in March 2007. The improvement was also due to increased utilization from the Pride North America, which had non-revenue maintenance and repair downtime in 2006, and an increase of $47.7 million in revenue from the non-cash amortization of deferred revenue related to the Pride Portland and Pride Rio de Janeiro. Average daily revenues in 2007 increased 28% over 2006 primarily due to contract dayrate increases. Earnings from operations increased $150.8 million, or 122%, in 2007 over 2006 due to an increase in revenues and a decrease in rental expenses resulting from our acquisition in November 2006 of the remaining 70% interest in a joint venture company, the principal assets of which were the Pride Rio de Janeiro and the Pride Portland. These favorable conditions were offset partially by a 19% increase in overall labor costs for our rig crews. Utilization increased to 96% for 2007 from 91% in 2006 primarily due to downtime in the fourth quarter of 2006 for the Pride North America, which sustained crane damage as a result of new equipment failure.
Midwater
Revenues increased $90.7 million, or 27%, in 2008 over 2007 principally due to higher contracted dayrates. Three rigs, the Pride Mexico, the Sea Explorer and the Pride South Seas, commenced new contracts in 2008 at substantially higher dayrates than their previously contracted rates; these new contracts contributed approximately $85 million in incremental revenue for 2008 over 2007. Partially offsetting the revenue increase was the loss of revenue resulting from out-of-service time for the Pride Venezuela and Pride South Atlantic in 2008 for unplanned repairs. Average daily revenues for 2008 increased 30% over 2007 due to higher dayrates. Earnings from operations increased $23.7 million, or 16%, for 2008 over 2007 due to increased revenues offset partially by lost revenue days from planned shipyard projects coupled with repair and maintenance expenses for the Pride Venezuela and unscheduled maintenance for the Pride South Atlantic in 2008. Utilization decreased to 78% for 2008 from 79% for 2007. The decline in utilization is primarily attributable to unscheduled maintenance and downtime in 2008.
40
Revenues increased $153.3 million, or 85%, in 2007 over 2006 due primarily to higher dayrates. Average daily revenues for 2007 increased 88% over 2006 due to four of our rigs commencing new contracts in 2007 with dayrates that were substantially higher than previously contracted rates. Earnings from operations in 2007 increased $117.2 million over 2006 due to higher dayrates across much of our midwater fleet. Overall, utilization of our midwater fleet decreased to 79% in 2007 from 81% in 2006. The decline in utilization in 2007 is primarily due to the Pride Mexico entering the shipyard in May 2007 for upgrade in preparation for its new contract that began in mid-2008. In addition, the Pride South Seas entered the shipyard in September 2007 for upgrade and maintenance, lowering its utilization for 2007 as compared to 2006.
Jackups — Independent Leg
Revenues increased $53.5 million, or 24%, for 2008 over 2007 primarily due to the increased utilization for the Pride Hawaii, Pride Tennessee and Pride Wisconsin coupled with the incremental revenue from the Pride Montana, which commenced a new contract in June 2008 at a dayrate that was substantially higher than its previously contracted rate. Average daily revenues increased 20% for 2008 over 2007 primarily due to higher dayrates for the Pride Cabinda and the Pride Montana. Earnings from operations in 2008 increased $40.8 million, or 43%, over 2007 as a result of increased revenues, partially offset by the loss of revenues from higher downtime for the Pride Pennsylvania and the Pride North Dakota. Utilization increased to 89% for 2008 from 86% for 2007. The increase in utilization is primarily the result of decreased shipyard activity for 2008 over 2007.
Revenues increased $96.1 million, or 77%, in 2007 over 2006 primarily due to higher dayrates across the fleet. This dayrate increase was offset partially by the loss of revenue from increased shipyard time in 2007 over 2006 for the Pride Hawaii, Pride Cabinda and Pride Tennessee. Average daily revenues increased 71% in 2007 over 2006 principally due to the higher dayrates experienced by the Pride Hawaii, the Pride Pennsylvania, the Pride Wisconsin and the Pride Tennessee, which all commenced new contracts in 2007 at dayrates that were substantially higher than previously contracted rates. Earnings from operations in 2007 increased $60.9 million, or 179%, over 2006 as the increase in dayrates exceeded the increases in labor and repair and maintenance costs. Overall, utilization of our independent leg jackup fleet decreased to 86% for 2007 from 93% for 2006. The decrease in utilization was principally due to downtime experienced by the Pride Hawaii, the Pride Cabinda and the Pride Wisconsin resulting from planned shipyard projects completed in 2007.
Jackups — Mat-Supported
Revenues increased $1.4 million, or less than 1%, for 2008 over 2007 due to increased utilization offset by declining dayrates. Average daily revenues decreased 3% for 2008 over 2007 due to lower dayrates. The Pride Wyoming accounted for $16.8 million, or approximately 3%, of our revenue for 2008. Earnings from operations decreased $30.7 million, or 13%, for 2008 over 2007 due to increased rig and shore-based labor costs, higher costs to mobilize and demobilize rigs in and out of Mexico and higher repair and maintenance expenses for the Pride Nevada. Partially offsetting these increases in costs were increased earnings from operations due to increased utilization for the Pride Texas, which was in the shipyard for all of the third quarter and part of the fourth quarter of 2007. Utilization increased to 81% for 2008 from 77% for 2007. The increase in utilization is primarily due to increased activity in the U.S. Gulf of Mexico in the first three quarters of 2008 partially offset by the stacking of the Pride Utah in late 2007, the Pride Alabama in April 2008 and three additional rigs in late 2008. In the fourth quarter of 2008, a decision was made to stack the Pride Colorado, the Pride Nevada and the Pride South Carolina as a result of unfavorable market conditions resulting from declining crude oil and natural gas prices.
Revenues increased $0.8 million, or less than 1%, in 2007 over 2006 primarily due to lower utilization in the U.S. partially offset by dayrate increases in Mexico. Average daily revenue for our mat-supported jackup fleet increased 7% for 2007 over 2006 as our rigs in Mexico recontracted at higher dayrates. Earnings from operations in 2007 decreased $41.3 million, or 15%, over 2006 due to lower utilization. In October 2007, the Pride Alabama experienced a lightning strike from severe storms in Mexico and required 10 days to repair. Overall, utilization of our mat-supported jackup fleet decreased to 77% for 2007 from 89% in 2006 due to weaker demand for rigs in the U.S., which resulted in increases in idle time between drilling contracts.
41
Other Operations
Other operations include our drilling operations for three deepwater drilling rigs under management contracts that expire in 2009, 2011 and 2012 (with early termination permitted in certain cases) and two deepwater drilling rigs under management contracts that ended in the third and fourth quarters of 2008, respectively, our 10 platform rigs that were sold in May 2008 and other operating activities.
Revenues decreased $24.5 million, or 12%, for 2008 over 2007 primarily due to a reduction in revenues resulting from the sale of our platform rig fleet in May 2008 and suspension of drilling services, and the subsequent termination of our management services contract, on the Kizomba A deepwater rig in the third quarter of 2008. We earned approximately $8.6 million in management fee revenues in 2008 for the Kizomba A. Earnings from operations decreased $22.7 million, or 36%, for 2008 over 2007 primarily due to the gain on the sale of our barge rig, Bintang Kalimantan, in December 2007 coupled with higher labor costs and transportation costs in Mexico in 2008, partially offset by the gain on sale of our platform fleet.
Revenues increased $16.5 million, or 9%, in 2007 over 2006 primarily as a result of higher dayrates, higher utilization for our platform rigs and higher rates for our managed rigs, partially offset by our reduction in labor services contracts and swamp barge rig operations. In December 2007, we sold our barge rig the Bintang Kalimantan, which had been idle since early 2006, resulting in a gain on sale of $20 million. Earnings from operations increased $30.7 million, or 96%, for 2007 over 2006 primarily due to the gain on the sale of the Bintang Kalimantan.
42
Results of Operations
The discussion below relating to significant line items represents our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items.
The following table presents selected consolidated financial information for our continuing operations:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| REVENUES | $ | 2,310.4 | $ | 1,951.5 | $ | 1,518.8 | ||||||
| COSTS AND EXPENSES | ||||||||||||
| Operating costs, excluding depreciation and amortization | 1,127.9 | 966.7 | 887.9 | |||||||||
| Depreciation and amortization | 206.5 | 215.3 | 188.0 | |||||||||
| General and administrative, excluding depreciation and amortization | 130.6 | 138.1 | 105.8 | |||||||||
| Impairment charges | - | - | 0.5 | |||||||||
| Gain on sales of assets, net | (24.1 | ) | (30.5 | ) | (28.6 | ) | ||||||
| 1,440.9 | 1,289.6 | 1,153.6 | ||||||||||
| EARNINGS FROM OPERATIONS | 869.5 | 661.9 | 365.2 | |||||||||
| OTHER INCOME (EXPENSE), NET | ||||||||||||
| Interest expense | (18.5 | ) | (73.3 | ) | (78.2 | ) | ||||||
| Refinancing charges | (2.3 | ) | - | - | ||||||||
| Interest income | 17.5 | 14.4 | 4.2 | |||||||||
| Other income (expense), net | 17.4 | (3.4 | ) | 0.9 | ||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST | 883.6 | 599.6 | 292.1 | |||||||||
| INCOME TAXES | (217.2 | ) | (172.3 | ) | (117.4 | ) | ||||||
| MINORITY INTEREST | - | (3.5 | ) | (4.1 | ) | |||||||
| INCOME FROM CONTINUING OPERATIONS, NET OF TAX | $ | 666.4 | $ | 423.8 | $ | 170.6 | ||||||
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues. Revenues for 2008 increased $358.9 million, or 18%, compared with 2007. For additional information about our revenues, please read “— Segment Review” above.
Operating Costs. Operating costs for 2008 increased $161.2 million, or 17%, compared with 2007 primarily due to approximately $100.9 million in higher labor costs for rig crew personnel, including costs for merit increases, retention programs designed to retain key operations personnel and increased training costs. In addition, there was an increase of approximately $51.9 million in repair and maintenance costs for rigs in our deepwater and midwater fleet. Operating costs in 2008 increased $3.0 million related to reimbursable costs for a shipyard project we supervised for a rig that we provide with labor but with respect to which we are not responsible for the drilling contract. Operating costs as a percentage of revenues were 49% and 50% for 2008 and 2007, respectively.
Depreciation and Amortization. Depreciation expense for 2008 decreased $8.8 million, or 4%, compared with 2007. This decrease is primarily the result of the change in useful life estimates for several of our rigs (see “—Critical Accounting Estimates – Property and Equipment” above), partially offset by the completion of a number of capitalized shipyard projects in 2008.
General and Administrative. General and administrative expenses for 2008 decreased $7.5 million, or 5%, compared with 2007, primarily due to a decrease of $17.3 million of expenses related to the ongoing investigation
43
described under “— FCPA Investigation” above, partially offset by $6.1 million for expenses in 2008 relating to the spin-off of our mat-supported jackup business and a $1.4 million increase in the amount expensed in 2008 for upgrades to our information technology infrastructure. The remainder of the increase is due to increased wages and benefits costs.
Gain on Sale of Assets, Net. We had net gain on sale of assets of $24.1 million for 2008, primarily related to the sale of our platform rigs in May 2008. We had net gain on sale of assets of $30.5 million for 2007, primarily due to the sale of one land rig and one barge rig.
Interest Expense. Interest expense for 2008 decreased by $54.8 million, or 75%, compared with 2007 primarily due to a $28.6 million increase in capitalized interest and a reduction in interest expense on lower total debt balances resulting from repayment of our 3 1/4% Convertible Senior Notes Due 2033 in May 2008 and our drillship loan facility in March 2008.
Refinancing Charges. Refinancing charges for 2008 were $2.3 million and included $1.2 million for the write-off of unamortized debt issuance costs in March 2008 in conjunction with our drillship loan facility repayment and $1.1 million for the write-off of unamortized debt issuance costs in December 2008 upon retirement of our senior secured credit facility. There were no refinancing charges in 2007.
Interest Income. Interest income for 2008 increased by $3.1 million compared with 2007 as a result of maintaining higher cash balances in 2008.
Other Income (Expense), Net. Other income, net for 2008 increased by $20.8 million compared with 2007 primarily due to an $11.4 million gain recorded in the first quarter of 2008 resulting from the sale of our 30% minority interest in a joint venture that operates several land rigs in Oman. In addition, we had a $7.1 million foreign exchange gain in 2008 as compared to a $4.1 million foreign exchange loss for 2007. Partially offsetting these increases was a $0.9 million decrease in 2008 in equity earnings from unconsolidated subsidiaries.
Income Taxes. Our consolidated effective income tax rate for continuing operations for 2008 was 24.6% compared with 28.7% for 2007. The lower tax rate for 2008 was principally the result of increased income in lower-taxed jurisdictions partially offset by the recognition of benefits derived from previously unrecognized tax credits in 2007.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues. Revenues for 2007 increased $432.7 million, or 28%, compared with 2006. For additional information about our revenues, please read “— Segment Review” above.
Operating Costs. Operating costs for 2007 increased $78.8 million, or 9%, compared with 2006 primarily due to higher labor costs for rig crew personnel, including costs for merit increases, retention programs designed to retain key operations personnel and increased training costs, along with higher repair and maintenance costs. Operating costs in 2006 include $15.0 million of expenses for the termination of agency fee agreements in Brazil in connection with our buyout of the remaining 70% interest in the former joint venture entity that owned the Pride Portland and the Pride Rio de Janeiro in November 2006. Operating costs in 2007 increased $12.3 million related to reimbursable costs for a shipyard project we supervised for a rig that we provide with labor but with respect to which we are not responsible for the drilling contract. Operating costs as a percentage of revenues were 50% and 58% for 2007 and 2006, respectively. The decrease as a percentage of revenue was primarily driven by the increase in dayrates.
Depreciation and Amortization. Depreciation expense for 2007 increased $27.3 million, or 15%, compared with 2006. This increase relates to additional depreciation expense as a result of the acquisition of the remaining 70% interest in the former joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro in November 2006 and the completion of a number of capitalized shipyard projects during 2006 and 2007, partially offset by a $28.5 million reduction in depreciation expense for 2007 as a result of the change in useful life estimates for several of our rigs.
44
General and Administrative. General and administrative expenses for 2007 increased $32.3 million, or 31%, compared with 2006, primarily due to an increase of $7.4 million of expenses related to the ongoing investigation described under “— FCPA Investigation” above, $6.7 million expensed for upgrades to our information technology infrastructure and a $5.3 million increase in stock-based compensation and termination and retirement benefits in 2007. The remainder of the increase is due to increased staffing and related wages and benefits.
Gain on Sale of Assets, Net. We had net gains on sales of assets of $30.5 million in 2007 primarily due to the sale of one of our barge rigs and one land rig. We had net gains on sales of assets of $28.6 million in 2006 primarily due to the sale of the Pride Rotterdam.
Interest Expense. Interest expense for 2007 decreased by $4.9 million, or 6%, compared with 2006 primarily due to a $7.9 million increase in capitalized interest and a reduction in interest expense for our senior secured revolving credit facility, partially offset by the addition of interest expense on the debt acquired as part of our buyout of the remaining 70% interest in the former joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro in November 2006.
Interest Income. Interest income for 2007 increased by $10.2 million, or 243%, compared with 2006 primarily due to investment of cash received from the third quarter 2007 sale of our Latin America Land and E&P Services segments.
Other Income (Expense), Net. Other expense, net for 2007 increased by $4.3 million compared with 2006 primarily due to a $2.6 million increase in losses in 2007 for realized and unrealized gains and losses on our interest rate swap and cap agreements as compared to 2006, and a $2.3 million decrease from 2007 to 2006 in equity earnings from unconsolidated subsidiaries. In addition, in 2007 we had a $4.1 million foreign exchange loss as compared to a $4.2 million loss for 2006.
Income Taxes. Our consolidated effective income tax rate for continuing operations for 2007 was 28.7% compared with 40.2% for 2006. The lower rate for 2007 was principally the result of increased income in lower taxed jurisdictions coupled with the recognition of benefits derived from previously unrecognized foreign tax credits.
Liquidity and Capital Resources
Our objective in financing our business is to maintain both adequate financial resources and access to additional liquidity. Our $300 million senior unsecured revolving credit facility provides back-up liquidity to meet our on-going working capital needs. At December 31, 2008, we had $300 million of availability under this facility.
During 2008, we used cash on hand (including from asset sales) and cash flows generated from operations as our primary source of liquidity for funding our working capital needs, debt repayment and capital expenditures. We believe that our cash on hand, cash flows from operations and availability under our revolving credit facility will provide sufficient liquidity through 2009 to fund our working capital needs, scheduled debt repayments and anticipated capital expenditures, including progress payments for our four drillship construction projects. In addition, we will continue to pursue opportunities to expand or upgrade our fleet, which could result in additional capital investment. Subject to the limitations imposed by our existing debt arrangements, we may also in the future elect to return capital to our stockholders by share repurchases or the payment of dividends.
We may review from time to time possible expansion and acquisition opportunities relating to our business, which may include the construction or acquisition of rigs or acquisitions of other businesses in addition to those described in this annual report. Any determination to construct additional rigs for our fleet will be based on market conditions and opportunities existing at the time, including the availability of long-term contracts with sufficient dayrates for the rigs and the relative costs of building new rigs with advanced capabilities compared with the costs of retrofitting or converting existing rigs to provide similar capabilities. The timing, size or success of any additional acquisition or construction effort and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to us at that time due to a variety of events, including, among others, credit rating agency
45
downgrades of our debt, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry.
We also review from time to time the possible disposition of assets that we do not consider core to our strategic long-term business plan.
As discussed above, we have filed a Form 10 registration statement with the Securities and Exchange Commission with respect to the distribution to our stockholders of all of the shares of common stock of a subsidiary that would hold, directly or indirectly, the assets and liabilities of our 20-rig mat-supported jackup business. For additional information about the spin-off, please read “—Recent Developments—Separation of Our Mat-Supported Jackup Business.”
Sources and Uses of Cash — 2008 Compared with 2007
Cash flows provided by operating activities
Cash flows from operations were $844.1 million for 2008 compared with $685.0 million for 2007. The increase in cash flows from operations was primarily due to the increase in our income from continuing operations in 2008.
Cash flows used in investing activities
Cash flows used in investing activities were $582.5 million for 2008 compared with cash flows received from investing activities of $299.1 million for 2007. The decrease in cash flows received from investing activities relates primarily to net decrease in cash provided by asset sales in 2008 as compared to 2007. In 2008, we received $295.7 million in connection with the sale of our three tender-assist rigs and our remaining Eastern Hemisphere land rigs. In 2007, we received cash proceeds of $947.1 million from the sale of our Latin America Land and E&P Services segments, net of cash disposed of and cash selling costs. The final net proceeds will differ as a result of settlement of the final working capital adjustment, post-closing indemnities, and payment of transaction costs. In addition, we used approximately $280 million more cash than 2007 for capital spending in connection with our four drillships currently under construction.
Purchases of property and equipment totaled $984.0 million and $656.4 million for 2008 and 2007, respectively. The increase in 2008 is primarily due to progress payments, equipment purchases and other capitalized costs aggregating $637.0 million in connection with the construction of our four deepwater drillship construction projects and the upgrade project for the Pride Mexico.
Proceeds from dispositions of property and equipment were $65.8 million for 2008 compared with $53.4 million for 2007. Included in the proceeds for 2008 was $64.2 million related to the sale of our platform rig fleet. Included in the proceeds for 2007 was $34.0 million related to the sale of one of our barge rigs and $17.3 million related to the sale of one land rig.
Cash flows used in financing activities
Cash flows used in financing activities were $439.5 million for 2008 compared with $157.8 million for the comparable period in 2007. Our net cash used for debt repayments included $300.0 million to retire all of the outstanding 3 1/4% Convertible Senior Notes Due 2033, $138.9 million paid in March 2008 to repay in full the outstanding amounts under our drillship loan facility and $30.3 million in other scheduled debt repayments. We also received net proceeds of $24.7 million and $29.7 million from employee stock transactions in 2008 and 2007, respectively.
Cash flows from discontinued operations
Our discontinued operations were largely dependent on us for funding of capital expenditures, strategic investments and acquisitions. The discontinued operations would periodically distribute to us available cash through intercompany invoices or capital dividends or require us to fund their operations through intercompany working
46
capital or capital investments. For 2008, we provided net cash of $4.4 million from discontinued operations as compared to receiving cash of $24.7 million for 2007.
Our cash flows used in operating activities of discontinued operations for 2008 were $5.5 million compared with cash flows provided of $73.2 million for 2007. The decrease in cash flows from operations was due primarily to the inclusion in 2007 of eight months of operations of our Latin America Land and E&P Services segments prior to the disposal.
Purchases of property and equipment were $1.1 million for 2008 compared with $50.8 million for 2007.
We do not believe that, in the future, the loss of the cash flows from our discontinued operations will significantly affect our liquidity or ability to fund our capital expenditures.
Sources and Uses of Cash — 2007 Compared with 2006
Cash flows provided by operating activities
Cash flows from operations were $685.0 million for 2007 compared with $611.7 for 2006. The increase in cash flows from operations was primarily due to the increase in our income from continuing operations partially offset by increased use of cash for working capital items.
Cash flows provided by (used in) investing activities
Cash flows provided by investing activities were $299.1 million for 2007 compared with cash flows used in investing activities of $513.6 for 2006. The increase in cash flows from investing activities was primarily due to the proceeds received from the sale of our Latin America Land and E&P Services segments.
Purchases of property and equipment totaled $656.4 million and $356.2 million for 2007 and 2006, respectively. With respect to our recent drillship construction contracts, we had capital expenditures of approximately $309.0 million in 2007 towards the construction of the rigs. We also spent $45 million for the acquisition of the remaining nine percent interest in our Angolan joint venture in August 2007. The majority of the remaining expenditures were incurred in connection with life enhancements and other upgrades and sustaining capital projects.
Proceeds from dispositions of property and equipment were $53.4 million and $60.5 million for 2007 and 2006, respectively. Included in the proceeds for 2007 was $34.0 million related to the sale of one of our barge rigs and $17.3 million related to the sale of one land rig. Included in the proceeds for 2006 was $51.3 million related to the sale of the Pride Rotterdam and four land rigs that were part of our former Latin America Land segment.
Cash flows used in financing activities
Cash flows used in financing activities were $157.8 million for 2007 compared with $79.1 million for 2006. Our net cash used for debt repayments included $58.4 million paid in August 2007 to repay in full the outstanding amounts under our 9.35% semisubmersible loan, a net reduction of our revolving credit facility of $50.0 million and $88.1 million in scheduled debt repayments. We received net proceeds of $29.7 million and $51.7 million from employees stock transactions in 2007 and 2006, respectively.
Cash flows from discontinued operations
For 2007, we received net cash of $24.7 million from discontinued operations as compared to $66.8 million for 2006.
Our cash flows from operating activities of discontinued operations for 2007 were $73.2 million compared with $148.1 million for 2006. The decrease in cash flows from operations was due primarily to the inclusion in 2007 of eight months of operations of our Latin America Land and E&P Services segments prior to the disposal compared with a full year of operations in 2006. An increase in net working capital in 2007 also negatively affected cash flow from operations in 2007.
47
Purchases of property and equipment were $50.8 million for 2007 compared with $52.5 million for 2006.
Working Capital
As of December 31, 2008, we had working capital of $849.6 million compared with $888.0 million as of December 31, 2007. The decrease in working capital is primarily due to expenditures incurred towards the construction of our four deepwater drillships and cash used towards debt repayments and retirements, offset by increased working capital due to increased dayrates and net proceeds received from various asset sales in 2008.
Credit Ratings
Our 7 3/8% Senior Notes due 2014 are rated Ba1 by Moody’s Investor Service, Inc. and BB+ by Standard & Poor’s Rating Services and Fitch Ratings. Moody’s and Standard & Poor’s report a positive outlook, while Fitch’s outlook is stable.
Revolving Credit Facility
In December 2008, we entered into a new $300 million unsecured revolving credit agreement with a group of banks maturing in December 2011. Borrowings under the credit facility are available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes. We may obtain up to $100 million of letters of credit under the facility. The credit facility also has an accordion feature that would, under certain circumstances, allow us to increase the availability under the facility to up to $600 million. Amounts drawn under the credit facility bear interest at variable rates based on LIBOR plus a margin or the alternative base rate. The interest rate margin applicable to LIBOR advances varies based on our credit rating. As of December 31, 2008, there were no outstanding borrowings or letters of credit outstanding under the facility, and our borrowing availability was $300 million.
The credit facility contains a number of covenants restricting, among other things, liens; indebtedness of our subsidiaries; mergers and dispositions of all or substantially all of our or certain of our subsidiaries’ assets; agreements limiting the ability of subsidiaries to make dividends, distributions or other payments to us or other subsidiaries; affiliate transactions; hedging arrangements outside the ordinary course of business; and sale-leaseback transactions. The facility also requires us to maintain certain ratios with respect to earnings to interest expenses and debt to tangible capitalization. The facility contains customary events of default, including with respect to a change of control.
In connection with the closing under our new credit facility, we terminated our then-existing $500.0 million senior secured credit facility. We incurred no termination penalties and recognized a charge of $1.1 million related to the write-off of unamortized debt issuance costs in connection with the termination.
Other Outstanding Debt
As of December 31, 2008, in addition to our credit facility, we had the following long-term debt, including current maturities, outstanding:
| • | $500.0 million principal amount of 7 3/8% senior notes due 2014; and |
| • | $227.3 million principal amount of notes guaranteed by the United States Maritime Administration. |
Our 7 3/8% senior notes contain provisions that limit our ability and the ability of our subsidiaries to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt or issue preferred stock; enter into agreements containing dividend or other payment restrictions affecting our subsidiaries; dispose of 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.
48
Our notes guaranteed by the United States Maritime Administration were used to finance a portion of the cost of construction of the Pride Portland and Pride Rio de Janeiro. The notes bear interest at a weighted average fixed rate of 4.33%, mature in 2016 and are prepayable, in whole or in part, at any time, subject to a make-whole premium. The notes are collateralized by the two rigs and the net proceeds received by subsidiary project companies chartering the rigs.
In April 2008, we called for redemption all of the outstanding 3 1/4% Convertible Senior Notes Due 2033 in accordance with the terms of the indenture governing the notes. The redemption price was 100% of the principal amount thereof, plus accrued and unpaid interest (including contingent interest) to the redemption date. Holders of the notes could elect to convert the notes into our common stock at a rate of 38.9045 shares of common stock per $1,000 principal amount of the notes, at any time prior to the redemption date. Holders of the notes elected to convert a total of $299.7 million aggregate principal amount of the notes, and the remaining $254,000 aggregate principal amount was redeemed by us on the redemption date. We delivered an aggregate of approximately $300.0 million in cash and approximately 5.0 million shares of common stock in connection with the retirement of the notes.
Although we do not expect that our level of total indebtedness will have a material adverse impact on our financial position, results of operations or liquidity in future periods, it may limit our flexibility in certain areas. Please read “Risk Factors — Our significant debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities” in Item 1A of this annual report.
Other Sources and Uses of Cash
We expect our purchases of property and equipment for 2009, excluding our new drillship commitments, to be approximately $350 million for refurbishment and upgrade of our rigs and $30 million for critical spares and other ancillary projects. These purchases are expected to be used primarily for various rig upgrades in connection with new contracts as contracts expire during the year along with other sustaining capital projects. With respect to our four deepwater drillships currently under construction, the total remaining costs are estimated to be approximately $2.0 billion, of which approximately $1.8 billion is committed at December 31, 2008. We anticipate making additional payments for the construction of these drillships of approximately $735 million in 2009, approximately $740 million in 2010 and approximately $535 million in 2011. We expect to fund construction of these rigs through available cash, cash flow from operations and borrowings under our revolving credit facility.
We anticipate making income tax payments of approximately $135 million to $150 million in 2009.
Mobilization fees received from customers and the costs incurred to mobilize a rig from one geographic area to another, as well as up-front fees to modify a rig to meet a customer’s specifications, are deferred and amortized over the term of the related drilling contracts. These up-front fees and costs impact liquidity in the period in which the fees are received or the costs incurred, whereas they will impact our statement of operations in the periods during which the deferred revenues and costs are amortized. The amount of up-front fees received and the related costs vary from period to period depending upon the nature of new contracts entered into and market conditions then prevailing. Generally, contracts for drilling services in remote locations or contracts that require specialized equipment will provide for higher up-front fees than contracts for readily available equipment in major markets.
Additionally, we defer costs associated with obtaining in-class certification from various regulatory bodies in order to operate our offshore rigs. We amortize these costs over the period of validity of the related certificate.
We may redeploy additional assets to more active regions if we have the opportunity to do so on attractive terms. We frequently bid for or negotiate with customers regarding multi-year contracts that could require significant capital expenditures and mobilization costs. We expect to fund project opportunities primarily through a combination of working capital, cash flow from operations and borrowings under our revolving credit facility.
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.
49
Letters of Credit
We are contingently liable as of December 31, 2008 in the aggregate amount of $211.3 million under certain performance, bid and custom bonds and letters of credit. As of December 31, 2008, we had not been required to make any collateral deposits with respect to these agreements.
Contractual Obligations
In the table below, we set forth our contractual obligations as of December 31, 2008. 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.
| Less Than | After | |||||||||||||||||||
| Total | 1 Year | 1 - 3 Years | 4 - 5 Years | 5 Years | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Recorded contractual obligations: | ||||||||||||||||||||
Principal payments on long-term debt(1) | $ | 723.2 | $ | 30.3 | $ | 60.6 | $ | 60.6 | $ | 571.7 | ||||||||||
| Trade payables | 137.3 | 137.3 | - | - | - | |||||||||||||||
Other long-term liabilities(2) | 1.1 | 0.8 | 0.3 | - | - | |||||||||||||||
| $ | 861.6 | $ | 168.4 | $ | 60.9 | $ | 60.6 | $ | 571.7 | |||||||||||
| Unrecorded contractual obligations: | ||||||||||||||||||||
Interest payments on long-term debt(3) | 260.7 | 46.4 | 88.9 | 83.6 | 41.8 | |||||||||||||||
Operating lease obligations(4) | 48.1 | 11.6 | 9.5 | 8.6 | 18.4 | |||||||||||||||
Purchase obligations(5) | 352.4 | 261.6 | 90.8 | - | - | |||||||||||||||
Drillship construction agreements(6) | 1,708.8 | 575.3 | 1,133.5 | - | - | |||||||||||||||
| $ | 2,370.0 | $ | 894.9 | $ | 1,322.7 | $ | 92.2 | $ | 60.2 | |||||||||||
| Total | $ | 3,231.6 | $ | 1,063.3 | $ | 1,383.6 | $ | 152.8 | $ | 631.9 | ||||||||||
____________
| (1) | Amounts represent the expected cash payments for our total long-term debt and do not reflect any unamortized discount. |
| (2) | Amounts represent other liabilities related to severance and termination benefits and capital leases. |
| (3) | Amounts represent the expected cash payments for interest on our long-term debt based on the interest rates in place and amounts outstanding at December 31, 2008. |
| (4) | We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the leases. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements. |
| (5) | Includes approximately $94.0 million in purchase obligations related to drillship construction projects. |
| (6) | Includes shipyard payments under drillship construction agreements for our four drillship construction projects. |
As of December 31, 2008, we have approximately $45.1 million of unrecognized tax benefits, including penalties and interest. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.
50
Pending Accounting Pronouncements
In December 2007, the Financial Accounting Standards Board (“FASB”) issued the revised Statement of Financial Accounting Standards (“SFAS”) No. 141(R), Business Combinations. Under SFAS No. 141(R), all business combinations will be accounted for by applying the acquisition method and an acquirer is required to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any noncontrolling interest at their fair values as of the acquisition date. SFAS No. 141(R) also requires transaction costs and restructuring charges to be expensed. Effective January 1, 2009, we will begin applying this statement to any business combination completed by us.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which is an amendment of Accounting Research Bulletin No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, SFAS No. 160 requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This statement is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted SFAS No. 160 on January 1, 2009 but its adoption did not have a significant impact on our results of operations and financial condition.
In May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement). FSP APB 14-1 will apply to any convertible debt instrument that may be wholly or partially settled in cash and will require the separation of the debt and equity components of cash-settleable convertibles at the date of issuance. The value assigned to the debt component is the estimated value of similar debt instrument without the conversion feature. The difference between the proceeds received and the estimated value of the debt component will be recorded as additional paid-in capital. The difference between the estimated value of the debt at issuance and the par value at the redemption date will be accreted to interest expense over the estimated life of the convertible debt. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied retroactively to all periods presented. Early adoption of this FSP is prohibited. We expect the adoption of FSP APB 14-1 to result in a non-cash increase of our historical interest expense, net of amounts capitalized, of $1.1 million, $9.1 million and $9.9 million for 2008, 2007 and 2006, respectively.
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 and the economy in general; |
| • | our ability to enter into new contracts for our rigs, commencement dates for rigs and future utilization rates and contract rates for rigs; |
| • | customer requirements for drilling capacity and customer drilling plans; |
| • | contract backlog and the amounts expected to be realized within one year; |
| • | future capital expenditures and investments in the construction, acquisition and refurbishment of rigs (including the amount and nature thereof and the timing of completion and delivery thereof); |
51
| • | future asset sales and the consummation of the sale of our remaining Eastern Hemisphere land rig; |
| • | the proposed distribution to stockholders of our mat-supported jackup business and the timing thereof; |
| • | expected use of proceeds from our asset sales; |
| • | adequacy of funds for capital expenditures, working capital and debt service requirements; |
| • | future income tax payments and the utilization of net operating loss and foreign tax credit carryforwards; |
| • | expected costs for salvage and removal of the Pride Wyoming and expected insurance recoveries with respect to those costs and the damage to offshore structures caused by the loss of the rig; |
| • | business strategies; |
| • | expansion and growth of operations; |
| • | future exposure to currency devaluations or exchange rate fluctuations; |
| • | expected outcomes of legal, tax and administrative proceedings, including our ongoing investigation into improper payments to foreign government officials, and their expected effects on our financial position, results of operations and cash flows; |
| • | future operating results and financial condition; and |
| • | the effectiveness of our disclosure controls and procedures and internal control over financial reporting. |
We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. These statements are subject to a number of assumptions, risks and uncertainties, including those described under “— FCPA Investigation” above and in “Risk Factors” in Item 1A of this annual report and the following:
| • | general economic and business conditions, including conditions in the credit markets; |
| • | prices of crude oil and natural gas and industry expectations about future prices; |
| • | ability to adequately staff our rigs; |
| • | foreign exchange controls and currency fluctuations; |
| • | political stability in the countries in which we operate; |
| • | the business opportunities (or lack thereof) that may be presented to and pursued by us; |
| • | cancellation or renegotiation of our drilling contracts; |
| • | changes in laws and 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.
52
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, 2008 and 2007 was $702.5 million and $1,331.9 million, respectively, which was more than its carrying value as of December 31, 2008 and 2007 of $723.2 million and $1,191.5 million, respectively. A hypothetical 100 basis point decrease in interest rates relative to market interest rates at December 31, 2008 would increase the fair market value of our long-term debt at December 31, 2008 by approximately $28.3 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 also utilize derivative instruments to hedge forecasted foreign currency denominated transactions. At December 31, 2008, we had contracts outstanding to exchange an aggregate $7.0 million U.S. dollars to hedge against the change in value of forecasted payroll transactions and related costs denominated in Euros. We had no such contracts outstanding as of December 31, 2007. If we were to incur a hypothetical 10% adverse change in the exchange rate between the U.S. dollar and the Euro, the net unrealized loss associated with our foreign currency denominated exchange contracts as of December 31, 2008 would be approximately $0.7 million. We do not hold or issue foreign currency forward contracts, option contracts or other derivative financial instruments for speculative purposes.
53
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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2008. 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, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
As discussed in note 8 to the consolidated financial statements, in 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pride International, Inc.’s internal control over financial reporting as of December 31, 2008, 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 24, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 24, 2009
54
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Pride International, Inc.:
We have audited Pride International, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pride International, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting for the year ended December 31, 2008. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pride International, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the 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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated February 24, 2009 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 24, 2009
55
Pride International, Inc.
Consolidated Balance Sheets
(In millions, except par value)
| December 31, | ||||||||
| 2008 | 2007 | |||||||
ASSETS | ||||||||
| CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 712.5 | $ | 890.4 | ||||
| Trade receivables, net | 438.8 | 339.8 | ||||||
| Deferred income taxes | 90.5 | 70.1 | ||||||
| Prepaid expenses and other current assets | 177.4 | 149.5 | ||||||
| Assets held for sale | 1.4 | 82.8 | ||||||
| Total current assets | 1,420.6 | 1,532.6 | ||||||
| PROPERTY AND EQUIPMENT | 6,063.8 | 5,438.4 | ||||||
| Less: accumulated depreciation | 1,474.9 | 1,418.7 | ||||||
| Property and equipment, net | 4,588.9 | 4,019.7 | ||||||
| INTANGIBLE AND OTHER ASSETS | 55.5 | 61.6 | ||||||
| Total assets | $ | 6,065.0 | $ | 5,613.9 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| CURRENT LIABILITIES: | ||||||||
| Current portion of long-term debt | $ | 30.3 | $ | 75.8 | ||||
| Accounts payable | 137.3 | 133.1 | ||||||
| Accrued expenses and other current liabilities | 403.4 | 428.3 | ||||||
| Liabilities held for sale | - | 7.4 | ||||||
| Total current liabilities | 571.0 | 644.6 | ||||||
| OTHER LONG-TERM LIABILITIES | 146.1 | 171.8 | ||||||
| LONG-TERM DEBT, NET OF CURRENT PORTION | 692.9 | 1,115.7 | ||||||
| DEFERRED INCOME TAXES | 257.6 | 211.4 | ||||||
| STOCKHOLDERS' EQUITY: | ||||||||
| Preferred stock, $0.01 par value; 50.0 shares authorized; none issued | - | - | ||||||
Common stock, $0.01 par value; 400.0 shares authorized; 173.8 and 167.5 shares issued; 173.1 and 166.9 shares outstanding | 1.7 | 1.7 | ||||||
| Paid-in capital | 1,971.2 | 1,886.1 | ||||||
| Treasury stock, at cost; 0.7 and 0.6 shares | (13.3 | ) | (9.9 | ) | ||||
| Retained earnings | 2,437.0 | 1,584.9 | ||||||
| Accumulated other comprehensive income | 0.8 | 7.6 | ||||||
| Total stockholders’ equity | 4,397.4 | 3,470.4 | ||||||
| Total liabilities and stockholders’ equity | $ | 6,065.0 | $ | 5,613.9 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
56
Pride International, Inc.
Consolidated Statements of Operations
(In millions, except per share amounts)
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| REVENUES | $ | 2,310.4 | $ | 1,951.5 | $ | 1,518.8 | ||||||
| COSTS AND EXPENSES | ||||||||||||
| Operating costs, excluding depreciation and amortization | 1,127.9 | 966.7 | 887.9 | |||||||||
| Depreciation and amortization | 206.5 | 215.3 | 188.0 | |||||||||
| General and administrative, excluding depreciation and amortization | 130.6 | 138.1 | 105.8 | |||||||||
| Impairment expense | - | - | 0.5 | |||||||||
| Gain on sales of assets, net | (24.1 | ) | (30.5 | ) | (28.6 | ) | ||||||
| 1,440.9 | 1,289.6 | 1,153.6 | ||||||||||
| EARNINGS FROM OPERATIONS | 869.5 | 661.9 | 365.2 | |||||||||
| OTHER INCOME (EXPENSE), NET | ||||||||||||
| Interest expense | (18.5 | ) | (73.3 | ) | (78.2 | ) | ||||||
| Refinancing charges | (2.3 | ) | - | - | ||||||||
| Interest income | 17.5 | 14.4 | 4.2 | |||||||||
| Other income (expense), net | 17.4 | (3.4 | ) | 0.9 | ||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST | 883.6 | 599.6 | 292.1 | |||||||||
| INCOME TAXES | (217.2 | ) | (172.3 | ) | (117.4 | ) | ||||||
| MINORITY INTEREST | - | (3.5 | ) | (4.1 | ) | |||||||
| INCOME FROM CONTINUING OPERATIONS, NET OF TAX | 666.4 | 423.8 | 170.6 | |||||||||
| INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX | 185.7 | 360.5 | 125.9 | |||||||||
| NET INCOME | $ | 852.1 | $ | 784.3 | $ | 296.5 | ||||||
| BASIC EARNINGS PER SHARE: | ||||||||||||
| Income from continuing operations | $ | 3.91 | $ | 2.56 | $ | 1.05 | ||||||
| Income from discontinued operations | 1.09 | 2.18 | 0.77 | |||||||||
| Net income | $ | 5.00 | $ | 4.74 | $ | 1.82 | ||||||
| DILUTED EARNINGS PER SHARE: | ||||||||||||
| Income from continuing operations | $ | 3.81 | $ | 2.41 | $ | 1.01 | ||||||
| Income from discontinued operations | 1.06 | 2.02 | 0.71 | |||||||||
| Net income | $ | 4.87 | $ | 4.43 | $ | 1.72 | ||||||
| SHARES USED IN PER SHARE CALCULATIONS | ||||||||||||
| Basic | 170.6 | 165.6 | 162.8 | |||||||||
| Diluted | 175.6 | 178.5 | 176.5 | |||||||||
The accompanying notes are an integral part of the consolidated financial statements.
57
Pride International, Inc.
Consolidated Statements of Stockholders’ Equity
(In millions)
| Accumulated | ||||||||||||||||||||||||||||||||
| Other | Total | |||||||||||||||||||||||||||||||
| Common Stock | Paid-in | Treasury Stock | Retained | Comprehensive | Stockholders’ | |||||||||||||||||||||||||||
| Shares | Amount | Capital | Shares | Amount | Earnings | Income (Loss) | Equity | |||||||||||||||||||||||||
| Balance, December 31, 2005 | 161.8 | $ | 1.6 | $ | 1,738.5 | 0.4 | $ | (5.5 | ) | $ | 522.5 | $ | 2.3 | $ | 2,259.4 | |||||||||||||||||
| Comprehensive income | ||||||||||||||||||||||||||||||||
| Net income | 296.5 | 296.5 | ||||||||||||||||||||||||||||||
| Foreign currency translation | 1.5 | 1.5 | ||||||||||||||||||||||||||||||
Adjustment to initially apply SFAS No. 158, net of tax | (0.5 | ) | (0.5 | ) | ||||||||||||||||||||||||||||
| Total comprehensive income | 296.5 | 1.0 | 297.5 | |||||||||||||||||||||||||||||
| Exercise of stock options | 3.0 | 50.3 | 50.3 | |||||||||||||||||||||||||||||
| Tax benefit on non-qualified stock | ||||||||||||||||||||||||||||||||
| options | 14.0 | 14.0 | ||||||||||||||||||||||||||||||
| Reclassification of restricted stock | ||||||||||||||||||||||||||||||||
| awards from equity to liability | (4.0 | ) | (4.0 | ) | ||||||||||||||||||||||||||||
| Stock-based compensation, net | 0.9 | 0.1 | 19.1 | 0.1 | (2.5 | ) | 16.7 | |||||||||||||||||||||||||
| Balance, December 31, 2006 | 165.7 | 1.7 | 1,817.9 | 0.5 | (8.0 | ) | 819.0 | 3.3 | 2,633.9 | |||||||||||||||||||||||
| Comprehensive income | ||||||||||||||||||||||||||||||||
| Net income | 784.3 | 784.3 | ||||||||||||||||||||||||||||||
| Foreign currency translation | 2.6 | 2.6 | ||||||||||||||||||||||||||||||
| Adjustment to initially apply | ||||||||||||||||||||||||||||||||
| FIN 48, net of tax | (18.4 | ) | (18.4 | ) | ||||||||||||||||||||||||||||
| SFAS No. 158 change in | ||||||||||||||||||||||||||||||||
| funded status | 1.7 | 1.7 | ||||||||||||||||||||||||||||||
| Total comprehensive income | 765.9 | 4.3 | 770.2 | |||||||||||||||||||||||||||||
| Exercise of stock options | 27.6 | 27.6 | ||||||||||||||||||||||||||||||
| Tax benefit on non-qualified stock | ||||||||||||||||||||||||||||||||
| options | 7.2 | 7.2 | ||||||||||||||||||||||||||||||
| Reclassification of restricted stock | ||||||||||||||||||||||||||||||||
| awards from liability to equity | 5.0 | 5.0 | ||||||||||||||||||||||||||||||
| Stock-based compensation, net | 1.8 | - | 28.4 | 0.1 | (1.9 | ) | 26.5 | |||||||||||||||||||||||||
| Balance, December 31, 2007 | 167.5 | 1.7 | 1,886.1 | 0.6 | (9.9 | ) | 1,584.9 | 7.6 | 3,470.4 | |||||||||||||||||||||||
| Comprehensive income | ||||||||||||||||||||||||||||||||
| Net income | 852.1 | 852.1 | ||||||||||||||||||||||||||||||
| Foreign currency translation | (6.0 | ) | (6.0 | ) | ||||||||||||||||||||||||||||
| Foreign currency hedges, net of | ||||||||||||||||||||||||||||||||
| tax | 0.2 | 0.2 | ||||||||||||||||||||||||||||||
| SFAS No. 158 change in | ||||||||||||||||||||||||||||||||
| funded status | (1.0 | ) | (1.0 | ) | ||||||||||||||||||||||||||||
| Total comprehensive income | 852.1 | (6.8 | ) | 845.3 | ||||||||||||||||||||||||||||
| Exercise of stock options | 1.1 | - | 19.0 | 19.0 | ||||||||||||||||||||||||||||
| Tax benefit from stock-based | ||||||||||||||||||||||||||||||||
| compensation | 7.6 | 7.6 | ||||||||||||||||||||||||||||||
| Retirement of 3 1/4% Convertible | ||||||||||||||||||||||||||||||||
| Notes | 5.0 | - | 31.4 | 31.4 | ||||||||||||||||||||||||||||
| Stock-based compensation, net | 0.2 | - | 27.1 | 0.1 | (3.4 | ) | 23.7 | |||||||||||||||||||||||||
| Balance, December 31, 2008 | 173.8 | $ | 1.7 | $ | 1,971.2 | 0.7 | $ | (13.3 | ) | $ | 2,437.0 | $ | 0.8 | $ | 4,397.4 | |||||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
58
Pride International, Inc.
Consolidated Statements of Cash Flows
(In millions)
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 852.1 | $ | 784.3 | $ | 296.5 | ||||||
| Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||
| Gain on sale of tender-assist rigs | (121.4 | ) | - | - | ||||||||
| Gain on sale of Latin America and E&P Services segments | (56.8 | ) | (268.6 | ) | - | |||||||
| Gain on sale of Eastern Hemisphere land rigs | (6.2 | ) | - | - | ||||||||
| Gain on sale of equity method investment | (11.4 | ) | - | - | ||||||||
| Depreciation and amortization | 210.8 | 269.7 | 269.9 | |||||||||
| Amortization and write-offs of deferred financing costs | 5.2 | 4.0 | 4.0 | |||||||||
| Amortization of deferred contract liabilities | (59.0 | ) | (57.3 | ) | (12.4 | ) | ||||||
| Impairment charges | - | - | 3.9 | |||||||||
| Gain on sales of assets, net | (24.0 | ) | (31.5 | ) | (31.4 | ) | ||||||
| Deferred income taxes | 78.6 | 53.0 | 65.4 | |||||||||
| Excess tax benefits from stock-based compensation | (7.7 | ) | (7.2 | ) | (14.0 | ) | ||||||
| Stock-based compensation | 24.8 | 23.0 | 17.2 | |||||||||
| Loss (gain) on mark-to-market of derivatives | - | 3.9 | 1.3 | |||||||||
| Other, net | 0.7 | 3.4 | 4.1 | |||||||||
| Net effect of changes in operating accounts (See Note 15) | (26.9 | ) | (152.0 | ) | 14.4 | |||||||
| Deferred gain on asset sales and retirements | (12.3 | ) | - | - | ||||||||
| Increase (decrease) in deferred revenue | (8.7 | ) | 35.3 | (14.5 | ) | |||||||
| Decrease (increase) in deferred expense | 6.3 | 25.0 | 7.3 | |||||||||
| NET CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES | 844.1 | 685.0 | 611.7 | |||||||||
| CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: | ||||||||||||
| Purchases of property and equipment | (984.0 | ) | (656.4 | ) | (356.2 | ) | ||||||
| Purchase of net assets of acquired entities, including acquisition costs, less | ||||||||||||
| cash acquired | - | (45.0 | ) | (212.6 | ) | |||||||
| Proceeds from dispositions of property and equipment | 65.8 | 53.4 | 60.5 | |||||||||
| Proceeds from sale of tender-assist rigs, net | 210.8 | - | - | |||||||||
| Proceeds from sale of Eastern Hemisphere land rigs | 84.9 | - | - | |||||||||
| Proceeds from sale of equity method investment | 15.0 | - | - | |||||||||
| Net proceeds from disposition of Latin America Land and E&P Services | ||||||||||||
| segments, net of cash disposed | - | 947.1 | - | |||||||||
| Proceeds from hurricane insurance | 25.0 | - | - | |||||||||
| Investments in and advances to affiliates | - | - | (5.3 | ) | ||||||||
| NET CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES | (582.5 | ) | 299.1 | (513.6 | ) | |||||||
| CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: | ||||||||||||
| Repayments of borrowings | (537.2 | ) | (599.5 | ) | (568.7 | ) | ||||||
| Proceeds from debt borrowings | 68.0 | 403.0 | 423.9 | |||||||||
| Debt finance costs | (2.7 | ) | - | - | ||||||||
| Decrease in restricted cash | - | 1.8 | - | |||||||||
| Net proceeds from employee stock transactions | 24.7 | 29.7 | 51.7 | |||||||||
| Excess tax benefits from stock-based compensation | 7.7 | 7.2 | 14.0 | |||||||||
| NET CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES | (439.5 | ) | (157.8 | ) | (79.1 | ) | ||||||
| Increase (decrease) in cash and cash equivalents | (177.9 | ) | 826.3 | 19.0 | ||||||||
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 890.4 | 64.1 | 45.1 | |||||||||
| CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 712.5 | $ | 890.4 | $ | 64.1 | ||||||
The accompanying notes are an integral part of the consolidated financial statements.
59
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 offshore contract drilling services. We provide these services to oil and natural gas exploration and production companies through the operation and management of 44 offshore rigs. We also have four ultra-deepwater drillships under construction.
Basis of Presentation
In August 2007, we completed the sale of our Latin America Land and E&P Services segments. In early 2008, we completed the sale of our three tender-assist rigs. In the third quarter of 2008, we entered into agreements to sell our Eastern Hemisphere land rig operations and completed the sale of all but one land rig used in those operations in the fourth quarter of 2008. The results of operations for all periods presented of the assets disposed or to be disposed of in all of these transactions have been reclassified to income from discontinued operations. Except where noted, the discussions in the following notes relate to our continuing operations only (see Note 2).
The consolidated financial statements include the accounts of Pride and all entities that we control by ownership of a majority voting interest as well as variable interest entities for which we are the primary beneficiary. All significant intercompany transactions and balances have been eliminated in consolidation. Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. Investments in which we do not exercise significant influence are accounted for using the cost method of accounting.
Management Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Fair Value Accounting
On January 1, 2008, we adopted, without any impact on our consolidated financial statements, the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurement, for our financial assets and liabilities with respect to which we have recognized or disclosed at fair value on a recurring basis. In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date for non-financial assets and non-financial liabilities to fiscal years beginning after November 15, 2008, except for items that are measured at fair value in the financial statements on a recurring basis at least annually. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We do not expect the provisions of SFAS No. 157 related to these items to have a material effect on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be recognized in earnings at each subsequent reporting date. SFAS No. 159 is effective for fiscal years beginning on or after January 1, 2008. The adoption of the provisions of SFAS No. 159 did not have a material impact on our financial statements.
60
Segment Information
During the fourth quarter of 2008, we changed our reportable segments to reflect the general asset class of our drilling rigs. We believe that this change reflects how we manage our business. Our new reportable segments by asset class consist of Deepwater, Midwater, Independent Leg Jackups and Mat-Supported Jackups segments. We also manage the drilling operations for three deepwater rigs that are included in a non-reported operating segment, as “Other.” 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, crude oil and natural gas prices, expectations about future prices, the cost of producing and delivering crude oil and natural gas, government regulations and local and international political and economic conditions. There can be no assurance that current levels of exploration and production expenditures of oil and natural gas companies will be maintained or that demand for our services will reflect the level of such activities.
Dollar Amounts
All dollar amounts (except per share amounts) presented in the tabulations within the notes to our financial statements are stated in millions of dollars, unless otherwise indicated.
Revenue Recognition
We recognize revenue as services are performed based upon contracted dayrates and the number of operating days during the period. We record all taxes imposed directly on revenue-producing transactions on a net basis. 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.
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.
Property and Equipment
Property and equipment are carried at original cost or adjusted net realizable value, as applicable. Major renewals and improvements are capitalized and depreciated over the respective asset’s remaining useful life. Maintenance and repair costs are charged to expense as incurred. When assets are sold or retired, the remaining costs and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in results of operations.
We depreciate property and equipment using the straight-line method based upon expected useful lives of each class of assets. The expected original useful lives of the assets for financial reporting purposes range from five to 35 years for rigs and rig equipment and three to 20 for other property and equipment. We evaluate our estimates of remaining useful lives and salvage value for our rigs when changes in market or economic conditions occur that may impact our estimates of the carrying value of these assets. During 2007, we completed a technical evaluation of our offshore fleet. As a result of our evaluation, we increased our estimates of the remaining lives of certain semisubmersible and jackup rigs in our fleet between four and eight years, increased the expected useful lives of our drillships from 25 years to 35 years and our semisubmersibles from 25 years to 30 years, and updated our estimated
61
salvage value for all of our offshore drilling rig fleet to 10% of the historical cost of the rigs. The effect for 2007 of these changes in estimates was a reduction to depreciation expense of approximately $28.5 million and an after-tax increase to diluted earnings per share of $0.13. During 2008, we reviewed the useful lives of certain rigs upon completion of shipyard projects, which resulted in extending the useful lives of the rigs, and as a result reduced depreciation expense by $2.9 million and increased after-tax diluted earnings per share by $0.01.
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 2008 and 2007, we recognized no impairment charges. In 2006, we recognized an impairment charge of $0.5 million related to two platform rigs.
Goodwill
At December 31, 2008 and 2007, we had $1.2 million and $1.5 million of goodwill, respectively. Goodwill is not amortized. We perform an annual impairment test of goodwill as of December 31, or more frequently if circumstances indicate that impairment may exist. Impairment assessments are performed using a variety of methodologies, including cash flows analysis and estimates of market value. There were no impairments in 2008, 2007 or 2006.
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 $2.3 million, $8.1 million and $22.1 million during 2008, 2007 and 2006, respectively, in obtaining and maintaining such certifications. As of December 31, 2008 and 2007, the deferred and unamortized portion of such costs on our balance sheet was $22.1 million and $32.9 million, respectively. The portion of the costs that are expected to be amortized in the 12 month periods following each balance sheet date are included in other current assets on the balance sheet and the costs expected to be amortized after more than 12 months from each balance sheet date are included in other assets. The costs are amortized on a straight-line basis over the period of validity of the certifications obtained. These certifications are typically for five years, but in some cases are for shorter periods. Accordingly, the remaining useful lives for these deferred costs are up to five years.
Derivative Financial Instruments
We enter into derivative financial transactions to hedge exposures to changing foreign currency exchange rates. We do not enter into derivative transactions for speculative or trading purposes. As of December 31, 2008, we designated our foreign currency derivative financial instruments as cash flow hedges whereby gains and losses on these instruments were recognized in earnings in the same period in which the hedged transactions affected earnings. In 2006 and 2007, we maintained interest rate swap and cap agreements that were not designated as hedges for accounting purposes. Accordingly, the changes in fair value of those derivative financial instruments are recorded in “Other income, net” in our consolidated statement of operations. We have elected to early adopt SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, which is an amendment of SFAS No. 133. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of our derivative and hedging activities (see Note 6).
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
62
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 invest 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
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, restricted stock awards, 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.
Pending Accounting Pronouncements
In December 2007, the FASB issued the revised SFAS No. 141(R), Business Combinations. Under SFAS No. 141(R), all business combinations will be accounted for by applying the acquisition method and an acquirer is required to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as
63
the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any noncontrolling interest at their fair values as of the acquisition date. SFAS No. 141(R) also requires transaction costs and restructuring charges to be expensed. Effective January 1, 2009, we will begin applying this statement to any business combination completed by us.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which is an amendment of Accounting Research Bulletin No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, SFAS No. 160 requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This statement is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted SFAS No. 160 on January 1, 2009 but its adoption did not have a significant impact on our results of operations and financial condition.
In May 2008, the FASB issued FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement). FSP APB 14-1 will apply to any convertible debt instrument that may be wholly or partially settled in cash and will require the separation of the debt and equity components of cash-settleable convertibles at the date of issuance. The value assigned to the debt component is the estimated value of similar debt instrument without the conversion feature. The difference between the proceeds received and the estimated value of the debt component will be recorded as additional paid-in capital. The difference between the estimated value of the debt at issuance and the par value at the redemption date will be accreted to interest expense over the estimated life of the convertible debt. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied retroactively to all periods presented. Early adoption of this FSP is prohibited. We expect the adoption of FSP APB 14-1 to result in a non-cash increase of our historical interest expense, net of amounts capitalized, of $1.1 million, $9.1 million and $9.9 million for 2008, 2007 and 2006, respectively.
Reclassifications
Certain reclassifications have been made to the prior years’ consolidated financial statements to conform with the current year presentation.
NOTE 2. DISCONTINUED OPERATIONS
We report discontinued operations in accordance with the guidance of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. For the disposition of any asset group accounted for as discontinued operations under SFAS No. 144, we have reclassified the results of operations as discontinued operations for all periods presented. Such reclassifications had no effect on our net income or stockholders’ equity.
Sale of Latin America Land and E&P Services Segments
During the third quarter of 2007, we completed the disposition of our Latin America Land and E&P Services segments for $1.0 billion in cash. The purchase price is subject to certain post-closing adjustments for working capital and other indemnities. The following table presents selected information regarding the results of operations of our former Latin America Land and E&P Services segments:
64
| 2008 | 2007(1) | 2006 | ||||||||||
| Revenues | $ | - | $ | 640.7 | $ | 823.9 | ||||||
| Income before taxes | (0.1 | ) | 101.2 | 151.9 | ||||||||
| Income taxes | - | (36.4 | ) | (48.4 | ) | |||||||
| Gain on disposal of assets, net of tax | 56.8 | 268.6 | - | |||||||||
| Income from discontinued operations | $ | 56.7 | $ | 333.4 | $ | 103.5 | ||||||
____________
| (1) | Includes results of operations through August 31, 2007 (the effective date of the disposal) |
From the closing date of the sale through December 31, 2008, we recorded a total gain on disposal of $325.4 million, which included certain estimates for the settlement of closing date working capital, valuation adjustments for tax and other indemnities provided to the buyer, and selling costs incurred by us. We have indemnified the buyer for certain obligations that may arise or be incurred in the future by the buyer with respect to the business. We believe it is probable that some of these liabilities will be settled with the buyer in cash. Our total estimated gain on disposal of assets includes a $29.7 million liability based on our fair value estimates for the indemnities. In December 2008, the final amount of working capital payable by the buyer to us was determined in accordance with the purchase agreement to be approximately $44.5 million, plus approximately $3.5 million of accrued interest. That amount was payable in December. To date, the buyer has not made the required payment, and we have received no assurance that payment will be made. The buyer has made various tax and other indemnification claims totaling approximately $43 million, as compared to our recorded liabilities related to these claims of $17.0 million, but has only recently begun to provide information with respect to a substantial portion of those claims and, in the case of various tax claims, did not comply with the procedural requirements of the agreement. In connection with this divestiture, we recorded additional pre-tax gain on disposal of assets of $56.8 during 2008 for changes in estimates of indemnification obligations and working capital. The expected settlement dates for the remaining tax indemnities vary from within one year to several years. The final gain may differ from the amount recorded as of December 31, 2008.
Sale of Tender-Assist Rigs
In the first quarter of 2008, we sold our three tender-assist rigs, the Barracuda, Alligator and Al Baraka I, for $213 million in cash. In connection with the sale, we entered into an agreement to operate the Alligator until its current contract, as extended, is completed, which is anticipated to be in the first quarter of 2009. The following table presents selected information regarding the results of operations of this asset group:
| 2008 | 2007 | 2006 | ||||||||||
| Revenues | $ | 88.0 | $ | 75.8 | $ | 60.7 | ||||||
| Income before taxes | 5.9 | 26.0 | 5.8 | |||||||||
| Income taxes | (2.0 | ) | (6.9 | ) | (2.7 | ) | ||||||
| Gain on disposal of assets, net of tax | 121.4 | - | - | |||||||||
| Income from discontinued operations | $ | 125.3 | $ | 19.1 | $ | 3.1 | ||||||
Sale of Eastern Hemisphere Land Rigs
In third quarter of 2008, we entered into agreements to sell our remaining seven land rigs for $95 million in cash. The sale of all but one rig closed in the fourth quarter of 2008. We entered into an agreement to lease the remaining
65
rig to the buyer until the sale of that rig is completed, which is expected to occur in the first half of 2009. The following table presents selected information regarding the results of operations of this operating segment:
| 2008 | 2007 | 2006 | ||||||||||
| Revenues | $ | 70.4 | $ | 92.3 | $ | 91.9 | ||||||
| Income before taxes | 8.6 | 15.4 | 26.0 | |||||||||
| Income taxes | (11.1 | ) | (7.4 | ) | (7.9 | ) | ||||||
| Gain on disposal of assets, net of tax | 6.2 | - | - | |||||||||
| Income from discontinued operations | $ | 3.7 | $ | 8.0 | $ | 18.1 | ||||||
Disposition of Fixed-fee Rig Construction Business
In 2006, income from discontinued operations includes $1.2 million from the disposition of the fixed-fee rig construction business.
NOTE 3. ACQUISITIONS
In August 2007, we acquired the remaining nine percent interest in the joint venture company that manages our Angolan operations from our partner Sonangol, the national oil company of Angola, for $45.0 million in cash, bringing our total ownership interest to 100%. Prior to this acquisition, we owned a 91% interest in the joint venture company and fully consolidated the balance sheet and results of operations of the joint venture company. The principal assets of the joint venture company include the two ultra-deepwater drillships the Pride Africa and Pride Angola, the jackup rig Pride Cabinda and management agreements for the deepwater platform rigs the Kizomba A and Kizomba B.
We allocated the purchase price by increasing the carrying values of the drillships and the jackup rig by $36.7 million and eliminated the remaining minority interest in the joint venture company of $31.7 million. As the current operating contracts for the Pride Africa and the Pride Angola were unfavorable compared with current market rates, we recorded a non-cash deferred contract liability of $23.4 million to record the difference between stated values of the non-cancelable contracts and the current fair value of contracts with similar terms. The deferred contract liability will be amortized to revenues over the remaining lives of the contracts of approximately one to four years.
In November 2006, we acquired from our joint venture partner its 70% interest in a joint venture company that owned two deepwater semi-submersible drilling rigs, the Pride Portland and the Pride Rio de Janeiro. The acquisition increased our ownership interest in the joint venture entity and the rigs from 30% to 100%. Consideration consisted of $215.0 million in cash, plus earn-out payments, if any, to be made during the six-year period (subject to certain extensions for non-operating periods) following the expiration of the existing drilling contracts for the rigs. Such earn-out payments will equal 30% of the amount, if any, by which the standard operating dayrate, excluding bonuses, for a rig (less adjustments to reflect certain capital additions and certain increases in operating costs) exceeds $294,975 (or, in the case of Petroleo Brasileiro S.A. (“Petrobras”), which currently contracts with a 15% bonus opportunity, $256,500). 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.
In a related transaction, we cancelled future obligations under certain existing agency relationships related to five offshore rigs we operate in Brazil, including the Pride Portland and the Pride Rio de Janeiro. For this cancellation, we paid $15 million in cash, which we expensed during the fourth quarter 2006.
NOTE 4. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following at December 31:
66
| 2008 | 2007 | |||||||
| Rigs and rig equipment | $ | 4,872.9 | $ | 4,856.8 | ||||
| Construction-in-progress - newbuild drillships | 962.2 | 322.7 | ||||||
| Construction-in-progress - other | 165.7 | 186.0 | ||||||
| Other | 63.0 | 72.9 | ||||||
| Property and equipment, cost | 6,063.8 | 5,438.4 | ||||||
| Accumulated depreciation and amortization | (1,474.9 | ) | (1,418.7 | ) | ||||
| Property and equipment, net | $ | 4,588.9 | $ | 4,019.7 | ||||
Depreciation and amortization expense of property and equipment for 2008, 2007 and 2006 was $206.5 million, $215.3 million and $188.0 million, respectively.
During 2008, 2007 and 2006, maintenance and repair costs included in operating costs on the accompanying consolidated statements of operations were $168.0 million, $116.0 million and $95.4 million, respectively.
We capitalize interest applicable to the construction of significant additions to property and equipment. For 2008, 2007 and 2006, we capitalized interest of $39.0 million, $10.3 million and $2.4 million, respectively.
Construction-in-progress – Newbuild Drillships
In July 2007, we acquired an ultra-deepwater drillship under construction. We paid the seller $108.5 million in cash and assumed its obligations under the construction contract, including remaining scheduled payments of approximately $540 million. The construction contract provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before February 28, 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from the shipyard for delays during certain periods.
During 2007 and 2008, we entered into agreements to construct three additional advanced-capability ultra-deepwater drillships. The agreements contain fixed purchase prices and delivery dates of June 2010, March 2011 and fourth quarter of 2011, respectively. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from the shipyard for delays during certain periods.
We expect the total project costs for the four drillships, including commissioning and testing, to be approximately $2.9 billion, excluding capitalized interest. As of December 31, 2008, construction-in-progress related to these four drillship construction contracts was $917.6 million, excluding $44.6 million of capitalized interest.
At December 31, 2008, our purchase obligations to the shipyard related to our four newbuild drillship construction projects as of such date are as follows:
| Amount | ||||
| 2009 | $ | 575.3 | ||
| 2010 | 623.8 | |||
| 2011 | 509.7 | |||
| 2012 | - | |||
| 2013 | - | |||
| Thereafter | - | |||
| $ | 1,708.8 | |||
Sale of assets
In May 2008, we sold our entire fleet of platform rigs and related land, buildings and equipment for $66 million in cash. In connection with the sale, we entered into lease agreements with the buyer to operate two platform rigs
67
until their current contracts are completed, which is expected to occur in the second quarter of 2009. The leases require us to pay to the buyer all revenues from the operation of the rigs, less operating costs and a small per day management fee, which we retain. In the second quarter of 2008, we recorded a gain on the sale of the assets of $18.0 million, excluding a deferred gain of approximately $10.9 million for the two rigs that we will operate until the completion of their current drilling contracts. At December 31, 2008, the remaining balance of the unamortized deferred gain was $4.9 million.
In December 2007, we sold the Bintang Kalimantan, a barge rig, for $34.0 million, resulting in a pre-tax gain of $20.0 million. In the second quarter of 2007, we completed the sale of one land rig for $17.3 million, resulting in a pre-tax gain on the sale of $8.5 million.
During 2006, we sold the Pride Rotterdam, an accommodation unit, 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.
NOTE 5. INDEBTEDNESS
Unsecured Revolving Credit Facility
In December 2008, we entered into an unsecured revolving credit agreement with a group of banks providing for availability of up to $300 million. The credit facility matures in December 2011. The credit facility has an accordion feature that would, under certain circumstances, allow us to increase the availability under the facility to up to $600 million. Amounts drawn under the credit facility bear interest at variable rates based on LIBOR plus a margin or the alternative base rate as defined in the agreement. The interest rate margin applicable to LIBOR advances varies based on our credit rating.
The credit facility contains a number of covenants restricting, among other things, liens; indebtedness of our subsidiaries; mergers and dispositions of all or substantially all of our or certain of our subsidiaries’ assets; agreements limiting the ability of subsidiaries to make dividends, distributions or other payments to us or other subsidiaries; affiliate transactions; amendments or other modifications to the charter, bylaws or similar documents of us and our subsidiaries; hedging arrangements outside the ordinary course of business; and sale-leaseback transactions. The facility also requires us to maintain certain ratios with respect to earnings to interest expenses and debt to tangible capitalization. The facility contains customary events of default, including with respect to a change of control.
Borrowings under the credit facility are available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes. We may obtain up to $100 million of letters of credit under the facility. As of December 31, 2008, there were no outstanding borrowings and no letters of credit outstanding under the facility.
Senior Secured Credit Facility
In connection with the closing under our new credit facility, we terminated our then-existing $500 million senior secured revolving credit facility. Amounts drawn under the facility bore interest at variable rates based on LIBOR plus a margin or the base rate plus a margin. The interest rate margin varied based on our leverage ratio. The revolving credit facility would have matured in July 2009. In connection with the retirement of the facility, we recognized a charge of $1.1 million related to the write-off of unamortized debt issuance costs, which is included in “Refinancing charges.”
Our indebtedness consisted of the following at December 31:
68
| 2008 | 2007 | |||||||
| 7 3/8% Senior Notes due 2014, net of unamortized discount of $1.7 million | ||||||||
| and $1.9 million, respectively | $ | 498.3 | $ | 498.1 | ||||
| MARAD notes, net of unamortized fair value discount of $2.4 million and | ||||||||
| $3.1 million, respectively | 224.9 | 254.5 | ||||||
| 3 1/4% Convertible Senior Notes due 2033 | - | 300.0 | ||||||
| Drillship loan facility due 2010, interest at LIBOR plus 1.5% | - | 138.9 | ||||||
| Total debt | 723.2 | 1,191.5 | ||||||
| Less: current portion of long-term debt | 30.3 | 75.8 | ||||||
| Long-term debt | $ | 692.9 | $ | 1,115.7 | ||||
7 3/8% Senior Notes due 2014
In July 2004, we completed an offering of $500.0 million principal amount of 7 3/8% Senior Notes due 2014. The notes bear interest at 7.375% per annum, payable semiannually. The notes contain provisions that limit our ability and the ability of our subsidiaries to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt or issue preferred stock; enter into agreements containing dividend or other payment restrictions affecting our subsidiaries; dispose of 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% for redemptions occurring on or after 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.
MARAD Notes
In November 2006, we completed the purchase of the remaining 70% interest in the joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro, which resulted in the addition of approximately $284 million of debt, net of fair value discount, to our consolidated balance sheet. Repayment of the notes, which were used to fund a portion of the construction costs of the rigs, 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.
3 1/4% Convertible Senior Notes Due 2033
In 2003, we issued $300.0 million aggregate principal amount of 3 1/4% Convertible Senior Notes due 2033. The notes paid interest at a rate of 3.25% per annum. In April 2008, we called for redemption all of our outstanding 3 1/4% Convertible Senior Notes Due 2033 in accordance with the terms of the indenture governing the notes. The redemption price was 100% of the principal amount thereof, plus accrued and unpaid interest (including contingent interest) to the redemption date. Under the indenture, holders of the notes could elect to convert the notes into our common stock at a rate of 38.9045 shares of common stock per $1,000 principal amount of the notes, at any time prior to the redemption date. Holders of the notes elected to convert a total of $299.7 million aggregate principal amount of the notes, and the remaining $254,000 aggregate principal amount was redeemed by us on the redemption date. We delivered an aggregate of approximately $300.0 million in cash and approximately 5.0 million shares of common stock in connection with the retirement of the notes. As a result of the retirement of the notes, we reversed a long-term deferred tax liability of $31.4 million, which was accounted for as an increase to “Paid-in capital.” The reversal related to interest expense imputed on these notes for U.S. federal income tax purposes.
Drillship Loan Facility
In March 2008, we repaid the outstanding aggregate principal amount of $138.9 million under the drillship loan facility collateralized by the Pride Africa and Pride Angola. In connection with the retirement of the drillship loan
69
facility, we recognized a charge of $1.2 million related to the write-off of unamortized debt issuance costs, which is included in “Refinancing charges.” We also settled all of the related interest rate swap and cap agreements (see Note 6).
Future Maturities
Future maturities of long-term debt were as follows at December 31:
| Amount | ||||
| 2009 | $ | 30.3 | ||
| 2010 | 30.3 | |||
| 2011 | 30.3 | |||
| 2012 | 30.3 | |||
| 2013 | 30.3 | |||
| Thereafter | 571.7 | |||
| $ | 723.2 | |||
NOTE 6. 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, 2008 and 2007 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, 2008 and 2007 was $702.5 million and $1,331.9 million, respectively, which differs from the carrying amounts of $723.2 million and $1,191.5 million, respectively, included in our consolidated balance sheets.
Interest Rate Swap and Cap Agreements
Our drillship loan facility required us to maintain interest rate swap and cap agreements, which were all settled as part of the retirement of the loan facility in March 2008. We did not designate any of the interest rate swap and cap agreements as hedging instruments as defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Accordingly, the changes in fair value of the interest rate swap and cap agreements were recorded in earnings. The total aggregate fair value of the interest rate swap and cap agreements as of December 31, 2007 was an asset of $0.2 million. In 2008, we recognized a charge of $1.7 million for the realized loss on the settlement of the interest rate swap and cap agreements, which is included in “Other income, net.”
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.
Cash Flow Hedging
In September 2008, we initiated a foreign currency hedging program to moderate the change in value of forecasted payroll transactions and related costs denominated in Euros. We are hedging a portion of these payroll and related costs using forward contracts. When the U.S. dollar strengthens against the Euro, the decline in the value of the forward contracts is offset by lower future payroll costs. Conversely, when the U.S. dollar weakens, the increase in value of forward contracts offsets higher future payroll costs. The maximum amount of time that we are hedging our exposure to Euro-denominated forecasted payroll costs is six months. The aggregate notional amount of these forward contracts, expressed in U.S. dollars, was $7.0 million at December 31, 2008.
70
All of our foreign currency forward contracts were accounted for as cash flow hedges under SFAS No. 133. The fair market value of these derivative instruments is included in prepaid expenses and other current assets or accrued expenses and other current liabilities, with the cumulative unrealized gain or loss included in accumulated other comprehensive income in our consolidated balance sheet. The estimated fair market value of our outstanding foreign currency forward contracts resulted in an asset of approximately $0.2 million at December 31, 2008. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between derivative contracts and the hedge item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings and recorded to other income (expense). We did not recognize a gain or loss due to hedge ineffectiveness in our consolidated statements of operations for the year ended December 31, 2008 related to these derivative instruments.
The balance of the net unrealized gain related to our foreign currency forward contracts in accumulated other comprehensive income is as follows:
| 2008 | ||||
| Net unrealized gain at beginning of period | $ | - | ||
| Activity during period: | ||||
| Settlement of forward contracts outstanding at beginning of period | - | |||
| Net unrealized loss on outstanding foreign currency forward contracts | 0.2 | |||
| Net unrealized gain at end of period | $ | 0.2 | ||
Fair Value of Financial Instruments
The following table presents the carrying amount and estimated fair value of our financial instruments recognized at fair value on a recurring basis:
| December 31, 2008 | ||||||||||||||||
| Estimated Fair Value Measurements | ||||||||||||||||
Carrying Amount | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||||
| Derivative Instruments: | ||||||||||||||||
| Foreign currency forward contracts | $ | 0.2 | $ | - | $ | 0.2 | $ | - | ||||||||
The derivative instruments have been valued using a combined income and market based valuation methodology based on forward exchange curves and credit. These curves are obtained from independent pricing services reflecting broker market quotes. Our cash and cash equivalents, accounts receivable and accounts payable are by their nature short-term. As a result, the carrying value included in the accompanying consolidated balance sheets approximate fair value.
NOTE 7. INVESTMENTS IN AFFILIATES
As of December 31, 2007, we had a 30% interest in United Gulf Energy Resource Co. SAOC-Sultanate of Oman (“UGER”), which owns 99.9% of National Drilling and Services Co. LLC (“NDSC”), an Omani company. NDSC owns and operates four land drilling rigs. As of December 31, 2007, our investment in UGER was $3.4 million. In February 2008, we sold our interest in UGER for approximately $15 million.
71
NOTE 8. INCOME TAXES
The provision for income taxes on income from continuing operations is comprised of the following for the years ended December 31:
| 2008 | 2007 | 2006 | ||||||||||
| U.S.: | ||||||||||||
| Current | $ | 20.8 | $ | 9.0 | $ | 3.5 | ||||||
| Deferred | 78.0 | 67.0 | 74.5 | |||||||||
| Total U.S. | 98.8 | 76.0 | 78.0 | |||||||||
| Foreign: | ||||||||||||
| Current | 117.8 | 92.9 | 43.7 | |||||||||
| Deferred | 0.6 | 3.4 | (4.3 | ) | ||||||||
| Total foreign | 118.4 | 96.3 | 39.4 | |||||||||
| Income taxes | $ | 217.2 | $ | 172.3 | $ | 117.4 | ||||||
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:
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| Amount | Rate (%) | Amount | Rate (%) | Amount | Rate (%) | |||||||||||||||||||
| U.S. statutory rate | $ | 309.3 | 35.0 | $ | 209.9 | 35.0 | $ | 102.2 | 35.0 | |||||||||||||||
| Taxes on foreign earnings at greater | ||||||||||||||||||||||||
| (lesser) than the U.S. statutory rate | (102.9 | ) | (11.6 | ) | (37.9 | ) | (6.3 | ) | 10.5 | 3.6 | ||||||||||||||
| Change in valuation allowance | - | - | (6.9 | ) | (1.2 | ) | 1.8 | 0.6 | ||||||||||||||||
| Tax benefit from prior year FTC | - | - | (10.5 | ) | (1.8 | ) | - | - | ||||||||||||||||
| Change in unrecognized tax benefits | 2.7 | 0.3 | 4.9 | 0.8 | 4.0 | 1.4 | ||||||||||||||||||
| Other | 8.1 | 0.9 | 12.8 | 2.2 | (1.1 | ) | (0.4 | ) | ||||||||||||||||
| Income taxes | $ | 217.2 | 24.6 | $ | 172.3 | 28.7 | $ | 117.4 | 40.2 | |||||||||||||||
The 2008 effective tax rate is below the U.S. statutory tax rate primarily due to certain profits taxed in low-tax jurisdictions. The 2007 tax rate is below the U.S. statutory rate primarily due to certain profits taxed in the low-tax jurisdictions and the recognition of a U.S. foreign tax credit benefit for a prior period. The 2006 effective tax rate is above the U.S. statutory rate due to non-deductible expenses and U.S. tax on certain foreign earnings offset by the impact of profits taxed in low-tax jurisdictions.
The domestic and foreign components of income from continuing operations before income taxes and minority interest were as follows for the years ended December 31:
| 2008 | 2007 | 2006 | ||||||||||
| U.S. | $ | 435.0 | $ | 292.1 | $ | 182.2 | ||||||
| Foreign | 448.6 | 307.5 | 109.9 | |||||||||
| Income from continuing operations before income taxes and minority interest | $ | 883.6 | $ | 599.6 | $ | 292.1 | ||||||
72
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:
| 2008 | 2007 | |||||||
| Deferred tax assets: | ||||||||
| Operating loss carryforwards | $ | 42.2 | $ | 71.7 | ||||
| Tax credit carryforwards | 86.6 | 137.3 | ||||||
| Employee stock-based awards and other benefits | 25.8 | 23.7 | ||||||
| Other | 9.2 | 7.4 | ||||||
| Subtotal | 163.8 | 240.1 | ||||||
| Valuation allowance | (42.2 | ) | (49.0 | ) | ||||
| Total | 121.6 | 191.1 | ||||||
| Deferred tax liabilities: | ||||||||
| Depreciation | 287.3 | 301.6 | ||||||
| Other | 0.8 | 29.7 | ||||||
| Total | 288.1 | 331.3 | ||||||
Net deferred tax liability(1) | $ | 166.5 | $ | 140.2 | ||||
| (1) | The change in deferred tax liability of $26.3 million between December 31, 2008 and 2007 is different from the 2008 reported deferred tax expense of $78.6 million. This difference is caused primarily by deferred taxes on discontinued operations and tax return benefits from the exercise of non-qualified stock options and excess original issue discount on contingent convertible debt that were charged directly to equity accounts. |
Applicable U.S. deferred income taxes and related foreign dividend withholding taxes have not been provided on approximately $1,826.5 million of undistributed earnings and profits of our foreign subsidiaries. We consider such earnings to be permanently reinvested outside the United States. It is not practicable to estimate the amount of deferred income taxes associated with these unremitted earnings.
As of December 31, 2008, we had deferred tax assets of $42.2 million relating to $147.0 million of foreign net operating loss (“NOL”) carryforwards, $27.8 million of non-expiring Alternative Minimum Tax (“AMT”) credits, and $58.8 million of U.S. foreign tax credits (“FTC”). The NOL carryforwards and tax credits can be used to reduce our income taxes payable in future years. NOL carryforwards include $39.7 million of losses that do not expire and $107.3 million that could expire starting in 2009 through 2018. We have recognized a $42.2 million valuation allowance on all of these foreign NOL carryforwards due to the uncertainty of realizing certain foreign NOL carryforwards. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized. We have not recorded a valuation allowance against our FTC and AMT credit deferred tax assets, since we believe that future profitability will allow us to fully utilize these tax attributes. Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings prior to the expiration of the carryforwards. The foreign tax credits begin to expire in 2018 and the AMT credits do not expire. We could be required to record an additional valuation allowance against certain or all of our remaining deferred tax assets if market conditions deteriorate or future earnings are below current estimates.
Uncertain Tax Positions
We have adopted and account for uncertainty in income taxes under the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). Under this interpretation, if we determine that a position is more likely than not of being sustained upon audit, based solely on the technical merits of the position, we recognize the benefit. We measure the benefit by determining the amount that is greater than 50 percent likely of being realized upon settlement. We presume that all tax positions will be examined by a taxing authority with full knowledge of all relevant information. We regularly monitor our tax positions and FIN 48 tax liabilities. We reevaluate the technical merits of our tax positions and recognize an uncertain tax benefit, or derecognize a previously recorded tax benefit, when (i) there is a completion of a tax audit, (ii) there is a change in applicable tax law including a tax case or legislative guidance, or (iii) there is an expiration of the statute of limitations. Significant judgment is required in accounting for tax reserves. Although we believe that we have adequately provided for liabilities resulting from tax assessments by taxing authorities, positions taken by tax authorities could have a material impact on our effective tax rate in future periods.
73
As of December 31, 2008, we have approximately $45.1 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate.
We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2008, we have approximately $12.5 million of accrued interest and penalties related to uncertain tax positions on the consolidated balance sheet. During 2008, we recorded interest and penalties of $3.0 million through the consolidated statement of operations.
The following table presents the reconciliation of the total amounts of unrecognized tax benefits from January 1, 2008 to December 31, 2008:
| Beginning balance, January 1, 2008 | $ | 44.4 | ||
| Increase related to prior period tax positions | 2.7 | |||
| Increase related to current period tax positions | 1.5 | |||
| Statue expirations | - | |||
| Settlements | (2.8 | ) | ||
| Other | (0.7 | ) | ||
| Ending balance, December 31, 2008 | $ | 45.1 | ||
74
For jurisdictions other than the United States, tax years 1995 through 2007 remain open to examination by the major taxing jurisdictions. With regard to the United States, tax years 2006 through 2008 remain open to examination.
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 do not expect the ultimate resolution of outstanding tax assessments to have a material adverse effect on our consolidated financial statements.
In 2006, we received tax assessments from the Mexican government related to the operations of certain entities for the tax years 2001 through 2003. These assessments contest our right to claim certain deductions. As required by statutory requirements, we have provided bonds totaling 555 million Mexican pesos, or approximately $40 million as of December 31, 2008, to contest these assessments. 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 expect the ultimate outcome of these assessments to have a material impact on our consolidated financial statements. We anticipate that the Mexican government will make additional assessments contesting similar deductions for other tax years or entities. Additional security will be required to be provided to the extent future assessments are contested (See Note 17).
NOTE 9. STOCKHOLDERS’ EQUITY
Preferred Stock
We are authorized to issue 50.0 million shares of preferred stock with a par value $0.01 per share. Our Board of Directors has the authority to issue shares of preferred stock in one or more series and to fix the number of shares, designations and other terms of each series. The Board of Directors has designated 4.0 million shares of preferred stock to constitute the Series A Junior Participating Preferred Stock in connection with our stockholders’ rights plan. As of December 31, 2008 and 2007, no shares of preferred stock were outstanding.
Common Stock
In connection with the retirement in the second quarter of 2008 of our 3¼% Convertible Senior Notes Due 2033, we issued a total of 5.0 million shares of common stock to the holders (See Note 5).
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. In 2008, our Board of Directors took action under the plan to reduce the applicable percentage of beneficial stock ownership that triggers the plan, only as it relates to Seadrill Limited and its affiliates and associates, from 15% to 10%.
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
75
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 our Board of Directors makes this determination, the purchase of shares under the offer will not be a flip-in event.
If, after there is an acquiring person, we are acquired in a merger or other business combination transaction or 50% or more of our assets, earning power or cash flow are sold or transferred, each holder of a right will have the right to purchase shares of the common stock of the acquiring company at a price of one-half the current market price of that stock. This occurrence is referred to as a “flip-over event” under the plan. An acquiring person will not be entitled to exercise its rights, which will have become void.
Until ten days after the announcement that a person has become an acquiring person, our Board of Directors may decide to redeem the rights at a price of $0.01 per right, payable in cash, shares of common stock or other consideration. The rights will not be exercisable after a flip-in event until the rights are no longer redeemable.
At any time after a flip-in event and prior to either a person’s becoming the beneficial owner of 50% or more of the shares of common stock or a flip-over event, our Board of Directors may decide to exchange the rights for shares of common stock on a one-for-one basis. Rights owned by an acquiring person, which will have become void, will not be exchanged.
NOTE 10. EARNINGS PER SHARE
The following table presents information necessary to calculate basic and diluted earnings per share from continuing operations for the years ended December 31:
| 2008 | 2007 | 2006 | ||||||||||
| Income from continuing operations - basic | $ | 666.4 | $ | 423.8 | $ | 170.6 | ||||||
| Interest expense on convertible notes | 3.6 | 10.7 | 10.7 | |||||||||
| Income tax effect | (1.2 | ) | (3.7 | ) | (3.7 | ) | ||||||
| Income from continuing operations - diluted | $ | 668.8 | $ | 430.8 | $ | 177.6 | ||||||
| Weighted average shares of common stock outstanding - basic | 170.6 | 165.6 | 162.8 | |||||||||
| Convertible notes | 4.1 | 11.7 | 11.7 | |||||||||
| Stock options | 0.5 | 0.8 | 1.9 | |||||||||
| Restricted stock awards | 0.4 | 0.4 | 0.1 | |||||||||
| Weighted average shares of common stock outstanding - diluted | 175.6 | 178.5 | 176.5 | |||||||||
| Income from continuing operations per share: | ||||||||||||
| Basic | $ | 3.91 | $ | 2.56 | $ | 1.05 | ||||||
| Diluted | $ | 3.81 | $ | 2.41 | $ | 1.01 | ||||||
The calculation of weighted average shares of common stock outstanding - diluted, as adjusted, excludes 1.3 million, 1.1 million and 0.6 million of common stock issuable pursuant to outstanding stock options and restricted stock awards for the years ended December 31, 2008, 2007 and 2006, respectively, because their effect was antidilutive.
NOTE 11. STOCK-BASED COMPENSATION
Our employee stock-based compensation plans provide for the granting or awarding of stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards and cash awards to directors, officers and other key employees. As of December 31, 2008, two of our plans had shares available for future option grants or other awards. As of December 31, 2008, we had a total of approximately 181,000 shares available for award under the 2004 Directors’ Stock Incentive Plan. The 2007 Long-Term Incentive Plan allows for up to 8.0 million shares to be awarded to our employees. The maximum number of shares of common stock that may be
76
issued with respect to awards other than options and stock appreciation rights is 4.0 million shares. As of December 31, 2008, we had granted stock awards totaling approximately 8,000 shares under the 2007 plan.
Stock-based compensation expense related to stock options, restricted stock and our Employee Stock Purchase Plan (“ESPP”) was allocated as follows:
| 2008 | ||||
Operating costs, excluding depreciation and amortization | $ | 14.0 | ||
| General and administrative, excluding depreciation and amortization | 10.8 | |||
| Stock-based compensation expense before income taxes | 24.8 | |||
| Income tax benefit | (6.9 | ) | ||
| Total stock-based compensation expense after income taxes | $ | 17.9 | ||
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:
| Stock Options | ESPP | |||||||||||||||
| 2008 | 2007 | 2006 | 2008 | |||||||||||||
| Dividend yield | 0.0 | % | 0.0 | % | 0.0 | % | 0.0 | % | ||||||||
| Expected volatility | 35.1 | % | 31.2 | % | 32.6 | % | 35.1 | % | ||||||||
| Risk-free interest rate | 3.3 | % | 4.7 | % | 4.6 | % | 3.3 | % | ||||||||
| Expected life | 5.3 years | 6.3 years | 6.3 years | 1.0 year | ||||||||||||
| Weighted average grant-date fair value of stock | ||||||||||||||||
| options granted | $ | 12.92 | $ | 11.80 | $ | 13.79 | $ | 12.92 | ||||||||
The following table summarizes activity in our stock options:
Number of Shares | Weighted Average Exercise Price per Share | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||||||
| (In Thousands) | (In Years) | |||||||||||||||
| Outstanding as of December 31, 2007 | 3,184 | $ | 23.03 | |||||||||||||
| Granted | 522 | 34.48 | ||||||||||||||
| Exercised | 1,004 | 18.93 | ||||||||||||||
| Forfeited | - | 19.75 | ||||||||||||||
| Cancellations | 58 | 26.67 | ||||||||||||||
| Outstanding as of December 31, 2008 | 2,644 | $ | 26.77 | 6.9 | $ | 1.3 | ||||||||||
| Exercisable as of December 31, 2008 | 1,524 | $ | 23.01 | 5.9 | $ | 0.2 | ||||||||||
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.
77
Other information pertaining to option activity was as follows:
| 2008 | 2007 | 2006 | ||||||||||
| Total fair value of stock options vested | $ | 5.2 | $ | 5.2 | $ | 7.7 | ||||||
| Total intrinsic value of stock options exercised | $ | 21.6 | $ | 26.9 | $ | 46.7 | ||||||
During 2008, 2007 and 2006, we received cash from the exercise of stock options of $19.0 million, $27.6 million and $50.3 million, respectively. Income tax benefits of $7.9 million, $7.7 million and $14.1 million were realized from the exercise of stock options for 2008, 2007 and 2006, respectively. As of December 31, 2008, there was $9.5 million of total stock option compensation expense related to nonvested stock options not yet recognized, which is expected to be recognized over a weighted average period of 2.2 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:
| 2008 | 2007 | 2006 | ||||||||||
| Number of restricted stock awards (in thousands) | 932 | 948 | 839 | |||||||||
| Fair value of restricted stock awards at date of grant (in millions) | $ | 31.7 | $ | 27.6 | $ | 26.9 | ||||||
The following table summarizes activity in our nonvested restricted stock awards:
Number of Shares | Weighted Average Grant Date Fair Value per Share | |||||||
| (In Thousands) | ||||||||
| Nonvested at December 31, 2007 | 1,444 | $ | 29.43 | |||||
| Granted | 933 | 33.99 | ||||||
| Vested | 487 | 29.34 | ||||||
| Forfeited | 192 | 31.35 | ||||||
| Nonvested at December 31, 2008 | 1,698 | $ | 31.75 | |||||
As of December 31, 2008, there was $32.7 million of unrecognized stock-based compensation expense related to nonvested restricted stock awards. That cost is expected to be recognized over a weighted average period of 2.2 years.
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
78
withholding and settlement of vested awards, which resulted in the reclassification of the affected restricted stock awards back to equity classified awards. The February 15, 2007, modification did not result in any material incremental compensation cost and resulted in the reclassification of the full amount of the recorded liability to equity in the first quarter of 2007.
During 2008, 2007 and 2006, we recognized $0.1 million, $0.1 million and $0.4 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 applicable purchase period. Prior to 2009, the annual purchase period extended from January 1 to December 31 of each year. Starting in 2009, there will be two annual purchase periods of six months each. A total of 0.2 million shares remained available for issuance under the plan as of December 31, 2008. Employees purchased approximately 133,000, 95,000 and 83,000 shares in the years ended December 31, 2008, 2007 and 2006, respectively.
NOTE 12. EMPLOYEE BENEFIT PLANS
Defined Benefit Pension Plans
We have a non-qualified Supplemental Executive Retirement Plan (the “SERP”) that provides for benefits, to the extent vested, to be paid to participating executive officers upon the officer’s termination or retirement. No assets are held with respect to the SERP; therefore, benefits will be funded when paid to the participants. We account for the SERP in accordance with SFAS No. 87, Employers Accounting for Pensions. We recorded expenses of $3.5 million, $5.6 million and $4.3 million related to the SERP in 2008, 2007 and 2006, respectively. As of December 31, 2008 and 2007, the unfunded accrued pension liability was $18.0 million and $13.6 million, respectively.
We fully recognize the funded status of defined benefit pension plan and other postretirement plans in the balance sheet. Based on the funded status of our plans, total liabilities for underfunded plans were approximately $0.8 million as of December 31, 2008 and total assets for overfunded plans were approximately $1.1 million as of December 31, 2007. As of December 31, 2008 and 2007, the unfunded accrued liability was approximately $19.0 million and $14.3 million, respectively. The adoption of SFAS 158 as of December 31, 2006, 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 $9.2 million, $6.4 million and $4.8 million in 2008, 2007 and 2006, respectively.
In addition, we have a deferred compensation plan that allows senior managers and other highly compensated employees, as defined in the plan, to participate in an unfunded, non-qualified plan. Participants may defer up to 100% of compensation, including bonuses and net proceeds from the exercise of stock options.
NOTE 13. COMMITMENTS AND CONTINGENCIES
Leases
At December 31, 2008, 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:
79
| Amount | ||||
| 2009 | $ | 11.6 | ||
| 2010 | 5.1 | |||
| 2011 | 4.4 | |||
| 2012 | 4.3 | |||
| 2013 | 4.3 | |||
| Thereafter | 18.4 | |||
| $ | 48.1 | |||
FCPA Investigation
During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.
The investigation, which is continuing, has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.
The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations. In addition, the U.S. Department of Justice has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria. The Audit Committee is reviewing the issues raised by the request, and we are cooperating with the DOJ in connection with its request.
This review has found evidence suggesting that during the period from 2001 through 2006 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola, and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2.5 million. We are also reviewing certain agent payments related to Malaysia.
The investigation of the matters described in the prior paragraph and the Audit Committee’s compliance review are ongoing. Accordingly, there can be no assurances that evidence of additional potential FCPA violations may not be uncovered in those or other countries.
Our management and the Audit Committee of our Board of Directors believe it likely that then 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
80
retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.
We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the Securities and Exchange Commission and are cooperating with these authorities as the investigation and compliance reviews continue and as they review the matter. If violations of the FCPA occurred, we could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.
We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company. 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, claims or other penalties, which could be material individually or in the aggregate.
We cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, any other applicable government or other authorities or our customers or other third parties or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.
Litigation
Since 2004, certain of our subsidiaries have been named, along with numerous other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi by several hundred individuals that allege that they were employed by some of the named defendants between approximately 1965 and 1986. The complaints allege that certain drilling contractors used products containing asbestos in their operations and seek, among other things, an award of unspecified compensatory and punitive damages. Nine individuals of the many plaintiffs in these suits have been identified as allegedly having worked for us. A trial is set for one of the claimants in October 2009. 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.
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.
Loss of Pride Wyoming
In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig operating in the U.S. Gulf of Mexico, was deemed a total loss for insurance purposes after it was severely damaged and sank as a result of Hurricane Ike. The rig had a net book value of approximately $14 million and was insured for $45 million. We have collected a total of $25 million through October 2008 for the insured value of the rig, which is net of our deductibles of $20 million. We
81
expect to incur costs of approximately $48.6 million for removal of the wreckage and salvage operations, not including any costs arising from damage to offshore structures owned by third parties. These costs for removal of the wreckage and salvage operations in excess of a $1 million retention are expected to be covered by our insurance. We will be responsible for payment of the $1 million retention, $2.5 million in premium payments for a removal of wreckage claim and for any costs not covered by our insurance.
The owners of two pipelines on which parts of the Pride Wyoming settled have requested that we pay for all costs, expenses and other losses associated with the damage, including loss of revenue. Each owner has claimed damages in excess of $40 million. Other pieces of the rig may have also caused damage to certain other offshore structures. In October 2008, we filed a complaint in the U.S. Federal District Court pursuant to the Limitation of Liability Act, which has the potential to statutorily limit our exposure for claims arising out of third-party damages caused by the loss of the Pride Wyoming. Based on information available to us at this time, we do not expect the outcome of this potential claim 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 potential claim. Although we believe we have adequate insurance, we will be responsible for any awards not covered by our insurance.
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 $211.3 million at December 31, 2008. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions.
NOTE 14. SEGMENT AND GEOGRAPHIC INFORMATION
During the fourth quarter of 2008, we reorganized our reportable segments to reflect the general asset class of our drilling rigs. We believe that this change reflects how we manage our business. Our new reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths greater than 4,500 feet, and Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,500 feet or less. Our jackup fleet, which operates in water depths up to 300 feet, is reported as two segments, Independent Leg Jackups and Mat-Supported Jackups, based on rig design as well as our intention to separate the mat-supported jackup business. We also manage the drilling operations for three deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations. For all periods presented, we have excluded the results of operations of our discontinued operations. As a result of our disposal of these operations, certain operating and administrative costs were reallocated for all periods presented to our remaining continuing operating segments.
The accounting policies for our segments are the same as those described in Note 1 of our Consolidated Financial Statements.
Summarized financial information for our reportable segments are listed below.
82
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Revenues: | ||||||||||||
| Deepwater | $ | 882.2 | $ | 643.9 | $ | 479.0 | ||||||
| Midwater | 425.2 | 334.5 | 181.2 | |||||||||
| Jackups - Independent Leg | 275.2 | 221.7 | 125.6 | |||||||||
| Jackups - Mat-Supported | 553.1 | 551.7 | 550.9 | |||||||||
| Other | 174.2 | 198.7 | 182.2 | |||||||||
| Corporate | 0.5 | 1.0 | (0.1 | ) | ||||||||
| Total | $ | 2,310.4 | $ | 1,951.5 | $ | 1,518.8 | ||||||
| Earnings (loss) from operations: | ||||||||||||
| Deepwater | $ | 463.0 | $ | 274.2 | $ | 123.4 | ||||||
| Midwater | 168.7 | 145.0 | 27.8 | |||||||||
| Jackups - Independent Leg | 135.7 | 94.9 | 34.0 | |||||||||
| Jackups - Mat-Supported | 197.1 | 227.8 | 269.1 | |||||||||
| Other | 39.9 | 62.6 | 31.9 | |||||||||
| Corporate | (134.9 | ) | (142.6 | ) | (121.0 | ) | ||||||
| Total | $ | 869.5 | $ | 661.9 | $ | 365.2 | ||||||
| Capital expenditures: | ||||||||||||
| Deepwater | $ | 714.4 | $ | 336.8 | $ | 24.4 | ||||||
| Midwater | 169.3 | 101.1 | 106.6 | |||||||||
| Jackups - Independent Leg | 40.1 | 39.6 | 48.3 | |||||||||
| Jackups - Mat-Supported | 21.6 | 102.6 | 96.8 | |||||||||
| Other | 7.5 | 12.1 | 21.1 | |||||||||
| Corporate | 29.4 | 21.9 | 2.7 | |||||||||
| Discontinued operations | 1.7 | 42.3 | 56.3 | |||||||||
| Total | $ | 984.0 | $ | 656.4 | $ | 356.2 | ||||||
| Depreciation and amortization: | ||||||||||||
| Deepwater | $ | 71.9 | $ | 83.2 | $ | 67.5 | ||||||
| Midwater | 40.3 | 35.3 | 33.6 | |||||||||
| Jackups - Independent Leg | 26.8 | 26.1 | 18.3 | |||||||||
| Jackups - Mat-Supported | 56.3 | 54.2 | 49.0 | |||||||||
| Other | 3.9 | 11.3 | 15.0 | |||||||||
| Corporate | 7.3 | 5.2 | 4.6 | |||||||||
| Total | $ | 206.5 | $ | 215.3 | $ | 188.0 | ||||||
We measure segment assets as property and equipment and goodwill. At December 31, 2008 and 2007, goodwill of $1.2 million for both periods was included in our Jackups – Mat-Supported segment and for 2007 $0.3 million of goodwill was included in other. Our total long-lived assets by segment as of December 31, 2008 and 2007 were as follows:
83
| As of December 31, | ||||||||
| 2008 | 2007 | |||||||
| Total long-lived assets: | ||||||||
| Deepwater | $ | 3,011.2 | $ | 2,369.4 | ||||
| Midwater | 681.4 | 604.8 | ||||||
| Jackups - Independent Leg | 275.8 | 269.4 | ||||||
| Jackups - Mat-Supported | 528.7 | 588.0 | ||||||
| Other | 10.9 | 43.7 | ||||||
| Corporate | 81.8 | 79.2 | ||||||
| Discontinued operations | 0.3 | 66.7 | ||||||
| Total | $ | 4,590.1 | $ | 4,021.2 | ||||
Our significant customers for the years ended December 31, 2008, 2007 and 2006, were as follows:
| 2008 | 2007 | 2006 | ||||||||||
| Petroleos Mexicanos S.A. | 20% | 22% | 15% | |||||||||
| Petroleo Brasileiro S.A. | 19% | 14% | 16% | |||||||||
| BP America and affiliates | 10% | 7% | 7% | |||||||||
| Total S.A. | 9% | 8% | 12% | |||||||||
For the year ended December 31, 2008, we derived 86% of our revenues from countries outside of the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in foreign operations. Revenues by geographic area are presented by attributing revenues to the individual country where the services were performed.
Revenues by geographic area where the services are performed are as follows for years ended December 31:
| 2008 | 2007 | 2006 | ||||||||||
| Angola | $ | 532.1 | $ | 464.8 | $ | 298.0 | ||||||
| Mexico | 464.7 | 432.5 | 227.1 | |||||||||
| Brazil | 513.7 | 394.6 | 269.4 | |||||||||
| Other countries | 480.7 | 313.6 | 254.6 | |||||||||
| All International | 1,991.2 | 1,605.5 | 1,049.1 | |||||||||
| United States | 319.2 | 346.0 | 469.7 | |||||||||
| Total | $ | 2,310.4 | $ | 1,951.5 | $ | 1,518.8 | ||||||
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.
84
Long-lived assets, which include property and equipment and goodwill, by geographic area, including our four drillships under construction in South Korea, are as follows at December 31:
| 2008 | 2007 | |||||||
| Brazil | $ | 1,520.5 | $ | 1,424.5 | ||||
| South Korea | 962.2 | 322.7 | ||||||
| Angola | 793.8 | 786.0 | ||||||
| Mexico | 343.1 | 490.9 | ||||||
| Other countries | 597.7 | 635.4 | ||||||
| All International | 4,217.3 | 3,659.5 | ||||||
| United States | 372.8 | 361.7 | ||||||
| Total | $ | 4,590.1 | $ | 4,021.2 | ||||
NOTE 15. OTHER SUPPLEMENTAL INFORMATION
Prepaid expenses and other current assets consisted of the following at December 31:
| 2008 | 2007 | |||||||
| Other receivables | $ | 62.2 | $ | 62.5 | ||||
| Insurance receivables | 52.3 | 1.9 | ||||||
| Prepaid expenses | 31.0 | 39.9 | ||||||
| Deferred mobilization and inspection costs | 26.4 | 30.0 | ||||||
| Deferred financing costs | 1.6 | 3.3 | ||||||
| Derivative asset | - | 0.2 | ||||||
| Other | 3.9 | 11.7 | ||||||
| Total | $ | 177.4 | $ | 149.5 | ||||
Accrued expenses and other current liabilities consisted of the following at December 31:
| 2008 | 2007 | |||||||
| Payroll and benefits | $ | 82.3 | $ | 87.4 | ||||
| Deferred mobilization revenues | 78.1 | 90.1 | ||||||
| Current income taxes | 70.7 | 54.7 | ||||||
| Salvage costs | 41.2 | - | ||||||
| Interest | 20.2 | 22.7 | ||||||
| Short-term indemnity | 19.5 | 77.8 | ||||||
| Taxes other than income | 18.9 | 20.5 | ||||||
| Importation duties | 7.5 | - | ||||||
| Other | 65.0 | 75.1 | ||||||
| Total | $ | 403.4 | $ | 428.3 | ||||
85
Supplemental consolidated statement of operations information is as follows for the years ended December 31:
| 2008 | 2007 | 2006 | ||||||||||
| Rental expense | $ | 72.9 | $ | 59.7 | $ | 87.1 | ||||||
| Other income, net | ||||||||||||
| Foreign exchange gain (loss) | $ | 7.1 | $ | (4.1 | ) | $ | (4.2 | ) | ||||
| Realized and unrealized changes in fair value of derivatives | - | (1.0 | ) | 1.6 | ||||||||
| Equity earnings in unconsolidated subsidiaries | 0.2 | 1.0 | 3.3 | |||||||||
| Other | 10.1 | 0.7 | 0.2 | |||||||||
| Total | $ | 17.4 | $ | (3.4 | ) | $ | 0.9 | |||||
Supplemental cash flows and non-cash transactions were as follows for the years ended December 31:
| 2008 | 2007 | 2006 | ||||||||||
| Decrease (increase) in: | ||||||||||||
| Trade receivables | $ | (101.2 | ) | $ | (78.5 | ) | $ | (69.5 | ) | |||
| Prepaid expenses and other current assets | 9.4 | (0.7 | ) | (42.2 | ) | |||||||
| Other assets | (2.5 | ) | (19.0 | ) | 7.1 | |||||||
| Increase (decrease) in: | ||||||||||||
| Accounts payable | 58.8 | (53.5 | ) | 69.6 | ||||||||
| Accrued expenses | (15.9 | ) | (15.6 | ) | 23.5 | |||||||
| Other liabilities | 24.5 | 15.3 | 25.9 | |||||||||
| Net effect of changes in operating accounts | $ | (26.9 | ) | $ | (152.0 | ) | $ | 14.4 | ||||
| Cash paid during the year for: | ||||||||||||
| Interest | $ | 56.1 | $ | 77.6 | $ | 74.0 | ||||||
| Income taxes — U.S., net | 2.4 | 8.6 | 4.1 | |||||||||
| Income taxes — foreign, net | 145.8 | 127.6 | 101.6 | |||||||||
| Change in capital expenditures in accounts payable | (54.6 | ) | (50.6 | ) | (12.5 | ) | ||||||
| Non-cash interest accreted to principal balance of debt | 0.9 | 0.9 | 0.3 | |||||||||
86
NOTE 16. SELECTED QUARTERLY FINANCIAL DATA (1) (UNAUDITED)
| First | Second | Third | Fourth | |||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
| 2008 | ||||||||||||||||
| Revenues | $ | 540.1 | $ | 541.5 | $ | 607.2 | $ | 621.6 | ||||||||
| Earnings from operations | 176.4 | 198.2 | 239.2 | 255.7 | ||||||||||||
| Income from continuing operations, net of tax | 136.1 | 153.4 | 179.7 | 197.4 | ||||||||||||
| Income from discontinued operations, net of tax | 104.6 | 34.3 | 9.4 | 37.3 | ||||||||||||
| Net income | 240.7 | 187.7 | 189.1 | 234.7 | ||||||||||||
| Basic earnings per share: | ||||||||||||||||
| Income from continuing operations | 0.81 | 0.90 | 1.04 | 1.14 | ||||||||||||
| Income from discontinued operations | 0.63 | 0.20 | 0.05 | 0.22 | ||||||||||||
| Net income | $ | 1.44 | $ | 1.10 | $ | 1.09 | $ | 1.36 | ||||||||
| Diluted earnings per share: | ||||||||||||||||
| Income from continuing operations | 0.77 | 0.87 | 1.03 | 1.14 | ||||||||||||
| Income from discontinued operations | 0.58 | 0.20 | 0.06 | 0.22 | ||||||||||||
| Net income | $ | 1.35 | $ | 1.07 | $ | 1.09 | $ | 1.36 | ||||||||
| 2007 | ||||||||||||||||
| Revenues | $ | 443.9 | $ | 505.2 | $ | 520.0 | $ | 482.4 | ||||||||
| Earnings from operations | 129.0 | 188.9 | 180.6 | 163.4 | ||||||||||||
| Income from continuing operations, net of tax | 71.6 | 115.8 | 118.4 | 118.0 | ||||||||||||
| Income from discontinued operations, net of tax | 30.1 | 30.3 | 283.1 | 17.0 | ||||||||||||
| Net income | 101.7 | 146.1 | 401.5 | 135.0 | ||||||||||||
| Basic earnings per share: | ||||||||||||||||
| Income from continuing operations | 0.43 | 0.70 | 0.71 | 0.71 | ||||||||||||
| Income from discontinued operations | 0.19 | 0.18 | 1.71 | 0.10 | ||||||||||||
| Net income | $ | 0.62 | $ | 0.88 | $ | 2.42 | $ | 0.81 | ||||||||
| Diluted earnings per share: | ||||||||||||||||
| Income from continuing operations | 0.41 | 0.66 | 0.67 | 0.67 | ||||||||||||
| Income from discontinued operations | 0.17 | 0.17 | 1.59 | 0.10 | ||||||||||||
| Net income | $ | 0.58 | $ | 0.83 | $ | 2.26 | $ | 0.77 | ||||||||
____________
| (1) | All periods presented reflect the reclassification of our former Latin America Land and E&P Services segments, three tender-assist barge rigs and remaining Eastern Hemisphere land rig operations to discontinued operations. |
NOTE 17. SUBSEQUENT EVENT (UNAUDITED)
In February 2009, we received additional tax assessments from the Mexican government related to the operations of certain entities for the tax years 2003 and 2004 in the amount of 1,097 million pesos, or approximately $74 million. Bonds for these assessments are to be provided later in 2009. Additional bonds will need to be provided to the extent future assessments are contested. We anticipate that the Mexican government will make additional assessments contesting similar deductions for other tax years or entities.
87
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
(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, 2008 were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
(b) Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined under Rule 13a-15(f) promulgated under the Exchange Act. In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2008, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, using the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (the “COSO Framework”). The inherent limitations of internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management concluded that our internal control over financial reporting was effective based on the criteria set forth in the COSO Framework as of December 31, 2008.
KPMG LLP, our independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2008 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 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
None.
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, 2008. 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.
88
Code of Business Conduct and Ethical Practices
We have adopted a Code of Business Conduct and Ethical Practices, which applies to all employees, including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of the code under “Corporate Governance” in the “Investor Relations” section of our internet website at www.prideinternational.com. Copies of the code may be obtained free of charge on our website or by requesting a copy in writing from our Chief Compliance Officer at 5847 San Felipe, Suite 3300, Houston, Texas 77057. Any waivers of the code must be approved by our Board of Directors or a designated board committee. Any amendments to, or waivers from, the code that apply to our executive officers and directors will be posted under “Corporate Governance” in the “Investor Relations” section of our internet website at www.prideinternational.com.
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, 2008.
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, 2008.
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, 2008.
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, 2008.
(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
89
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.
Exhibit No. | Description | |
| 3.1 | Certificate of Incorporation of Pride (incorporated by reference to Annex D to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4, Registration Nos. 333-66644 and 333-66644-01 (the “Registration Statement’)). | |
| 3.2 | Bylaws of Pride, as amended on December 12, 2008 (incorporated by reference to Exhibit 3.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 18, 2008, File No. 1-13289). | |
| 4.1 | Form of Common Stock Certificate (incorporated by reference to Exhibit 4.13 to the Registration Statement). | |
| 4.2 | Rights Agreement, dated as of September 13, 2001, between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.2 Pride’s Current Report on Form 8-K filed with the SEC on September 28, 2001, File No. 1-13289 (the “Form 8-K”)). | |
| 4.3 | First Amendment to Rights Agreement dated as of January 29, 2008 between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.3 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13289). | |
| 4.4 | Certificate of Designations of Series A Junior Participating Preferred Stock of Pride (incorporated by reference to Exhibit 4.3 to the Form 8-K). | |
| 4.5 | Revolving Credit Agreement dated as of December 9, 2008 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis, as syndication agent for the lenders, BNP Paribas, Bayerische Hypo-Und Vereinsbank AG and Wells Fargo Bank, N.A., as documentation agents for the lenders, and Citibank, N.A., as issuing bank of the letters of credit thereunder (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 15, 2008, File No. 1-13289). | |
| 4.6 | Indenture dated as of July, 1, 2004 by and between Pride and The Bank of New York Mellon Trust Company, N.A. (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Pride’s Registration Statement on Form S-4, File No. 333-118104). | |
| 4.7 | First Supplemental Indenture dated as of July 7, 2004 by and between Pride and The Bank of New York Mellon Trust Company, N.A. (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Pride’s Registration Statement on Form S-4, File No. 333-118104). | |
| Pride and its subsidiaries are parties to several debt instruments that have not been filed with the SEC under which the total amount of securities authorized does not exceed 10% of the total assets of Pride and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, Pride agrees to furnish a copy of such instruments to the SEC upon request. | ||
| 10.1† | Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10(j) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-16963). | |
| 10.2† | First Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 4.7 to Pride’s Registration Statement on Form S-8, Registration No. 333-35093). | |
| 10.3† | Second Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.10 to Pride’s Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-13289). | |
| 10.4† | Third Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.11 of Pride’s Annual Report on Form 10-K for the year ended December 31, 1998, File No. 1-13289). | |
| 10.5† | Fourth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.12 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289). | |
| 10.6† | Fifth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.13 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289). | |
| 10.7† | Sixth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-13289). | |
| 10.8† | Pride International, Inc. 401(k) Restoration Plan (incorporated by reference to Exhibit 10(k) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1993, File No. 0-16963). | |
| 10.9† | Pride International, Inc. Supplemental Executive Retirement Plan, as amended and restated effective December 31, 2008 (the “SERP”) (incorporated by reference to Exhibit 10.6 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.10† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.7 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.11† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.8 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.12† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.9 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.13† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.10 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.14† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.11 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.15†* | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Kevin C. Robert. | |
| 10.16† | Pride International, Inc. 1998 Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.21 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-13289). | |
| 10.17† | Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289). | |
| 10.18† | Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289). | |
| 10.19† | Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289). | |
| 10.20† | Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289). | |
| 10.21† | Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289). | |
| 10.22† | Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.6 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289). | |
| 10.23† | Pride International, Inc. Employee Stock Purchase Plan (as amended and restated effective January 1, 2009) (incorporated by reference to Exhibit 10.3 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.24† | Pride International, Inc. Annual Incentive Plan (as amended and restated effective January 1, 2008) (incorporated by reference to Exhibit 10.4 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.25† | Pride International, Inc. 2004 Directors’ Stock Incentive Plan (as amended and restated) (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2008 Annual Meeting of Stockholders, File No. 1-13289). | |
| 10.26† | First Amendment to 2004 Directors’ Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.27† | Form of 2004 Director’s Stock Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289). | |
| 10.28† | Form of 2004 Director’s Stock Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289). | |
| 10.29† | Form of 2004 Directors’ Stock Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.30† | Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2007 Annual Meeting of Stockholders, File No. 1-13289). | |
| 10.31† | First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.32† | Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.33† | Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.34† | Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.35† | Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.36† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.37† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.38† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.39† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.40† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.41†* | Amended and Restated Employment/Non- Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Kevin C. Robert. | |
| 10.42† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement effective as of October 29, 2008, between Pride and Randall D. Stilley (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.43†* | Summary of certain executive officer and director compensation arrangements. | |
| 12* | Computation of ratio of earnings to fixed charges. | |
| 21* | Subsidiaries of Pride. | |
| 23.1* | Consent of KPMG LLP. | |
| 31.1* | Certification of Chief Executive Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2* | Certification of Chief Financial Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32* | Certification of the Chief Executive Officer and the Chief Financial Officer of Pride pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
____________
| * | Filed herewith. |
| † | Management contract or compensatory plan or arrangement. |
90
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on February 24, 2009.
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 February 24, 2009.
| Signatures | Title | |
/s/ LOUIS A. RASPINO | President, Chief Executive Officer and Director | |
| (Louis A. Raspino) | (principal executive officer) | |
/s/ BRIAN C. VOEGELE | Senior Vice President and Chief Financial Officer | |
| (Brian C. Voegele) | (principal financial officer) | |
/s/ LEONARD E. TRAVIS | Vice President and Chief Accounting Officer | |
| (Leonard E. Travis) | (principal accounting officer) | |
/s/ DAVID A. B. BROWN | Chairman of the Board | |
| (David A. B. Brown) | ||
/s/ KENNETH M. BURKE | Director | |
| (Kenneth M. Burke) | ||
/s/ ARCHIE W. DUNHAM | Director | |
| (Archie W. Dunham) | ||
/s/ DAVID A. HAGER | Director | |
| (David A. Hager) | ||
/s/ FRANCIS S. KALMAN | Director | |
| (Francis S. Kalman) | ||
/s/ RALPH D. MCBRIDE | Director | |
| (Ralph D. McBride) | ||
/s/ ROBERT G. PHILLIPS | Director | |
| (Robert G. Phillips) |
91
INDEX TO EXHIBITS
Exhibit No. | Description | |
| 3.1 | Certificate of Incorporation of Pride (incorporated by reference to Annex D to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4, Registration Nos. 333-66644 and 333-66644-01 (the “Registration Statement’)). | |
| 3.2 | Bylaws of Pride, as amended on December 12, 2008 (incorporated by reference to Exhibit 3.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 18, 2008, File No. 1-13289). | |
| 4.1 | Form of Common Stock Certificate (incorporated by reference to Exhibit 4.13 to the Registration Statement). | |
| 4.2 | Rights Agreement, dated as of September 13, 2001, between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.2 Pride’s Current Report on Form 8-K filed with the SEC on September 28, 2001, File No. 1-13289 (the “Form 8-K”)). | |
| 4.3 | First Amendment to Rights Agreement dated as of January 29, 2008 between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.3 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13289). | |
| 4.4 | Certificate of Designations of Series A Junior Participating Preferred Stock of Pride (incorporated by reference to Exhibit 4.3 to the Form 8-K). | |
| 4.5 | Revolving Credit Agreement dated as of December 9, 2008 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis, as syndication agent for the lenders, BNP Paribas, Bayerische Hypo-Und Vereinsbank AG and Wells Fargo Bank, N.A., as documentation agents for the lenders, and Citibank, N.A., as issuing bank of the letters of credit thereunder (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 15, 2008, File No. 1-13289). | |
| 4.6 | Indenture dated as of July, 1, 2004 by and between Pride and The Bank of New York Mellon Trust Company, N.A. (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Pride’s Registration Statement on Form S-4, File No. 333-118104). | |
| 4.7 | First Supplemental Indenture dated as of July 7, 2004 by and between Pride and The Bank of New York Mellon Trust Company, N.A. (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Pride’s Registration Statement on Form S-4, File No. 333-118104). | |
| Pride and its subsidiaries are parties to several debt instruments that have not been filed with the SEC under which the total amount of securities authorized does not exceed 10% of the total assets of Pride and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, Pride agrees to furnish a copy of such instruments to the SEC upon request. | ||
| 10.1† | Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10(j) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-16963). | |
| 10.2† | First Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 4.7 to Pride’s Registration Statement on Form S-8, Registration No. 333-35093). | |
| 10.3† | Second Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.10 to Pride’s Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-13289). | |
| 10.4† | Third Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.11 of Pride’s Annual Report on Form 10-K for the year ended December 31, 1998, File No. 1-13289). | |
| 10.5† | Fourth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.12 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289). | |
| 10.6† | Fifth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.13 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289). | |
| 10.7† | Sixth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-13289). | |
| 10.8† | Pride International, Inc. 401(k) Restoration Plan (incorporated by reference to Exhibit 10(k) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1993, File No. 0-16963). | |
| 10.9† | Pride International, Inc. Supplemental Executive Retirement Plan, as amended and restated effective December 31, 2008 (the “SERP”) (incorporated by reference to Exhibit 10.6 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.10† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.7 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.11† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.8 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.12† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.9 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.13† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.10 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.14† | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.11 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.15†* | Amended SERP Participation Agreement dated December 31, 2008 between Pride and Kevin C. Robert. | |
| 10.16† | Pride International, Inc. 1998 Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.21 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-13289). | |
| 10.17† | Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289). | |
| 10.18† | Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289). | |
| 10.19† | Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289). | |
| 10.20† | Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289). | |
| 10.21† | Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289). | |
| 10.22† | Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.6 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289). | |
| 10.23† | Pride International, Inc. Employee Stock Purchase Plan (as amended and restated effective January 1, 2009) (incorporated by reference to Exhibit 10.3 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.24† | Pride International, Inc. Annual Incentive Plan (as amended and restated effective January 1, 2008) (incorporated by reference to Exhibit 10.4 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.25† | Pride International, Inc. 2004 Directors’ Stock Incentive Plan (as amended and restated) (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2008 Annual Meeting of Stockholders, File No. 1-13289). | |
| 10.26† | First Amendment to 2004 Directors’ Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.27† | Form of 2004 Director’s Stock Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289). | |
| 10.28† | Form of 2004 Director’s Stock Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289). | |
| 10.29† | Form of 2004 Directors’ Stock Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.30† | Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2007 Annual Meeting of Stockholders, File No. 1-13289). | |
| 10.31† | First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.32† | Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.33† | Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.34† | Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.35† | Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289). | |
| 10.36† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.37† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.38† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.39† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.40† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289). | |
| 10.41†* | Amended and Restated Employment/Non- Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Kevin C. Robert. | |
| 10.42† | Amended and Restated Employment/Non-Competition/Confidentiality Agreement effective as of October 29, 2008, between Pride and Randall D. Stilley (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289). | |
| 10.43†* | Summary of certain executive officer and director compensation arrangements. | |
| 12* | Computation of ratio of earnings to fixed charges. | |
| 21* | Subsidiaries of Pride. | |
| 23.1* | Consent of KPMG LLP. | |
| 31.1* | Certification of Chief Executive Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2* | Certification of Chief Financial Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32* | Certification of the Chief Executive Officer and the Chief Financial Officer of Pride pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
____________
| * | Filed herewith. |
| † | Management contract or compensatory plan or arrangement. |
92