ITEM 1. BUSINESS
Transocean Inc. (together with its subsidiaries and predecessors, unless the context requires otherwise, the "Company," "Transocean," "we," "us" or "our") is a leading international provider of offshore contract drilling services for oil and gas wells. As of March 1, 2004, we owned, had partial ownership interests in or operated 96 mobile offshore drilling units, excluding the fleet of TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, "TODCO"), a publicly traded drilling company in which we own a majority interest. As of this date, our fleet consisted of 32 High-Specification semisubmersibles and drillships ("floaters"), 26 Other Floaters, 26 Jackup Rigs and 12 Other Rigs. As of March 1, 2004, TODCO's fleet consisted of 24 jackup rigs, 30 drilling barges, nine land rigs, three submersible drilling rigs and four other drilling rigs.
Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. Our primary business is to contract these drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding segments of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We also provide additional services, including management of third party well service activities. Our ordinary shares are listed on the New York Stock Exchange under the symbol "RIG."
Transocean Inc. is a Cayman Islands exempted company with principal executive offices in the U.S. located at 4 Greenway Plaza, Houston, Texas 77046. Our telephone number at that address is (713) 232-7500.
BACKGROUND OF TRANSOCEAN
In June 1993, the Company, then known as "Sonat Offshore Drilling Inc.," completed an initial public offering of approximately 60 percent of the outstanding shares of its common stock as part of its separation from Sonat Inc., and in July 1995 Sonat Inc. sold its remaining 40 percent interest in the Company through a secondary public offering. In September 1996, the Company acquired Transocean ASA, a Norwegian offshore drilling company, and changed its name to "Transocean Offshore Inc." On May 14, 1999, the Company completed a corporate reorganization by which it changed its place of incorporation from Delaware to the Cayman Islands.
In December 1999, we completed our merger with Sedco Forex Holdings Limited ("Sedco Forex"), the former offshore contract drilling business of Schlumberger Limited ("Schlumberger"). Effective upon the merger, we changed our name to "Transocean Sedco Forex Inc." On January 31, 2001, we completed our merger transaction (the "R&B Falcon merger") with R&B Falcon Corporation ("R&B Falcon"). We accounted for the R&B Falcon merger using the purchase method of accounting with the Company treated as the accounting acquiror. At the time of the merger, R&B Falcon operated a diverse global drilling rig fleet, consisting of drillships, semisubmersibles, jackup rigs and other units in addition to the Gulf of Mexico Shallow and Inland Water segment fleet. In May 2002, we changed our name to "Transocean Inc."
In July 2002, we announced plans to pursue a divestiture of our Gulf of Mexico Shallow and Inland Water business, which was a part of R&B Falcon. R&B Falcon's overall business was considerably broader than the Gulf of Mexico Shallow and Inland Water business. In preparation for this divestiture, we began the transfer of all assets and businesses out of R&B Falcon that were unrelated to the Gulf of Mexico Shallow and Inland Water business. In December 2002, R&B Falcon changed its name to TODCO and, in January 2004, the Gulf of Mexico Shallow and Inland Water business segment became known as the TODCO segment.
In February 2004, we completed an initial public offering of TODCO, in which we sold 13.8 million shares of TODCO's class A common stock representing 23 percent of TODCO's outstanding common stock. Before the closing of the offering, TODCO completed the transfer to us of all unrelated assets and businesses. At March 1, 2004, we held approximately 77 percent of the outstanding common stock of TODCO, represented by 46.2 million shares of class B common stock, and consolidate TODCO in our financial statements. TODCO's class A common stock has one vote per share, and its class B common stock has five votes per share. Our current long-term intent is to dispose of our remaining interest in TODCO, which could be achieved through a number of possible transactions including additional public offerings, open market sales, sales to one or more third parties, a spin-off to our shareholders, split-off offerings to our shareholders that would allow for the opportunity to exchange our shares for shares of TODCO class A common stock or a combination of these transactions.
We provide contract drilling services in several market sectors and aggregate these operations into two business segments. Our Transocean Drilling segment (formerly called the "International and U.S. Floater Contract Drilling Services" business segment) is comprised of drillships, semisubmersibles, jackups and other drilling rigs. Our TODCO segment (formerly called the "Gulf of Mexico Shallow and Inland Water" business segment) consists of our interest in TODCO, which conducts jackup, drilling barge, land rig, submersible and other rig operations in the U.S. Gulf of Mexico and inland waters, Mexico, Trinidad and Venezuela. Our operations are aggregated into these two business segments based on the similarity of economic characteristics among the market sectors in which each operates. These characteristics include the
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services provided and the types of customers for which we provide these services. Although each of our business segments consists of various rig categories, the type of rig used to perform our drilling operations is dependent upon the needs and demands of our clients. As a result, operating decisions and allocation of assets and resources are determined by our customers.
For information about the revenues, operating income, assets and other information relating to our business segments and the geographic areas in which we operate, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 19 to our consolidated financial statements included in Item 8 of this report. For information about the risks and uncertainties relating to our business, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Risk Factors."
DRILLING FLEET
We principally use three types of drilling rigs: - drillships; - semisubmersibles; and - jackups.
Also included in our fleet are barge drilling rigs, tenders, a mobile offshore production unit, a platform drilling rig and a land rig. TODCO's fleet consists of jackups, barge drilling rigs, submersibles, land drilling rigs, a platform rig and lake barges.
Most of our drilling equipment is suitable for both exploration and development drilling, and we normally engage in both types of drilling activity. Likewise, most of our drilling rigs are mobile and can be moved to new locations in response to client demand. All of our mobile offshore drilling units are designed for operations away from port for extended periods of time and most have living quarters for the crews, a helicopter landing deck and storage space for pipe and drilling supplies.
TRANSOCEAN DRILLING FLEET
As of March 1, 2004, our Transocean Drilling segment fleet of 96 rigs included: - 32 High-Specification Floaters, which are comprised of: - 13 Fifth-Generation Deepwater Floaters; - 15 Other Deepwater Floaters; and - four Other High-Specification Floaters; - 26 Other Floaters; - 26 Jackups; and - 12 Other Rigs, which are comprised of: - four barge drilling rigs; - four tenders; - one platform drilling rig; - one mobile offshore production unit; - one land rig; and - one coring drillship.
As of February 27, 2004, this segment's fleet was located in the U.S. Gulf of Mexico (14 units), Canada (one unit), Brazil (10 units), North Europe (17 units), the Mediterranean and Middle East (nine units), the Caspian Sea (one unit), Africa (18 units), India (10 units) and Asia and Australia (16 units).
We periodically review the use of the term "deepwater" in connection with our fleet. The term as used in the drilling industry to denote a particular segment of the market varies somewhat and continues to evolve with technological improvements. We generally view the deepwater market sector as that which begins in water depths of approximately 4,500 feet.
In the first quarter of 2004, we changed the categories we use to describe this segment's fleet into a "High-Specification Floaters" category, consisting of our "Fifth-Generation Deepwater Floaters," "Other Deepwater Floaters" and Other "High-Specification Floaters," an "Other Floaters" category, a "Jackups" category and an "Other Rigs" category. Within our High-Specification Floaters category, we consider our Fifth-Generation Deepwater Floaters to be those set forth in the fleet table listed below, which were built in the last construction cycle (approximately 1996-2001) and have high-pressure mud pumps and a water depth capability of 7,500 feet or greater. The Other Deepwater Floaters are generally those other
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semisubmersible rigs and drillships that have a water depth capacity of at least 4,500 feet and the Other High-Specification Floaters are harsh environment floaters that were built as fourth-generation rigs in the mid- to late-1980's and have greater displacement than previously constructed rigs resulting in larger variable load capacity, more usable deck space and better motion characteristics. Our Other Floaters category is generally comprised of those non-high-specification floaters with a water depth capacity of less than 4,500 feet. The Jackups category consists of this segment's jackup fleet, and the Other Rigs category consists of other rigs which are of a different type or use. We have changed these categories to better reflect how we view, and how we believe our investors and the industry view, our fleet in an effort to better reflect our strategic focus on the ownership and operation of premium high-specification floating rigs.
Drillships are generally self-propelled, shaped like conventional ships and are the most mobile of the major rig types. Our drillships are either dynamically positioned, which allows them to maintain position without anchors through the use of their onboard propulsion and station-keeping systems, or are operated in a moored configuration. Drillships typically have greater load capacity than semisubmersible rigs. This enables them to carry more supplies on board, which often makes them better suited for drilling in remote locations where resupply is more difficult. However, drillships are typically limited to calmer water conditions than those in which semisubmersibles can operate. Our three Enterprise-class drillships are equipped for dual-activity drilling, which is a well-construction technology we developed and patented that allows for drilling tasks associated with a single well to be accomplished in a parallel rather than sequential manner by utilizing two complete drilling systems under a single derrick. The dual-activity well-construction process is designed to reduce critical path activity and improve efficiency in both exploration and development drilling.
Semisubmersibles are floating vessels that can be submerged by means of a water ballast system such that the lower hulls are below the water surface during drilling operations. These rigs maintain their position over the well through the use of an anchoring system or computer controlled dynamic positioning thruster system. Some semisubmersible rigs are self-propelled and move between locations under their own power when afloat on the pontoons although most are relocated with the assistance of tugs. Typically, semisubmersibles are better suited for operations in rough water conditions than drillships. Our three Express-class semisubmersibles equipped with the unique tri-act derrick were designed to reduce overall well construction costs and effectively integrate new technology and working relationships.
Jackup rigs are mobile self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the drilling platform. Once a foundation is established, the drilling platform is then jacked further up the legs so that the platform is above the highest expected waves. These rigs are generally suited for water depths of 300 feet or less.
Rigs described in the following tables as "operating" are under contract, including rigs being mobilized under contract. Rigs described as "warm stacked" are not under contract and may require the hiring of additional crew, but are generally ready for service with little or no capital expenditures and are being actively marketed. Rigs described as "cold stacked" are not being actively marketed on short or near term contracts, generally cannot be reactivated upon short notice and normally require the hiring of most of the crew, a maintenance review and possibly significant refurbishment before they can be reactivated. Our cold stacked rigs and some of our warm stacked rigs would require additional costs to return to service. The actual cost, which could fluctuate over time, is dependent upon various factors, including the availability and cost of shipyard facilities, cost of equipment and materials and the extent of repairs and maintenance that may ultimately be required. For some of these rigs, the cost could be significant. We would take these factors into consideration together with market conditions, length of contract and dayrate and other contract terms in deciding whether to return a particular idle rig to service. We may consider marketing some of our cold stacked rigs for alternative uses, including as accommodation units, from time to time until drilling activity increases and we obtain drilling contracts for these units.
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HIGH-SPECIFICATION FLOATERS (32)
The following tables provide certain information regarding our High-Specification fleet in this segment as of February 27, 2004:
OTHER FLOATERS (26)
The following table provides certain information regarding our Other Floater drilling rigs in this segment as of February 27, 2004:
JACKUP RIGS (26)
The following table provides certain information regarding our Jackup Rig fleet in this segment as of February 27, 2004:
OTHER RIGS
In addition to our floaters and jackups, we also own or operate several other types of rigs in this segment. These rigs include four drilling barges, four tenders, a platform drilling rig, a mobile offshore production unit and a land rig, as well as a coring drillship.
TODCO FLEET
As of March 1, 2004, the TODCO segment fleet consisted of 24 jackups, 30 drilling barges, three submersible rigs and a platform drilling rig, as well as nine land rigs and three lake barges. As of March 1, 2004, TODCO's fleet was located in the U.S. (52 units), Mexico (three units), Venezuela (13 units) and Trinidad (two units). The following table contains information relating to TODCO's fleet as of such date:
MARKETS
Our operations are geographically dispersed in oil and gas exploration and development areas throughout the world. Rigs can be moved from one region to another, but 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. However, significant variations between regions do not tend to exist long-term because of rig mobility. Consequently, we operate in a single, global offshore drilling market. Because our drilling rigs are mobile assets and are able to be moved according to prevailing market conditions, we cannot predict the percentage of our revenues that will be derived from particular geographic or political areas in future periods.
In recent years, there has been increased emphasis by oil companies on exploring for hydrocarbons in deeper waters. This is, in part, because of technological developments that have made such exploration more feasible and cost-effective. For this reason, water-depth capability is a key component in determining rig suitability for a particular drilling project. Another distinguishing feature in some drilling market segments is a rig's ability to operate in harsh environments, including extreme marine and climatic conditions and temperatures.
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The deepwater and mid-water market sectors are serviced by our semisubmersibles and drillships. While the use of the term "deepwater" as used in the drilling industry to denote a particular segment of the market can vary and continues to evolve with technological improvements, we generally view the deepwater market segment as that which begins in water depths of approximately 4,500 feet and extends to the maximum water depths in which rigs are capable of drilling, which is currently approximately 10,000 feet. We view the mid-water market sector as that which covers water depths of about 300 feet to approximately 4,500 feet.
The global shallow water market segment begins at the outer limit of the transition zone and extends to water depths of about 300 feet. We service this segment with our jackups and drilling tenders, which are located outside of the U.S. TODCO also operates in this market segment with jackups and submersibles. This segment has been developed to a significantly greater degree than the deepwater market segment because the shallower water depths have made it much more accessible than the deeper water market segments.
The "transition zone" market segment is characterized by marshes, rivers, lakes, shallow bay and coastal water areas. We operate in this segment using our drilling barges located in West Africa and Southeast Asia. TODCO operates in this market segment along the U.S. Gulf of Mexico coastline, which has been the world's largest market segment for barge rigs.
TODCO also conducts land rig operations in Venezuela.
MANAGEMENT SERVICES
We use our engineering and operating expertise to provide management of third party drilling service activities. These services are provided through service teams generally consisting of our personnel and third party subcontractors and we frequently serve as lead contractor. The work generally consists of individual contractual agreements to meet specific client needs and may be provided on either a dayrate or fixed price basis. As of March 1, 2004, we were performing such services in the North Sea, India and Malaysia. These management service revenues did not represent a material portion of our revenues during 2003.
DRILLING CONTRACTS
Our contracts to provide offshore drilling services are individually negotiated and vary in their terms and provisions. We obtain most of our contracts through competitive bidding against other contractors. Drilling contracts generally provide for payment on a dayrate basis, with higher rates while the drilling unit is operating and lower rates for periods of mobilization or when drilling operations are interrupted or restricted by equipment breakdowns, adverse environmental conditions or other conditions beyond our control.
A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. These contracts typically can be terminated by the client under various circumstances such as the loss or destruction of the drilling unit or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. The contract term in some instances may be extended by the client exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal. In reaction to depressed market conditions, our clients may seek renegotiation of firm drilling contracts to reduce their obligations or may seek to suspend or terminate their contracts. Some drilling contracts permit the customer to terminate the contract at the customer's option without paying a termination fee. 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 if contracts are suspended for an extended period of time, it could adversely affect our results of operations.
SIGNIFICANT CLIENTS
During the past five years, we have engaged in offshore drilling for most of the leading international oil companies (or their affiliates), as well as for many government-controlled and independent oil companies. Major clients included BP, Shell, Petrobras and Statoil. Our largest unaffiliated clients in 2003 were Petrobras, BP and Shell accounting for 11.8 percent, 11.1 percent and 10.7 percent, respectively, of our 2003 operating revenues. No other unaffiliated client accounted for 10 percent or more of our 2003 operating revenues. The loss of any of these significant clients could, at least in the short term, have a material adverse effect on our results of operations.
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REGULATION
Our operations are affected from time to time in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws generally relating to the energy business.
International contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel and use of local employees and suppliers by foreign contractors. Governments in some foreign countries are active in regulating and controlling the ownership of concessions and companies holding concessions, the exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government action, including initiatives by the Organization of Petroleum Exporting Countries ("OPEC"), may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies and may continue to do so.
In the U.S., regulations applicable to our operations include certain regulations controlling the discharge of materials into the environment and requiring the removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment.
The U.S. Oil Pollution Act of 1990 ("OPA") and related regulations impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by OPA, and such liability could be substantial. Failure to comply with ongoing requirements or inadequate cooperation in a spill event could subject a responsible party to civil or criminal enforcement action.
The U.S. Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the outer continental shelf. Included among these are regulations that require the preparation of spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to outer continental shelf vessels, rigs, platforms, vehicles and structures. Violations of environmental related lease conditions or regulations issued pursuant to the U.S. Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
The U.S. Comprehensive Environmental Response Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability without regard to fault or the legality of the original conduct on some classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a particular site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA principally in connection with TODCO's inland activities.
Certain of the other countries in whose waters we are presently operating or may operate in the future have regulations covering the discharge of oil and other contaminants in connection with drilling operations.
Although significant capital expenditures may be required to comply with these governmental laws and regulations, such compliance has not materially adversely affected our earnings or competitive position.
EMPLOYEES
We require highly skilled personnel to operate our drilling units. As a result, we conduct extensive personnel recruiting, training and safety programs. At January 31, 2004, excluding TODCO employees, we had approximately 10,100 employees, of which approximately 1,900 persons were contracted through contract labor providers. As of such date, approximately 24 percent of these employees worldwide worked under collective bargaining agreements, most of whom worked in Brazil, Norway, U.K. and Nigeria. Of these represented employees, substantially all are working under agreements that are subject to salary negotiation in 2004. These negotiations could result in higher personnel expenses, other increased costs or increased operating restrictions.
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At January 31, 2004, TODCO had approximately 1,800 employees, of which approximately six percent worked under collective bargaining agreements in Trinidad and Venezuela.
AVAILABLE INFORMATION
Our website address is www.deepwater.com. We make our website content ----------------- available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under "Investor Relations-Financial Reports," free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission ("SEC"). The SEC also maintains a website at www.sec.gov that contains reports, proxy ----------- statements and other information regarding SEC registrants, including us.
You may also find information related to our corporate governance, board committees and company code of ethics at our website. Among the information you can find there is the following:
- Corporate Governance Guidelines; - Audit Committee Charter; - Corporate Governance Committee Charter; - Executive Compensation Committee Charter; - Finance and Benefits Committee Charter; and - Code of Ethics.
ITEM 2.
ITEM 2. PROPERTIES
The description of our property included under "Item 1. Business" is incorporated by reference herein.
We maintain offices, land bases and other facilities worldwide, including our principal executive offices in Houston, Texas and regional operational offices in the U.S., Brazil, France and Indonesia. Our remaining offices and bases are located in various countries in North America, South America, the Caribbean, Europe, Africa, the Middle East, India and Asia. We lease most of these facilities.
TODCO maintains principal executive offices in Houston, Texas and has operational offices in the U.S., Mexico, Trinidad and Venezuela.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In 1990 and 1991, two of our subsidiaries were served with various assessments collectively valued at approximately $5.8 million from the municipality of Rio de Janeiro, Brazil to collect a municipal tax on services. We believe that neither subsidiary is liable for the taxes and have contested the assessments in the Brazilian administrative and court systems. In October 2001, the Brazil Supreme Court rejected our appeal of an adverse lower court's ruling with respect to a June 1991 assessment, which is valued at approximately $5 million. We are continuing to challenge the assessment and have an action to suspend a related tax foreclosure proceeding. We have received a favorable ruling in connection with a disputed August 1990 assessment but the government has appealed that ruling. We also are awaiting a ruling from the Taxpayer's Council in connection with an October 1990 assessment. If our defenses are ultimately unsuccessful, we believe that the Brazilian government-controlled oil company, Petrobras, has a contractual obligation to reimburse us for municipal tax payments required to be paid by them. We do not expect the liability, if any, resulting from these assessments to have a material adverse effect on our business or consolidated financial position.
The Indian Customs Department, Mumbai, filed a "show cause notice" against one of our subsidiaries and various third parties in July 1999. The show cause notice alleged that the initial entry into India in 1988 and other subsequent movements of the Trident II jackup rig operated by the subsidiary constituted imports and exports for which proper customs procedures were not followed and sought payment of customs duties of approximately $31 million based on an alleged 1998 rig value of $49 million, with interest and penalties, and confiscation of the rig. In January 2000, the Customs Department issued its order, which found that we had imported the rig improperly and intentionally concealed the import from the authorities, and directed us to pay a redemption fee of approximately $3 million for the rig in lieu of confiscation and to pay penalties of approximately $1 million in addition to the amount of customs duties owed. In February 2000, we filed an appeal with the Customs, Excise and Gold (Control) Appellate Tribunal ("CEGAT") together with an application to have
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the confiscation of the rig stayed pending the outcome of the appeal. In March 2000, the CEGAT ruled on the stay application, directing that the confiscation be stayed pending the appeal. The CEGAT issued its opinion on our appeal on February 2, 2001, and while it found that the rig was imported in 1988 without proper documentation or payment of duties, the redemption fee and penalties were reduced to less than $0.1 million in view of the ambiguity surrounding the import practice at the time and the lack of intentional concealment by us. The CEGAT further sustained our position regarding the value of the rig at the time of import as $13 million and ruled that subsequent movements of the rig were not liable to import documentation or duties in view of the prevailing practice of the Customs Department, thus limiting our exposure as to custom duties to approximately $6 million. Following the CEGAT order, we tendered payment of redemption, penalty and duty in the amount specified by the order by offset against a $0.6 million deposit and $10.7 million guarantee previously made by us. The Customs Department attempted to draw the entire guarantee, alleging the actual duty payable is approximately $22 million based on an interpretation of the CEGAT order that we believe is incorrect. This action was stopped by an interim ruling of the High Court, Mumbai on writ petition filed by us. We and the Customs Department both filed appeals with the Supreme Court of India against the order of the CEGAT, and both appeals have been admitted. We are now awaiting a hearing date. We and our customer agreed to pursue and obtained the issuance of documentation from the Ministry of Petroleum that, if accepted by the Customs Department, would reduce the duty to nil. The agreement with the customer further provided that if this reduction was not obtained by the end of 2001, our customer would pay the duty up to a limit of $7.7 million. The Customs Department did not accept the documentation or agree to refund the duties already paid. We are pursuing our remedies against the Customs Department and our customer. We do not expect, in any event, that the ultimate liability, if any, resulting from the matter will have a material adverse effect on our business or consolidated financial position.
In March 1997, an action was filed by Mobil Exploration and Producing U.S. Inc. and affiliates, St. Mary Land & Exploration Company and affiliates and Samuel Geary and Associates, Inc. against TODCO, the underwriters and insurance broker in the 16th Judicial District Court of St. Mary Parish, Louisiana. The plaintiffs alleged damages amounting to in excess of $50 million in connection with the drilling of a turnkey well in 1995 and 1996. The case was tried before a jury in January and February 2000, and the jury returned a verdict of approximately $30 million in favor of the plaintiffs for excess drilling costs, loss of insurance proceeds, loss of hydrocarbons and interest. The matter has now been fully resolved with all the plaintiffs. We believe that most, if not all, of the settlement amounts are covered by relevant primary and excess liability insurance policies. However, the insurers and underwriters denied coverage and one has filed a counterclaim. TODCO has instituted litigation against those insurers and underwriters to enforce its rights under the relevant policies. TODCO has settled with some of the insurers but is continuing the litigation against the remaining insurers. Pursuant to the master separation agreement with TODCO, we are responsible and will indemnify TODCO for any losses TODCO incurs from these actions and we will benefit from any recovery. We do not expect that the ultimate outcome of this case will have a material adverse effect on our business or consolidated financial position.
In October 2001, TODCO was notified by the U.S. Environmental Protection Agency ("EPA") that the EPA had identified a subsidiary as a potentially responsible party in connection with the Palmer Barge Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon the information provided by the EPA and a review of TODCO's internal records to date, TODCO disputes its designation as a potentially responsible party. Pursuant to the master separation agreement with TODCO, we are responsible and will indemnify TODCO for any losses TODCO incurs in connection with this action. We do not expect that the ultimate outcome of this case will have a material adverse effect on our business or consolidated financial position.
In August 2003, a judgment of approximately $9.5 million was entered by the Labor Division of the Provincial Court of Luanda, Angola, against us and one of our labor contractors, Hull Blyth, in favor of certain former workers on several of our drilling rigs. The workers were employed by Hull Blyth to work on several drilling rigs while the rigs were located in Angola. When the drilling contracts concluded and the rigs left Angola, the workers' employment ended. The workers brought suit claiming that they were not properly compensated when their employment ended. In addition to the monetary judgment, the Labor Division ordered the workers to be hired by us. We believe that this judgment is without sufficient legal foundation and have appealed the matter to the Angola Supreme Court. We further believe that Hull Blyth has an obligation to protect us from any judgment. We do not believe that the ultimate outcome of this matter will have a material adverse effect on our business or consolidated financial position.
We are involved in a number of other lawsuits, all of which have arisen in the ordinary course of our business. We do not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on our business or consolidated financial position. We cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending litigation. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management's current estimates.
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ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matter to a vote of its security holders during the fourth quarter of 2003.
EXECUTIVE OFFICERS OF THE REGISTRANT
The officers of the Company are elected annually by the Board of Directors. There is no family relationship between any of the above-named executive officers.
J. Michael Talbert is Chairman of the Board of the Company. Mr. Talbert served as Chief Executive Officer of the Company from August 1994 to October 2002, at which time he assumed his current position, and has been a member of the Board of Directors since August 1994. Mr. Talbert also served as Chairman of the Board of the Company from August 1994 until the time of the Sedco Forex merger and as President of the Company from the time of such merger until December 2001. Prior to assuming his duties with the Company, Mr. Talbert was President and Chief Executive Officer of Lone Star Gas Company, a natural gas distribution company and a division of Ensearch Corporation.
Robert L. Long is President, Chief Executive Officer and a member of the Board of Directors of the Company. Mr. Long served as President of the Company from December 2001 to October 2002, at which time he assumed the additional position of Chief Executive Officer and became a member of the Board of Directors. Mr. Long served as Chief Financial Officer of the Company from August 1996 until December 2001. Mr. Long served as Senior Vice President of the Company from May 1990 until the time of the Sedco Forex merger, at which time he assumed the position of Executive Vice President. Mr. Long also served as Treasurer of the Company from September 1997 until March 2001. Mr. Long has been employed by the Company since 1976 and was elected Vice President in 1987.
Jean P. Cahuzac is Executive Vice President and Chief Operating Officer of the Company. Mr. Cahuzac served as Executive Vice President, Operations of the Company from February 2001 until October 2002, at which time he assumed his current position. Mr. Cahuzac served as President of Sedco Forex from January 1999 until the time of the Sedco Forex merger, at which time he assumed the positions of Executive Vice President and President, Europe, Middle East and Africa with the Company. Mr. Cahuzac served as Vice President-Operations Manager of Sedco Forex from May 1998 to January 1999, Region Manager-Europe, Africa and CIS of Sedco Forex from September 1994 to May 1998 and Vice President/General Manager-North Sea Region of Sedco Forex from February 1994 to September 1994. He had been employed by Schlumberger since 1979.
Eric B. Brown is Senior Vice President, General Counsel and Corporate Secretary of the Company. Mr. Brown served as Vice President and General Counsel of the Company since February 1995 and Corporate Secretary of the Company since September 1995. He assumed the position of Senior Vice President in February 2001. Prior to assuming his duties with the Company, Mr. Brown served as General Counsel of Coastal Gas Marketing Company.
Gregory L. Cauthen is Senior Vice President and Chief Financial Officer of the Company. He was also Treasurer of the Company until July 2003. Mr. Cauthen served as Vice President, Chief Financial Officer and Treasurer from December 2001 until he was elected in July 2002 as Senior Vice President. Mr. Cauthen served as Vice President, Finance from March 2001 to December 2001. Prior to joining the Company, he served as President and Chief Executive Officer of WebCaskets.com, Inc., a provider of death care services, from June 2000 until February 2001. Prior to June 2000, he was employed at Service Corporation International, a provider of death care services, where he served as Senior Vice President, Financial Services from July 1998 to August 1999, Vice President, Treasurer from July 1995 to July 1998, was assigned to various special projects from August 1999 to May 2000 and had been employed in various other positions since February 1991.
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Barbara S. Koucouthakis is Vice President and Chief Information Officer of the Company. Ms. Koucouthakis served as Controller of the Company from January 1990 and Vice President from April 1993 until the time of the Sedco Forex merger, at which time she assumed her current position. She has been employed by the Company since 1982.
Tim L. Juran is Vice President, Human Resources of the Company. Mr. Juran served as Region Manager, North America of the Company from February 2001 until August 2002, at which time he assumed his current position. Mr. Juran served as Vice President & Regional Manager, North America & Europe for R&B Falcon from June 1999 to February 2001 and as Vice President & Regional Manager, Europe from January 1997 to May 1999. Prior to the R&B Falcon merger, Mr. Juran had been employed by R&B Falcon since 1980.
Jan Rask is President and Chief Executive Officer of TODCO, a publicly traded drilling company in which the Company owns a majority interest. Mr. Rask was Managing Director, Acquisitions and Special Operations, of Pride International, Inc., a contract drilling company, from September 2001 to July 2002, when he joined TODCO in his current capacity. From July 1996 to September 2001, Mr. Rask was President, Chief Executive Officer and a director of Marine Drilling Companies, Inc., a contract drilling company. Mr. Rask served as President and Chief Executive Officer of Arethusa (Off-Shore) Limited from May 1993 until the acquisition of Arethusa (Off-Shore) Limited by Diamond Offshore Drilling in May 1996. Mr. Rask joined Arethusa (Off-Shore) Limited's principal operating subsidiary in 1990 as its President and Chief Executive Officer. Mr. Rask has been a director of Veritas DGC, Inc., an integrated geophysical service company since 1998.
Brenda S. Masters, previously the Company's Vice President and Controller, left the Company in December 2003. Mr. Cauthen now serves as the Company's Principal Accounting Officer.
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PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
Our ordinary shares are listed on the New York Stock Exchange (the "NYSE") under the symbol "RIG." The following table sets forth the high and low sales prices of our ordinary shares for the periods indicated as reported on the NYSE Composite Tape.
On February 27, 2004, the last reported sales price of our ordinary shares on the NYSE Composite Tape was $29.48 per share. On such date, there were 17,564 holders of record of the Company's ordinary shares and 320,711,252 ordinary shares outstanding.
We discontinued the payment of a quarterly cash dividend, and the last dividend payment of $0.03 per share was paid on June 13, 2002. Prior to the elimination of the cash dividend, we had paid quarterly cash dividends of $0.03 per ordinary share since the fourth quarter of 1993. Any future declaration and payment of dividends will be (i) dependent upon our results of operations, financial condition, cash requirements and other relevant factors, (ii) subject to the discretion of the Board of Directors, (iii) subject to restrictions contained in our bank credit agreements and note purchase agreement and (iv) payable only out of our profits or share premium account in accordance with Cayman Islands law.
There is currently no reciprocal tax treaty between the Cayman Islands and the United States. However, under current Cayman Islands law, there is no withholding tax on dividends.
We are a Cayman Islands exempted company. Our authorized share capital is $13,000,000, divided into 800,000,000 ordinary shares, par value $0.01, and 50,000,000 preference shares, par value $0.10, of which shares may be designated and created as shares of any other classes or series of shares with the respective rights and restrictions determined by action of our board of directors. On February 27, 2004, no preference shares were outstanding.
The holders of ordinary shares are entitled to one vote per share other than on the election of directors.
With respect to the election of directors, each holder of ordinary shares entitled to vote at the election has the right to vote, in person or by proxy, the number of shares held by him for as many persons as there are directors to be elected and for whose election that holder has a right to vote. The directors are divided into three classes, with only one class being up for election each year. Directors are elected by a plurality of the votes cast in the election. Cumulative voting for the election of directors is prohibited by our articles of association.
There are no limitations imposed by Cayman Islands law or our articles of association on the right of nonresident shareholders to hold or vote their ordinary shares.
The rights attached to any separate class or series of shares, unless otherwise provided by the terms of the shares of that class or series, may be varied only with the consent in writing of the holders of all of the issued shares of that class or series or by a special resolution passed at a separate general meeting of holders of the shares of that class or series. The necessary quorum for that meeting is the presence of holders of at least a majority of the shares of that class or series. Each holder of shares of the class or series present, in person or by proxy, will have one vote for each share of the class or series of
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which he is the holder. Outstanding shares will not be deemed to be varied by the creation or issuance of additional shares that rank in any respect prior to or equivalent with those shares.
Under Cayman Islands law, some matters, like altering the memorandum or articles of association, changing the name of a company, voluntarily winding up a company or resolving to be registered by way of continuation in a jurisdiction outside the Cayman Islands, require approval of shareholders by a special resolution. A special resolution is a resolution (1) passed by the holders of two-thirds of the shares voted at a general meeting or (2) approved in writing by all shareholders entitled to vote at a general meeting of the company.
The presence of shareholders, in person or by proxy, holding at least a majority of the issued shares generally entitled to vote at a meeting, is a quorum for the transaction of most business. However, different quorums are required in some cases to approve a change in our articles of association.
Our board of directors is authorized, without obtaining any vote or consent of the holders of any class or series of shares unless expressly provided by the terms of issue of that class or series, to provide from time to time for the issuance of classes or series of preference shares and to establish the characteristics of each class or series, including the number of shares, designations, relative voting rights, dividend rights, liquidation and other rights, redemption, repurchase or exchange rights and any other preferences and relative, participating, optional or other rights and limitations not inconsistent with applicable law.
Our articles of association contain provisions that could prevent or delay an acquisition of our company by means of a tender offer, proxy contest or otherwise.
The foregoing description is a summary. This summary is not complete and is subject to the complete text of our memorandum and articles of association. For more information regarding our ordinary shares and our preference shares, see our Current Report on Form 8-K dated May 14, 1999 and our memorandum and articles of association. Our memorandum and articles of association are filed as exhibits to this Report.
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ITEM 6.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The selected consolidated financial data as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003 has been derived from the audited consolidated financial statements included elsewhere herein. The selected consolidated financial data as of December 31, 2001, 2000 and 1999, and for the years ended December 31, 2000 and 1999 has been derived from audited consolidated financial statements not included herein. The following data should be read in conjunction with "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following information should be read in conjunction with the information contained in the audited consolidated financial statements and the notes thereto included under "Item 8. Financial Statements and Supplementary Data" elsewhere in this annual report.
OVERVIEW
Transocean Inc. (together with its subsidiaries and predecessors, unless the context requires otherwise, the "Company," "Transocean," "we," "us" or "our") is a leading international provider of offshore contract drilling services for oil and gas wells. As of March 1, 2004, we owned, had partial ownership interests in or operated 96 mobile offshore and barge drilling units, excluding the fleet of TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, "TODCO"), a publicly traded company in which we own a majority interest. As of this date, our fleet included 32 High-Specification semisubmersibles and drillships ("floaters"), 26 Other Floaters, 26 Jackup Rigs and 12 Other Rigs. As of March 1, 2004, TODCO's fleet consisted of 24 jackup rigs, 30 drilling barges, nine land rigs, three submersible drilling rigs and four other drilling rigs.
Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. Our primary business is to contract these drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding segments of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We also provide additional services, including management of third party well service activities.
Key measures of our total company results of operations and financial condition are as follows:
The decreases in our average dayrates and utilization were mainly attributable to the decline in overall market conditions primarily within our Other Floaters fleet category. The increase in our operating and maintenance expenses was primarily due to a change in accounting for client reimbursable expenses. In addition, our revenues, utilization and operating and maintenance expense were negatively impacted by a riser separation incident on the drillship Discoverer Enterprise, a well control incident on inland barge Rig 62, an electrical fire on the Peregrine I, a fire on inland barge Rig 20 and a labor strike and a restructuring of a benefit plan in Nigeria (see "-Significant Events"). With the overall market decline we have responded rapidly to reduce costs when rigs were idled. We also reduced costs by implementing standardized purchasing through negotiated agreements, nationalization of our labor force where appropriate and headcount reductions in support groups. Our 2003 financial results included the recognition of a number of non-cash charges pertaining to asset impairments and loss on debt retirements. Debt and cash decreased during 2003 primarily as a result of repayments on debt instruments as we continue to maintain our focus on debt reduction. We also increased our investment in the Fifth-Generation fleet category by purchasing the portions of the Deepwater Drilling L.L.C. ("DD LLC") and Deepwater Drilling II L.L.C. ("DDII LLC")
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joint ventures that had previously been held by ConocoPhillips and paying off the synthetic lease financing arrangements associated with the Deepwater Pathfinder and Deepwater Frontier. See "-Acquisitions and Dispositions."
As a result of the implementation of Emerging Issues Task Force ("EITF") Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, costs we incur that are charged to our customers on a reimbursable basis are being recognized as operating and maintenance expense beginning in 2003. In addition, the amounts billed to our customers associated with these reimbursable costs are being recognized as operating revenue. The increase in operating revenues and operating and maintenance expense resulting from this implementation was approximately $100.5 million for the year ended December 31, 2003. This change in the accounting treatment for client reimbursables had no effect on our results of operations or consolidated financial position. We previously recorded these charges and related reimbursements on a net basis in operating and maintenance expense. Prior period amounts have not been reclassified, as the amounts were not material.
In the first quarter of 2004, we changed the categories we use to describe our Transocean Drilling segment fleet into a "High-Specification Floaters" category, consisting of our "Fifth-Generation Deepwater Floaters," "Other Deepwater Floaters" and "Other High-Specification Floaters," an "Other Floaters" category, a "Jackups" category and an "Other Rigs" category. Within our High-Specification Floaters category, we consider our Fifth-Generation Deepwater Floaters to be the semisubmersibles Deepwater Horizon, Cajun Express, Deepwater Nautilus, Sedco Energy and Sedco Express and the drillships Deepwater Discovery, Deepwater Expedition, Deepwater Frontier, Deepwater Millennium, Deepwater Pathfinder, Discoverer Deep Seas, Discoverer Enterprise, and Discoverer Spirit. These rigs were built in the last construction cycle and have high-pressure mud pumps and a water depth capability of 7,500 feet or greater. The Other Deepwater Floaters are generally those other semisubmersible rigs and drillships that have a water depth capacity of at least 4,500 feet. The Other High-Specification Floaters are those rigs capable of drilling in harsh environments that were built as fourth-generation rigs in the mid- to late-1980's and have greater displacement than previously constructed rigs resulting in larger variable load capacity, more useable deck space and better motion characteristics. The Other Floaters category is generally comprised of those non-high-specification floaters with a water depth capacity of less than 4,500 feet. The Jackups category consists of this segment's jackup fleet, and the Other Rigs category consists of other rigs that are of a different type or use. We changed these categories to better reflect how we view, and how we believe our investors and the industry view, our fleet in an effort to better reflect our strategic focus on the ownership and operation of premium high-specification floating rigs.
Our operations are aggregated into two reportable segments: (i) Transocean Drilling (formerly called "International and U.S. Floater Contract Drilling Services") and (ii) TODCO (formerly called "Gulf of Mexico Shallow and Inland Water"). The Transocean Drilling segment consists of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services. The TODCO segment consists of our interest in TODCO, which conducts jackup, drilling barge, land rig, submersible and other rig operations in the U.S. Gulf of Mexico and inland waters, Mexico, Trinidad and Venezuela. We provide services with different types of drilling equipment in several geographic regions. The location of our rigs and the allocation of resources to build or upgrade rigs is determined by the activities and needs of our customers.
SIGNIFICANT EVENTS
Transocean Drilling Segment
DD LLC and DDII LLC Joint Ventures-In May 2003, we purchased ConocoPhillips' 40 percent interest in DDII LLC. DDII LLC was the lessee in a synthetic lease financing facility with a special purpose entity entered into in connection with the construction of the Deepwater Frontier. As a result of this purchase, we consolidated DDII LLC in our financial statements late in the second quarter of 2003. In December 2003, DDII LLC paid $197.5 million for the purchase of the rig through the payoff of the synthetic lease financing arrangement. In conjunction with the payoff of the synthetic lease financing arrangements, our relationship with the special purpose entity was terminated. See "-Special Purpose Entities."
In December 2003, we purchased ConocoPhillips' 50 percent interest in DD LLC. DD LLC was the lessee in a synthetic lease financing facility with a special purpose entity entered into in connection with the construction of the Deepwater Pathfinder. As a result of this purchase, we consolidated DD LLC in our financial statements late in the fourth quarter of 2003. In December 2003, DD LLC paid $185.3 million for the purchase of the rig through the payoff of the synthetic lease financing arrangement. In conjunction with the payoff of the synthetic lease financing arrangement, our relationship with the special purpose entity was terminated. See "-Special Purpose Entities."
Operational Incidents-In April 2003, our deepwater drillship Peregrine I temporarily suspended drilling operations as a result of an electrical fire requiring repairs at a shipyard. The rig resumed operations in early July 2003. Operating income was negatively impacted by approximately $9.5 million due to the loss of dayrate and related expenses. See "-Historical 2003 compared to 2002."
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In April 2003, we announced that drilling operations had ceased on four of our mobile offshore drilling units located offshore Nigeria due to a strike by local members of the labor unions in Nigeria on the semisubmersible rigs M.G. Hulme, Jr. and Sedco 709 and the jackup rigs Trident VI and Trident VIII. All of these rigs returned to operations in May and June 2003. Labor issues in Nigeria were resolved and settled in the fourth quarter of 2003. Operating income was negatively impacted by approximately $26.6 million due to loss of dayrate and the restructuring of the Nigeria defined benefit plan (see "-Defined Benefit Pension Plans").
In May 2003, we announced that a drilling riser had separated on our deepwater drillship Discoverer Enterprise and that the rig had temporarily suspended drilling operations for our customer. The rig resumed operations in July 2003. Operating income for the year ended December 31, 2003 was negatively impacted by approximately $46.4 million due to expenses incurred on the Discoverer Enterprise as well as several other of our Fifth-Generation Deepwater Floaters related to the drilling riser separation and a related disagreement with our customer that was resolved in the first quarter of 2004. See "-Historical 2003 compared to 2002." We are currently in discussions with our insurers relating to an insurance claim for a portion of our losses stemming from this incident.
TODCO Segment
IPO-In February 2004, we completed the initial public offering ("IPO") of TODCO, in which we sold 13.8 million shares of TODCO's class A common stock, representing approximately 23 percent of TODCO's total outstanding shares, at $12.00 per share. We received net proceeds of $155.7 million from the IPO and expect to recognize a gain of approximately $43 million in the first quarter of 2004, which represents the excess of net proceeds received over the net book value of the shares of TODCO sold in the IPO. Additionally, as a result of the deconsolidation of TODCO from our other U.S. subsidiaries for U.S. federal income tax purposes in conjunction with the IPO, we expect to establish a valuation allowance against the deferred tax assets of TODCO in excess of its deferred tax liabilities. The amount of such valuation allowance will depend upon many factors, including the ultimate allocation of tax benefits between TODCO and other Transocean subsidiaries under applicable law and taxable income for calendar year 2004. The amount of the valuation allowance could be as much as or more than the gain on the sale of the TODCO shares in the IPO.
As of March 1, 2004, we held an approximate 77 percent interest in TODCO, represented by 46.2 million shares of class B common stock, and we have approximately 94 percent of the outstanding voting interest in TODCO. Each share of our class B common stock has five votes per share compared to one vote per share of the class A common stock. We consolidate TODCO in our financial statements and expect to continue to consolidate TODCO in our financial statements until we no longer own a majority voting interest. Because the IPO had not been completed by the end of the third quarter of 2003, we recognized $8.8 million of costs relating to the IPO in general and administrative expense for the year ended December 31, 2003, of which $3.1 million was incurred and deferred during 2002. TODCO was formerly known as R&B Falcon Corporation ("R&B Falcon"). Before the closing of the IPO, TODCO transferred to us all assets and businesses unrelated to TODCO's business. R&B Falcon's business was previously considerably broader than TODCO's ongoing business.
Operational Incidents-In June 2003, TODCO incurred a loss as a result of a well blowout and fire aboard inland barge Rig 62. During the year ended December 31, 2003, TODCO incurred a $7.6 million loss relating to this incident. While the loss did not exceed our insurance deductible for this incident, we do not expect any additional amounts that may be incurred related to this incident to have a material adverse affect on our consolidated financial statements or results of operations. See "-Historical 2003 compared to 2002."
In September 2003, TODCO recorded a loss of approximately $3.5 million on inland barge Rig 20 as a result of a fire. While the loss did not exceed our insurance deductible for this incident, we do not expect any additional amounts that may be incurred related to this incident to have a material adverse affect on our consolidated financial statements or results of operations. See "-Historical 2003 compared to 2002."
OUTLOOK
Drilling Market-Commodity prices were at historically strong levels during 2003, and we believe commodity price indicators point towards continued near-term strength in oil and gas prices. While future commodity price expectations have historically been a key driver for offshore drilling demand, the availability of quality drilling prospects, relative production costs, the stage of reservoir development and political and regulatory environments all affect our customers' drilling programs. Strong commodity prices did not result in significant increased offshore drilling activity in the fourth quarter or in 2003 generally.
Prospects for our High-Specification Floaters appear relatively stable over the next six months, with expected improvement in the latter half of the year and in 2005. A number of our Fifth-Generation Deepwater Floaters will conclude longer term contracts in 2004 and will be pursuing future work, so intermittent idle time is possible for these units. However, we have recently been successful in securing work for five of our High-Specification Floaters that ended term contracts in late 2003 and early 2004, with three of these units obtaining long-term contracts and the other two obtaining shorter-term
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exploratory work. We continue to believe that over the long term, deepwater exploration and development drilling opportunities in the Gulf of Mexico, West Africa and other market sectors represent a significant source of future deepwater rig demand. We have also seen an unexpected increase in bid activity in Norway, which presents opportunities for our Other High-Specification Floaters.
The level of activity for the non-U.S. jackup market sector is expected to increase in 2004. There is currently a modest overcapacity in the West Africa jackup market sector, but it is expected to dissipate by mid-2004. The Middle East and India are both expected to see increases in jackup demand in 2004. As a result of the anticipated increased activity, we believe jackup dayrates will generally meet or exceed levels achieved in each non-U.S. geographic market sector in 2003.
The outlook for our Other Floaters that operate in the mid-water market sector remains weak as this sector continues to be significantly oversupplied globally. We expect overall North Sea industry fleet utilization to remain at current levels until the expected normal seasonal increase in demand in the summer months. We expect the Norwegian sector to improve over the remainder of the year. Demand in the U.S. Gulf of Mexico market sector continues to be dampened by increased competition from deepwater rigs operating below their full water depth capability.
The TODCO segment continues to benefit from a declining base of jackup rig supply in the Gulf of Mexico, which has helped to lift utilization and dayrates in an otherwise flat rig demand environment. With a potential increase in international jackup activity causing a further reduction in supply, dayrates are expected to generally remain stable. Demand in the inland waters of Louisiana and Texas for drilling barges has remained flat over the past quarter. We believe there are signs of increased drilling of deep wells greater than 18,000 feet in these inland areas in 2004, which could increase the utilization and dayrates in this segment.
Our operations are geographically dispersed in oil and gas exploration and development areas throughout the world. Rigs can be moved from one region to another, but 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. However, significant variations between regions do not tend to exist long-term because of rig mobility. Consequently, we operate in a single, global offshore drilling market.
The offshore contract drilling market remains highly competitive and cyclical, and it has been historically difficult to forecast future market conditions. Extraneous risks include declines in oil and/or gas prices that reduce rig demand and adversely affect utilization and dayrates. Major operator and national oil company capital budgets are key drivers of the overall business climate, and these may change within a fiscal year depending on exploration results and other factors. Additionally, increased competition for our customers' drilling budgets could come from, among other areas, land-based energy markets in Russia, other former Soviet Union states and the Middle East.
As of February 27, 2004, approximately 45 percent of our Transocean Drilling segment fleet days were committed for the remainder of 2004 and approximately 18 percent for the year 2005. For our TODCO segment, which has traditionally operated under short-term contracts, committed fleet days were approximately seven percent for the remainder of 2004 and three percent are currently committed for the year 2005.
Tax Matters-As a result of our reorganization in 1999, we became a Cayman Islands company in a transaction commonly referred to as an "inversion." Legislation in various forms has been introduced in the U.S. House of Representatives and Senate that would change the tax law applicable to companies that have completed inversion transactions. Some of the proposals would have retroactive application and would treat us as a U.S. corporation. Other proposals would impose additional limitations on the deductibility, for U.S. federal income tax purposes, of intercompany interest expense and could also make it more difficult to integrate acquired U.S. businesses with existing operations or to undertake internal restructuring. We cannot provide any assurance as to what form, if any, final legislation will take or the impact such legislation will ultimately have.
Our income tax returns are subject to review and examination in the various jurisdictions in which we operate. The U.S. Internal Revenue Service is currently auditing our tax returns for calendar years 1999, the year we became a Cayman Islands company, and 2000. In addition, other tax authorities have examined the amounts of income and expense subject to tax in their jurisdiction for prior periods. We are currently contesting various non-U.S. assessments that have been asserted and would expect to contest any future U.S. or non-U.S. assessments. While we cannot predict or provide assurance as to the final outcome of existing or future assessments, we do not believe that the ultimate resolution of these asserted income tax liabilities will have a material adverse effect on our business or consolidated financial position.
As a result of the deconsolidation of TODCO from our other U.S. subsidiaries for U.S. federal income tax purposes in conjunction with the IPO, we expect to establish a valuation allowance against the deferred tax assets of TODCO in excess of its deferred tax liabilities. The amount of such valuation allowance will depend upon many factors, including the ultimate allocation of tax benefits between TODCO and our other subsidiaries under applicable law and taxable income for calendar
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year 2004. The amount of the valuation allowance could be as much as or more than the gain on the sale of the TODCO shares in the IPO (see "-Significant Events").
Insurance-In January 2003, we renewed our principal insurance coverages for property damage, liability, and occupational injury and illness. Premiums for such coverages would have increased substantially were it not for us taking significantly higher deductibles. The increased premiums were a result of increased rates demanded by the insurance markets for most insurance coverages as a result of losses the insurance industry has sustained in the past several years and perceived increased risks following the terrorist attacks on September 11, 2001. The renewal of these coverages was for the period January 1, 2003 through March 1, 2004.
We renewed these insurance coverages as of March 1, 2004 for a 14-month period ending May 1, 2005. Although premiums for these coverages were somewhat lower, we again chose to increase deductibles to reduce premiums further, given our continued improvement in our loss history. If our property and occupational illness claim experience in 2004 is comparable to 2003, we would expect a small decrease in our insurance expenses related to property damage, liabilities, and occupational injury and illness coverages. Because of the increase in our deductible exposure for 2004, an increase in our loss experience could result in higher insurance related expense for the period.
During the second quarter of 2003, we renewed our directors' and officers' liability insurance. Insurance markets have demanded significant premium increases for this type of insurance. As a result, we chose to increase our deductible substantially and agreed to co-insure losses with the underwriters in order to mitigate increased premiums. We expect to renew our directors' and officers' insurance in 2004 with substantially the same structure. At this time, we expect the cost of such insurance to rise slightly.
Stock-Based Compensation Expense-As a result of the adoption of Statement of Financial Accounting Standards ("SFAS") 123, Accounting for Stock-Based Compensation, our stock-based compensation expense is expected to increase in 2004. The increase will result from the impact of a full year of expense related to our 2003 awards, compared to six months of expense in 2003, and expense related to our 2004 awards, expected to occur in July 2004. Future periods will continue to have increases in stock-based compensation expense until the impact of the layering effect of future awards is normalized. In conjunction with the TODCO IPO, TODCO granted stock option and nonvested restricted share awards to certain key employees. Due to accelerated vesting provisions outlined in certain key executives employment agreements, TODCO expects to record a charge of approximately $5.6 million during the first quarter of 2004, and a total of $10.8 million during 2004 related to its stock-based compensation awards. Additionally, TODCO expects to recognize approximately $1.5 million of expense during the first quarter of 2004 related to a modification of our options issued in prior periods to TODCO employees for which vesting was accelerated and all unvested options became fully vested, and the exercise term extended through the life of the option, under the employee matters agreement executed in connection with the TODCO IPO.
Debt Retirement-In February 2004, we announced the redemption of our 9.5% Senior Notes due December 2008 at the make-whole premium price provided in the indenture. The redemption is expected to be completed by March 30, 2004. The face value of the bonds to be redeemed is $289.8 million. Based on interest rates at March 1, 2004, the cost to redeem these bonds is expected to be approximately $366.3 million, and we expect to recognize a loss on retirement of debt of approximately $24.1 million, which reflects adjustments for fair value of the debt at the merger transaction ("R&B Falcon merger") with R&B Falcon in January 2001 and the premium on the termination of the related interest rate swap. These amounts could vary depending upon actual interest rates. We expect to utilize existing cash balances, which includes proceeds from the TODCO IPO, to fund this redemption. The redemption does not affect the 9.5% Senior Notes due December 2008 of TODCO.
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PERFORMANCE AND OTHER KEY INDICATORS
Fleet Utilization and Dayrates-The following table shows our average dayrate and utilization for the quarterly periods ending on or prior to December 31, 2003. Average dayrate is defined as contract drilling revenue earned per revenue earning day in the period. Utilization in the table below is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.
Contract Drilling Revenue-Our contract drilling revenues are based primarily on dayrates received for our drilling services and the number of operating days during the relevant periods. The level of our contract drilling revenue depends on dayrates, which in turn are primarily a function of industry supply and demand for drilling units in the markets in which we
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operate. During periods of high demand, our rigs typically achieve higher utilization and dayrates than during periods of low demand. Some of our drilling contracts also enable us to earn mobilization, contract preparation, capital upgrade, and bonus and demobilization revenue. Mobilization, contract preparation and capital upgrade revenue earned on a lump sum basis is recognized over the original contract term. Bonus and demobilization revenue is recognized when earned.
Operating and Maintenance Costs-Our operating and maintenance costs represent all direct and indirect costs associated with the operation and maintenance of our drilling rigs. The principal elements of these costs are direct and indirect labor and benefits, repair and maintenance, insurance, boat and helicopter rentals, professional and technical fees, freight costs, communications, customs duties, tool rentals and services, fuel and water, general taxes and licenses. Labor, repair and maintenance and insurance costs represent the most significant components of our operating and maintenance costs.
We do not expect operating and maintenance expenses to necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in dayrate; however, costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned. In addition, should our rigs incur idle time between contracts, we typically do not de-man those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. 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. In addition, due to unfavorable insurance market conditions and the resulting increase in premiums, our insurance deductibles increased effective December 2002. Our deductible level for the year 2003 under our hull and machinery and our protection and indemnity policies was $10.0 million per occurrence. While our deductible per occurrence will remain unchanged in 2004, our overall aggregate insurance deductible has increased for the upcoming policy year.
Depreciation Expense-Our depreciation expense is based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our assets. We generally compute depreciation using the straight-line method after allowing for salvage values.
General and Administrative Expense-General and administrative expense includes all costs related to our corporate executives, directors, investor relations, corporate accounting and reporting, information technology, internal audit, legal, tax, treasury, risk management and human resource functions.
Interest Expense-Interest expense consists of financing cost amortization and interest associated with our senior notes and other debt. Interest expense is partially offset by the amortization of gains on interest rate swaps terminated during 2003. We expect the amortization of these gains to continue over the life of the related debt instruments (see "-Derivative Instruments").
Income Taxes-Provisions for income taxes are based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. Taxable income may differ from pre-tax income for financial accounting purposes, particularly in countries with revenue-based taxes. There is no expected relationship between the provision for income taxes and income before income taxes because the countries in which we operate have different taxation regimes. We provide a valuation allowance for deferred tax assets when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. See "-Critical Accounting Policies."
FINANCIAL CONDITION
DECEMBER 31, 2003 COMPARED TO DECEMBER 31, 2002
The decrease in the Transocean Drilling segment assets was mainly due to a decrease in cash and cash equivalents ($551.4 million) that resulted primarily from the repayment of debt during 2003 and depreciation ($416.0 million). The decrease in TODCO segment assets was primarily due to depreciation ($92.2 million) and asset impairments ($11.3 million),
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partially offset by an increase in total assets due to the consolidation of Delta Towing Holdings, LLC ("Delta Towing") ($6.7 million) as a result of the early adoption of Financial Accounting Standards Board's ("FASB") Interpretation ("FIN") 46, Consolidation of Variable Interest Entities (as revised December 2003) (see "-New Accounting Pronouncements").
LIQUIDITY AND CAPITAL RESOURCES
SOURCES AND USES OF CASH
Net cash provided by operating activities decreased due to a combination of poor operating results after adjusting for non-cash items and a decrease in cash provided from working capital changes in 2003 compared to 2002.
Net cash used in investing activities increased for the year ended December 31, 2003 as compared to the prior year due to an increase in capital expenditures resulting primarily from the acquisition of the Deepwater Frontier and Deepwater Pathfinder totaling $382.8 million (see "Capital Expenditures") and lower proceeds from disposal of assets, partially offset by $36.7 million of cash acquired upon acquisition of ConocoPhillips' interests in DD LLC and DDII LLC.
Net cash used in financing activities increased in 2003 compared to 2002 primarily due to higher debt repayments, which included the repurchase of debt put to us during the year and early debt retirements. Partially offsetting the cash paid for debt retirements were cash received from the termination of interest rate swaps (see "-Derivative Instruments") and borrowings under our revolving credit facility to partially fund the payoff of synthetic lease financing facilities (see "-Acquisitions and Dispositions"). Also in 2002 we discontinued the payment of quarterly dividends after the second quarter dividend payment.
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CAPITAL EXPENDITURES
Capital expenditures totaled $495.9 million during the year ended December 31, 2003 and included our acquisition of two fifth-generation deepwater rigs, the Deepwater Pathfinder and Deepwater Frontier, through the payoff of synthetic lease financing arrangements totaling $382.8 million (see "-Acquisitions and Dispositions"). The remaining $113.1 million related to capital expenditures for existing fleet and corporate infrastructure. A substantial majority of our capital expenditures in 2003 related to the Transocean Drilling segment.
During 2004, we expect to spend less than $100 million on our existing fleet, corporate infrastructure and major upgrades, excluding those upgrades required and funded by our drilling contracts, although this amount is dependent upon the actual level of operational and contracting activity. A substantial majority of our expected capital expenditures in 2004 relates to our Transocean Drilling segment. We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales. We also have available credit under our revolving credit agreements (see "-Sources of Liquidity") and may engage in other commercial bank or capital market financings.
ACQUISITIONS AND DISPOSITIONS
From time to time, we review possible acquisitions of businesses and drilling units and may in the future make significant capital commitments for such purposes. Any such acquisition could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional ordinary shares or other securities. We would likely fund the cash portion of any such acquisition through cash balances on hand, the incurrence of additional debt, sales of assets, ordinary shares or other securities or a combination thereof. In addition, from time to time, we review possible dispositions of drilling units.
Acquisitions-As a result of the R&B Falcon merger, we had ownership interests in two unconsolidated joint ventures, 50 percent in DD LLC, and 60 percent in DDII LLC. Subsidiaries of ConocoPhillips owned the remaining interests in these joint ventures. Each of the joint ventures was a lessee in a synthetic lease financing facility entered into in connection with the construction of the Deepwater Pathfinder, in the case of DD LLC, and the Deepwater Frontier, in the case of DDII LLC. Pursuant to the lease financings, the rigs were owned by special purpose entities and leased to the joint ventures.
In May 2003, WestLB AG, one of the lenders in the Deepwater Frontier synthetic lease financing facility, assigned its $46.1 million remaining promissory note receivable to us in exchange for cash of $46.1 million. Also in May 2003, but subsequent to the WestLB AG assignment, we purchased ConocoPhillips' 40 percent interest in DDII LLC for approximately $5.0 million. As a result of this purchase, we consolidated DDII LLC late in the second quarter of 2003. In addition, we acquired certain drilling and other contracts from ConocoPhillips for approximately $9.0 million in cash. In December 2003, DDII LLC prepaid the remaining $197.5 million debt and equity principal amounts owed, plus accrued and unpaid interest, to us and other lenders under the synthetic lease financing facility. As a result of this prepayment, DDII LLC became the legal owner of the Deepwater Frontier.
In November 2003, we purchased the remaining 25 percent minority interest in the Caspian Sea Ventures International Limited ("CSVI") joint venture. CSVI owns the jackup rig Trident 20 and is now a wholly owned subsidiary.
In December 2003, we purchased ConocoPhillips' 50 percent interest in DD LLC in connection with the payoff of the Deepwater Pathfinder synthetic lease financing facility. As a result of this purchase, we consolidated DD LLC late in the fourth quarter of 2003. Concurrent with the purchase of this ownership interest, DD LLC prepaid the remaining $185.3 million debt and equity principal amounts owed, plus accrued and unpaid interest, to the lenders under the synthetic lease financing facility. As a result of this prepayment, DD LLC became the legal owner of the Deepwater Pathfinder.
Dispositions-In January 2003, we completed the sale of the RBF 160 to a third party for net proceeds of $13.1 million and recognized a net after-tax gain on sale of $0.2 million. The proceeds were received in December 2002 and were reflected as deferred income and proceeds from asset sales in the consolidated balance sheet and consolidated statement of cash flows, respectively.
In February 2004, we completed the IPO of TODCO. See "-Significant Events."
SOURCES OF LIQUIDITY
Our primary sources of liquidity in 2003 were our cash flows from operations, existing cash balances, borrowings on our $800 million, five-year revolving credit agreement and proceeds from the termination of our interest rate swaps. The
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primary uses of cash were debt repayment and capital expenditures. At December 31, 2003, we had $474.0 million in cash and cash equivalents.
We expect to rely primarily upon existing cash balances and internally generated cash flows to maintain liquidity in 2004, as cash flows from operations are expected to be positive and, together with existing cash balances, adequate to fulfill anticipated obligations such as scheduled debt maturities, capital expenditures and working capital needs. From time to time, we may also use bank lines of credit to maintain liquidity for short-term cash needs.
Excluding the acquisition of the Deepwater Pathfinder and Deepwater Frontier (see "-Capital Expenditures"), we have significantly reduced our capital expenditures compared to prior years due to the completion of our newbuild program in 2001 and ongoing efforts to contain capital expenditures. We expect capital expenditures for the fleet to be less than $100 million in 2004.
When cash on hand, cash flows from operations, proceeds from asset sales, including the TODCO IPO, and committed bank facility availability exceed our expected liquidity needs, we may use a portion of such cash to reduce debt prior to scheduled maturity through repurchases, redemptions or tender offers, or make repayments on bank borrowings.
In February 2004, we announced the redemption of the 9.5% Senior Notes due December 2008 at the make-whole premium price provided in the indenture, which does not effect the 9.5% Senior Notes due December 2008 of TODCO (see "-Outlook"). We expect to utilize existing cash balances, which includes proceeds from the TODCO IPO, to fund this redemption.
At December 31, 2003 and 2002, our total debt was $3,658.1 million and $4,678.0 million, respectively. During the year ended December 31, 2003, we reduced net debt, a non-GAAP financial measure defined as total debt less swap receivables and cash and cash equivalents, by $98.4 million. The components of net debt at carrying value were as follows (in millions):
We believe net debt provides useful information regarding the level of our indebtedness by reflecting the amount of indebtedness assuming cash and investments are used to repay debt. Net debt has been reduced each year since 2001 due to the fact that cash flows, primarily from operations and asset sales, have been greater than that needed for capital expenditures.
Our internally generated cash flow is directly related to our business and the market sectors in which we operate. Should the drilling market deteriorate, or should we experience poor results in our operations, cash flow from operations may be reduced. However, we have continued to generate positive cash flow from operating activities over recent years.
We have access to a bank line of credit under an $800 million five-year revolving credit agreement expiring in December 2008. As of March 1, 2004, $600.0 million remained available under this credit line. Because our current cash balances and this revolving credit agreement provide us with adequate liquidity, we terminated our commercial paper program during the first quarter of 2004.
The bank credit line requires compliance with various covenants and provisions customary for agreements of this nature, including earnings before interest, taxes, depreciation and amortization ("EBITDA") to interest coverage ratio and debt to tangible capital ratio, both as defined by the credit agreement, of not less than three to one and not greater than 50 percent, respectively. Other provisions of the credit agreement includes limitations on creating liens, incurring debt, transactions with affiliates, sale/leaseback transactions and mergers and sale of substantially all assets. Should we fail to comply with these covenants, we would be in default and may lose access to this facility. We are also subject to various covenants under the indentures pursuant to which our public debt was issued, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. A default under our public debt could trigger a default under our credit line and cause us to lose access to this facility.
In April 2001, the Securities and Exchange Commission ("SEC") declared effective our shelf registration statement on Form S-3 for the proposed offering from time to time of up to $2.0 billion in gross proceeds of senior or subordinated debt securities, preference shares, ordinary shares and warrants to purchase debt securities, preference shares, ordinary shares or
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other securities. At February 28, 2004, $1.6 billion in gross proceeds of securities remained unissued under the shelf registration statement.
Our access to debt and equity markets may be reduced or closed to us due to a variety of events, including, among others, downgrades of ratings of our debt, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry.
Our contractual obligations included in the table below are at face value (in millions).
Bondholders may, at their option, require us to repurchase the 1.5% Convertible Debentures due 2021, the 7.45% Notes due 2027 and the Zero Coupon Convertible Debentures due 2020 in May 2006, April 2007 and May 2008, respectively. With regard to both series of the Convertible Debentures, we have the option to pay the repurchase price in cash, ordinary shares or any combination of cash and ordinary shares. The chart above assumes that the holders of these convertible debentures and notes exercise the options at the first available date. We are also required to repurchase the convertible debentures at the option of the holders at other later dates.
See "-Defined Benefit Pension Plans" for discussion of pension funding requirements.
At December 31, 2003, we had other commitments that we are contractually obligated to fulfill with cash should the obligations be called. These obligations include standby letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, tax and other obligations in various jurisdictions. Letters of credit are issued under a number of facilities provided by several banks. The obligations that are the subject of these surety bonds are geographically concentrated in the United States and Brazil. These letters of credit and surety bond obligations are not normally called as we typically comply with the underlying performance requirement. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.
DERIVATIVE INSTRUMENTS
We have established policies and procedures for derivative instruments that have been approved by our Board of Directors. These policies and procedures provide for the prior approval of derivative instruments by our Chief Financial Officer. From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to fluctuations in foreign exchange rates and interest rates. We do not enter into derivative transactions for speculative purposes; however, for accounting purposes, certain transactions may not meet the criteria for hedge accounting.
Gains and losses on foreign exchange derivative instruments that qualify as accounting hedges are deferred as accumulated other comprehensive income and recognized when the underlying foreign exchange exposure is realized. Gains and losses on foreign exchange derivative instruments that do not qualify as hedges for accounting purposes are recognized currently based on the change in market value of the derivative instruments. At December 31, 2003, we had no material open foreign exchange derivative instruments.
From time to time, we may use interest rate swaps to manage the effect of interest rate changes on future income. Interest rate swaps are designated as a hedge of underlying future interest payments. The interest rate differential to
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be received or paid under the swaps is recognized over the lives of the swaps as an adjustment to interest expense. If an interest rate swap is terminated, the gain or loss is amortized over the life of the underlying debt.
In June 2001, we entered into $700 million aggregate notional amount of interest rate swaps as a fair value hedge against our 6.625% Notes due April 2011. In February 2002, we entered into $900 million aggregate notional amount of interest rate swaps as a fair value hedge against our 6.75% Senior Notes due April 2005, 6.95% Senior Notes due April 2008 and 9.5% Senior Notes due December 2008. The swaps effectively converted the fixed interest rate on each of the four series of notes into a floating rate. The market value of the swaps was carried as an asset or a liability in our consolidated balance sheet and the carrying value of the hedged debt was adjusted accordingly.
In January 2003, we terminated the swaps with respect to our 6.75% Senior Notes due April 2005, 6.95% Senior Notes due April 2008 and 9.5% Senior Notes due December 2008. In March 2003, we terminated the swaps with respect to our 6.625% Notes due April 2011. As a result of these terminations, we received cash proceeds, net of accrued interest, of approximately $173.5 million that was recognized as a fair value adjustment to long-term debt in our consolidated balance sheet and is being amortized as a reduction to interest expense over the life of the underlying debt. Such reduction amounted to approximately $23.1 million in 2003 and is expected to be approximately $27.2 million in 2004.
HISTORICAL 2003 COMPARED TO 2002
Following is an analysis of our Transocean Drilling segment and TODCO segment operating results, as well as an analysis of income and expense categories that we have not allocated to our two segments.
Transocean Drilling Segment
Due to a general deterioration in market conditions, average dayrates and utilization declined resulting in a decrease in this segment's contract drilling revenues of approximately $339.0 million, excluding the impact of the items discussed separately below. Contract drilling revenues were also adversely impacted by approximately $37.0 million due to the labor strike in Nigeria, the riser separation incident on the Discoverer Enterprise and the electrical fire on the Peregrine I. Additional decreases of $29.1 million resulted from rigs sold, returned to owner and transferred from this segment to the
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TODCO segment and the favorable settlement of a contract dispute during 2002. These decreases were partially offset by increases in contract drilling revenue of $45.2 million from a rig transferred into this segment from the TODCO segment during the second quarter of 2002 and from the Deepwater Frontier as a result of the consolidation of DDII LLC late in the second quarter of 2003. See "-Significant Events."
Operating revenues for 2003 included $82.7 million related to costs incurred and billed to customers on a reimbursable basis. See "-Overview."
The increase in this segment's operating and maintenance expense was primarily due to the recognition of approximately $83.0 million in client reimbursable costs as operating and maintenance expense as a result of implementing EITF 99-19 in 2003 (see "-Overview"). In addition, expenses increased approximately $89.9 million due to costs associated with the riser separation incident on the Discoverer Enterprise, the consolidation of DDII LLC, which leased the Deepwater Frontier, the restructuring of the Nigeria defined benefit plan, costs related to the electrical fire on the Peregrine I and the transfer of a jackup rig into this segment from the TODCO segment during the second quarter of 2002 (see "-Significant Events"). Partially offsetting these increases were decreased operating and maintenance expenses of approximately $51.0 million resulting from lower activity, implementation of standardized purchasing through negotiated agreements, nationalization of our labor force in certain operating locations and headcount reductions in support groups. Operating and maintenance expenses were further reduced by $44.0 million relating to rigs sold, returned to owner or removed from drilling service during and subsequent to 2002, the settlements of a dispute and an insurance claim as well as a reduction in our insurance program expense during 2003 and costs incurred in 2002 associated with restructuring charges and a litigation provision with no comparable activity in 2003.
The increase in this segment's depreciation expense resulted primarily from $9.1 million of additional depreciation on capital upgrades, the transfer of a rig from the TODCO segment into this segment and depreciation expense related to assets reclassified from held for sale to our active fleet during 2002 because they no longer met the criteria for assets held for sale under SFAS 144. These increases were partially offset by lower depreciation expense of $2.8 million following the sale of rigs classified as held and used during and subsequent to 2002.
The decrease in impairment loss in this segment is primarily due to the recognition of a $2,494.1 million goodwill impairment charge that resulted from our annual impairment test of goodwill conducted as of October 1, 2002 with no comparable charge in 2003. The impairment charge recorded in 2003 resulted from the removal of two drilling units from our active fleet. In 2002, we also recorded $28.5 million of non-cash impairment charges in this segment primarily related to assets reclassified from held for sale to our active fleet because they no longer met the held for sale criteria under SFAS 144.
During 2003, this segment recognized net pre-tax gains of $4.9 million related to the sale of the RBF 160, the Searex 15, the settlement of an insurance claim and the sale of other assets. During 2002, this segment recognized net pre-tax gains of $5.5 million related to the sale of the Transocean 96, Transocean 97 and a mobile offshore production unit, the partial settlement of an insurance claim and the sale of other assets, which were partially offset by net pre-tax losses of $2.8 million from the sale of the RBF 209 and an office building.
Higher utilization in 2003 resulted in an increase in this segment's contract drilling revenue of $42.9 million, partially offset by a decrease of $21.7 million due to lower average dayrates.
Operating revenues for 2003 included $17.8 million related to costs incurred and billed to customers on a reimbursable basis. See "-Overview."
A large portion of our operating and maintenance expense consists of employee-related costs and is fixed or only semi-variable. Accordingly, operating and maintenance expense does not vary in direct proportion to activity or dayrates.
The increase in this segment's operating and maintenance expense was due primarily to approximately $18.0 million in client reimbursable costs as operating and maintenance expense as a result of implementing EITF 99-19 during 2003 (see "-Overview"). In addition, expenses increased due to an increase in activity of approximately $14.0 million in 2003, costs of approximately $11.0 million associated with the well control incident on inland barge Rig 62 and the fire incident on inland barge Rig 20 (see " Significant Events"), as well as approximately $7.4 million related to a write-down of other receivables, an insurance claim provision and the consolidation of a joint venture that owns two land rigs during the third quarter of 2002. These increases were partially offset by approximately $10.9 million of reduced expense relating to our insurance program in 2003 compared to the same period in 2002, the release of a provision for doubtful accounts receivable during 2003 upon collection of amounts previously reserved, lower expenses resulting from the transfer of a jackup rig from this segment into the Transocean Drilling segment during the second quarter of 2002 and severance-related costs, other restructuring charges and compensation-related expenses incurred in 2002 with no comparable activity in 2003.
The decrease in impairment loss in this segment is primarily due to the recognition of a $381.9 million non-cash goodwill impairment charge that resulted from our annual impairment test of goodwill conducted as of October 1, 2002 with no comparable charge in 2003. Our 2003 impairment charges resulted primarily from our decision to take five jackup rigs out of drilling service and market the rigs for alternative uses. In 2002, we recorded non-cash impairment charges in this segment of $17.4 million primarily related to assets reclassified from held for sale to our active fleet because they no longer met the held for sale criteria under SFAS 144.
Total Company Results of Operations
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The decrease in general and administrative expense was primarily attributable to $9.0 million of costs related to the exchange of our newly issued notes for TODCO's notes in March 2002 as more fully described in Note 8 to our consolidated financial statements and reduced expense related to employee benefits for 2003. Offsetting these decreases was $8.8 million in expenses relating to the IPO of TODCO in 2003, of which $3.1 million was incurred and deferred in 2002.
Equity in earnings of joint ventures decreased approximately $3.8 million primarily related to TODCO's 25 percent share of losses from Delta Towing, which included TODCO's share of non-cash impairment charges on the carrying value of Delta Towing's fleet and a decrease in our 50 percent share of earnings from Overseas Drilling Limited ("ODL"), which owns the drillship Joides Resolution, as the rig came off contract in the third quarter of 2003. Offsetting these decreases was an increase in equity in earnings of $1.6 million related to our 50 percent share of earnings of DD LLC, which leased the Deepwater Pathfinder, as a result of the rig's increased utilization and average dayrates in 2003 compared to the same period in 2002.
The decrease in interest income was primarily due to a decrease of $3.2 million in interest earned on the notes receivable from Delta Towing due largely to the establishment of a reserve in the third quarter of 2003 resulting from Delta Towing's failure to make scheduled quarterly interest payments (see "-Related Party Transactions"). Also contributing to the decrease was lower average cash balances for 2003 compared to 2002 primarily due to the utilization of cash for debt reduction and capital expenditures.
The decrease in interest expense was attributable to reductions in interest expense of $29.7 million associated with debt that was refinanced, repaid or retired during and subsequent to 2002. We also received a refund of interest in 2003 from a taxing authority compared to an interest payment in 2002 resulting in a reduction in interest expense of $2.1 million. Partially offsetting these decreases was the termination of our fixed to floating interest rate swaps in the first quarter of 2003, which resulted in a net increase in interest expense of $22.2 million (see "-Derivative Instruments").
During 2003, we recognized a $15.7 million loss on early retirements of $888.6 million face value debt.
During 2003, we recognized a $21.3 million impairment loss on our note receivable from Delta Towing (see " Related Party Transactions").
We recognized a $3.5 million loss in other, net relating to the effect of foreign currency exchange rate changes on our monetary assets and liabilities primarily those denominated in Venezuelan bolivars (see "-Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
Our exposure to market risk for changes in interest rates relates primarily to our long-term and short-term debt. The table below presents scheduled debt and related weighted-average interest rates for each of the years ended December 31 relating to debt as of December 31, 2003. Weighted-average variable rates are based on London Interbank Offered Rate in effect at December 31, 2003, plus applicable margins.
At December 31, 2003 (in millions, except interest rate percentages):
At December 31, 2003, we had approximately $250.0 million of variable rate debt at face value (7.2 percent of total debt at face value). This variable rate debt represented revolving credit bank debt. Given outstanding amounts as of that date, a one percent rise in interest rates would result in an additional $1.9 million in interest expense per year. Offsetting this, a large part of our cash investments would earn commensurately higher rates of return. Using December 31, 2003 cash investment levels, a one percent increase in interest rates would result in approximately $4.7 million of additional interest income per year.
FOREIGN EXCHANGE RISK
Our international operations expose us to foreign exchange risk. We use a variety of techniques to minimize the exposure to foreign exchange risk. Our primary foreign exchange risk management strategy involves structuring customer contracts to provide for payment in both U.S. dollars, which is our functional currency, and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. Due to various factors, including local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign exchange needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk. Fluctuations in foreign currencies typically have minimal impact on overall results. In situations where payments of local currency do not equal local currency requirements, foreign exchange derivative instruments, specifically foreign exchange forward contracts or spot purchases, may be used. We do not enter into derivative transactions for speculative purposes. At December 31, 2003, we had no material open foreign exchange contracts.
In January 2003, Venezuela implemented foreign exchange controls that limit our ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. The exchange controls could also result in an artificially high value being placed on the local currency. As a result, we recognized a loss of $1.5 million, net of tax of $0.8 million, on the revaluation of the local currency into functional U.S dollars during the second quarter of 2003. In the third quarter of 2003, to limit our local currency exposure, we entered into an interim arrangement with one of our customers in which we are to receive 55 percent of the billed receivables in U.S. dollars with the remainder paid in local currency. Until new contracts have been negotiated, the interim arrangement will remain in place.
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ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT AUDITORS
To the Shareholders and Board of Directors of Transocean Inc.
We have audited the accompanying consolidated balance sheets of Transocean Inc. and Subsidiaries (the "Company") as of December 31, 2003 and 2002, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in Item 15(a) of this Form 10-K. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transocean Inc. and Subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, the Company adopted Statements of Financial Accounting Standards Nos. 123 and 142, effective January 1, 2003 and January 1, 2002, respectively.
/s/ Ernst & Young LLP
Houston, Texas January 29, 2004
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See accompanying notes.
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See accompanying notes.
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See accompanying notes.
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See accompanying notes.
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See accompanying notes.
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See accompanying notes.
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TRANSOCEAN INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-NATURE OF BUSINESS AND PRINCIPLES OF CONSOLIDATION
Transocean Inc. (together with its subsidiaries and predecessors, unless the context requires otherwise, the "Company") is a leading international provider of offshore contract drilling services for oil and gas wells. The Company's mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. The Company specializes in technically demanding segments of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. At December 31, 2003, the Company owned, had partial ownership interests in or operated 96 mobile offshore and barge drilling units, excluding the fleet of TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, "TODCO"), a publicly traded company as of February 2004 in which the Company owns a majority interest. As of this date, the Company's assets consisted of 32 High-Specification semisubmersibles and drillships ("floaters"), 26 Other Floaters, 26 Jackup Rigs and 12 Other Rigs. As of December 31, 2003, TODCO's fleet consisted of 24 jackups, 30 drilling barges, nine land rigs, three submersible drilling rigs and four other drilling rigs. The Company contracts its drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. The Company also provides additional services, including management of third party well service activities.
On January 31, 2001, the Company completed a merger transaction (the "R&B Falcon merger") with R&B Falcon Corporation ("R&B Falcon"). At the time of the merger, R&B Falcon owned, had partial ownership interests in, operated or had under construction more than 100 mobile offshore drilling units consisting of drillships, semisubmersibles, jackup rigs and other units in addition to the Gulf of Mexico Shallow and Inland Water segment fleet. As a result of the merger, R&B Falcon became an indirect wholly owned subsidiary of the Company. The merger was accounted for as a purchase with the Company as the accounting acquiror. The consolidated statements of operations and cash flows for the year ended December 31, 2001 include 11 months of operating results and cash flows for the merged company.
In July 2002, the Company announced plans to pursue a divestiture of its Gulf of Mexico Shallow and Inland Water business, which was a part of R&B Falcon. R&B Falcon's overall business was considerably broader than the Gulf of Mexico Shallow and Inland Water business. In preparation for this divestiture, the Company began the transfer of all assets and businesses out of R&B Falcon that were unrelated to the Gulf of Mexico Shallow and Inland Water business. In December 2002, R&B Falcon changed its name to TODCO and, in January 2004, the Gulf of Mexico Shallow and Inland Water business segment became known as the TODCO segment. In February 2004, TODCO completed an initial public offering ("IPO") (see Note 25). Before the closing of the IPO, TODCO completed the transfer to the Company of all unrelated assets and businesses.
For investments in joint ventures that do not meet the criteria of a variable interest entity and where the Company is not deemed to be the primary beneficiary for accounting purposes of those entities that meet the variable interest entity criteria, the equity method of accounting is used for investments in joint ventures where the Company's ownership is between 20 percent and 50 percent and for investments in joint ventures owned more than 50 percent where the Company does not have significant influence over the joint venture. The cost method of accounting is used for investments in joint ventures where the Company's ownership is less than 20 percent and the Company does not have significant influence over the joint venture. For investments in joint ventures that meet the criteria of a variable interest entity and where the Company is deemed to be the primary beneficiary for accounting purposes, such entities are consolidated (see Note 2). Intercompany transactions and accounts are eliminated.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting Estimates-The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities. On an ongoing basis, the Company evaluates its estimates, including those related to bad debts, materials and supplies obsolescence, investments, intangible assets and goodwill, property and equipment and other long-lived assets, income taxes, financing operations, workers' insurance, pensions and other postretirement benefits, other employment benefits and contingent liabilities. The Company bases its estimates on historical experience and on various other assumptions it believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.
Segments-The Company's operations have been aggregated into two reportable business segments: (i) Transocean Drilling (formerly "International and U.S. Floater Contract Drilling Services") and (ii) TODCO (formerly "Gulf of Mexico Shallow and Inland Water"). The Company provides services with different types of drilling equipment in several geographic regions. The location of the Company's operating assets and the allocation of resources to build or upgrade drilling units are determined by the activities and needs of customers. See Note 19.
Cash and Cash Equivalents-Cash equivalents are stated at cost plus accrued interest, which approximates fair value. Cash equivalents are highly liquid debt instruments with an original maturity of three months or less and may consist of time deposits with a number of commercial banks with high credit ratings, Eurodollar time deposits, certificates of deposit and commercial paper. The Company may also invest excess funds in no-load, open-end, management investment trusts ("mutual funds"). The mutual funds invest exclusively in high quality money market instruments. Generally, the maturity date of the Company's investments is the next business day.
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As a result of the Deepwater Nautilus project financing in 1999, the Company is required to maintain in cash an amount to cover certain principal and interest payments. Such restricted cash, classified as other assets in the consolidated balance sheets, was $12.0 million and $13.2 million at December 31, 2003 and 2002, respectively.
Accounts and Notes Receivable-Accounts receivable trade are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts receivable. Interest receivable on delinquent accounts receivable is included in the accounts receivable trade balance and recognized as interest income when chargeable and collectibility is reasonably assured. Notes receivable, included in investments in and advances to joint ventures, are carried at the historical carrying amount net of write-offs and allowance for loan loss. Interest receivable on notes receivable, which is included in accounts receivable-other, is accrued and recognized as interest income monthly on any unimpaired loan balance. The Company's notes receivable do not have premiums or discounts associated with their balances. Uncollectible notes and accounts receivable trade are written off when a settlement is reached for an amount that is less than the outstanding historical balance. With the consolidation of Delta Towing Holdings, LLC ("Delta Towing"), TODCO's notes receivable have been eliminated from the Company's consolidated balance sheet at December 31, 2003 (see "-New Accounting Pronouncements").
Allowance for Doubtful Accounts-The Company establishes an allowance for doubtful accounts on a case-by-case basis when it believes the required payment of specific amounts owed is unlikely to occur. This allowance was approximately $29 million and $21 million at December 31, 2003 and 2002, respectively. An allowance for loan loss is established when events or circumstances indicate that both the contractual interest and principal for a note receivable are not fully collectible. A loan is considered delinquent when principal and/or interest payments have not been made in accordance with the payment terms of the loan. Collectibility is determined based on estimated future cash flows discounted at the respective loan's effective interest rate with the excess of the loan's total contractual interest and principal over the estimated discounted future cash flows recorded as an allowance for loan loss. During the year ended December 31, 2003, TODCO recorded an allowance for loan loss of $21.3 million (see Note 20). As a result of the consolidation of Delta Towing, the allowance, together with the note receivable balance, was eliminated from the Company's consolidated balance sheet (see "-New Accounting Pronouncements"). There was no allowance for loan loss at December 31, 2003 and 2002.
Materials and Supplies-Materials and supplies are carried at the lower of average cost or market less an allowance for obsolescence. Such allowance was approximately $17 million and $19 million at December 31, 2003 and 2002, respectively.
Property and Equipment-Property and equipment, consisting primarily of offshore drilling rigs and related equipment, represented more than 65 percent of the Company's total assets at December 31, 2003. The carrying values of these assets are based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of the Company's rigs. These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations. Property and equipment obtained in the R&B Falcon merger (see Note 4) were recorded at fair value. The Company generally provides for depreciation using the straight-line method after allowing for salvage values. Expenditures for renewals, replacements and improvements are capitalized. Maintenance and repairs are charged to operating expense as incurred. Upon sale or other disposition, the applicable amounts of asset cost and accumulated depreciation are removed from the accounts and the net amount, less proceeds from disposal, is charged or credited to income.
As a result of the R&B Falcon merger, the Company conformed its policies relating to estimated rig lives and salvage values. Estimated useful lives of its drilling units now range from 18 to 35 years, reflecting maintenance history and market demand for these drilling units, buildings and improvements from 10 to 30 years and machinery and equipment from four to 12 years. Depreciation expense for the year ended December 31, 2001 was reduced by approximately $23 million ($0.07 per diluted share) as a result of conforming these policies.
Assets Held for Sale-Assets are classified as held for sale when the Company has a plan for disposal of certain assets and those assets meet the held for sale criteria of the Financial Accounting Standards Board's ("FASB") Statement of Financial Accounting Standards ("SFAS") 144, Accounting for Impairment or Disposal of Long-Lived Assets. The Company had no assets classified as held for sale at December 31, 2003 and 2002.
Goodwill-Prior to the adoption of SFAS 142, Goodwill and Other Intangible Assets, the excess of the purchase price over the estimated fair value of net assets acquired was accounted for as goodwill and was amortized on a straight-line basis based on a 40-year life. The amortization period was based on the nature of the offshore drilling industry, long-lived drilling equipment and the long-standing relationships with core customers. In accordance with SFAS 142, goodwill is no longer amortized and is now tested for impairment at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by
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management. Management has determined that the Company's reporting units are the same as its operating segments for the purpose of allocating goodwill and the subsequent testing of goodwill for impairment. Goodwill resulting from the R&B Falcon merger was allocated to the Company's two reporting units, Transocean Drilling and TODCO, at a ratio of 68 percent and 32 percent, respectively. The allocation was determined based on the percentage of each reporting unit's assets at fair value to the total fair value of assets acquired in the R&B Falcon merger. The fair value was determined from a third party valuation. Goodwill resulting from previous mergers was allocated entirely to the Transocean Drilling reporting unit.
During the first quarter of 2002, the Company implemented SFAS 142 and performed the initial test of impairment of goodwill on its two reporting units. The test was applied utilizing the estimated fair value of the reporting units as of January 1, 2002 determined based on a combination of each reporting unit's discounted cash flows and publicly traded company multiples and acquisition multiples of comparable businesses. There was no goodwill impairment for the Transocean Drilling reporting unit. However, because of deterioration in market conditions that affected the TODCO reporting unit since the completion of the R&B Falcon merger, a $1,363.7 million ($4.27 per diluted share) impairment of goodwill was recognized as a cumulative effect of a change in accounting principle in the first quarter of 2002.
During the fourth quarter of 2002, the Company performed its annual test of goodwill impairment as of October 1. Due to a general decline in market conditions, the Company recorded a non-cash impairment charge of $2,876.0 million ($9.01 per diluted share) of which $2,494.1 million and $381.9 million related to the Transocean Drilling and TODCO reporting units, respectively.
During the fourth quarter of 2003, the Company performed its annual test of goodwill impairment as of October 1 with no impairment indicated for the year ended December 31, 2003.
The Company's goodwill balance and changes in the carrying amount of goodwill are as follows (in millions):
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Net income (loss) and earnings (loss) per share for the years ended December 31, 2003, 2002 and 2001 adjusted for goodwill amortization are as follows (in millions, except per share data):
Impairment of Long-Lived Assets-The carrying value of long-lived assets, principally property and equipment, is reviewed for potential impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. For property and equipment held for use, the determination of recoverability is made based upon the estimated undiscounted future net cash flows of the related asset or group of assets being evaluated. Property and equipment held for sale are recorded at the lower of net book value or net realizable value. See Note 7.
Operating Revenues and Expenses-Operating revenues are recognized as earned, based on contractual daily rates or on a fixed price basis. Although the Company ceased providing turnkey drilling services in 2001, turnkey profits were recognized on completion of the well and acceptance by the customer. Events occurring after the date of the financial statements and before the financial statements are issued that are within the normal exposure and risk aspects of the turnkey contracts were considered refinements of the estimation process of the prior year and were recorded as adjustments at the date of the financial statements. Provisions for losses are made on contracts in progress when losses are anticipated. In connection with drilling contracts, the Company may receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to rigs. In connection with new drilling contracts, revenues earned and incremental costs incurred directly related to preparation and mobilization are deferred and recognized over the primary contract term of the drilling project. Costs of relocating drilling units without contracts to more promising market areas are expensed as incurred. Upon completion of drilling contracts, any demobilization fees received are reported in income, as are any related expenses. Capital upgrade revenues received are deferred and recognized over the primary contract term of the drilling project. The actual cost incurred for the capital upgrade is depreciated over the estimated useful life of the asset. The Company incurs periodic survey and drydock costs in connection with obtaining regulatory certification to operate its rigs on an ongoing basis. Costs associated with these certifications are deferred and amortized over the period until the next survey.
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Capitalized Interest-Interest costs for the construction and upgrade of qualifying assets are capitalized. The Company incurred total interest expense of $202.0 million, $212.0 million and $258.8 million for the years ended December 31, 2003, 2002 and 2001, respectively. The Company capitalized interest costs on construction work in progress of $34.9 million for the year ended December 31, 2001. No interest cost was capitalized during the years ended December 31, 2003 and 2002.
Derivative Instruments and Hedging Activities-The Company accounts for its derivative instruments and hedging activities in accordance with SFAS 133, Accounting for Derivative Instruments and Hedging Activities. See Notes 9 and 10.
Foreign Currency Translation-The Company accounts for translation of foreign currency in accordance with SFAS 52, Foreign Currency Translation. The majority of the Company's revenues and expenditures are denominated in U.S. dollars to limit the Company's exposure to foreign currency fluctuations, resulting in the use of the U.S. dollar as the functional currency for all of the Company's operations. Foreign currency exchange gains and losses are included in other income (expense) as incurred. Net foreign currency gains (losses) were $(3.5) million, $(0.5) million, and $1.1 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Income Taxes-Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. The income tax rates imposed by these taxing authorities vary substantially. Taxable income may differ from pre-tax income for financial accounting purposes, particularly in countries with revenue-based taxes. There is no expected relationship between the provision for income taxes and income before income taxes because the countries in which the Company operates have different taxation regimes, which vary not only with respect to nominal rate but also in terms of the availability of deductions, credits and other benefits. Variations also arise because income earned and taxed in any particular country or countries may fluctuate from period to period. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company's assets and liabilities using the applicable tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that, some or all of the benefit from the deferred tax asset will not be realized. See Note 14.
Stock-Based Compensation-In accordance with the provisions of SFAS 123, Accounting for Stock-Based Compensation, the Company had elected to follow the Accounting Principles Board Opinion ("APB") 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for its employee stock-based compensation plans through December 31, 2002 (see "-New Accounting Pronouncements" and Note 16). Under the intrinsic value method of APB 25, if the exercise price of employee stock options equals or exceeds the fair value of the underlying stock on the date of grant, no compensation expense is recognized. If an employee stock option is modified subsequent to the original grant date, and the exercise price is less than the fair value of the underlying stock on the date of the modification, compensation expense equal to the excess of the fair value over the exercise price is recognized over the remaining vesting period. Compensation expense for grants of restricted shares to employees is calculated based on the fair value of the shares on the date of grant and is recognized over the vesting period. Stock appreciation rights are considered variable grants and are recorded at fair value, with the change in the recorded fair value recognized as compensation expense.
Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS 123 using the prospective method. Under the prospective method and in accordance with the provisions of SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure, the recognition provisions are applied to all employee awards granted, modified, or settled after January 1, 2003. As a result of the adoption of SFAS 123, the Company recorded higher compensation expense of $4.3 million ($0.01 per diluted share), net of tax of $1.8 million, related to its stock-based compensation awards and modifications, and its Employee Stock Purchase Plan ("ESPP") during 2003.
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The expense related to stock-based employee compensation included in the determination of net income for the years ended December 31, 2003, 2002 and 2001 would be less than that which would have been recognized if the fair value method had been applied to all awards granted after the original effective date of SFAS 123. If the Company had elected to adopt the fair value recognition provisions of SFAS 123 as of its original effective date, pro forma net income and diluted net income per share would have been as follows:
The above pro forma amounts are not indicative of future pro forma results. The fair value of each option grant under the Long-Term Incentive Plan was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used:
The fair value of each option grant under the ESPP was estimated using the following weighted-average assumptions:
New Accounting Pronouncements-In April 2002, the FASB issued SFAS 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement eliminates the requirement under SFAS 4 to aggregate and classify all gains and losses from extinguishment of debt as an extraordinary item, net of related income tax effect. This statement also amends SFAS 13 to require certain lease modifications with economic effects similar to
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sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. In addition, SFAS 145 requires reclassification of gains and losses in all prior periods presented in comparative financial statements related to debt extinguishment that do not meet the criteria for extraordinary item in APB 30. The statement is effective for fiscal years beginning after May 15, 2002 with early adoption encouraged. The Company adopted SFAS 145 effective January 1, 2003. As a result of the adoption of this statement, the Company's results of operations for the year ended December 31, 2001 included $28.8 million ($0.09 per diluted share) related to the loss on early retirement of debt previously classified as an extraordinary item.
In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure, which is effective for fiscal years ending after December 15, 2002. SFAS 148 amends SFAS 123 to permit two additional transition methods for a voluntary change to the fair value based method of accounting for stock-based employee compensation from the intrinsic method under APB 25. The prospective method of transition under SFAS 123 is an option for entities adopting the recognition provisions of SFAS 123 in a fiscal year beginning before December 15, 2003. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements concerning the method of accounting used for stock-based employee compensation and the effects of that method on reported results of operations. Under SFAS 148, pro forma disclosures are required in a specific tabular format in the "Summary of Significant Accounting Policies." The Company adopted the disclosure requirements of this statement as of December 31, 2002. The adoption of the disclosure requirements had no effect on the Company's consolidated financial position or results of operations. The Company adopted the fair value method of accounting for stock-based compensation using the prospective method of transition under SFAS 123 effective January 1, 2003. Compensation expense in 2003 increased approximately $4.3 million ($0.01 per diluted share), net of tax of $1.8 million, as of result of adoption. See "-Stock-Based Compensation."
In January 2003, the FASB issued Interpretation ("FIN") 46, Consolidation of Variable Interest Entities. FIN 46 requires the consolidation of variable interest entities in which an enterprise absorbs a majority of the entity's expected losses, receives a majority of the entity's expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. The provisions of FIN 46 were effective immediately for those variable interest entities created after January 31, 2003. The provisions, as amended December 2003, are effective for the first interim or annual period ending after December 15, 2003 for those variable interest entities held prior to February 1, 2003 that are considered to be special purpose entities. The provisions, as amended, are to be applied no later than the end of the first reporting period that ends after March 15, 2004 for all other variable interest entities held prior to February 1, 2003. The Company adopted and applied the provisions of FIN 46, as revised December 31, 2003, effective December 31, 2003 for all variable interest entities.
At December 31, 2003, through TODCO, the Company had a 25 percent ownership interest in Delta Towing, a joint venture established for the purpose of owning and operating inland and shallow water marine support vessel equipment. See Note 20. Delta Towing is considered a variable interest entity as its equity is not sufficient to absorb its expected losses. Because TODCO has the largest percentage of investment at risk through the notes receivable, TODCO would absorb the majority of the joint venture's expected losses; therefore, TODCO is deemed to be the primary beneficiary of Delta Towing for accounting purposes. As such, TODCO consolidated Delta Towing effective December 31, 2003 and the consolidation resulted in an increase in net assets and a corresponding gain as a cumulative effect of a change in accounting principle of approximately $0.8 million.
The Company is party to a sale/leaseback agreement for the semisubmersible drilling rig M.G. Hulme, Jr. with an unrelated third party leasing company (see Note 15). Under the sale/leaseback agreement, the Company has the option to purchase the semisubmersible drilling rig at the end of the lease for a maximum amount of approximately $35.7 million. Because the sale/leaseback agreement is with an entity in which the Company has no direct investment, the Company is not entitled to receive the financial statements of the leasing entity and the equity holders of the leasing company will not release the financial statements or other financial information in order for the Company to make the determination of whether the entity is a variable interest entity. In addition, without the financial statements, the Company is unable to determine if it is the primary beneficiary of the entity and, if so, what it would consolidate. The Company has no exposure to loss as a result of the sale/leaseback agreement. The Company has incurred rig rental expense related to the sale/leaseback agreement of $12.5 million, $12.6 million and $11.9 million during each of the years ended December 31, 2003, 2002 and 2001, respectively. The Company currently accounts for the lease of this semisubmersible drilling rig as an operating lease.
Effective January 2003, the Company implemented Emerging Issues Task Force ("EITF") Issue No. 99-19, Reporting Revenues Gross as a Principal versus Net as an Agent. As a result of the implementation of the EITF, the costs incurred and charged to the Company's customers on a reimbursable basis are recognized as operating and maintenance expense. In addition,
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the amounts billed to the Company's customers associated with these reimbursable costs are being recognized as client reimbursable revenue. The increase in client reimbursable revenues and operating and maintenance expense was $100.5 million in 2003 as a result of the implementation of EITF 99-19. The change in accounting principle had no effect on the Company's results of operations or consolidated financial position. Prior period amounts have not been reclassified, as these amounts were not material.
Reclassifications-Certain reclassifications have been made to prior period amounts to conform with the current year presentation.
NOTE 3-ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss) at December 31, 2003 and 2002, net of tax, are as follows (in millions):
Deepwater Drilling L.L.C. ("DD LLC"), a previously unconsolidated subsidiary in which the Company had a 50 percent ownership interest, entered into interest rate swaps with aggregate market values netting to a $6.7 million liability at December 31, 2002 (see Note 18). The Company's interest in these swaps was recorded as other comprehensive loss related to unconsolidated joint venture. These swaps expired in October 2003 (see Note 10).
NOTE 4-BUSINESS COMBINATION
On January 31, 2001, the Company completed a merger transaction with R&B Falcon, in which an indirect wholly owned subsidiary of the Company merged with and into R&B Falcon. As a result of the merger, R&B Falcon common shareholders received 0.5 newly issued ordinary shares of the Company for each R&B Falcon share. The Company issued approximately 106 million ordinary shares in exchange for the issued and outstanding shares of R&B Falcon and assumed warrants and options exercisable for approximately 13 million ordinary shares. The ordinary shares issued in exchange for the issued and outstanding shares of R&B Falcon constituted approximately 33 percent of the Company's outstanding ordinary shares after the merger.
The Company accounted for the merger using the purchase method of accounting with the Company treated as the accounting acquiror. The purchase price of $6.7 billion was comprised of the calculated market capitalization of the Company's ordinary shares issued at the time of merger with R&B Falcon of $6.1 billion and the estimated fair value of R&B Falcon stock options and warrants at the time of the merger of $0.6 billion. The market capitalization of the Company's ordinary shares issued was calculated using the average closing price of the Company's ordinary shares for a period immediately before and after August 21, 2000, the date the merger was announced.
The purchase price included, at estimated fair value at January 31, 2001, current assets of $672 million, drilling and other property and equipment of $4,010 million, other assets of $160 million and the assumption of current liabilities of $338 million, other net long-term liabilities of $242 million and long-term debt of $3,206 million. The excess of the purchase price over the estimated fair value of net assets acquired was $5,630 million, which was accounted for as goodwill and is reviewed for impairment annually in accordance with SFAS 142. See Note 2.
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In conjunction with the R&B Falcon merger, the Company established a liability of $16.5 million for the estimated severance-related costs associated with the involuntary termination of 569 R&B Falcon employees pursuant to management's plan to consolidate operations and administrative functions post-merger. Included in the 569 planned involuntary terminations were 387 employees engaged in the Company's land drilling business in Venezuela. The Company suspended active marketing efforts to divest this business and, as a result, the estimated liability was reduced by $4.3 million in the third quarter of 2001 with an offset to goodwill. Through December 31, 2002, all required severance-related costs were paid to 182 employees whose positions were eliminated as a result of this plan.
Unaudited pro forma combined operating results of the Company and R&B Falcon assuming the R&B Falcon merger was completed as of January 1, 2001 for the year ended December 31, 2001 are as follows (in millions, except per share data):
The pro forma information includes adjustments for additional depreciation based on the fair market value of the drilling and other property and equipment acquired, amortization of goodwill arising from the transaction, increased interest expense for debt assumed in the merger and related adjustments for income taxes. The pro forma information is not necessarily indicative of the results of operations had the transaction been effected on the assumed dates or the results of operations for any future periods.
NOTE 5-CAPITAL EXPENDITURES AND OTHER ASSET ACQUISITIONS
Capital expenditures totaled $495.9 million during the year ended December 31, 2003 and included the Company's acquisition of two Fifth-Generation Deepwater Floaters, the Deepwater Pathfinder and Deepwater Frontier, through the payoff of synthetic lease financing arrangements totaling $382.8 million. The remaining $113.1 million related to capital expenditures for existing fleet and corporate infrastructure. A substantial majority of the capital expenditures in 2003 related to the Transocean Drilling segment.
Capital expenditures totaled $141.0 million during the year ended December 31, 2002 and related to the Company's existing fleet and corporate infrastructure. A substantial majority of the capital expenditures in 2002 related to the Transocean Drilling segment.
Capital expenditures, including capitalized interest, totaled $506.2 million during the year ended December 31, 2001 and included approximately $175.0 million, $42.0 million, $41.0 million and $24.0 million spent on the construction of the Deepwater Horizon, Sedco Energy, Sedco Express and Cajun Express, respectively. A substantial majority of the capital expenditures in 2001 related to the Transocean Drilling segment. The Company's construction program was completed as of December 31, 2001.
As a result of the R&B Falcon merger, the Company acquired ownership interests in two unconsolidated joint ventures, 50 percent in DD LLC and 60 percent in Deepwater Drilling II L.L.C. ("DDII LLC"). Subsidiaries of ConocoPhillips owned the remaining interests in these joint ventures. Each of the joint ventures was a lessee in a synthetic lease financing facility entered into in connection with the construction of the Deepwater Pathfinder, in the case of DD LLC, and the Deepwater Frontier, in the case of DDII LLC. Pursuant to the lease financings, the rigs were owned by special purpose entities and leased to the joint ventures.
In May 2003, WestLB AG, one of the lenders in the Deepwater Frontier synthetic lease financing facility, assigned its $46.1 million remaining promissory note receivable to the Company in exchange for cash of $46.1 million. Also in May 2003, but subsequent to the WestLB AG assignment, the Company purchased ConocoPhillips' 40 percent interest in DDII LLC for approximately $5.0 million. As a result of this purchase, the Company consolidated DDII LLC late in the second quarter of 2003. In addition, the Company acquired certain drilling and other contracts from ConocoPhillips for approximately $9.0 million in cash. In December 2003, DDII LLC prepaid the remaining $197.5 million debt and equity principal amounts owed,
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plus accrued and unpaid interest, to the Company and other lenders under the synthetic lease financing facility. As a result of this prepayment, DDII LLC became the legal owner of the Deepwater Frontier.
In November 2003, the Company purchased the remaining 25 percent minority interest in the Caspian Sea Ventures International Limited ("CSVI") joint venture. CSVI owns the jackup rig Trident 20 and is now a wholly owned subsidiary of the Company.
In December 2003, the Company purchased ConocoPhillips' 50 percent interest in DD LLC in connection with the payoff of the Deepwater Pathfinder synthetic lease financing facility. As a result of this purchase, the Company consolidated DD LLC late in the fourth quarter of 2003. Concurrent with the purchase of this ownership interest, DD LLC prepaid the remaining $185.3 million debt and equity principal amounts owed, plus accrued and unpaid interest, to the lenders under the synthetic lease financing facility. As a result of this prepayment, DD LLC became the legal owner of the Deepwater Pathfinder.
NOTE 6-ASSET DISPOSITIONS
In January 2003, in the Transocean Drilling segment, the Company completed the sale of a jackup rig, the RBF 160, for net proceeds of $13.1 million and recognized a gain of $0.2 million, net of tax of $0.1 million. The proceeds were received in December 2002.
During the year ended December 31, 2003, the Company settled an insurance claim and sold certain other assets for net proceeds of approximately $8.4 million and recorded net gains of $4.0 million ($0.01 per diluted share), net of tax of $0.6 million, in the Transocean Drilling segment and $0.6 million, net of tax of $0.3 million, in its TODCO segment.
During the year ended December 31, 2002, in the Transocean Drilling segment, the Company sold the jackup rig RBF 209 and two semisubmersible rigs, the Transocean 96 and Transocean 97, for net proceeds of $49.4 million and recognized net losses of $0.3 million, net of tax of $0.1 million.
During the year ended December 31, 2002, the Company settled an insurance claim and sold certain other assets for net proceeds of approximately $38.9 million and recorded net gains of $2.8 million ($0.01 per diluted share), net of tax of $0.3 million, and $0.6 million, net of tax of $0.4 million, in the Transocean Drilling and TODCO segments, respectively.
In December 2001, in the Transocean Drilling segment, the Company sold RBF FPSO L.P., which owned the Seillean, a multi-purpose service vessel. The Company received net proceeds from the sale of $85.6 million and recorded a net gain of $17.1 million ($0.05 per diluted share), net of tax of $9.2 million, for the year ended December 31, 2001.
In February 2001, in the Transocean Drilling segment, Sea Wolf Drilling Limited ("Sea Wolf"), a joint venture in which the Company held a 25 percent interest, sold two semisubmersible rigs, the Drill Star and Sedco Explorer, to Pride International, Inc. In the first quarter of 2001, the Company recognized accelerated amortization of the after-tax deferred gain related to the Sedco Explorer of $18.5 million ($0.06 per diluted share), which was included in gain from sale of assets. The Company's bareboat charter with Sea Wolf on the Sedco Explorer was terminated effective June 2000. The Company continued to operate the Drill Star, which was renamed the Pride North Atlantic, under a bareboat charter agreement until October 2001, at which time the rig was returned to its owner. The amortization of the Drill Star's deferred gain was accelerated and produced incremental after-tax gains in 2001 of $36.3 million ($0.12 per diluted share), which was included as a reduction in operating and maintenance expense.
During the year ended December 31, 2001, the Company sold certain other assets acquired in the R&B Falcon merger and certain other assets held for sale. The Company received net proceeds of approximately $116.1 million, and recorded net gains of $5.1 million ($0.02 per diluted share), net of tax of $0.8 million, and $3.8 million ($0.01 million per diluted share), net of tax of $2.0 million, in the Transocean Drilling and TODCO segments, respectively.
NOTE 7-IMPAIRMENT LOSS ON LONG-LIVED ASSETS
During the year ended December 31, 2003, the Company recorded non-cash impairment charges of $6.9 million ($0.02 per diluted share), net of tax of $3.7 million, in the TODCO segment as a result of the Company's decision to take five jackup rigs out of drilling service and market the rigs for alternative uses. The Company does not anticipate returning these rigs to drilling service as it is believed to be cost prohibitive. In accordance with SFAS 144, the carrying value of these assets was adjusted to fair market value. The fair market values of these units as non-drilling rigs were based on third party valuations. The
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Company also recorded a non-cash impairment charge in this segment of $0.5 million, net of tax of $0.2 million, related to its approximate 12 percent investment in Energy Virtual Partners, LP and Energy Virtual Partners Inc. The impairment resulted from the Company's determination that the fair value of the assets of those entities did not support its carrying value, which is included in investments in and advances to joint ventures in the Company's consolidated balance sheets. The impairment was determined and measured based on the remaining book value of the Company's investment, management's assessment of the fair value of that investment at the time the decision was made and the amount received upon liquidation of the assets of the investment.
During the year ended December 31, 2003, the Company recorded an after-tax, non-cash impairment charge of $4.2 million ($0.01 per diluted share) related to assets held and used in the Transocean Drilling segment as a result of the Company's decision to remove one mid-water semisubmersible rig and one self-erecting tender rig from drilling service. The impairment was determined and measured based on an estimate of fair value derived from an offer from a potential buyer. The Company also recorded an after-tax, non-cash impairment charge of $1.0 million in this segment as a result of the Company's decision to discontinue its leases on its oil and gas properties. The impairment was determined and measured based on the remaining book value of the assets and management's assessment of the fair value at the time the decision was made.
In 2002, the Company recorded non-cash impairment charges of $18.6 million ($0.06 per diluted share), net of tax of $9.9 million, and $10.6 million ($0.03 per diluted share), net of tax of $5.7 million, in its Transocean Drilling and TODCO segments, respectively, relating to the reclassification of assets held for sale to assets held and used. The impairment of these assets resulted from management's assessment that they no longer met the held for sale criteria under SFAS 144. In accordance with SFAS 144, the carrying value of these assets was adjusted to the lower of fair market value or carrying value adjusted for depreciation from the date the assets were classified as held for sale. The fair market values of these assets were based on third party valuations.
During the fourth quarter of 2002, the Company performed its annual test of goodwill impairment as of October 1, 2002. As a result of that test and a general decline in market conditions, the Company recorded non-cash impairments of $2,494.1 million ($7.82 per diluted share) and $381.9 million ($1.20 per diluted share) in its Transocean Drilling and TODCO segments, respectively. See Note 2.
In 2002, the Company recorded non-cash impairment charges in its Transocean Drilling and TODCO segments of $3.6 million ($0.01 per diluted share), net of tax of $1.9 million, and $0.7 million, net of tax of $0.4 million, respectively, related to assets held for sale, which resulted from deterioration in market conditions. The impairments were determined and measured based on an estimate of fair value derived from offers from potential buyers.
During the fourth quarter 2001, the Company recorded non-cash impairment charges in its Transocean Drilling and TODCO segments of $30.4 million ($0.10 per diluted share), net of tax of $9.0 million, and $0.7 million, net of tax of $0.3 million, respectively. In the Transocean Drilling segment, the impairment related to assets held for sale and certain assets held and used of $18.6 million, net of tax of $9.0 million, and $11.8 million, respectively. In the TODCO segment, the impairment related to certain assets held and used. The impairments resulted from deterioration in market conditions. The methodology used in determining the fair market value included third party appraisals and industry experience for assets held and used and offers from potential buyers for assets held for sale.
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NOTE 8-DEBT
Debt, net of unamortized discounts, premiums and fair value adjustments, is comprised of the following (in millions):
The scheduled maturity of the Company's debt, at face value, assumes the bondholders exercise their options to require the Company to repurchase the 1.5% Convertible Debentures, 7.45% Notes and Zero Coupon Convertible Debentures in May 2006, April 2007 and May 2008, respectively, and is as follows (in millions):
YEARS ENDING DECEMBER 31, ------------- 2004 . . . $ 45.8 2005 . . . 370.3 2006 . . . 400.0 2007 . . . 100.0 2008 . . . 819.0 Thereafter 1,750.0 ------------- Total. . . $ 3,485.1 =============
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Commercial Paper Program-The Company has a revolving credit agreement, described below, which, together with previous revolving credit agreements, provided liquidity through commercial paper borrowings during 2002 and 2003. At December 31, 2003, no amounts were outstanding under the Commercial Paper Program.
Revolving Credit Agreements-The Company is party to an $800.0 million five-year revolving credit agreement (the "Revolving Credit Agreement") dated December 16, 2003. This revolving credit agreement replaced the previously existing $550.0 million five-year revolving credit agreement dated December 29, 2000 and the $250.0 million 364-day revolving credit agreement dated December 26, 2002, which were both terminated effective December 16, 2003. The Revolving Credit Agreement bears interest, at the Company's option, at a base rate or London Interbank Offered Rate ("LIBOR") plus a margin that can vary from 0.350 percent to 0.950 percent depending on the Company's non-credit enhanced senior unsecured public debt rating. At December 31, 2003, the applicable margin was 0.500 percent. A facility fee varying from 0.075 percent to 0.225 percent depending on the Company's non-credit enhanced senior unsecured public debt rating, is incurred on the daily amount of the underlying commitment, whether used or unused, throughout the term of the facility. At December 31, 2003, the applicable facility fee was 0.125 percent. A utilization fee of 0.125 percent is payable if amounts outstanding under the Revolving Credit Agreement are greater than $264.0 million. At December 31, 2003, $250.0 million was outstanding under the Revolving Credit Agreement.
The Revolving Credit Agreement requires compliance with various covenants and provisions customary for agreements of this nature, including earnings before interest, taxes, depreciation and amortization ("EBITDA") to interest coverage ratio, as defined by the credit agreement, of not less than three to one, a debt to total tangible capital ratio, as defined by the credit agreement, of not greater than 50 percent, and limitations on creating liens, incurring debt, transactions with affiliates, sale/leaseback transactions and mergers and sale of substantially all assets.
6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes and Exchange Offer-In March 2002, the Company completed exchange offers and consent solicitations for TODCO's 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes ("the Exchange Offer"). As a result of the Exchange Offer, approximately $234.5 million, $342.3 million, $247.8 million, $246.5 million, $76.9 million and $289.8 million principal amount of TODCO's outstanding 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, were exchanged for the Company's newly issued 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes having the same principal amount, interest rate, redemption terms and payment and maturity dates. Because the holders of a majority in principal amount of each of these series of notes consented to the proposed amendments to the applicable indenture pursuant to which the notes were issued, some covenants, restrictions and events of default were eliminated from the indentures with respect to these series of notes. After the Exchange Offer, approximately $5.0 million, $7.7 million, $2.2 million, $3.5 million, $10.2 million and $10.2 million principal amount of the outstanding 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, not exchanged remain the obligation of TODCO (see "-Retired and Repurchased Debt"). These notes are combined with the notes of the corresponding series issued by the Company in the above table. In connection with the Exchange Offer, TODCO paid $8.3 million in consent payments to holders of TODCO's notes whose notes were exchanged. The consent payments are being amortized as an increase to interest expense over the remaining term of the respective notes and such amortization was approximately $1.3 million in each of the years ended December 31, 2003 and 2002. The 6.75%, 6.95%, 7.375% and 9.5% Senior Notes are redeemable at the Company's option at a make-whole premium (see Note 25).
1.5% Convertible Debentures-In May 2001, the Company issued $400.0 million aggregate principal amount of 1.5% Convertible Debentures due May 2021. The Company has the right to redeem the debentures after five years for a price equal to 100 percent of the principal. Each holder has the right to require the Company to repurchase the debentures after five, 10 and 15 years at 100 percent of the principal amount. The Company may pay this repurchase price with either cash or ordinary shares or a combination of cash and ordinary shares. The debentures are convertible into ordinary shares of the Company at the option of the holder at any time at a ratio of 13.8627 shares per $1,000 principal amount debenture, subject to adjustments if certain events take place, if the closing sale price per ordinary share exceeds 110 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the trading day immediately prior to the conversion date or if other specified conditions are met. At December 31, 2003, $400.0 million principal amount of these notes was outstanding.
Zero Coupon Convertible Debentures-In May 2000, the Company issued Zero Coupon Convertible Debentures due May 2020 with a face value at maturity of $865.0 million. The debentures were issued to the public at a price of $579.12 per debenture and accrue original issue discount at a rate of 2.75 percent per annum compounded semiannually to reach a face value at maturity of $1,000 per debenture. The Company will pay no interest on the debentures prior to maturity and has the right to redeem the debentures after three years for a price equal to the issuance price plus accrued original issue discount to the date of redemption. Each holder has the right to require the Company to repurchase the debentures on the third, eighth and thirteenth
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anniversary of issuance at the issuance price plus accrued original issue discount to the date of repurchase (see "-Retired and Repurchased Debt"). The Company may pay this repurchase price with either cash or ordinary shares or a combination of cash and ordinary shares. The debentures are convertible into ordinary shares of the Company at the option of the holder at any time at a ratio of 8.1566 shares per debenture subject to adjustments if certain events take place. At December 31, 2003, $26.4 million face value of these notes was outstanding with a discounted value of $16.8 million. Should all of the debentures be put to the Company in May 2008, the debentures will have a discounted value of $19.0 million.
Retired and Repurchased Debt-In December 2003, the Company repaid all of the $87.1 million principal amount outstanding 9.125% Senior Notes, of which $10.2 million principal amount outstanding was the obligation of TODCO, plus accrued and unpaid interest, in accordance with their scheduled maturity. The Company funded the repayment from existing cash balances.
In December 2003, the Company repaid the remaining $187.5 million principal amount outstanding under the Term Loan Agreement, plus accrued and unpaid interest, of which $150.0 million related to the early retirement of this debt. The Term Loan Agreement was terminated in conjunction with this repayment. The Company funded the repayment from existing cash balances.
In May 2003, the Company repurchased and retired all of the $50.0 million principal amount outstanding 9.41% Nautilus Class A2 Notes due May 2005 and funded the repurchase from existing cash balances. The Company recognized a loss on the early retirement of debt of approximately $3.6 million ($0.01 per diluted share), net of tax of $1.9 million, in the second quarter of 2003.
In May 2003, holders of the Company's Zero Coupon Convertible Debentures due May 24, 2020 had the option to require the Company to repurchase their debentures. Holders of $838.6 million aggregate principal amount, or approximately 97 percent, of these debentures exercised this option and the Company repurchased their debentures at a repurchase price of $628.57 per $1,000 principal amount. Under the terms of the debentures, the Company had the option to pay for the debentures with cash, the Company's ordinary shares, or a combination of cash and shares, and elected to pay the $527.2 million repurchase price from existing cash balances. The Company recognized additional expense of approximately $10.2 million ($0.03 per diluted share) as an after-tax loss on retirement of debt in the second quarter of 2003 to fully amortize the remaining debt issue costs related to the repurchased debentures.
In April 2003, the Company repaid the entire $239.5 million principal amount outstanding 6.5% Senior Notes, of which $5.0 million principal amount outstanding was the obligation of TODCO, plus accrued and unpaid interest, in accordance with their scheduled maturity. The Company funded the repayment from existing cash balances.
NOTE 9-FINANCIAL INSTRUMENTS AND RISK CONCENTRATION
Foreign Exchange Risk-The Company's international operations expose the Company to foreign exchange risk. This risk is primarily associated with compensation costs denominated in currencies other than the U.S. dollar and with purchases from foreign suppliers. The Company uses a variety of techniques to minimize exposure to foreign exchange risk, including customer contract payment terms and foreign exchange derivative instruments.
The Company's primary foreign exchange risk management strategy involves structuring customer contracts to provide for payment in both U.S. dollars and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. Due to various factors, including local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign exchange needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk. Fluctuations in foreign currencies typically have minimal impact on overall results. In situations where payments of local currency do not equal local currency requirements, foreign exchange derivative instruments, specifically foreign exchange forward contracts, or spot purchases may be used. A foreign exchange forward contract obligates the Company to exchange predetermined amounts of specified foreign currencies at specified exchange rates on specified dates or to make an equivalent U.S. dollar payment equal to the value of such exchange.
The Company does not enter into derivative transactions for speculative purposes. At December 31, 2003, the Company had no material open foreign exchange contracts.
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In January 2003, Venezuela implemented foreign exchange controls that limit the Company's ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. The Company's drilling contracts in Venezuela typically call for payments to be made in local currency, even when the dayrate is denominated in U.S. dollars. The exchange controls could also result in an artificially high value being placed on the local currency. As a result, the Company recognized a loss of $1.5 million, net of tax of $0.8 million, on the revaluation of the local currency into functional U.S. dollars during the second quarter of 2003. In the third quarter of 2003, to limit its exposure, the Company entered into an interim arrangement with one of its customers in which the Company is to receive 55 percent of the billed receivables in U.S. dollars with the remainder paid in local currency.
Gains and losses on foreign exchange derivative instruments, which qualify as accounting hedges, are deferred as other comprehensive income and recognized when the underlying foreign exchange exposure is realized. Gains and losses on foreign exchange derivative instruments, which do not qualify as hedges for accounting purposes, are recognized currently based on the change in market value of the derivative instruments. At December 31, 2003 and 2002, the Company did not have any foreign exchange derivative instruments not qualifying as accounting hedges.
Interest Rate Risk-The Company's use of debt directly exposes the Company to interest rate risk. Floating rate debt, where the interest rate can be changed every year or less over the life of the instrument, exposes the Company to short-term changes in market interest rates. Fixed rate debt, where the interest rate is fixed over the life of the instrument and the instrument's maturity is greater than one year, exposes the Company to changes in market interest rates should the Company refinance maturing debt with new debt.
In addition, the Company is exposed to interest rate risk in its cash investments, as the interest rates on these investments change with market interest rates.
The Company, from time to time, may use interest rate swap agreements to manage the effect of interest rate changes on future income. These derivatives are used as hedges and are not used for speculative or trading purposes. Interest rate swaps are designated as a hedge of underlying future interest payments. These agreements involve the exchange of amounts based on variable interest rates and amounts based on a fixed interest rate over the life of the agreement without an exchange of the notional amount upon which the payments are based. The interest rate differential to be received or paid on the swaps is recognized over the lives of the swaps as an adjustment to interest expense. Gains and losses on terminations of interest rate swap agreements are deferred and recognized as an adjustment to interest expense over the remaining life of the underlying debt. In the event of the early retirement of a designated debt obligation, any realized or unrealized gain or loss from the swap would be recognized in income.
The major risks in using interest rate derivatives include changes in interest rates affecting the value of such instruments, potential increases in interest expense of the Company due to market increases in floating interest rates in the case of derivatives that exchange fixed interest rates for floating interest rates and the credit worthiness of the counterparties in such transactions.
The Company has entered into interest rate swap transactions hedging debt. These interest rate swap transactions, however, have all been terminated as of December 31, 2003. See Note 10. The Company has not hedged any of its other assets or liabilities against interest rate movements.
The market value of the Company's swaps is carried on its consolidated balance sheet as an asset or liability depending on the movement of interest rates after the transaction is entered into and depending on the security being hedged. Because the Company's swaps are considered to be perfectly effective, the carrying value of the debt being hedged is adjusted for the market value of the swaps.
Should a counterparty default at a time in which the market value of the swap with that counterparty is classified as an asset in the Company's consolidated balance sheet, the Company may be unable to collect on that asset. To mitigate such risk of failure, the Company enters into swap transactions with a diverse group of high-quality institutions.
Credit Risk-Financial instruments that potentially subject the Company to concentrations of credit risk are primarily cash and cash equivalents, trade receivables, swap receivables and, prior to December 31, 2003, notes receivable from Delta Towing (see Notes 2 and 10). It is the Company's practice to place its cash and cash equivalents in time deposits at commercial banks with high credit ratings or mutual funds, which invest exclusively in high quality money market instruments. In foreign
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locations, local financial institutions are generally utilized for local currency needs. The Company limits the amount of exposure to any one institution and does not believe it is exposed to any significant credit risk.
The Company derives the majority of its revenue from services to international oil companies and government-owned and government-controlled oil companies. Receivables are dispersed in various countries. See Note 19. The Company maintains an allowance for doubtful accounts receivable based upon expected collectibility. The Company is not aware of any significant credit risks relating to its customer base and does not generally require collateral or other security to support customer receivables.
Labor Agreements-On a worldwide basis, excluding TODCO employees, approximately 24 percent of the Company's employees worked under collective bargaining agreements at December 31, 2003, most of whom worked in Brazil, Norway, U.K. and Nigeria. Of these represented employees, substantially all are working under agreements that are subject to salary negotiation in 2004.
At December 31, 2003, approximately five percent of TODCO employees worked under collective bargaining agreements in Trinidad and Venezuela.
NOTE 10-INTEREST RATE SWAPS
In June 2001, the Company entered into interest rate swap agreements in the aggregate notional amount of $700.0 million with a group of banks relating to the Company's $700.0 million aggregate principal amount of 6.625% Notes due April 2011. In February 2002, the Company entered into interest rate swap agreements with a group of banks in the aggregate notional amount of $900.0 million relating to the Company's $350.0 million aggregate principal amount of 6.75% Senior Notes due April 2005, $250.0 million aggregate principal amount of 6.95% Senior Notes due April 2008 and $300.0 million aggregate principal amount of 9.5% Senior Notes due December 2008. The objective of each transaction was to protect the debt against changes in fair value due to changes in the benchmark interest rate. Under each interest rate swap, the Company received the fixed rate equal to the coupon of the hedged item and paid LIBOR plus a margin of 50 basis points, 246 basis points, 171 basis points and 413 basis points, respectively, which were designated as the respective benchmark interest rates, on each of the interest payment dates until maturity of the respective notes. The hedges were considered perfectly effective against changes in the fair value of the debt due to changes in the benchmark interest rates over their term. As a result, the shortcut method applied and there was no requirement to periodically reassess the effectiveness of the hedges during the term of the swaps.
In January 2003, the Company terminated the swaps with respect to its 6.75%, 6.95% and 9.5% Senior Notes. In March 2003, the Company terminated the swaps with respect to its 6.625% Notes. As a result of these terminations, the Company received cash proceeds, net of accrued interest, of approximately $173.5 million that was recognized as a fair value adjustment to long-term debt in the Company's consolidated balance sheet and is being amortized as a reduction to interest expense over the life of the underlying debt. Such reduction amounted to approximately $23.1 million ($0.07 per diluted share) in 2003 and is expected to be approximately $27.2 million ($0.08 per diluted share) in 2004.
At December 31, 2003, the Company had no outstanding interest rate swaps. At December 31, 2002, the Company had outstanding interest rate swaps in the aggregate notional amount of $1.6 billion. The market value of the Company's outstanding interest rate swaps was included in other assets with corresponding increases to long-term debt as follows at December 31, 2002 (in millions):
DD LLC, a previously unconsolidated joint venture in which the Company had a 50 percent ownership interest, entered into interest rate swaps in August 1998 that expired in October 2003 (see Note 6). The Company's interest in these swaps was included in accumulated other comprehensive income, net of tax, with corresponding reductions to deferred income taxes and investments in and advances to joint ventures.
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NOTE 11-FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash and cash equivalents and trade receivables-The carrying amounts approximate fair value because of the short maturity of those instruments.
Swap receivables-The carrying value of swap receivables are adjusted to estimated market value based on current and forward LIBOR rates. The Company had no outstanding swap receivables at December 31, 2003 (see Note 10).
Notes receivable from related party-The fair value of notes receivable from related party with a carrying amount of $82.8 million at December 31, 2002 could not be determined because there is no available market price for such notes. Due to the adoption of FIN 46 and the consolidation of the related party, the notes receivable have been eliminated in consolidation. See Notes 2 and 21.
Debt-The fair value of the Company's fixed rate debt is calculated based on the estimated yield to maturity. The carrying value of variable rate debt approximates fair value.
NOTE 12-OTHER CURRENT LIABILITIES
Other current liabilities are comprised of the following (in millions):
NOTE 13-SUPPLEMENTARY CASH FLOW INFORMATION
Non-cash investing activities for the years ended December 31, 2003, 2002 and 2001 included $8.9 million, $7.9 million and $11.8 million, respectively, related to accruals of capital expenditures. The accruals have been reflected in the consolidated balance sheet as an increase in property and equipment, net and accounts payable.
In 2002, the Company reclassified the remaining assets that had not been disposed of from assets held for sale to property and equipment based on management's assessment that these assets no longer met the held for sale criteria under SFAS 144. As a result, $55.0 million was reflected as an increase in property and equipment with a corresponding decrease in other assets.
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Non-cash financing activities for the year ended December 31, 2001 included $6.7 billion related to the Company's ordinary shares issued in connection with the R&B Falcon merger. Non-cash investing activities for the year ended December 31, 2001 included $6.4 billion of net assets acquired in the R&B Falcon merger.
Concurrent with and subsequent to the R&B Falcon merger, the Company removed certain non-strategic assets from the active rig fleet and categorized them as assets held for sale. These reclassifications were reflected in the December 31, 2001 consolidated balance sheet as a decrease in property and equipment, net of $177.8 million, with a corresponding increase in other assets.
In February 2001, the Company received a distribution from a joint venture in the form of marketable securities held for sale valued at $19.9 million. The distribution was reflected in the consolidated balance sheet as an increase in other current assets with a corresponding decrease in investments in and advances to joint ventures.
Cash payments for interest were $219.0 million, $210.5 million and $190.6 million for the years ended December 31, 2003, 2002 and 2001, respectively. Cash payments for income taxes, net, were $73.4 million, $91.1 million and $122.5 million for the years ended December 31, 2003, 2002 and 2001, respectively.
NOTE 14-INCOME TAXES
Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. There is no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes because the countries have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits and other benefits. Variations also arise because income earned and taxed in any particular country or countries may fluctuate from year to year. Transocean Inc., a Cayman Islands company, is not subject to income tax in the Cayman Islands.
In June 2003, the Company recorded a $14.6 million ($0.04 per diluted share) foreign tax benefit attributable to the favorable resolution of a non-U.S. income tax liability.
During 2002, the Company recorded a $175.7 million ($0.55 per diluted share) tax benefit attributable to the restructuring of certain non-U.S. operations. As a result of the restructuring, previously unrecognized losses were offset against deferred gains, resulting in a reduction of noncurrent deferred taxes payable.
The components of the provision (benefit) for income taxes are as follows (in millions):
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Significant components of deferred tax assets and liabilities are as follows (in millions):
Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company's assets and liabilities using the applicable tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.
The Company provided a valuation allowance to offset deferred tax assets on net operating losses incurred during the year in certain jurisdictions where, in the opinion of management, it is more likely than not that the financial statement benefit of these losses would not be realized. The Company has also provided a valuation allowance for foreign tax credit carryforwards reflecting the possible expiration of their benefits prior to their utilization. At December 31, 2001, the Company's valuation allowance was $90.7 million. The valuation allowance for non-current deferred tax assets increased $42.6 million and $21.6 million during the years ended December 31, 2003 and 2002, respectively.
The Company's U.S. net operating loss carryforwards expire between 2004 and 2023. The tax effect of the U.S. net operating loss carryforwards was $580.9 million at December 31, 2003. The Company's U.K. net operating loss
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carryforwards do not expire. The tax effect of the U.K. net operating loss carryforwards was $28.2 million at December 31, 2003, which the Company intends to utilize through future earnings. The Company's fully benefited U.S. foreign tax credit carryforwards will expire between 2004 and 2008.
Transocean Inc., a Cayman Islands company, is not subject to income taxes in the Cayman Islands. For the three years ended December 31, 2003, there was no Cayman Islands income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by a Cayman Islands company or its shareholders. The Company has obtained an assurance from the Cayman Islands government under the Tax Concessions Law (1995 Revision) that, in the event that any legislation is enacted in the Cayman Islands imposing tax computed on profits or income, or computed on any capital assets, gain or appreciation, or any tax in the nature of estate duty or inheritance tax, such tax shall not, until June 1, 2019, be applicable to the Company or to any of its operations or to the shares, debentures or other obligations of the Company. Therefore, under present law there will be no Cayman Islands tax consequences affecting distributions.
The Company's income tax returns are subject to review and examination in the various jurisdictions in which the Company operates. The U.S. Internal Revenue Service is currently auditing the years 1999 and 2000. In addition, other tax authorities have questioned the amounts of income and expense subject to tax in their jurisdiction for prior periods. The Company is currently contesting additional assessments which have been asserted and may contest any future assessments. While the Company cannot predict or provide assurance as to the final outcome of existing or future assessments, it believes the ultimate resolution of these asserted income tax liabilities will not have a material adverse effect on the Company's business, consolidated financial position or results of operations.
In connection with the distribution of Sedco Forex Holdings Limited ("Sedco Forex") to the Schlumberger Limited ("Schlumberger") shareholders in December 1999, Sedco Forex and Schlumberger entered into a Tax Separation Agreement. In accordance with the terms of the Tax Separation Agreement, Schlumberger agreed to indemnify Sedco Forex for any tax liabilities incurred directly in connection with the preparation of Sedco Forex for this distribution. In addition, Schlumberger agreed to indemnify Sedco Forex for tax liabilities associated with Sedco Forex operations conducted through Schlumberger entities prior to the merger and any tax liabilities associated with Sedco Forex assets retained by Schlumberger.
The Company was included in the consolidated federal income tax returns filed by a former parent, Sonat Inc. ("Sonat") during all periods in which Sonat's ownership was greater than or equal to 80 percent ("Affiliation Years"). The Company and Sonat entered into a Tax Sharing Agreement providing for the manner of determining payments with respect to federal income tax liabilities and benefits arising in the Affiliation Years. Under the Tax Sharing Agreement, the Company will pay to Sonat an amount equal to the Company's share of the Sonat consolidated federal income tax liability, generally determined on a separate return basis. In addition, Sonat will pay the Company for Sonat's utilization of deductions, losses and credits that are attributable to the Company and in excess of that which would be utilized on a separate return basis.
NOTE 15-COMMITMENTS AND CONTINGENCIES
Operating Leases-The Company has operating lease commitments expiring at various dates, principally for real estate, office space, office equipment and rig bareboat charters. In addition to rental payments, some leases provide that the Company pay a pro rata share of operating costs applicable to the leased property. As of December 31, 2003, future minimum rental payments related to noncancellable operating leases are as follows (in millions):
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The Company is a party to an operating lease on the M. G. Hulme, Jr. The drilling rig is leased from Deep Sea Investors, L.L.C., a special purpose entity formed by several leasing companies to acquire the rig from one of the Company's subsidiaries in November 1995 in a sale/leaseback transaction. Under this lease, the Company may purchase the rig for a maximum amount of approximately $35.7 million at the end of the lease term of November 29, 2005. At December 31, 2003, the future minimum lease payments, excluding the purchase option, was $24.9 million and was included in the table above.
Rental expense for all operating leases, including leases with terms of less than one year, was approximately $51 million, $52 million and $96 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Legal Proceedings-In 1990 and 1991, two of the Company's subsidiaries were served with various assessments collectively valued at approximately $5.8 million from the municipality of Rio de Janeiro, Brazil to collect a municipal tax on services. The Company believes that neither subsidiary is liable for the taxes and has contested the assessments in the Brazilian administrative and court systems. In October 2001, the Brazil Supreme Court rejected the Company's appeal of an adverse lower court's ruling with respect to a June 1991 assessment, which is valued at approximately $5 million. The Company is continuing to challenge the assessment and has an action to suspend a related tax foreclosure proceeding, which is currently at the trial court level. The Company received a favorable ruling in connection with a disputed August 1990 assessment but the government has appealed that ruling. The Company also received an adverse ruling from the Taxpayer's Council in connection with an October 1990 assessment and is appealing the ruling. If the Company's defenses are ultimately unsuccessful, the Company believes that the Brazilian government-controlled oil company, Petrobras, has a contractual obligation to reimburse the Company for municipal tax payments required to be paid by them. The Company does not expect the liability, if any, resulting from these assessments to have a material adverse effect on its business or consolidated financial position.
The Indian Customs Department, Mumbai, filed a "show cause notice" against a subsidiary of the Company and various third parties in July 1999. The show cause notice alleged that the initial entry into India in 1988 and other subsequent movements of the Trident II jackup rig operated by the subsidiary constituted imports and exports for which proper customs procedures were not followed and sought payment of customs duties of approximately $31 million based on an alleged 1998 rig value of $49 million, with interest and penalties, and confiscation of the rig. In January 2000, the Customs Department issued its order, which found that the Company had imported the rig improperly and intentionally concealed the import from the authorities, and directed the Company to pay a redemption fee of approximately $3 million for the rig in lieu of confiscation and to pay penalties of approximately $1 million in addition to the amount of customs duties owed. In February 2000, the Company filed an appeal with the Customs, Excise and Gold (Control) Appellate Tribunal ("CEGAT") together with an application to have the confiscation of the rig stayed pending the outcome of the appeal. In March 2000, the CEGAT ruled on the stay application, directing that the confiscation be stayed pending the appeal. The CEGAT issued its opinion on the Company's appeal on February 2, 2001, and while it found that the rig was imported in 1988 without proper documentation or payment of duties, the redemption fee and penalties were reduced to less than $0.1 million in view of the ambiguity surrounding the import practice at the time and the lack of intentional concealment by the Company. The CEGAT further sustained the Company's position regarding the value of the rig at the time of import as $13 million and ruled that subsequent movements of the rig were not liable to import documentation or duties in view of the prevailing practice of the Customs Department, thus limiting the Company's exposure as to custom duties to approximately $6 million. Following the CEGAT order, the Company tendered payment of redemption, penalty and duty in the amount specified by the order by offset against a $0.6 million deposit and $10.7 million guarantee previously made by the Company. The Customs Department attempted to draw the entire guarantee, alleging the actual duty payable is approximately $22 million based on an interpretation of the CEGAT order that the Company believes is incorrect. This action was stopped by an interim ruling of the High Court, Mumbai on writ petition filed by the Company. Both the Customs Department and the Company filed appeals with the Supreme Court of India against the order of the CEGAT, and both appeals have been admitted. The Company is now awaiting a hearing date. The Company and its customer agreed to pursue and obtained the issuance of documentation from the Ministry of Petroleum that, if accepted by the Customs Department, would reduce the duty to nil. The agreement with the customer further provided that if this reduction was not obtained by the end of 2001, the customer would pay the duty up to a limit of $7.7 million. The Customs Department did not accept the documentation or agree to refund the duties already paid. The Company is pursuing its remedies against the Customs Department and the customer. The Company does not expect, in any event, that the ultimate liability, if any, resulting from the matter will have a material adverse effect on its business or consolidated financial position.
In March 1997, an action was filed by Mobil Exploration and Producing U.S. Inc. and affiliates, St. Mary Land & Exploration Company and affiliates and Samuel Geary and Associates, Inc. against TODCO, its underwriters and insurance broker in the 16th Judicial District Court of St. Mary Parish, Louisiana. The plaintiffs alleged damages amounting to in excess of $50 million in connection with the drilling of a turnkey well in 1995 and 1996. The case was tried before a jury in January and February 2000, and the jury returned a verdict of approximately $30 million in favor of the plaintiffs for excess drilling
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costs, loss of insurance proceeds, loss of hydrocarbons and interest. The Company believes that most, if not all, of the settlement amounts are covered by relevant primary and excess liability insurance policies. However, the insurers and underwriters denied coverage and one has filed a counterclaim. TODCO has instituted litigation against those insurers and underwriters to enforce its rights under the relevant policies. TODCO has settled with some of the insurers but is continuing the litigation against the remaining insurers. The Company is responsible for any losses TODCO incurs from these actions under the master separation agreement with TODCO and the Company will benefit from any recovery. The Company does not expect that the ultimate outcome of this case will have a material adverse effect on its business or consolidated financial position.
In October 2001, TODCO was notified by the U.S. Environmental Protection Agency ("EPA") that the EPA had identified a subsidiary of TODCO as a potentially responsible party in connection with the Palmer Barge Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon the information provided by the EPA and the review of TODCO's internal records to date, TODCO disputes its designation as a potentially responsible party. Pursuant to the master separation agreement with TODCO, the Company is responsible and will indemnify TODCO for any losses TODCO incurs in connection with this action. The Company does not expect that the ultimate outcome of this case will have a material adverse effect on the Company's business or consolidated financial position.
In August 2003, a judgment of approximately $9.5 million was entered by the Labor Division of the Provincial Court of Luanda, Angola, against the Company and a labor contractor for the Company, Hull Blyth, in favor of certain former workers on several of the Company's drilling rigs. The workers were employed by Hull Blyth to work on several drilling rigs while the rigs were located in Angola. When the drilling contracts concluded and the rigs left Angola, the workers' employment ended. The workers brought suit claiming that they were not properly compensated when their employment ended. In addition to the monetary judgment, the Labor Division ordered the workers to be hired by the Company. The Company believes that this judgment is without sufficient legal foundation and has appealed the matter to the Angola Supreme Court. The Company further believes that Hull Blyth has an obligation to protect the Company from any judgment. The Company does not believe that the ultimate outcome of this matter will have a material adverse effect on the Company's business or consolidated financial position.
The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of the Company's business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on its business or consolidated financial position.
Self Insurance-The Company is self-insured for the deductible portion of its insurance coverage. In the opinion of management, adequate accruals have been made based on known and estimated exposures up to the deductible portion of the Company's insurance coverages. Management believes that claims and liabilities in excess of the amounts accrued are adequately insured.
Letters of Credit and Surety Bonds-The Company had letters of credit outstanding at December 31, 2003 totaling $186.2 million. These letters of credit guarantee various contract bidding and insurance activities under various lines provided by several banks.
As is customary in the contract drilling business, the Company also has various surety bonds totaling $169.5 million in place that secure customs obligations relating to the importation of its rigs and certain performance and other obligations.
NOTE 16-STOCK-BASED COMPENSATION PLANS
Long-Term Incentive Plan-The Company has an incentive plan for key employees and outside directors (the "Incentive Plan"). Prior to 2003, the Company accounted for its Incentive Plan under APB 25 and related interpretations. Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS 123 using the prospective method. Under the prospective method and in accordance with the provisions of SFAS 148 (see Note 2), the recognition provisions are applied to all employee awards granted, modified, or settled after January 1, 2003.
Under the Incentive Plan, awards can be granted in the form of stock options, nonvested restricted stock, stock appreciation rights ("SARs") and cash performance awards. Such awards include traditional time-vesting awards ("time-based vesting awards"), and awards that are earned based on the achievement of certain performance criteria ("performance-based awards"). Options issued under the Incentive Plan have a 10-year term. Time-based vesting awards vest in three equal annual installments after the date of grant. Performance-based awards have a two year performance cycle with the number of options or shares earned being determined following the completion of the performance cycle (the "determination date") at which time
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one-third of the options or shares granted vest. Additional vesting occurs January 1 of the two subsequent years following the determination date.
As of December 31, 2003, the Company was authorized to grant up to (i) 18.9 million ordinary shares to employees; (ii) 600,000 ordinary shares to outside directors; and (iii) 300,000 freestanding SARs to employees or directors under the Incentive Plan. On December 31, 1999, all unvested stock options and SARs and all nonvested restricted shares granted after April 1996 became fully vested as a result of the Sedco Forex merger. At December 31, 2003, there were approximately 6.2 million total shares available for future grants under the Incentive Plan, assuming that the 1.5 million performance-based awards in 2003 are ultimately issued at the maximum amount.
Prior to the Sedco Forex merger, key employees of Sedco Forex were granted stock options at various dates under the Schlumberger stock option plans. For all of the stock options granted under such plans, the exercise price of each option equaled the market price of Schlumberger stock on the date of grant, each option's maximum term was 10 years and the options generally vested in 20 percent increments over five years. Fully vested Schlumberger options held by Sedco Forex employees at the date of the spin-off will lapse in accordance with their provisions. Non-vested Schlumberger options were terminated and fully vested stock options to purchase ordinary shares of the Company were granted under a new plan (the "SF Plan").
Prior to the R&B Falcon merger (see Note 4), certain employees and outside directors of R&B Falcon and its subsidiaries were granted stock options under various plans. As a result of the R&B Falcon merger, the Company assumed all outstanding R&B Falcon stock options and converted them into options to purchase ordinary shares of the Company.
Time-Based Vesting Awards
The following table summarizes time-based vesting stock option activity:
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The following table summarizes information about time-based vesting stock options outstanding at December 31, 2003:
At December 31, 2003, there were 41,360 time-based vesting nonvested restricted ordinary shares and 135,418 SARs outstanding under the Incentive Plan.
Performance-Based Awards
There was no performance-based award activity prior to 2003. The following table summarizes performance-based stock option activity during 2003:
At December 31, 2003, none of the performance-based stock options were exercisable.
The following table summarizes information about performance-based stock options outstanding at December 31, 2003:
During 2003, the Company granted performance-based nonvested restricted ordinary share awards that are earnable based on the achievement of certain performance targets. The number of shares to be issued will be quantified upon completion of the performance period at the determination date. At December 31, 2003, the maximum number of nonvested restricted ordinary shares that could be issued at the determination date was 829,065.
Employee Stock Purchase Plan-The Company provides a stock purchase plan (the "Stock Purchase Plan") for certain full-time employees. Under the terms of the Stock Purchase Plan, employees can choose each year to have between two and 20 percent of their annual base earnings withheld to purchase up to $25,000 of the Company's ordinary shares. The purchase price of the stock is 85 percent of the lower of its beginning-of-year or end-of-year market price. At December 31, 2003, 777,930 ordinary shares were available for issuance pursuant to the Stock Purchase Plan.
NOTE 17-RETIREMENT PLANS, OTHER POSTEMPLOYMENT BENEFITS AND OTHER BENEFIT PLANS
Defined Benefit Pension Plans-The Company maintains a qualified defined benefit pension plan (the "Retirement Plan") covering substantially all U.S. employees except for TODCO employees, and an unfunded plan (the "Supplemental Benefit Plan") to provide certain eligible employees with benefits in excess of those allowed under the Retirement Plan. In conjunction with the R&B Falcon merger, the Company acquired two funded and one unfunded defined benefit pension plans (the "Frozen Plans") that were frozen prior to the merger for which benefits no longer accrue, but the pension obligations have not been fully paid out. The Company refers to the Retirement Plan, the Supplemental Benefit Plan and the Frozen Plans collectively as the U.S. Plans.
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In addition, the Company provides several defined benefit plans, primarily group pension schemes with life insurance companies covering our Norway operations and two unfunded plans covering certain of the Company's employees and former employees (the "Norway Plans"). Certain of the Norway plans are funded in part by employee contributions. Company contributions to the Norway Plans are determined primarily by the respective life insurance companies based on the terms of the plan. For the insurance-based plans, annual premium payments are considered to represent a reasonable approximation of the service costs of benefits earned during the period. The Company also has an unfunded defined benefit plan (the "Nigeria Plan") that provides retirement and severance benefits for certain Nigerian employees. The defined benefit pension benefits provided by the Company are comprised of the U.S. Plans, the Norway Plans and the Nigeria Plan (collectively the "Transocean Plans"). The Company uses a January 1 measurement date for all of its plans.
The change in projected benefit obligation, change in plan assets and funded status is shown in the table below (in millions):
The accumulated benefit obligation for all defined benefit pension plans was $241.5 million and $227.7 million at December 31, 2003 and 2002, respectively.
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The aggregate projected benefit obligation and fair value of plan assets for plans with a projected benefit obligation in excess of plan assets are as follows (in millions):
The aggregate accumulated benefit obligation and fair value of plan assets for plans with an accumulated benefit obligation in excess of plan assets are as follows (in millions):
Net periodic benefit cost included the following components (in millions):
Weighted-average assumptions used to determine benefit obligations:
Weighted-average assumptions used to determine net periodic benefit cost:
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The defined benefit pension obligations and the related benefit costs are accounted for in accordance with SFAS 87, Employers' Accounting for Pensions. Pension obligations are actuarially determined and are affected by assumptions including expected return on plan assets, discount rates, compensation increases, and employee turnover rates. The Company evaluates its assumptions periodically and makes adjustments to these assumptions and the recorded liabilities as necessary.
Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate. The Company evaluates assumptions regarding the estimated long-term rate of return on plan assets based on historical experience and future expectations on investment returns, which are calculated by a third party investment advisor utilizing the asset allocation classes held by the plan's portfolios. The Company utilizes the Moody's Aa long-term corporate bond yield as a basis for determining the discount rate for a majority of its plans. Changes in these and other assumptions used in the actuarial computations could impact the plans projected benefit obligations, pension liabilities, pension expense and other comprehensive income. The determination of pension expense is based on a market-related valuation of assets that reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.
The Company's pension plan weighted-average asset allocations for funded Transocean Plans by asset category are as follows:
The Company has determined the asset allocation of the plans that it believes is best able to produce maximum long-term gains without taking on undue risk. After modeling many different asset allocation scenarios, the Company has determined that an asset allocation mix of approximately 60 percent equity securities, 30 percent debt securities, and 10 percent other investments is most appropriate. Other investments are generally a diversified mix of funds that specialize in various equity and debt strategies that are expected to provide positive returns each year relative to U.S. Treasury Bills. These strategies may include, among others, arbitrage, short-selling, and merger and acquisition investment opportunities. The Company reviews asset allocations and results quarterly to ensure that managers are meeting specified objectives and policies as written and agreed to by each manager and the Company. These objectives and policies are reviewed each year.
The plan's investment managers have discretion in the securities in which they may invest within their asset category. Given this discretion, the managers may, from time-to-time, invest in the Company's stock or debt. This could include taking either long or short positions in such securities. As these managers are required to maintain well diversified portfolios, the actual investment in the Company's common stock would be immaterial relative to asset categories and the overall plan.
The Company expects to contribute $10.0 million to the Transocean Plans in 2004, comprised of $5.4 million to the funded U.S. Plans, an estimated $2.0 million to fund expected benefit payments for the unfunded U.S. Plans and Nigeria Plan, and an estimated $2.6 million for the Norway Plans to fund expected benefit payments.
Nigeria Plan-During 2003, the Company terminated all Nigerian employees, which resulted in the payment of all accrued benefits under the Nigeria Plan. Approximately 80 of these employees were made redundant during 2003, while the remaining employees not considered redundant were rehired under a new plan. In accordance with the provisions of SFAS 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and Termination Benefits, this resulted in a partial plan curtailment and a plan settlement. The Company paid approximately $17.0 million in severance benefits under the Nigeria Plan during 2003 as a result of these events. In accordance with SFAS 88, the Company has accounted for these events as a plan restructuring and recorded a net settlement expense of $10.4 million, as well as a $4.6 million liability. This liability will reduce future pension expense related to the Nigeria Plan as it will be recognized over the expected service term of the related employees. Pension expense for the Nigeria Plan is estimated to be $0.1 million in 2004 and represents a 94.6% decrease as compared to the 2003 plan expenses (excluding the settlement related expenses discussed above).
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Postretirement Benefits Other Than Pensions-The Company has several unfunded contributory and noncontributory postretirement benefit plans covering substantially all of its Transocean Drilling segment U.S. employees. The postretirement health care plans include a limit on the Company's share of costs for recent and future retirees. The Company uses a January 1 measurement date for all of its plans.
The change in benefit obligation, change in plan assets and funded status are shown in the table below (in millions):
Amounts recognized in the consolidated balance sheets for the years ended December 31, 2003 and 2002 consisted of accrued benefit costs totaling $34.8 million and $30.1 million, respectively. There were no prepaid benefit costs recognized for the years ended December 31, 2003 and 2002.
Net periodic benefit cost included the following components (in millions):
One of the Company's postretirement benefit plans is a retiree life insurance plan. Effective January 1, 2003, the plan was amended such that participants who retire after December 31, 2002 no longer receive postretirement benefits provided under this plan. As such, the Company recorded a curtailment gain of $0.6 million related to this amendment.
Weighted-average discount rates used to determine benefit obligations were 6.00% and 6.50% for the years ended December 31, 2003 and 2002, respectively.
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Weighted-average assumptions used to determine net periodic benefit cost were as follows:
Assumed health care cost trend rates were as follows:
The assumed health care cost trend rate has significant impact on the amounts reported for postretirement benefits other than pensions. A one-percentage point change in the assumed health care trend rate would have the following effects (in millions):
The Company's other postretirement benefit (retiree life insurance and medical benefits) obligations and the related benefit costs are accounted for in accordance with SFAS 106, Employers' Accounting for Postretirement Benefits Other than Pensions. Postretirement costs and obligations are actuarially determined and are affected by assumptions including expected discount rates, compensation increases, employee turnover rates and health care cost trend rates. The Company evaluates its assumptions periodically and makes adjustments to these assumptions and the recorded liabilities as necessary.
Two of the most critical assumptions for postretirement benefit plans are the assumed discount rate and the expected health care cost trend rates. The Company utilizes the Moody's Aa long-term corporate bond yield as a basis for determining the discount rate. The accumulated postretirement benefit obligation and service cost were developed using a health care trend rate of 11.0 percent for 2003 reducing 1.0 percent per year to an ultimate trend rate of 5.0 percent per year for 2009 and later. The initial trend rate was selected with reference to recent Transocean experience and broader national statistics. The ultimate trend rate is a long term assumption and was selected to reflect the anticipation that the portion of gross domestic product devoted to health care becomes constant. Changes in these and other assumptions used in the actuarial computations could impact the Company's projected benefit obligations, pension liabilities and pension expense.
The Company expects to contribute $1.8 million to its other postretirement benefit plans in 2004 to fund expected benefit payments.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") was signed into law. The Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that currently provide a prescription drug benefit that is equivalent to the expanded Medicare benefit. Employers have the option to either receive the subsidy or to supplement the Medicare paid prescription drug benefit on a secondary payor basis. In accordance with SFAS 106, employers are required to consider presently enacted changes in relevant laws in current period measurements of postretirement benefit costs and the accumulated postretirement benefit obligation. As a result, the accumulated postretirement benefit obligation and net periodic postretirement benefit costs for future periods should reflect the effects of the Act.
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In January 2004, the FASB staff issued FASB Staff Position ("FSP") 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act. The deferral will continue to apply until authoritative guidance on the accounting for the federal subsidy is issued or a significant event occurs that would ordinarily call for remeasurement of a plan's assets and obligations. The Company elected to defer accounting for the Act and will continue to assess the effects the Act will have on its postretirement benefit plan costs. As a result of the deferral election, the disclosures above relating to the net periodic postretirement benefit costs do not reflect the effects of the Act on the Company's postretirement benefit plans. The finalization of pending authoritative guidance could require restatement of previously reported information.
Defined Contribution Plans-The Company provides a defined contribution pension and savings plan covering senior non-U.S. field employees working outside the United States. Contributions and costs are determined as 4.5 percent to 6.5 percent of each covered employee's salary, based on years of service. In addition, the Company sponsors a U.S. defined contribution savings plan that covers certain employees and limits Company contributions to no more than 4.5 percent of each covered employee's salary, based on the employee's contribution. The Company also sponsors various other defined contribution plans worldwide. The Company recorded approximately $21.8 million, $21.3 million and $21.6 million of expense related to its defined contribution plans for the years ended December 31, 2003, 2002 and 2001, respectively.
Deferred Compensation Plan-The Company provides a Deferred Compensation Plan (the "Plan"). The Plan's primary purpose is to provide tax-advantageous asset accumulation for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company.
Eligible employees who enroll in the Plan may elect to defer up to a maximum of 90 percent of base salary, 100 percent of any future performance awards, 100 percent of any special payments and 100 percent of directors' meeting fees and annual retainers; however, the Administrative Committee (seven individuals appointed by the Finance and Benefits Committee of the Board of Directors) may, at its discretion, establish minimum amounts that must be deferred by anyone electing to participate in the Plan. In addition, the Executive Compensation Committee of the Board of Directors may authorize employer contributions to participants and the Chief Executive Officer of the Company, with Executive Compensation Committee approval, is authorized to cause the Company to enter into "Deferred Compensation Award Agreements" with such participants. There were no employer contributions to the Plan during the years ending December 31, 2003, 2002 or 2001.
NOTE 18-INVESTMENTS IN AND ADVANCES TO JOINT VENTURES
The Company had a 25 percent interest in Sea Wolf. In September 1997, Sedco Forex sold two semisubmersible rigs, the Drill Star and Sedco Explorer, to Sea Wolf. The Company operated the rigs under bareboat charters. The sale resulted in a deferred gain of approximately $157 million, which was being amortized to operating and maintenance expense over the six-year life of the bareboat charters. See Note 6. As of December 31, 2001, Sea Wolf distributed substantially all of its assets to its shareholders and was dissolved in 2003.
The Company has a 50 percent interest in Overseas Drilling Limited ("ODL"), which owns the drillship, Joides Resolution. The drillship is contracted to perform drilling and coring operations in deep waters worldwide for the purpose of scientific research. The Company manages and operates the vessel on behalf of ODL. See Note 20.
At December 31, 2000, the Company had a 24.9 percent interest in Arcade, a Norwegian offshore drilling company. Arcade owns two high-specification semisubmersible rigs, the Henry Goodrich and Paul B. Loyd, Jr. Because TODCO owned 74.4 percent of Arcade, Arcade was consolidated in the Company's financial statements effective with the R&B Falcon merger. In October 2001, the Company purchased the remaining minority interest in Arcade. The purchase price of $3.2 million was finalized in January 2003.
As a result of the R&B Falcon merger, the Company had ownership interests in two unconsolidated joint ventures, 50 percent in DD LLC and 60 percent in DDII LLC. Subsidiaries of ConocoPhillips owned the remaining interests in these joint ventures. The Company purchased ConocoPhillips' interests in DDII LLC and DD LLC in late May 2003 and late December 2003, respectively, at which time both DDII LLC and DD LLC became wholly owned subsidiaries. See Note 5.
As a result of the R&B Falcon merger, TODCO has a 25 percent ownership interest in Delta Towing. See Note 20. As result of the Company's adoption of FIN 46 effective December 31, 2003, Delta Towing was consolidated at December 31, 2003. See Note 2.
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NOTE 19-SEGMENTS, GEOGRAPHICAL ANALYSIS AND MAJOR CUSTOMERS
The Company's operations are aggregated into two reportable segments: (i) Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services. The TODCO segment consists of our interest in TODCO, which conducts jackups, barge drilling rigs, land rigs, submersibles and other rig operations located in the U.S. Gulf of Mexico and inland waters, Mexico, Trinidad and Venezuela. The Company provides services with different types of drilling equipment in several geographic regions. The location of the Company's rigs and the allocation of resources to build or upgrade rigs is determined by the activities and needs of customers. Accounting policies of the segments are the same as those described in the Summary of Significant Accounting Policies (see Note 2). The Company accounts for intersegment revenue and expenses as if the revenue or expenses were to third parties at current market prices.
Operating revenues and income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principles by segment were as follows (in millions):
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Operating revenues and long-lived assets by country were as follows (in millions):
A substantial portion of the Company's assets are mobile. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods.
The Company's international operations are subject to certain political and other uncertainties, including risks of war and civil disturbances (or other events that disrupt markets), expropriation of equipment, repatriation of income or capital, taxation policies, and the general hazards associated with certain areas in which operations are conducted.
For the year ended December 31, 2003, Petrobras, BP and Shell accounted for approximately 11.8 percent, 11.1 percent and 10.7 percent, respectively, of the Company's operating revenues, of which the majority was reported in the Transocean Drilling segment. For the year ended December 31, 2002, BP and Shell accounted for approximately 14.1 percent and 11.6 percent, respectively, of the Company's operating revenues, of which the majority was reported in the Transocean Drilling segment. For the year ended December 31, 2001, BP and Petrobras accounted for approximately 12.3 percent and 10.9 percent, respectively, of the Company's operating revenues, of which the majority was reported in the Transocean Drilling segment. The loss of these or other significant customers could have a material adverse effect on the Company's results of operations.
NOTE 20-RELATED PARTY TRANSACTIONS
DD LLC and DDII LLC-Prior to the Company's purchase of ConocoPhillips' interest in DD LLC and DDII LLC (see Note 5), the Company was party to drilling services agreements with DD LLC and DDII LLC for the operations of the Deepwater Pathfinder and Deepwater Frontier, respectively. For the year ended December 31, 2003, the Company earned $1.6 million and $1.3 million for such services to DD LLC and DDII LLC, respectively. For the years ended December 31, 2002 and 2001, the Company earned $1.6 million and $1.4 million, respectively, for such services to each of DD LLC and DDII LLC. Such revenue amounts were included in operating revenues in the consolidated statement of operations. At December 31, 2002, the Company had receivables from DD LLC and DDII LLC of $2.6 million and $3.9 million, respectively, which were included in accounts receivable - other.
From time to time, the Company contracted the Deepwater Frontier from DDII LLC. During that time, DDII LLC billed the Company for the full operating dayrate and issued a non-cash credit for downtime hours in excess of 24 hours in any calendar month. The Company recorded a dayrate rebate receivable for all such non-cash credits and was responsible for payment of 100 percent of all drilling contract invoices received. At December 31, 2002, the cumulative dayrate rebate receivable from DDII LLC totaled $15.1 million and was recorded as investment in and advances to joint ventures in the
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consolidated balance sheet. For the year ended December 31, 2001, the Company incurred $54.4 million net expense from DDII LLC under the drilling contract. This amount was included in operating and maintenance expense in the Company's consolidated statement of operations. The Company incurred no expense for the years ended December 31, 2003 or 2002 due to the expiration of its lease late in 2001. At December 31, 2002, the Company had amounts payable to DDII LLC of $0.3 million, which was included in accounts payable in the consolidated balance sheet.
Delta Towing-Immediately prior to the closing of the R&B Falcon merger, TODCO formed a joint venture to own and operate its U.S. inland marine support vessel business (the "Marine Business"). In connection with the formation of the joint venture, the Marine Business was transferred by a subsidiary of TODCO to Delta Towing in exchange for a 25 percent equity interest, and certain secured notes payable from Delta Towing. The secured notes consisted of (i) an $80.0 million principal amount note bearing interest at eight percent per annum due January 30, 2024 (the "Tier 1 Note"), (ii) a contingent $20.0 million principal amount note bearing interest at eight percent per annum with an expiration date of January 30, 2011 (the "Tier 2 Note") and (iii) a contingent $44.0 million principal amount note bearing interest at eight percent per annum with an expiration date of January 30, 2011 (the "Tier 3 Note"). The 75 percent equity interest holder in the joint venture also loaned Delta Towing $3.0 million in the form of a Tier 1 Note. Until January 2011, Delta Towing must use 100 percent of its excess cash flow towards the payment of principal and interest on the Tier 1 Notes. After January 2011, 50 percent of its excess cash flows are to be applied towards the payment of principal and unpaid interest on the Tier 1 Notes. Interest is due and payable quarterly without regard to excess cash flow.
Delta Towing must repay at least (i) $8.3 million of the aggregate principal amount of the Tier 1 Note no later than January 2004, (ii) $24.9 million of the aggregate principal amount no later than January 2006 and (iii) $62.3 million of the aggregate principal amount no later than January 2008. After the Tier 1 Note has been repaid, Delta Towing must apply 75 percent of its excess cash flow towards payment of the Tier 2 Note. Upon the repayment of the Tier 2 Note, Delta Towing must apply 50 percent of its excess cash to repay principal and interest on the Tier 3 Note. Any amounts not yet due under the Tier 2 and Tier 3 Notes at the time of their expiration will be waived. The Tier 1, 2 and 3 Notes are secured by mortgages and liens on the vessels and other assets of Delta Towing.
TODCO valued its Tier 1, 2 and 3 Notes at $80 million immediately prior to the closing of the R&B Falcon merger, the effect of which was to fully reserve the Tier 2 and 3 Notes. At December 31, 2002, $78.9 million was outstanding under the Company's Tier 1 Note. For the years ended December 31, 2003, 2002 and 2001, the Company earned interest income on the outstanding balance at each period of $3.1 million, $6.3 million and $5.8 million, respectively, on the Tier 1 Note. In December 2001, the note agreement was amended to provide for a $4.0 million, three-year revolving credit facility (the "Delta Towing Revolver") from the Company. Amounts drawn under the Delta Towing Revolver accrued interest at eight percent per annum, with interest payable quarterly. For each of the years ended December 31, 2003 and 2002, TODCO recognized $0.3 million of interest income on the Delta Towing Revolver. At December 31, 2002, $3.9 million was outstanding under the Delta Towing Revolver. At December 31, 2002, the Company had interest receivable from Delta Towing of $1.7 million.
Delta Towing defaulted on the notes in January 2003 by failing to make its scheduled quarterly interest payment and remains in default as a result of its continued failure to make its quarterly interest payments. As a result of TODCO's continued evaluation of the collectibility of the notes, TODCO recorded a $21.3 million impairment of the notes in June 2003 based on Delta Towing's discounted cash flows over the terms of the notes, which deteriorated in the second quarter of 2003 as a result of the continued decline in Delta Towing's business outlook. As permitted in the notes in the event of default, TODCO began offsetting a portion of the amount owed to Delta Towing against the interest due under the notes. Additionally, in 2003, TODCO established a reserve of $1.6 million for interest income earned during the year ended December 31, 2003 on the notes receivable.
As a result of the adoption of FIN 46 and a determination that TODCO was the primary beneficiary for accounting purposes of Delta Towing, TODCO consolidated Delta Towing effective December 31, 2003 and intercompany transactions and accounts have been eliminated. Consolidation of Delta Towing resulted in an increase in net assets and a corresponding gain as a cumulative effect of a change in accounting principle of approximately $0.8 million. See Note 2.
As part of the formation of the joint venture on January 31, 2001, TODCO entered into an agreement with Delta Towing under which TODCO committed to charter certain vessels for a period of one year ending January 31, 2002 and committed to charter for a period of 2.5 years from the date of delivery 10 crewboats then under construction, all of which had been placed into service as of December 31, 2002. During the year ended December 31, 2003, TODCO incurred charges of $11.7 million, which was reflected in operating and maintenance expense. During the year ended December 31, 2002, TODCO incurred charges totaling $10.7 million from Delta Towing for services rendered, of which $1.6 million was rebilled to
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TRANSOCEAN INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
TODCO's customers and $9.1 million was reflected in operating and maintenance expense. During the year ended December 31, 2001, TODCO incurred charges totaling $15.6 million from Delta Towing for services rendered, of which $6.5 million was rebilled to TODCO's customers and $9.1 million was reflected in operating and maintenance.
ODL-In conjunction with the management and operation of the Joides Resolution on behalf of ODL, the Company earned $1.2 million for the each of the years ended December 31, 2003, 2002 and 2001. Such amounts are included in operating revenues in the Company's consolidated statements of operations. At December 31, 2003 and 2002, the Company had receivables from ODL of $3.1 million and $1.2 million, respectively, which were recorded as accounts receivable - other in the consolidated balance sheets.
NOTE 21-RESTRUCTURING CHARGES
In September 2002, the Company committed to restructuring plans in France, Norway and in its TODCO segment. The Company established a liability of approximately $5.2 million for the estimated severance-related costs associated with the involuntary termination of 81 employees pursuant to these plans. The charge was reported as operating and maintenance expense in the Company's consolidated statements of operations of which approximately $4.0 million and $1.2 million related to the Transocean Drilling segment and TODCO segment, respectively. Through December 31, 2003, approximately $4.6 million had been paid to 74 employees representing full or partial payments. In June 2003, the Company released the expected surplus liability of $0.3 million to operating and maintenance expense in the Transocean Drilling segment. Substantially all of the remaining liability is expected to be paid by the end of the first quarter in 2005.
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TRANSOCEAN INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
NOTE 22-EARNINGS PER SHARE
The reconciliation of the numerator and denominator used for the computation of basic and diluted earnings (loss) per share is as follows (in millions, except per share data):
Ordinary shares subject to issuance pursuant to the conversion features of the convertible debentures (see Note 8) are not included in the calculation of adjusted weighted-average shares and assumed conversions for diluted earnings per share because the effect of including those shares is anti-dilutive for all periods presented. Incremental shares related to stock options, restricted stock grants and warrants are not included in the calculation of adjusted weighted-average shares and assumed conversions for diluted earnings per share because the effect of including those shares is anti-dilutive for the year ended December 31, 2002.
NOTE 23-STOCK WARRANTS
In connection with the R&B Falcon merger, the Company assumed the then outstanding R&B Falcon stock warrants. Each warrant enables the holder to purchase 17.5 ordinary shares of the Company at an exercise price of $19.00 per share. The warrants expire on May 1, 2009. In 2001, the Company received $10.6 million and issued 560,000 ordinary shares as a result of 32,000 warrants being exercised. At December 31, 2003 there were 261,000 warrants outstanding to purchase 4,567,500 ordinary shares.
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TRANSOCEAN INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
NOTE 24-QUARTERLY RESULTS (UNAUDITED)
Shown below are selected unaudited quarterly data (in millions, except per share data):
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TRANSOCEAN INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
NOTE 25-SUBSEQUENT EVENTS (UNAUDITED)
IPO-In February 2004, the Company completed the IPO of TODCO, in which the Company sold 13.8 million shares of TODCO's class A common stock, representing approximately 23 percent of TODCO's total outstanding shares, at $12.00 per share. The Company received net proceeds of $155.7 million from the IPO and expects to recognize a gain of approximately $43 million in the first quarter of 2004, which represents the excess of net proceeds received over the net book value of the shares of TODCO sold in the IPO. The Company holds an approximate 77 percent interest in TODCO, represented by 46.2 million shares of class B common stock, and consolidates TODCO in its financial statements as a business segment.
The Company and TODCO entered into various agreements to set forth their respective rights and obligations relating to their businesses and effect the separation of the two companies. These agreements included a master separation agreement, tax sharing agreement, employee matters agreement, transition services agreement and registration rights agreement.
As a result of the deconsolidation of TODCO from the Company's other U.S. subsidiaries for U.S. federal income tax purposes in conjunction with the IPO, the Company expects to establish a valuation allowance against the deferred tax assets of TODCO in excess of its deferred tax liabilities. The amount of such valuation allowance will depend upon many factors, including the ultimate allocation of tax benefits between TODCO and other subsidiaries of the Company under applicable law and taxable income for calendar year 2004. The amount of the valuation allowance could be as much as or more than the gain on the sale of the TODCO shares in the IPO discussed above.
In conjunction with the closing of the TODCO IPO, TODCO granted nonvested restricted stock and stock options to certain of its employees under its long-term incentive plan and certain of these awards vested at the time of grant. In accordance with the provisions of SFAS 123, TODCO expects to recognize as compensation expense approximately $17.0 million over the vesting periods of the awards. The Company expects TODCO will recognize approximately $6.0 million in the first quarter of 2004 as a result of the immediate vesting of certain awards. The Company also expects TODCO will amortize the remaining amount of approximately $11.0 million to compensation expense over the next three years with approximately $5.0 million over the remainder of 2004 and approximately $5.0 million and $1.0 million in 2005 and 2006, respectively. In addition, certain of TODCO's employees held options to acquire the Company's ordinary shares that were granted prior to the IPO. In accordance with the employee matters agreement, these options were modified, which resulted in the accelerated vesting of the options and the extension of the term of the options through the original contractual life. In connection with the modification of these options, TODCO will recognize approximately $1.5 million additional compensation in the first quarter of 2004.
9.5% Senior Note Redemption-In February 2004, the Company announced the redemption of the 9.5% Senior Notes due December 2008 at the make-whole premium price provided in the indenture. The redemption is expected to be completed by March 30, 2004. The face value of the bonds to be redeemed is $289.8 million. Based on interest rates at March 1, 2004, the cost to redeem these bonds is expected to be approximately $366.3 million, and the Company expects to recognize a loss on retirement of debt of approximately $24.1 million, which reflects adjustments for fair value of the debt at the R&B Falcon merger and the premium on the termination of the related interest rate swap. These amounts could vary depending upon actual interest rates. The Company expects to utilize existing cash balances, which includes proceeds from the TODCO IPO, to fund this redemption. The redemption does not affect the 9.5% Senior Notes due December 2008 of TODCO.
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ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The Company has not had a change in or disagreement with its accountants within 24 months prior to the date of its most recent financial statements or in any period subsequent to such date.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2003 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.
There has been no change in our internal controls over financial reporting that occurred during the three months ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Items 10, 11, 12, 13 and 14 is incorporated herein by reference to the Company's definitive proxy statement for its 2004 annual general meeting of shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2003. Certain information with respect to the executive officers of the Company is set forth in Item 4 of this annual report under the caption "Executive Officers of the Registrant."
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements
PAGE ---- Included in Part II of this report: Report of Independent Auditors . . . . . . . . . . . . . . . . . 53 Consolidated Statements of Operations. . . . . . . . . . . . . . 54 Consolidated Statements of Comprehensive Income (Loss) . . . . . 55 Consolidated Balance Sheets. . . . . . . . . . . . . . . . . . . 56 Consolidated Statements of Equity. . . . . . . . . . . . . . . . 57 Consolidated Statements of Cash Flows. . . . . . . . . . . . . . 58 Notes to Consolidated Financial Statements . . . . . . . . . . . 60
Financial statements of unconsolidated joint ventures are not presented herein because such joint ventures do not meet the significance test.
(2) Financial Statement Schedules
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Other schedules are omitted either because they are not required or are not applicable or because the required information is included in the financial statements or notes thereto.
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(3) Exhibits
The following exhibits are filed in connection with this Report:
NUMBER DESCRIPTION - -------------------
2.1 Agreement and Plan of Merger dated as of August 19, 2000 by and among Transocean Inc., Transocean Holdings Inc., TSF Delaware Inc. and R&B Falcon Corporation (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus dated October 30, 2000 included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)
2.2 Agreement and Plan of Merger dated as of July 12, 1999 among Schlumberger Limited, Sedco Forex Holdings Limited, Transocean Offshore Inc. and Transocean SF Limited (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus dated October 27, included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)
2.3 Distribution Agreement dated as of July 12, 1999 between Schlumberger Limited and Sedco Forex Holdings Limited (incorporated by reference to Annex B to the Joint Proxy Statement/Prospectus dated October 27, included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)
2.4 Agreement and Plan of Merger and Conversion dated as of March 12, 1999 between Transocean Offshore Inc. and Transocean Offshore (Texas) Inc. (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-4 of Transocean Offshore (Texas) Inc. filed on April 8, 1999 (Registration No. 333-75899))
2.5 Agreement and Plan of Merger dated as of July 10, 1997 among R&B Falcon, FDC Acquisition Corp., Reading & Bates Acquisition Corp., Falcon Drilling Company, Inc. and Reading & Bates Corporation (incorporated by reference to Exhibit 2.1 to R&B Falcon's Registration Statement on Form S-4 dated November 20, 1997)
2.6 Agreement and Plan of Merger dated as of August 21, 1998 by and among Cliffs Drilling Company, R&B Falcon Corporation and RBF Cliffs Drilling Acquisition Corp. (incorporated by reference to Exhibit 2 to R&B Falcon's Registration Statement No. 333-63471 on Form S-4 dated September 15, 1998)
3.1 Memorandum of Association of Transocean Sedco Forex Inc., as amended (incorporated by reference to Annex E to the Joint Proxy Statement/Prospectus dated October 30, 2000 included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)
3.2 Articles of Association of Transocean Sedco Forex Inc., as amended (incorporated by reference to Annex F to the Joint Proxy Statement/Prospectus dated October 30, 2000 included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)
3.3 Certificate of Incorporation on Change of Name to Transocean Inc. (incorporated by reference to Exhibit 3.3 to the Company's Form 10-Q for the quarter ended June 30, 2002)
4.1 Indenture dated as of April 15, 1997 between the Company and Texas Commerce Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Form 8-K dated April 29, 1997)
4.2 First Supplemental Indenture dated as of April 15, 1997 between the Company and Texas Commerce Bank National Association, as trustee, supplementing the Indenture dated as of April 15, 1997 (incorporated by reference to Exhibit 4.2 to the Company's Form 8-K dated April 29, 1997)
4.3 Second Supplemental Indenture dated as of May 14, 1999 between the Company and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company's Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-59001-99))
4.4 Third Supplemental Indenture dated as of May 24, 2000 between the Company and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on May 24, 2000)
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4.5 Fourth Supplemental Indenture dated as of May 11, 2001 between the Company and The Chase Manhattan Bank (incorporated by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001)
4.6 Form of 7.45% Notes due April 15, 2027 (incorporated by reference to Exhibit 4.3 to the Company's Form 8-K dated April 29, 1997)
4.7 Form of 8.00% Debentures due April 15, 2027 (incorporated by reference to Exhibit 4.4 to the Company's Form 8-K dated April 19, 1997)
4.8 Form of Zero Coupon Convertible Debenture due May 24, 2020 between the Company and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on May 24, 2000)
4.9 Form of 1.5% Convertible Debenture due May 15, 2021 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated May 8, 2001)
4.10 Form of 6.625% Note due April 15, 2011 (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K dated March 30, 2001)
4.11 Form of 7.5% Note due April 15, 2031 (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K dated March 30, 2001)
4.12 Officers' Certificate establishing the terms of the 6.50% Notes due 2003, 6.75% Notes due 2005, 6.95% Notes due 2008, 7.375% Notes due 2018, 9.125% Notes due 2003 and 9.50% Notes due 2008 (incorporated by reference to Exhibit 4.13 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001)
4.13 Officers' Certificate establishing the terms of the 7.375% Notes due 2018 (incorporated by reference to Exhibit 4.14 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001)
4.14 Indenture dated as of April 14, 1998, between R&B Falcon Corporation, as issuer, and Chase Bank of Texas, National Association, as trustee, with respect to Series A and Series B of each of $250,000,000 6 1/2% Senior Notes due 2003, $350,000,000 6 3/4% Senior Notes due 2005, $250,000,000 6.95% Senior Notes due 2008, and $250,000,000 7 3/8% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to R&B Falcon's Registration Statement No. 333-56821 on Form S-4 dated June 15, 1998)
4.15 First Supplemental Indenture dated as of February 14, 2002 between R&B Falcon Corporation and The Bank of New York (incorporated by reference to Exhibit 4.16 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001)
4.16 Second Supplemental Indenture dated as of March 13, 2002 between R&B Falcon Corporation and The Bank of New York (incorporated by reference to Exhibit 4.17 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001)
4.17 Indenture dated as of December 22, 1998, between R&B Falcon Corporation, as issuer, and Chase Bank of Texas, National Association, as trustee, with respect to $400,000,000 Series A and Series B 9 1/8% Senior Notes due 2003, and 9 1/2% Senior Notes due 2008 (incorporated by reference to Exhibit 4.21 to R&B Falcon's Annual Report on Form 10-K for 1998)
4.18 First Supplemental Indenture dated as of February 14, 2002 between R&B Falcon Corporation and The Bank of New York (incorporated by reference to Exhibit 4.19 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2001)
4.19 Warrant Agreement, including form of Warrant, dated April 22, 1999 between R&B Falcon and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to R&B Falcon's Registration Statement No. 333-81181 on Form S-3 dated June 21, 1999)
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4.20 Supplement to Warrant Agreement dated January 31, 2001 among Transocean Sedco Forex Inc., R&B Falcon Corporation and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000)
4.21 Registration Rights Agreement dated April 22, 1999 between R&B Falcon and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.2 to R&B Falcon's Registration Statement No. 333-81181 on Form S-3 dated June 21, 1999)
4.22 Supplement to Registration Rights Agreement dated January 31, 2001 between Transocean Sedco Forex Inc. and R&B Falcon Corporation (incorporated by reference to Exhibit 4.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000)
4.23 Exchange and Registration Rights Agreement dated April 5, 2001 by and between the Company and Goldman, Sachs & Co., as representatives of the initial purchasers (incorporated by reference to the Company's Current Report on Form 8-K dated March 30, 2001)
4.24 Note Agreement dated as of January 30, 2001 among Delta Towing, LLC, as Borrower, R&B Falcon Drilling USA, Inc., as RBF Noteholder and Beta Marine Services, L.L.C., as Beta Noteholder (incorporated by reference to Exhibit 4.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000)
+ 4.25 Revolving Credit Agreement dated December 16, 2003 among Transocean Inc., the lenders party thereto, Suntrust Bank, as administrative agent, Citibank, N.A. and Bank of America, N.A., as co-syndication agents, The Royal Bank of Scotland plc and Bank One, NA, as co-documentation agents, Wells Fargo Bank, N.A. and UBS Loan Finance LLC, as managing agents, The Bank of New York, Den Norske Bank ASA and HSBC Bank USA, as co-agents, and Citigroup Global Markets Inc. and Suntrust Capital Markets, Inc., as co-lead arrangers
10.1 Tax Sharing Agreement between Sonat Inc. and Sonat Offshore Drilling Inc. dated June 3, 1993 (incorporated by reference to Exhibit 10-(3) to the Company's Form 10-Q for the quarter ended June 30, 1993)
*10.2 Performance Award and Cash Bonus Plan of Sonat Offshore Drilling Inc. (incorporated by reference to Exhibit 10-(5) to the Company's Form 10-Q for the quarter ended June 30, 1993)
*10.3 Form of Sonat Offshore Drilling Inc. Executive Life Insurance Program Split Dollar Agreement and Collateral Assignment Agreement (incorporated by reference to Exhibit 10-(9) to the Company's Form 10-K for the year ended December 31, 1993)
*10.4 Employee Stock Purchase Plan, as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 4.4 to the Company's Registration Statement on Form S-8 (Registration No. 333-94551) filed January 12, 2000)
*10.5 First Amendment to the Amended and Restated Employee Stock Purchase Plan of Transocean Inc., effective as of January 31, 2001 (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000)
*10.6 Amended and Restated Long-Term Incentive Plan of Transocean Inc. (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended June 30,2003)
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*10.7 Form of Employment Agreement dated May 14, 1999 between J. Michael Talbert, Robert L. Long, Donald R. Ray, Eric B. Brown and Barbara S. Koucouthakis, individually, and the Company (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended June 30, 1999)
*10.8 Deferred Compensation Plan of Transocean Offshore Inc., as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999)
*10.9 Employment Matters Agreement dated as of December 13, 1999 among Schlumberger Limited, Sedco Forex Holdings Limited and Transocean Offshore Inc. (incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-8 (Registration No. 333-94551) filed January 12, 2000)
*10.10 Sedco Forex Employees Option Plan of Transocean Sedco Forex Inc. effective December 31, 1999 (incorporated by reference to Exhibit 4.5 to the Company's Registration Statement on Form S-8 (Registration No. 333-94569) filed January 12, 2000)
*10.11 Employment Agreement dated September 22, 2000 between J. Michael Talbert and Transocean Offshore Deepwater Drilling Inc. (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended September 30, 2000)
*10.12 Agreement dated October 10, 2002 by and among Transocean Inc., Transocean Offshore Deepwater Drilling Inc. and J. Michael Talbert (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated October 10, 2002)
*10.13 Employment Agreement dated September 17, 2000 between Robert L. Long and Transocean Offshore Deepwater Drilling Inc. (incorporated by reference to Exhibit 10.3 to the Company's Form 10-Q for the quarter ended September 30, 2000)
*10.14 Agreement dated May 9, 2002 by and among Transocean Offshore Deepwater Drilling Inc. and Robert L. Long (incorporated by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K dated October 10, 2002)
*10.15 Employment Agreement dated September 20, 2000 between Eric B. Brown and Transocean Offshore Deepwater Drilling Inc. (incorporated by reference to Exhibit 10.6 to the Company's Form 10-Q for the quarter ended September 30, 2000)
*10.16 Employment Agreement dated October 4, 2000 between Barbara S. Koucouthakis and Transocean Offshore Deepwater Drilling Inc. (incorporated by reference to Exhibit 10.7 to the Company's Form 10-Q for the quarter ended September 30, 2000)
*10.17 Employment Agreement dated July 15, 2002 by and among R&B Falcon Corporation, R&B Falcon Management Services, Inc. and Jan Rask (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended June 30, 2002)
*10.18 Amendment No. 1 dated December 12, 2003 to the Employment Agreement dated July 15, 2002 by and among Jan Rask, R&B Falcon Management Services, Inc. and R&B Falcon Corporation (incorporated by reference to Exhibit 10.8 to TODCO's Registration Statement No. 333-101921 on Form S-1 dated February 3, 2004)
*10.19 Consulting Agreement dated January 31, 2001 between Paul B. Loyd, Jr. and R&B Falcon Corporation (incorporated by reference to Exhibit 10.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000)
*10.20 Consulting Agreement dated December 13, 1999 between Victor E. Grijalva and Transocean Offshore Inc. (incorporated by reference to Exhibit 10.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
*10.21 Amendment to Consulting Agreement between Transocean Offshore Inc. (now known as Transocean Inc.) and Victor E. Grijalva dated October 10, 2002 (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated October 10, 2002)
*10.22 1992 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit B to Reading & Bates' Proxy Statement dated April 27, 1992)
*10.23 1995 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit 99.A to Reading & Bates' Proxy Statement dated March 29, 1995)
*10.24 1995 Director Stock Option Plan of Reading & Bates Corporation (incorporated by reference to Exhibit 99.B to Reading & Bates' Proxy Statement dated March 29, 1995)
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*10.25 1997 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit 99.A to Reading & Bates' Proxy Statement dated March 18, 1997)
*10.26 1998 Employee Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.A to R&B Falcon's Proxy Statement dated April 23, 1998)
*10.27 1998 Director Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.B to R&B Falcon's Proxy Statement dated April 23, 1998)
*10.28 1999 Employee Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.A to R&B Falcon's Proxy Statement dated April 13, 1999)
*10.29 1999 Director Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.B to R&B Falcon's Proxy Statement dated April 13, 1999)
10.30 Memorandum of Agreement dated November 28, 1995 between Reading and Bates, Inc., a subsidiary of Reading & Bates Corporation, and Deep Sea Investors, L.L.C. (incorporated by reference to Exhibit 10.110 to Reading & Bates' Annual Report on Form 10-K for 1995)
10.31 Amended and Restated Bareboat Charter dated July 1, 1998 to Bareboat Charter M. G. Hulme, Jr. dated November 28, 1995 between Deep Sea Investors, L.L.C. and Reading & Bates Drilling Co., a subsidiary of Reading & Bates Corporation (incorporated by reference to Exhibit 10.177 to R&B Falcon's Annual Report on Form 10-K for the year ended December 31, 1998)
10.32 Agreement dated as of August 31, 1991 among Reading & Bates, Arcade Shipping AS and Sonat Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.40 to Reading & Bates' Annual Report on Form 10-K for the year ended December 30, 1991)
10.33 Master Separation Agreement dated February 4, 2004 by and among Transocean Inc., Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated March 2, 2004)
10.34 Tax Sharing Agreement dated February 4, 2004 between Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated March 2, 2004)
10.35 Transition Services Agreement dated February 4, 2004 between Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K dated March 2, 2004)
10.36 Employee Matters Agreement dated February 4, 2004 by and among Transocean Inc., Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated March 2, 2004)
10.37 Registration Rights Agreement dated February 4, 2004 between Transocean Inc. and TODCO (incorporated by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated March 2, 2004)
+ 21 Subsidiaries of the Company
+ 23.1 Consent of Ernst & Young LLP
+ 24 Powers of Attorney
31.1 CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
31.2 CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
32.1 CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
32.2 CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
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- ------------------------------ *Compensatory plan or arrangement. +Filed herewith.
Exhibits listed above as previously having been filed with the Securities and Exchange Commission are incorporated herein by reference pursuant to Rule 12b-32 under the Securities Exchange Act of 1934 and made a part hereof with the same effect as if filed herewith.
Certain instruments relating to long-term debt of the Company and its subsidiaries have not been filed as exhibits since the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of each such instrument to the Commission upon request.
REPORTS ON FORM 8-K
The Company filed a Current Report on Form 8-K on October 28, 2003 (information furnished not filed) announcing the third quarter 2003 financial results.
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SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED; THEREUNTO DULY AUTHORIZED, ON MARCH 15, 2004.
TRANSOCEAN INC. By: /s/ Gregory L. Cauthen ----------------------------------- GREGORY L. CAUTHEN SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT IN THE CAPACITIES INDICATED ON MARCH 15, 2004
SIGNATURE TITLE --------- -----
/s/ J. Michael Talbert Chairman of the Board of Directors - ---------------------------------- J. MICHAEL TALBERT
/s/ Robert L. Long President and Chief Executive Officer - ---------------------------------- (Principal Executive Officer) ROBERT L. LONG
/s/ Gregory L. Cauthen Senior Vice President and Chief Financial - ---------------------------------- Officer (Principal Financial and GREGORY L. CAUTHEN Accounting Officer)
* Director - ---------------------------------- VICTOR E. GRIJALVA
* Director - ---------------------------------- ARTHUR LINDENAUER
* Director - ---------------------------------- PAUL B. LOYD, JR.
* Director - ---------------------------------- MARTIN B. MCNAMARA
* Director - ---------------------------------- ROBERTO MONTI
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SIGNATURE TITLE --------- -----
* Director - ---------------------------------- RICHARD A. PATTAROZZI
* Director - ---------------------------------- KRISTIAN SIEM
* Director - ---------------------------------- IAN C. STRACHAN
By /s/ William E. Turcotte -------------------------------- WILLIAM E. TURCOTTE (ATTORNEY-IN-FACT)
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