- -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-13926 DIAMOND OFFSHORE DRILLING, INC. (Exact name of registrant as specified in its charter)
DIAMOND OFFSHORE DRILLING, INC. FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2002 TABLE OF CONTENTS
PART I ITEM 1. BUSINESS. GENERAL Diamond Offshore Drilling, Inc., incorporated in Delaware in 1989, engages principally in the contract drilling of offshore oil and gas wells. Unless the context otherwise requires, references herein to the "Company" mean Diamond Offshore Drilling, Inc. and its consolidated subsidiaries. The Company is a leader in deep water drilling with a fleet of 46 offshore rigs and has signed a memorandum of agreement to purchase an additional offshore rig. The fleet currently consists of 31 semisubmersibles, 14 jack-ups and one drillship. THE FLEET The Company's large, diverse fleet, which includes some of the most technologically advanced rigs in the world, enables it to offer a broad range of services worldwide in various markets, including the deep water market, the harsh environment market, the conventional semisubmersible market and the jack-up market. Semisubmersibles. The Company owns and operates 31 semisubmersibles. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a "semi-submerged" position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles are typically anchored in position and remain stable for drilling in the semi-submerged floating position due in part to their wave transparency characteristics at the water line. Semisubmersibles can also be held in position through the use of a computer controlled thruster (dynamic-positioning) system to maintain the rig's position over a drillsite. Three semisubmersible rigs in the Company's fleet have this capability. The Company owns and operates eight high specification semisubmersibles. These semisubmersibles are larger than many other semisubmersibles, are capable of working in water depths of 3,500 feet or greater or in harsh environments and have other advanced features. As of February 3, 2003, six of the eight high specification semisubmersibles were located in the Gulf of Mexico, the Ocean Alliance was working offshore Brazil and the Ocean Baroness was offshore Singapore undergoing modifications as part of a 400 day contract offshore Indonesia. The Ocean Rover was in a shipyard in Singapore undergoing an upgrade to high specification capabilities. Completion of this upgrade, expected in the third quarter of 2003, will increase the number of high specification rigs to nine. See "--Fleet Enhancements." The Company owns and operates 22 other semisubmersibles which operate in maximum water depths up to 3,500 feet. The diverse capabilities of many of these semisubmersibles enable them to provide both shallow and deep water service in the U.S. and in other markets outside the U.S. As of February 3, 2003, ten of these semisubmersibles were located in the Gulf of Mexico; four were located in the North Sea; three were located offshore Brazil; two were located offshore Africa; and one each was located offshore Vietnam, Australia, and New Zealand. Six of the Company's 22 other semisubmersible rigs have been cold stacked. When the Company anticipates that a rig will be idle for an extended period of time, it cold stacks the rig by ceasing to actively market the rig and eliminates all expenditures associated with keeping the rig ready to go to work. Jack-ups. The Company owns 14 jack-ups. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. The Company's jack-ups are used extensively for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is principally determined by the length of the rig's legs. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues until the hull is elevated above the surface of the water. After completion of 3
drilling operations, the hull is lowered until it rests in the water and then the legs are retracted for relocation to another drillsite. As of February 3, 2003, twelve of the Company's jack-up rigs were located in the Gulf of Mexico. Of these jack-up rigs in the Gulf of Mexico, seven are independent-leg cantilevered rigs, two are mat-supported cantilevered rigs, two are independent-leg slot rigs and one is a mat-supported slot rig. One of the independent-leg slot rigs was in a shipyard in Brownsville, Texas for installation of a cantilever package which is expected to be completed in April 2003. Both of the Company's internationally based jack-ups are independent-leg cantilevered rigs; one was located offshore Indonesia while the other one was in a Singapore shipyard undergoing an upgrade. One jack-up has been cold stacked. Drillship. Drillships, which are typically self-propelled, are positioned over a drillsite through the use of either an anchoring system or a dynamic-positioning system similar to those used on certain semisubmersible rigs. Deep water drillships compete in many of the same markets as do high specification semisubmersible rigs. The Company has one drillship, the Ocean Clipper, which is located offshore Brazil. Fleet Enhancements. The Company's strategy is to maximize utilization and dayrates by economically upgrading its fleet to meet customer demand for advanced, efficient, high-tech rigs, particularly deepwater semisubmersibles. Since 1995, the Company has increased the number of semisubmersibles capable of operating in 3,500 feet of water or greater, from three to ten (eight of which are high specification units), primarily by upgrading its existing fleet. Four of these upgrades were to its Victory-class semisubmersible rigs; most recently the Ocean Baroness which was completed in early 2002 at an approximate cost of $169 million. The design of the Company's Victory-class semisubmersible rigs with its cruciform hull configurations, long fatigue-life and advantageous stress characteristics, makes this class of rig particularly well-suited for significant upgrade projects. The upgrade of the Ocean Rover, the fifth in a series of Victory-class upgrades, began in January 2002. Once complete, the Ocean Rover will be the Company's ninth high specification semisubmersible unit. The converted rig will be able to operate in 7,000-foot water depths on a stand alone basis. Water depths in excess of 7,000 feet should be achievable utilizing augmented mooring systems on a case by case basis. The upgrade is estimated to cost approximately $200 million with approximately $119.1 million spent project-to-date through December 31, 2002. The upgrade is expected to take 19 months to complete with delivery estimated in the third quarter of 2003. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources" in Item 7 of this report. In 2002 the Company began a two year program to expand the capabilities of its jack-up fleet by significantly upgrading six of its 14 jack-up rigs at a total estimated cost of $100 million. The Ocean Titan and Ocean Tower, both 350-foot water depth capability independent-leg slot rigs, are to have cantilever packages installed. The cantilever systems enable a rig to cantilever or extend its drilling package over the aft end of the rig. This is particularly important when attempting to drill over existing platforms. Cantilever rigs have historically enjoyed higher dayrates and greater utilization compared to slot rigs. The Ocean Tower is in the latter stages of its upgrade with delivery expected in April 2003. The upgrade planned for the Ocean Titan is expected to commence in early 2003. The Ocean Spartan, Ocean Spur, and Ocean Heritage, each had leg extensions installed (all completed during the fourth quarter of 2002) enabling these rigs to work in water depths up to 300 feet, up from 250 feet prior to the upgrades, at a combined approximate cost of $35.7 million. The Ocean Sovereign, a 250-foot water depth independent-leg cantilever rig, is in a shipyard undergoing leg extension installations to allow the rig to work in water depths up to 300 feet. Fleet Additions. Another of the Company's business strategies is to acquire assets at depressed levels during cyclical downturns. In late 2002 the Company purchased the Ocean Vanguard for $68.5 million. The semisubmersible rig is a third-generation Bingo 3000 design rig that, in accordance with the sales agreement, has been bare-boat chartered to its previous owner. The Company anticipates the bare-boat charter will continue until mid-2003. The Company has signed a memorandum of agreement to purchase the semisubmersible drilling rig Omega for $65 million. The agreement is subject to certain conditions and is expected to be completed in the 4
first quarter of 2003. Subsequent to its purchase, the Company anticipates that the rig initially will be working offshore South Africa. The Company continues to evaluate further rig acquisition and upgrade opportunities. However, there can be no assurance whether or to what extent rig acquisitions or upgrades will continue to be made to the Company's fleet. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources" in Item 7 of this report. 5
More detailed information concerning the Company's fleet of mobile offshore drilling rigs, as of February 3, 2003, is set forth in the table below.
MARKETS The Company's principal markets for its offshore contract drilling services are the Gulf of Mexico, Europe, including principally the U.K. and Norwegian sectors of the North Sea, South America, Africa and Australia/Southeast Asia. The Company actively markets its rigs worldwide. In the past, rigs in the Company's fleet have also operated in various other markets throughout the world. See Note 16 to the Company's Consolidated Financial Statements in Item 8 of Part II of this report. The Company believes its presence in multiple markets is valuable in many respects. For example, the Company believes that its experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and in the Gulf of Mexico while production experience gained through Brazilian and North Sea operations has potential application worldwide. Additionally, the Company believes its performance for a customer in one market segment or area enables it to better understand that customer's needs and better serve that customer in different market segments or other geographic locations. OFFSHORE CONTRACT DRILLING SERVICES The Company's contracts to provide offshore drilling services vary in their terms and provisions. The Company often obtains its contracts through competitive bidding, although it is not unusual for the Company to be awarded drilling contracts without competitive bidding. Drilling contracts generally provide for a basic drilling rate on a fixed dayrate basis regardless of whether such drilling results in a productive well. Drilling contracts may also provide for lower rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond the control of the Company. Under dayrate contracts, the Company generally pays the operating expenses of the rig, including wages and the cost of incidental supplies. Dayrate contracts have historically accounted for a substantial portion of the Company's revenues. In addition, the Company has worked some of its rigs under dayrate contracts pursuant to which the customer also agrees to pay an incentive bonus based upon performance. A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well, or a group of wells (a "well-to-well contract") or a stated term (a "term contract") and may be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for a period of time as a result of a breakdown of equipment or, in some cases, due to other events beyond the control of either party. In addition, certain of the Company's contracts permit the customer to terminate the contract early by giving notice and in some circumstances may require the payment of an early termination fee by the customer. The contract term in many instances may be extended by the customer exercising options for the drilling of additional wells at fixed or mutually agreed terms, including dayrates. The duration of offshore drilling contracts is generally determined by market demand and the respective management strategies of the offshore drilling contractor and its customers. In periods of rising demand for offshore rigs, contractors typically prefer well-to-well contracts that allow contractors to profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. Conversely, in periods of decreasing demand for offshore rigs, contractors generally prefer longer term contracts to preserve dayrates at existing levels and ensure utilization, while customers prefer well-to-well contracts that allow them to obtain the benefit of lower dayrates. To the extent possible, the Company seeks to have a foundation of long-term contracts with a reasonable balance of single-well, well-to-well and short-term contracts to minimize the downside impact of a decline in the market while still participating in the benefit of increasing dayrates in a rising market, although no assurance can be given that the Company will be able to achieve or maintain such a balance from time to time. The Company, through its wholly owned subsidiary, Diamond Offshore Team Solutions, Inc. ("DOTS"), offers a portfolio of drilling services to complement the Company's offshore contract drilling business. These services include overall project management, extended well tests, and drilling and completion operations. From time to time, DOTS also selectively engages in drilling services utilizing one of the Company's rigs pursuant to turnkey or modified-turnkey contracts under which DOTS agrees to drill a well to 7
a specified depth for a fixed price. In such cases, DOTS generally is not entitled to payment unless the well is drilled to the specified depth and profitability of the contract depends upon its ability to keep expenses within the estimates used by DOTS in determining the contract price. Drilling a well under a turnkey contract, therefore, typically requires a greater cash commitment by the Company and exposes the Company to risks of potential financial losses that generally are substantially greater than those that would ordinarily exist when drilling under a conventional dayrate contract. During 2002, DOTS completed three turnkey projects in the Gulf of Mexico which resulted in an operating loss of $0.6 million. During 2001, DOTS contributed operating income of $0.6 million to the Company's consolidated results of operations primarily from the completion of one international turnkey project, which began in the last quarter of 2000, and three turnkey permanent plug and abandonment projects in the Gulf of Mexico. CUSTOMERS The Company provides offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. Several customers have accounted for 10.0% or more of the Company's annual consolidated revenues, although the specific customers may vary from year to year. During 2002, the Company performed services for 46 different customers with Petrobraspetroleo Brasileiro S A ("Petrobras"), BP, and Murphy Exploration and Production Company accounting for 19.0%, 18.9% and 10.4% of the Company's annual total consolidated revenues, respectively. During 2001, the Company performed services for 44 different customers with BP and Petrobras accounting for 21.8% and 17.3% of the Company's annual total consolidated revenues, respectively. During 2000, the Company performed services for 48 different customers with Petrobras and BP accounting for 24.6% and 20.3% of the Company's annual total consolidated revenues, respectively. During periods of low demand for offshore drilling rigs, the loss of a single significant customer could have a material adverse effect on the Company's results of operations. The Company's services in North America are marketed principally through its Houston, Texas office, with support for U.S. Gulf of Mexico activities coming from its regional office in New Orleans, Louisiana. The Company's services in other geographic locations are marketed principally from its regional offices in Aberdeen, Scotland, Perth, Western Australia and The Hague, Netherlands. Technical and administrative support functions for the Company's operations are provided by its Houston office. COMPETITION The offshore contract drilling industry is highly competitive and is influenced by a number of factors, including the current and anticipated prices of oil and natural gas, the expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling rigs. In addition, demand for drilling services remains dependent on a variety of political and economic factors beyond the Company's control, including worldwide demand for oil and natural gas, the ability of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain production levels and pricing, the level of production of non-OPEC countries and the policies of the various governments regarding exploration and development of their oil and natural gas reserves. Customers often award contracts on a competitive bid basis, and although a customer selecting a rig may consider, among other things, a contractor's safety record, crew quality, rig location and quality of service and equipment, the historical oversupply of rigs has created an intensely competitive market in which price is the primary factor in determining the selection of a drilling contractor. In periods of increased drilling activity, rig availability has, in some cases, also become a consideration, particularly with respect to technologically advanced units. The Company believes competition for drilling contracts will continue to be intense in the foreseeable future. Contractors are also able to adjust localized supply and demand imbalances by moving rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. Such movements, reactivations or a decrease in drilling activity in any major market could depress dayrates and could adversely affect utilization of the Company's rigs. See "-- Offshore Contract Drilling Services." 8
GOVERNMENTAL REGULATION The Company's operations are subject to numerous federal, state and local laws and regulations that relate directly or indirectly to its operations, including certain regulations controlling the discharge of materials into the environment, requiring removal and clean-up under certain circumstances, or otherwise relating to the protection of the environment. For example, the Company may be liable for damages and costs incurred in connection with oil spills for which it is held responsible. Laws and regulations protecting the environment have become increasingly stringent in recent years and may, in certain circumstances, impose "strict liability" rendering a company liable for environmental damage without regard to negligence or fault on the part of such company. Liability under such laws and regulations may result from either governmental or citizen prosecution. Such laws and regulations may expose the Company to liability for the conduct of or conditions caused by others, or for acts of the Company that were in compliance with all applicable laws at the time such acts were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on the Company. The United States Oil Pollution Act of 1990 ("OPA '90"), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA '90 and such similar legislation and related regulations impose a variety of obligations on the Company related to the prevention of oil spills and liability for damages resulting from such spills. OPA '90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages. INDEMNIFICATION AND INSURANCE The Company's operations are subject to hazards inherent in the drilling of oil and gas wells such as blowouts, reservoir damage, loss of production, loss of well control, cratering or fires, the occurrence of which could result in the suspension of drilling operations, injury to or death of rig and other personnel and damage to or destruction of the Company's, the Company's customer's or a third party's property or equipment. Damage to the environment could also result from the Company's operations, particularly through oil spillage or uncontrolled fires. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. The Company has insurance coverage and contractual indemnification for certain risks, but there can be no assurance that such coverage or indemnification will adequately cover the Company's loss or liability in many circumstances or that the Company will continue to carry such insurance or receive such indemnification. In December 2002 the Company renewed its Hull and Machinery insurance policy. The Company's retention of liability for property damage increased at the time of renewal from approximately $0.2 million per incident to between $1.0 million and $2.5 million per incident, depending on the value of the equipment, with an aggregate annual deductible of $5.0 million. In addition, the Company retained 10% of its insured liability. OPERATIONS OUTSIDE THE UNITED STATES Operations outside the United States accounted for approximately 55.5%, 37.3% and 45.4% of the Company's total consolidated revenues for the years ended December 31, 2002, 2001 and 2000, respectively. The Company's non-U.S. operations are subject to certain political, economic and other uncertainties not encountered in U.S. operations, including risks of war and civil disturbances (or other risks that may limit or disrupt markets), expropriation and the general hazards associated with the assertion of national sovereignty over certain areas in which operations are conducted. No prediction can be made as to what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The Company's operations outside the United States may also face the additional risk of fluctuating currency values, hard currency shortages, controls of currency exchange and repatriation of income or capital. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Industry Conditions" and "-- Other -- Currency Risk" in Item 7 of this report and Note 16 to the Company's Consolidated Financial Statements in Item 8 of Part II of this report. 9
EMPLOYEES As of December 31, 2002, the Company had approximately 3,766 workers, including international crew personnel furnished through independent labor contractors. The Company has experienced satisfactory labor relations and provides comprehensive benefit plans for its employees. The Company does not currently consider the possibility of a shortage of qualified personnel to be a material factor in its business. ACCESS TO COMPANY FILINGS Access to the Company's filings of its annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), with the United States Securities and Exchange Commission ("SEC") may be obtained through the Company's website (http://www.diamondoffshore.com). The Company's website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably practicable after the Company has electronically filed such material with the SEC. The contents of the Company's website are not, and shall not be deemed to be, incorporated into this report. ITEM 2. PROPERTIES. The Company owns an eight-story office building containing approximately 182,000-net rentable square feet on approximately 6.2 acres of land located in Houston, Texas, where the Company has its corporate headquarters, a 18,000 square foot building and 20 acres of land in New Iberia, Louisiana, for its offshore drilling warehouse and storage facility, and a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for its North Sea operations. Additionally, the Company currently leases various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Scotland, Vietnam, Singapore, Netherlands and Norway to support its offshore drilling operations. ITEM 3. LEGAL PROCEEDINGS. Not applicable. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Not applicable. 10
EXECUTIVE OFFICERS OF THE REGISTRANT In reliance on General Instruction G (3) to Form 10-K, information on executive officers of the Registrant is included in this Part I. The executive officers of the Company are elected annually by the Board of Directors to serve until the next annual meeting of the Board of Directors, or until their successors are duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office. Information with respect to the executive officers of the Company is set forth below.
PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. PRICE RANGE OF COMMON STOCK The Company's common stock is listed on the New York Stock Exchange ("NYSE") under the symbol "DO." The following table sets forth, for the calendar quarters indicated, the high and low closing prices of common stock as reported by the NYSE.
ITEM 6. SELECTED FINANCIAL DATA. The following table sets forth certain historical consolidated financial data relating to the Company. The selected consolidated financial data are derived from the financial statements of the Company as of and for the periods presented. The selected consolidated financial data below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 and the Company's Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion should be read in conjunction with the Company's Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report. RESULTS OF OPERATIONS General Revenues. The Company's revenues vary based upon demand, which affects the number of days the fleet is utilized and the dayrates earned. When a rig is idle, generally no dayrate is earned and revenues will decrease as a result. Revenues can also increase or decrease as a result of the acquisition or disposal of rigs. In order to improve utilization or realize higher dayrates, the Company may mobilize its rigs from one market to another. During periods of mobilization, however, revenues may be adversely affected. As a response to changes in demand, the Company may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues, respectively. Revenues from dayrate drilling contracts are recognized currently. The Company may receive lump-sum payments in connection with specific contracts. Such payments are recognized as revenues over the term of the related drilling contract. Mobilization revenues, less costs incurred to mobilize an offshore rig from one market to another, are recognized over the primary term of the related drilling contract. Revenues from offshore turnkey drilling contracts are accrued to the extent of costs until the specified turnkey depth and other contract requirements are met. Income is recognized on the completed contract method. Provisions for future losses on turnkey contracts are recognized when it becomes apparent that expenses to be incurred on a specific contract will exceed the revenue from that contract. Revenues from reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of the customer in accordance with a contract or agreement are recorded for the gross amount billed to the customer, as "Revenues related to reimbursable expenses" in the Consolidated Statements of Income. Prior to 2002 and the guidance provided by the Emerging Issues Task Force ("EITF") 01-14 "Income Statement Characterization of Reimbursements Received for "Out-of-Pocket" Expense Incurred," the Company accounted for reimbursements, in most instances, as a reduction of expenses incurred. All comparative periods presented have been reclassified to comply with this guidance. Operating Income. Operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Operating expenses generally are not affected by changes in dayrates and may not be significantly affected by fluctuations in utilization. For instance, if a rig is to be idle for a short period of time, the Company may realize few decreases in operating expenses since the rig is typically maintained in a prepared state with a full crew. In addition, when a rig is idle, the Company is responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically a cost of the operator under drilling contracts. However, if the rig is to be idle for an extended period of time, the Company may reduce the size of a rig's crew and take steps to "cold stack" the rig, which lowers expenses and partially offsets the impact on operating income. The Company recognizes as operating expenses activities such as inspections, painting projects and routine overhauls, which meet certain criteria, that maintain rather than upgrade its rigs. These expenses vary from period to period. Costs of rig enhancements are capitalized and depreciated over the expected useful lives of the enhancements. Increased depreciation expense decreases operating income in periods subsequent to capital upgrades. Critical Accounting Estimates The Company's significant accounting policies are included in Note 1 of its Notes to Consolidated Financial Statements in Item 8 of this report. Management's judgments, assumptions and estimates are inherent in the preparation of the Company's financial statements and the application of its significant accounting policies. The Company believes that its most critical accounting estimates are as follows: Property, Plant and Equipment. Drilling and other property and equipment is carried at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which 14
meet certain criteria, are capitalized. Depreciation is amortized on the straight-line method over the remaining estimated useful lives. Management makes judgments, assumptions and estimates regarding capitalization, useful lives and salvage values. Changes in these assumptions could produce results that differ from those reported. The Company also evaluates its property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Management's assumptions are an inherent part of an asset impairment evaluation and the use of different assumptions could produce results that differ from those reported. Personal Injury Claims. The Company's retention of liability for personal injury claims, which primarily results from Jones Act liability in the Gulf of Mexico, is $0.5 million per claim with an aggregate annual deductible of $1.5 million. The Company estimates its liability for personal injury claims based on the existing facts and circumstances in conjunction with historical experience regarding past personal injury claims. Eventual settlement or adjudication of these claims could differ significantly from the estimated amounts. 15
YEARS ENDED DECEMBER 31, 2002 AND 2001 Comparative data relating to the Company's revenues and operating expenses by equipment type are listed below (eliminations offset (i) dayrate revenues earned when the Company's rigs are utilized in its integrated services and (ii) intercompany expenses charged to rig operations). Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings.
the overall decrease in revenue. The Ocean America was idle for approximately five months during 2002 but worked most of 2001. In 2002 the Ocean Star and the Ocean Victory spent three and one-half months and two months, respectively, in a shipyard for inspections and repairs but both worked all of 2001. Revenues generated by the Ocean Baroness, which began operations in mid-March 2002 after completing an upgrade to high specification capabilities, partially offset the overall decline in revenue for the year ended December 31, 2002 by $35.7 million. Contract Drilling Expense. Contract drilling expense for high specification floaters during the year ended December 31, 2002 increased $29.3 million from the same period in 2001. Operating expenses for the Ocean Baroness added $16.7 million to 2002 contract drilling expense and included costs incurred in connection with the recovery of its marine riser, net of insurance recoveries, as well as its normal operating costs. Shipyard inspections and repairs of the Ocean Star, Ocean Victory, and the Ocean Quest in 2002 resulted in an increase in expenses of $4.9 million. Higher Brazilian customs fees in 2002 for the importation of spare parts and supplies for the Ocean Alliance and the Ocean Clipper added $1.3 million to operating costs. Repairs to the Ocean America and boat and fuel costs while the rig was idle, contributed an additional $1.0 million to 2002 contract drilling expenses. The 2001 recognition of a $1.8 million revision to an estimated insurance deductible for the Ocean Clipper, which lowered costs in 2001, also contributed to the higher comparative costs in 2002. Other Semisubmersibles. Revenues. Revenues from other semisubmersibles decreased $60.4 million from the year ended December 31, 2001 to the same period of 2002. Lower utilization accounted for $38.4 million of the decrease, dropping to 61% for the year ended December 31, 2002 from 70% for the same period in 2001. The Ocean Voyager and the Ocean Endeavor have both been cold stacked since March 2002 while both of these rigs worked the majority of 2001. The Ocean New Era was idle or cold stacked all of 2002 but worked almost half of 2001. During part of 2002 the Ocean Worker was in a shipyard for inspection and repairs and the Ocean Saratoga was in a shipyard for repairs. Both of these rigs worked most of 2001. Improved utilization for the Ocean Bounty, which operated most of 2002 compared to being stacked for approximately two months in 2001, was partially offsetting. Lower overall average dayrates contributed $22.0 million to the decrease in other semisubmersibles revenue. However, the average operating dayrate for this fleet increased to $67,900 during the year ended December 31, 2002 from $66,900 during the same period of 2001. This occurred because several of the rigs that were contracted at lower dayrates in 2001 were stacked throughout parts of 2002. Consequently, the average operating dayrate rose in 2002 for the working rigs in this class. Significant changes in average operating dayrates included the Ocean Worker and the Ocean Whittington which decreased approximately $77,900 and $30,700 respectively, and the Ocean Guardian and Ocean Princess which increased approximately $28,300 and $20,800, respectively. Contract Drilling Expense. Contract drilling expense for other semisubmersibles was $12.1 million lower in 2002 than in 2001. The Ocean Endeavor and the Ocean Voyager, which have been cold stacked since March 2002, contributed cost savings of $14.5 million while the Ocean New Era and the Ocean Ambassador, which were both stacked with reduced crews for most of 2002, lowered costs by $4.3 million. Contract drilling expenses for the Ocean Whittington were lower by $2.8 million in 2002 when compared to 2001 resulting from its inspection, repairs and preparation for its mobilization to Namibia in December 2001. Partially offsetting was an increase in 2002 of contract drilling expenses for the Ocean Nomad of $3.0 million. In 2001 the rig was in a shipyard for an upgrade which resulted in lower operating costs. In addition, inspection and repairs to the Ocean Worker added $2.1 million to contract drilling expense in 2002. Also, higher Brazilian customs fees in 2002 for the importation of spare parts and supplies for the Ocean Yatzy, Ocean Yorktown and the Ocean Winner resulted in a $1.4 million increase in contract drilling expense. 17
Jack-Ups. Revenues. Revenues from jack-ups during the year ended December 31, 2002 decreased $75.1 million from the same period of 2001. A reduction in the average operating dayrate from $41,000 in 2001 to $27,300 in 2002, contributed $48.6 million to the overall revenue decline. All of the Gulf of Mexico jack-up rigs experienced lower average operating dayrates in 2002. Only the Ocean Heritage, a rig which operated offshore Indonesia and Australia, saw a significant improvement in its dayrate, from $34,700 in 2001 to $85,100 in 2002. Revenues decreased $26.5 million as a result of a decline in utilization to 71% in 2002 from 83% in 2001. Utilization was down for the Ocean Champion, which was idle and/or cold stacked throughout 2002, and for the Ocean Spartan, Ocean Spur, Ocean Tower and the Ocean Heritage all of which spent time in shipyards during 2002 undergoing upgrades. All five of these jack-ups worked most of 2001. Higher utilization in 2002 for the Ocean Sovereign, which worked all of 2002 but spent most of 2001 in a shipyard for repairs, was partially offsetting. Contract Drilling Expense. Contract drilling expense for jack-ups decreased $17.7 million in 2002 compared to 2001. Contract drilling expense was $8.2 million lower in 2002 for the Ocean Spartan, Ocean Spur, Ocean Tower and the Ocean Heritage as a result of a reduction in operating costs while these rigs were in shipyards undergoing upgrades. Contract drilling expense was $8.0 million lower for the Ocean Champion which was idle and/or cold stacked during all of 2002 but worked most of 2001. Increased contract drilling expense during the first half of 2001 from repairs to the Ocean Nugget, the Ocean Crusader, and the Ocean Summit also contributed to the lower comparative costs in 2002. Higher expenses for the Ocean Heritage in 2002, primarily due to the mobilization of the rig from Indonesia to Australia and higher labor costs in Australia, were partially offsetting. Integrated Services. Operating income for integrated services decreased $1.2 million during the year ended December 31, 2002 compared to the same period of 2001 resulting from the difference in type and magnitude of projects during those periods. During 2002, an operating loss of $0.6 million resulted primarily from an unprofitable turnkey project in the Gulf of Mexico. During the same period in 2001, operating income of $0.6 million was primarily due to the completion of one international turnkey project and three turnkey permanent plug and abandonment projects in the Gulf of Mexico. Other. Other operating income of $7.3 million for the year ended December 31, 2002 increased $9.3 million from the same period in 2001. The increase resulted primarily from a $5.9 million reimbursement of prior year foreign income tax to be received by the Company from its customers and relates to a tax settlement made between the Company and the Norwegian tax authorities in December 2002. The corresponding income tax expense is reflected in "Income tax expense" in the Company's Consolidated Statements of Income. Also contributing to the higher Other operating income in 2002 was a $2.4 million reversal of an accrual made in a prior year for personal injury claims and the elimination of a $1.0 million reserve for inventory obsolescence, from prior years, that was deemed no longer necessary. Reimbursables, net. Revenues related to reimbursable items that the Company purchases and/or services it performs at the request of its customers offset by the related expenditures for these items were $2.5 million in 2002 compared to $2.8 million in 2001. Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2002 increased $7.5 million over the same period of 2001. Higher 2002 depreciation resulted primarily from depreciation for 2002 capital 18
additions and additional depreciation for the Ocean Baroness, which completed its deepwater upgrade and began operations in March 2002. The suspension of goodwill amortization on January 1, 2002 partially offset this increase. Goodwill amortization during the year ended December 31, 2001 was $3.3 million. See Note 1 "-- Goodwill" and Note 6 to the Company's Consolidated Financial Statements in Item 8 of Part II of this report. General and Administrative Expense. General and administrative expense was $3.5 million higher in 2002 than in the comparable period in 2001 primarily due to higher personnel costs and professional expenses, including legal fees, tax and accounting fees and security consulting. Interest Income. Interest income of $29.8 million for the year ended December 31, 2002 decreased $18.9 million from $48.7 million for the same period in 2001 primarily due to a reduction in marketable securities held and lower interest rates earned on cash and marketable securities in 2002 compared to 2001. Interest Expense. Interest expense of $23.6 million for the year ended December 31, 2002 was $14.5 million lower than in the same period of 2001 primarily due to a $11.9 million pre-tax charge that resulted from the April 2001 redemption of the Company's 3.75% Convertible Subordinated Notes Due 2007 ("3.75% Notes"). In addition, the Company's weighted average interest rate in 2002 was lower than in 2001 resulting from the redemption in 2001 of the 3.75% Notes and the issuance of the 1.5% Convertible Senior Debentures due 2031 (the "1.5% Debentures") on April 11, 2001. Interest expense was also lower in 2002 than in 2001 due to more interest capitalized to rig upgrades in 2002. Interest capitalized to rig upgrades was $2.9 million in 2002 compared to $2.6 million in 2001. In 2002 interest was capitalized to the Ocean Baroness during the final three months of its upgrade and during the entire year for the Ocean Rover. See "-- Liquidity." Gain on Sale of Marketable Securities. Gain on sale of marketable securities of $36.5 million for the year ended December 31, 2002 increased $9.4 million from $27.1 million for the same period in 2001. Other Income and Expense (Other, net). Other income of $1.5 million for the year ended December 31, 2002 increased $4.2 million from other expense of $2.7 million for the same period in 2001. Other income in 2002 included a $1.1 million pre-tax gain on foreign exchange forward contracts. See Note 4 "-- Derivative Financial Instruments -- Forward Exchange Contracts" to the Company's Consolidated Financial Statements in Item 8 of Part II of this report. Other expense in 2001 included a $10.0 million reserve established for a class action lawsuit which was ultimately settled in June 2002 and was partially offset by a $7.3 million receipt for the settlement of an unrelated lawsuit. Income Tax Expense. Income tax expense of $33.7 million for the year ended December 31, 2002 decreased $53.0 million from $86.7 million for the same period in 2001 primarily as a result of a $164.3 million decrease in "Income before income tax expense" in 2002. The annual effective tax rate increased from 33% in 2001 to 35% in 2002. In 2001 the Company made the decision to indefinitely reinvest part of the earnings of its UK subsidiaries and the annual effective rate for the year 2001 reflects this decision. The effect of the indefinite reinvestment of the UK earnings in 2002 was to lower the annual effective tax rate but this decline was more than offset by prior year foreign tax expense recorded in 2002, primarily $5.9 million for a Norwegian income tax settlement. See "--Other." 19
YEARS ENDED DECEMBER 31, 2001 AND 2000 Comparative data relating to the Company's revenues and operating expenses by equipment type are listed below (eliminations offset (i) dayrate revenues earned when the Company's rigs are utilized in its integrated services and (ii) intercompany expenses charged to rig operations). Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings.
Improved utilization for high specification floaters in 2001 accounted for $11.4 million of the increase in revenues over 2000. Utilization for this class of rig rose to 95% in 2001 from 88% in 2000 (excluding the Ocean Confidence). The greatest improvements were from the Ocean Quest, which was idle for almost five months longer in 2000 than in 2001, and the Ocean Clipper, which had less downtime for repairs during 2001. Contract Drilling Expense. Contract drilling expense for high specification floaters during the year ended December 31, 2001 increased $22.6 million from the same period in 2000. This increase resulted primarily from costs incurred by the Ocean Confidence ($21.1 million) which began operations in January 2001. Other Semisubmersibles. Revenues. Revenues from other semisubmersibles increased $64.4 million during the year ended December 31, 2001 from the same period in 2000 primarily due to higher average operating dayrates. Average dayrates increased to $66,900 per day in 2001 from $61,300 in 2000 and contributed an additional $52.3 million to 2001 revenues. The greatest dayrate increases were for the Ocean General, Ocean Nomad, Ocean Guardian and the Ocean Bounty. However, lower average operating dayrates in 2001 for the Ocean Princess and the Ocean Whittington were partially offsetting. Improvements in utilization contributed $12.2 million to revenue during the year ended December 31, 2001 compared to the same period in 2000. Overall, utilization increased to 70% in 2001 from 61% in 2000. The Ocean Epoch spent most of 2000 in a shipyard for water depth capability and variable deckload upgrades while it worked most of 2001. The Ocean Voyager, Ocean New Era and the Ocean Guardian were all idle approximately one half-year longer in 2000 compared to 2001. However, utilization decreased in 2001 for the Ocean Whittington and the Ocean Yorktown. The Ocean Whittington was stacked for almost four months in 2001 for a special survey, repairs and preparation for its December 2001 mobilization to Namibia. The Ocean Yorktown was in a shipyard for over two months in 2001 for inspection and upgrades in connection with new contract requirements. Contract Drilling Expense. Contract drilling expense for other semisubmersibles during the year ended December 31, 2001 increased $11.0 million from the same period in 2000. Rig expenses increased $5.2 million for the Ocean Epoch in 2001 from the same period in 2000 when most of the expenses were associated with the rig's upgrade and were capitalized. The Ocean New Era's expenses increased $3.0 million in 2001 as it operated during six months of 2001 but was stacked all of 2000. An additional $2.8 million in contract drilling expense resulted from the mobilization of the Ocean Whittington from Brazil to Namibia in late 2001. Also, contract drilling expense increased $2.6 million from the 2001 inspections of the Ocean Yorktown, Ocean Whittington, Ocean Yatzy and Ocean Princess and $1.8 million from higher Brazilian customs fees in 2001. Partially offsetting these cost increases, contract drilling expenses were $5.5 million lower in 2001 due to Ocean Lexington and Ocean Saratoga repair projects in 2000 not repeated in 2001. Jack-Ups. Revenues. Revenues from jack-ups during the year ended December 31, 2001 increased $55.6 million from 2000. All of the Company's jack-up rigs experienced higher average operating dayrates with the overall average operating dayrate improving from $26,000 in 2000 to $41,000 in 2001. This 58% improvement in average operating dayrates resulted in an increase of $63.6 million in revenues. Lower utilization in 2001 than in 2000 partially offset the revenue improvements that resulted from the higher average operating dayrates. Revenue declined $8.0 million in 2001 as a result of 83% utilization in 2001 compared to 89% in 2000. This decrease in utilization was primarily due to inspection and repairs of the Ocean Summit, Ocean Sovereign, Ocean Crusader and Ocean Champion during 2001. In addition, the Ocean Nugget was stacked for over one-half of 2001 and the Ocean King was in a shipyard for part of the last two months of 2001 for inspections and repairs. All of these rigs worked most of 2000. Utilization improvements which were partially offsetting resulted from the Ocean Heritage and the Ocean Tower. The Ocean Heritage, which worked all of 2001, spent part of 2000 in a shipyard for repairs while the Ocean Tower worked most of 2001 but was cold stacked for part of 2000. 21
Contract Drilling Expense. Contract drilling expense increased $11.1 million for jack-ups during the year ended December 31, 2001 compared to the same period in 2000. Operating costs were higher in 2001 for the Ocean Champion, Ocean Summit and Ocean Crusader due to inspection and repairs. In addition, rig expenses were higher for the Ocean Tower which operated during most of 2001, but was cold stacked during part of 2000. Contract drilling expense decreased in 2001 for the Ocean Heritage due to major repairs in 2000. Integrated Services. Operating income for integrated services decreased as a result of the difference in number, type and magnitude of projects during 2001 compared to 2000. During 2001, integrated services contributed operating income of $0.6 million to the Company's consolidated results of operations primarily due to the completion of one international turnkey project, which began in the last quarter of 2000, and three turnkey permanent plug and abandonment projects in the Gulf of Mexico. During 2000, DOTS contributed operating income of $1.0 million to the Company's consolidated results of operations primarily from the completion of four turnkey projects in the Gulf of Mexico, one international turnkey project and integrated services provided in Aberdeen, Scotland. Other. Other operating expense of $2.0 million for the year ended December 31, 2001 decreased $4.1 million from the same period in 2000. Other operating expense in 2001, primarily for rig crew training and maintenance and repair of spare equipment, was lower by approximately $0.9 million compared to similar expenditures in 2000. Other operating expense in 2000 also included $1.8 million for settlements with the Company's customers related to prior years' disputes including compliance audit findings. Reimbursables, net. Revenues related to reimbursable items that the Company purchases and/or services it performs at the request of its customers offset by the related expenditures for these items were $2.8 million in 2001 compared to $2.7 million in 2000. Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2001 increased $24.4 million over the prior year. Higher depreciation in 2001 resulted primarily from depreciation for the Ocean Confidence, which completed its conversion from an accommodation vessel to a high specification semisubmersible drilling unit and commenced operations in January 2001. Also, 2001 depreciation was higher due to an increase of $35.2 million in ordinary capital expenditures compared to 2000. General and Administrative Expense. General and administrative expense increased $1.7 million in 2001 compared to the same period in 2000 primarily due to an increase in personnel costs, travel and professional expenses. Gain on Sale of Marketable Securities. Gain on sale of marketable securities of $27.1 million for the year ended December 31, 2001 increased $25.0 million from $2.1 million for the same period in 2000. Gain on Sale of Assets Gain on sale of assets of $0.3 million for the year ended December 31, 2001 decreased $14.0 million from $14.3 million for the same period in 2000 primarily due to the January 2000 sale of the Company's jack-up drilling rig, Ocean Scotian which had been cold stacked offshore The Netherlands prior to the sale. The rig was sold for $32.0 million in cash which resulted in a gain of $13.9 million ($9.0 million after tax). 22
Interest Income. Interest income of $48.7 million for the year ended December 31, 2001 decreased $0.8 million from $49.5 million for the same period in 2000. This decrease resulted from the Company's investment in marketable securities with lower interest rates in 2001 compared to 2000 and was partially offset by the investment of higher cash balances generated by the sale of the Company's 1.5% convertible senior debentures due 2031 (the "1.5% Debentures") on April 11, 2001, the sale of the Company's zero coupon convertible debentures due 2020 (the "Zero Coupon Debentures") on June 6, 2000 and the December 2000 lease-leaseback of the Ocean Alliance. Cash balances available for investment were partially reduced as a result of the Company's redemption of all of its outstanding 3.75% Notes on April 6, 2001. See "-- Liquidity." Interest Expense. Interest expense of $38.1 million for the year ended December 31, 2001 increased $27.8 million from $10.3 million for the same period in 2000 primarily due to the $11.9 million pre-tax loss from the April 2001 redemption of the Company's 3.75% Notes and less interest capitalized due to the completion of the Ocean Confidence conversion ($2.6 million interest capitalized in 2001 compared to $13.8 million interest capitalized in 2000). In addition, interest expense increased with the issuance of the Zero Coupon Debentures on June 6, 2000, the issuance of the 1.5% Debentures on April 11, 2001 and interest expense related to the December 2000 lease-leaseback of the Ocean Alliance. This increase was partially offset by a reduction in interest expense resulting from the Company's redemption of all of its outstanding 3.75% Notes on April 6, 2001. See "-- Liquidity." Other Income and Expense (Other, net). Other expense of $2.7 million for the year ended December 31, 2001 increased $0.7 million from other expense of $2.0 million for the same period in 2000. This increase resulted primarily from a $10.0 million reserve for the then pending litigation in connection with a proposed class action suit filed against major offshore drilling companies partially offset by a $7.3 million receipt of a settlement payment for resolved litigation. Income Tax Expense. Income tax expense of $86.7 million for the year ended December 31, 2001 increased $48.1 million from $38.6 million in 2000 primarily as a result of the increase in "Income before income taxes" of $149.6 million in 2001, which was partially offset by a lower effective income tax rate in 2001. The lower effective income tax rate in 2001 was primarily due to the Company's decision to permanently reinvest part of the earnings of its U.K. subsidiaries. INDUSTRY CONDITIONS The Company operates in an industry that is historically extremely competitive and deeply cyclical. The demand for its services has traditionally been highly correlated with the price of oil and natural gas. However, the rise in product prices that began in late 2001 and continued throughout 2002 did not yield the expected improvements in utilization and dayrates for the Company's equipment. The Company believes that its customers have been reluctant to increase offshore drilling expenditures or to commit to long term contracts due to uncertainties about the sustainability of current product prices as well as general uncertainties surrounding the state of the economy and the effects of a possible military conflict in Iraq. In the Gulf of Mexico, well-to-well contracts are the norm for the Company's deep water semisubmersible fleet, its mid-water semisubmersible fleet and its jack-up fleet. With limited to no backlog of work for these fleets, the Company does not anticipate any significant improvement in utilization or rates until its customers regain confidence in the sustainability of product prices. 23
Absent a change in its customers' perception of the overall energy market, the Company anticipates that the international markets in which it operates will remain relatively flat and consequently expects utilization and rates for its equipment in these markets to remain relatively unchanged. LIQUIDITY At December 31, 2002, the Company's cash and marketable securities totaled $812.5 million, down from $1.1 billion at December 31, 2001. Cash of $199.1 million generated by repurchase agreements is included at December 31, 2001. See Note 1 "-- Securities Sold Under Agreements to Repurchase" in Item 8 of Part II of this report. A discussion of the sources and uses of cash for the year ended December 31, 2002 compared to the same period in 2001 follows.
$5.2 million primarily due to the completion of the Ocean Baroness upgrade and the ongoing upgrade of the Ocean Rover. Cash provided by net investing activities increased $160.8 million in 2002 compared to 2001 from the net sale of certain of the Company's investments in marketable securities.
Company purchased 1,403,900 shares of its common stock at an aggregate cost of $37.8 million, or at an average cost of $26.90 per share. Cash provided by financing activities in 2001 consisted primarily of net proceeds of $449.1 million from the issuance of $460.0 million principal amount of the 1.5% Debentures on April 11, 2001. Contractual Cash Obligations.
2003, and the deepwater upgrade of the Ocean Baroness ($31.4 million) which was completed in March 2002. The Company expects to spend approximately $123 million for rig upgrade capital expenditures during 2003 for the completion of the Ocean Rover upgrade ($80 million) and the three remaining jack-up upgrades ($43 million). The upgrade of the Ocean Rover began in January 2002. The converted rig will be able to operate in 7,000-foot water depths on a stand alone basis. Water depths in excess of 7,000 feet should be achievable utilizing augmented mooring systems on a case by case basis. The upgrade is expected to take 19 months to complete with delivery estimated in the third quarter of 2003. The significant upgrade of the Company's semisubmersible rig, the Ocean Baroness, to high specification capabilities resulted in an enhanced version of the Company's previous Victory-class upgrades. The upgrade was similar to the upgrade being performed on the Ocean Rover. The Company took delivery of the Ocean Baroness in January 2002. The approximate cost of the upgrade was $169.0 million. In 2002 the Company began a two year program to expand the capabilities of its jack-up fleet by significantly upgrading six of its 14 jack-up rigs. The Company expects to spend approximately $100 million on the program, and as of December 31, 2002, has spent $57 million. The Ocean Titan and Ocean Tower, both 350-foot water depth capability independent-leg slot rigs, were to have cantilever packages installed. The cantilever systems enable a rig to cantilever or extend its drilling package over the aft end of the rig. Currently, the Ocean Tower is in the latter stages of its upgrade with delivery expected in April 2003. The upgrade planned for the Ocean Titan is expected to commence in early 2003. The Ocean Spartan, Ocean Spur, and Ocean Heritage, each had leg extensions installed (all completed during the fourth quarter of 2002) enabling these rigs to work in water depths up to 300 feet, up from 250 feet prior to the upgrades, at a combined approximate cost of $35.7 million. The Ocean Sovereign, a 250-foot water depth independent-leg cantilever rig, is currently in a shipyard undergoing leg extension installations to allow the rig to work in water depths up to 300 feet. All of the Company's upgrade projects are subject to risks of delay or cost overruns that are inherent in any large construction project. The Company has signed a memorandum of agreement to purchase the semisubmersible drilling rig Omega for $65 million. The agreement is subject to certain conditions and is expected to be completed in the first quarter of 2003. Subsequent to its purchase, the Company anticipates that the rig initially will be working offshore South Africa. The purchase of the Omega is expected to be funded from existing cash balances. During the year ended December 31, 2002, the Company spent $86.1 million in association with its ongoing rig equipment replacement and enhancement programs and to meet other corporate requirements. In addition, the Company spent $68.5 million ($67.0 million capitalized to rig equipment) for the purchase of the third-generation semisubmersible drilling rig, West Vanguard, renamed Ocean Vanguard. The Company has budgeted $111.3 million for 2003 capital expenditures associated with its ongoing rig equipment replacement and enhancement programs and other corporate requirements. INTEGRATED SERVICES The Company's wholly owned subsidiary, DOTS, from time to time, selectively engages in drilling services pursuant to turnkey or modified-turnkey contracts under which DOTS agrees to drill a well to a specified depth for a fixed price. In such cases, DOTS generally is not entitled to payment unless the well is drilled to the specified depth and other contract requirements are met. Profitability of the contract is dependent upon its ability to keep expenses within the estimates used in determining the contract price. Drilling a well under a turnkey contract therefore typically requires a greater cash commitment by the Company and exposes the Company to risks of potential financial losses that generally are substantially greater than those that would ordinarily exist when drilling under a conventional dayrate contract. DOTS also offers a portfolio of drilling services including overall project management, extended well tests, and completion operations. During 2002, DOTS had an operating loss of $0.6 million primarily from an unprofitable Gulf of Mexico turnkey project. During 2001, DOTS contributed operating income of $0.6 million to the Company's 27
consolidated results of operations primarily from the completion of one international turnkey project, which began in the last quarter of 2000, and three turnkey permanent plug and abandonment projects in the Gulf of Mexico. OTHER Currency Risk. Certain of the Company's subsidiaries use the local currency in the country where they conduct operations as their functional currency. Currency environments in which the Company has material business operations include Brazil, the U.K., Australia and Vietnam. The Company generally attempts to minimize its currency exchange risk by seeking international contracts payable in local currency in amounts equal to the Company's estimated operating costs payable in local currency with the balance of the contract payable in U.S. dollars. Because of this strategy, historically the Company has minimized its unhedged net asset or liability positions denominated in local currencies and has not experienced significant gains or losses associated with changes in currency exchange rates. At present, however, only contracts covering the Company's five rigs currently operating in Brazil are payable both in U.S. dollars and the local currency. The Company has not hedged its exposure to changes in the exchange rate between U.S. dollars and the local currencies, except in Australia for operating costs payable in the local currencies in which it operates, but it may seek to do so in the future. Currency translation adjustments are accumulated in a separate section of stockholders' equity. When the Company ceases its operations in a currency environment, the accumulated adjustments are recognized currently in results of operations. The effect on results of operations from these translation gains and losses has not been material and are not expected to have a significant effect in the future. Forward Exchange Contracts. In some instances, a foreign exchange forward contract is used to minimize the forward exchange risk. A forward exchange contract obligates the Company to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specified dates. In June 2002 the Company entered into forward contracts to purchase 50.0 million Australian dollars, 4.2 million Australian dollars to be purchased monthly from August 29, 2002 through June 26, 2003 and 3.8 million to be purchased on July 31, 2003. In July 2001 the Company entered into twelve forward contracts to purchase 3.5 million Australian dollars at each month end through July 31, 2002. ACCOUNTING STANDARDS In December 2002 the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements regarding the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. The Company accounts for stock-based employee compensation in accordance with Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees." However, the Company has adopted the provisions of SFAS No. 148 which require prominent disclosure regarding the method of accounting for stock-based employee compensation in its annual financial statements and will include such disclosure in all of its future interim financial statements. In July 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company does not expect the adoption of SFAS No. 146 to have a material impact on the Company's consolidated results of operations, financial position or cash flows. 28
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment to FASB Statement No. 13, and Technical Corrections." The rescission of SFAS No. 4 and 64 by SFAS No. 145 streamlines the reporting of debt extinguishments and requires that only gains and losses from extinguishments meeting the criteria in APB Opinion 30, "Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" would be classified as extraordinary. Thus, gains or losses arising from extinguishments that are part of a company's recurring operations would not be reported as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002 with earlier adoption encouraged. The Company adopted SFAS No. 145 in April 2002 and, accordingly, reclassified its April 2001 loss of $7.7 million, net-of-tax, from early extinguishment of debt, as a result of the Company's redemption of the outstanding 3.75% Notes, out of extraordinary items. The pre-tax loss from early extinguishment of debt of $11.9 million was reclassified to "Interest expense" and the related tax benefit was reclassified to "Income tax expense" in the Consolidated Statement of Income. See Note 1 "-- Capitalized Interest" to the Company's Consolidated Financial Statements in Item 8 of Part II of this report. In October 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 replaces SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and provides updated guidance concerning the recognition and measurement of an impairment loss for certain types of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 144 in January 2002 by the Company has not had, nor is it expected to have, a material impact on the Company's consolidated results of operations, financial position or cash flows. In August 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses financial accounting and reporting obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002 with early adoption encouraged. Adoption of SFAS No. 143 in 2003 is not expected to have a material impact on the Company's consolidated results of operations, financial position or cash flows. In June 2001 the FASB issued two new pronouncements, SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires that all business combinations be accounted for by the purchase method and applies to all business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for using the purchase method for which the date of acquisition is July 1, 2001 or later. There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 for all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company adopted SFAS No. 142 on January 1, 2002 and has suspended amortization of goodwill which was $3.3 million and $4.5 million for the years ended December 31, 2001 and 2000, respectively. SFAS No. 142 does not change the SFAS No. 109 "Accounting for Income Taxes" requirement to reduce goodwill for the excess of tax benefits not previously recognized. See Note 6 to the Company's Consolidated Financial Statements in Item 8 of Part II of this report. The adoption of SFAS No. 142 has not had, nor is it expected to have, a material impact on the Company's consolidated results of operations, financial position or cash flows. FORWARD-LOOKING STATEMENTS Certain written and oral statements made or incorporated by reference from time to time by the Company or its representatives are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words "expect," "intend," "plan," "predict," "anticipate," "estimate," "believe," "should," "could," "may," "might," "will be," "will continue," "will likely result," "project," "forecast," "budget" and similar expressions. Statements 29
by the Company in this report that contain forward-looking statements include, but are not limited to, information concerning possible or assumed future results of operations of the Company and statements about the following subjects: - future market conditions and the effect of such conditions on the Company's future results of operations (see "-- Industry Conditions"); - future uses of and requirements for financial resources, including, but not limited to, expenditures related to the upgrades of the Ocean Rover and three of the Company's jack-up rigs (see "Business -- The Fleet - Fleet Enhancements", "-- Liquidity" and "-- Capital Resources"); - interest rate and foreign exchange risk (see "Quantitative and Qualitative Disclosures About Market Risk"); - future contractual obligations (see "-- Liquidity -- Contractual Cash Obligations"); - business strategy; - growth opportunities; - competitive position; - expected financial position; - future cash flows; - future dividends; - financing plans; - budgets for capital and other expenditures; - timing and cost of completion of rig upgrades and other capital projects; - delivery dates and drilling contracts related to rig conversion and upgrade projects; - plans and objectives of management; - performance of contracts; - outcomes of legal proceedings; - compliance with applicable laws; and - adequacy of insurance or indemnification. Such statements inherently are subject to a variety of risks and uncertainties that could cause actual results to differ materially from those projected or expressed in forward-looking statements. Such risks and uncertainties include, among others, the following: - general economic and business conditions; - worldwide demand for oil and natural gas; - changes in foreign and domestic oil and gas exploration, development and production activity; - oil and natural gas price fluctuations and related market expectations; - the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing, and the level of production in non-OPEC countries; - policies of the various governments regarding exploration and development of oil and gas reserves; - advances in exploration and development technology; - the political environment of oil-producing regions; 30
- casualty losses; - operating hazards inherent in drilling for oil and gas offshore; - industry fleet capacity; - market conditions in the offshore contract drilling industry, including dayrates and utilization levels; - competition; - changes in foreign, political, social and economic conditions; - risks of international operations, compliance with foreign laws and taxation policies and expropriation or nationalization of equipment; - foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital; - risks of war, military operations, other armed hostilities, terrorist acts and embargoes; - changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness; - regulatory initiatives and compliance with governmental regulations; - compliance with environmental laws and regulations; - customer preferences; - effects of litigation; - cost, availability and adequacy of insurance; - adequacy of the Company's sources of liquidity; - risks inherent in turnkey operations, including the risk of failure to complete a well and cost overruns; - the availability of qualified personnel to operate and service the Company's drilling rigs; and - various other matters, many of which are beyond the Company's control. The risks included here are not exhaustive. Other sections of this report and the Company's other filings with the SEC include additional factors that could adversely affect the Company's business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. The Company expressly disclaims any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in the Company's expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based. 31
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The information included in this Item 7A is considered to constitute "forward-looking statements" for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Forward-Looking Statements" in Item 7 of this report. The Company's measure of market risk exposure represents an estimate of the change in fair value of its financial instruments. Market risk exposure is presented for each class of financial instrument held by the Company at December 31, 2002 and 2001 assuming immediate adverse market movements of the magnitude described below. The Company believes that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since the Company's investment portfolio is subject to change based on its portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results which may occur. Exposure to market risk is managed and monitored by senior management. Senior management approves the overall investment strategy employed by the Company and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to it. The Company may manage risk by buying or selling instruments or entering into offsetting positions. INTEREST RATE RISK The Company has exposure to interest rate risk arising from changes in the level or volatility of interest rates. The Company's investments in marketable securities are primarily in fixed maturity securities. The Company monitors its sensitivity to interest rate risk by evaluating the change in the value of its financial assets and liabilities due to fluctuations in interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of the Company's investments and the resulting effect on shareholders' equity. The analysis presents the sensitivity of the market value of the Company's financial instruments to selected changes in market rates and prices which the Company believes are reasonably possible over a one-year period. The sensitivity analysis estimates the change in the market value of the Company's interest sensitive assets and liabilities that were held on December 31, 2002 and 2001 due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant. The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes of market interest rates on the Company's earnings or shareholders' equity. Further, the computations do not contemplate any actions the Company could undertake in response to changes in interest rates. The Company's long-term debt, as of December 31, 2002 and 2001 is denominated in U.S. Dollars. The Company's debt has been primarily issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100 basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $153.8 and $154.3 million, respectively. A 100 basis point decrease would result in an increase in market value of $192.7 and $195.3 million, respectively. FOREIGN EXCHANGE RISK Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. As of December 31, 2002, the Company had contracted to purchase 50.0 million Australian dollars, 4.2 million Australian dollars to be purchased monthly from 32
August 29, 2002 through June 26, 2003 and 3.8 million to be purchased on July 31, 2003. These foreign exchange forward contracts are recorded at their fair value determined by discounting future cash flows at current forward rates. At December 31, 2002, an asset of $0.2 million reflecting the fair value of the forward contracts, was included with "Prepaid expenses and other" in the Consolidated Balance Sheet. At December 31, 2001 the Company had contracted to purchase 3.5 million Australian dollars each month through July 31, 2002. At December 31, 2001, an asset of $0.1 million reflecting the fair value of the forward contracts, was included with "Prepaid expenses and other" in the Consolidated Balance Sheet. The sensitivity analysis assumes an instantaneous 20% change in the foreign currency exchange rates versus the U.S. Dollar from their levels at December 31, 2002 and 2001, with all other variables held constant. The following table presents the Company's market risk by category (interest rates and foreign currency exchange rates):
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEPENDENT AUDITORS' REPORT Board of Directors and Stockholders Diamond Offshore Drilling, Inc. and subsidiaries Houston, Texas We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the "Company") as of December 31, 2002 and 2001, and the related consolidated statements of income, stockholders' equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Diamond Offshore Drilling, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the financial statements, in 2002 the Company changed its method of accounting for goodwill to conform to Statement of Financial Accounting Standards No. 142. Deloitte & Touche LLP Houston, Texas January 28, 2003 34
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA) ASSETS
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE DATA)
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS, EXCEPT NUMBER OF SHARES)
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (IN THOUSANDS)
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Business Diamond Offshore Drilling, Inc. (the "Company") was incorporated in Delaware on April 13, 1989. Loews Corporation ("Loews"), a Delaware corporation of which the Company had been a wholly owned subsidiary prior to the initial public offering in October 1995 (the "Common Stock Offering"), owns 53.8% of the outstanding common stock of the Company at December 31, 2002. The Company, through wholly owned subsidiaries, engages in the worldwide contract drilling of offshore oil and gas wells and is a leader in deep water drilling. Currently, the fleet is comprised of 31 semisubmersible rigs, 14 jack-up rigs and one drillship. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its subsidiaries after elimination of significant intercompany transactions and balances. Cash and Cash Equivalents and Marketable Securities Short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash are considered cash equivalents. Cash equivalents at December 31, 2001 included $199.1 million of invested cash deposits received in connection with securities sold under repurchase agreements. There were no securities sold under repurchase agreements at December 31, 2002. See "Securities Sold Under Agreements to Repurchase." The Company's investments are classified as available for sale and stated at fair value. Accordingly, any unrealized gains and losses, net of taxes, are reported in the Consolidated Balance Sheets in "Accumulated other comprehensive losses" until realized. The cost of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments are included in the Consolidated Statements of Income in "Interest income." The sale and purchase of securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific identification method and the cost of equity securities sold is based on the average cost method. Realized gains or losses and declines in value, if any, judged to be other than temporary are reported in the Consolidated Statements of Income in "Other income (expense)." Securities Sold Under Agreements to Repurchase The Company accounts for repurchase agreements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." From time to time the Company may lend securities to unrelated parties, primarily major brokerage firms. Borrowers of these securities must transfer to the Company cash collateral equal to the securities transferred. Cash deposits from these transactions are invested in short-term investments and are included in the Consolidated Balance Sheets in "Cash and cash equivalents." A liability is recognized for the obligation to return the cash collateral. The Company continues to receive interest income on the loaned debt securities, as beneficial owner, and accordingly, the loaned debt securities are included in the Consolidated Balance Sheets in "Marketable securities." Interest expense associated with the related liability is recorded as an offset to "Interest income" in the Consolidated Statements of Income. The Company did not have any loaned debt securities outstanding at December 31, 2002. At December 31, 2001 the fair value of collateral from loaned debt securities was $198.7 million. 40
Derivative Financial Instruments The Company accounts for derivative financial instruments in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" and its corresponding amendments under SFAS No. 138. Derivative financial instruments of the Company include forward exchange contracts and a contingent interest provision that is embedded in the 1.5% convertible senior debentures due 2031 (the "1.5% Debentures") issued on April 11, 2001. See Note 4. Supplementary Cash Flow Information Cash payments made for interest on long-term debt, including commitment fees, totaled $10.2 million, $17.1 million, and $15.0 million during the years ended December 31, 2002, 2001, and 2000, respectively. Cash payments for foreign income taxes, net of foreign tax refunds, were $14.7 million, $4.3 million, and $15.1 million during the years ended December 31, 2002, 2001, and 2000, respectively. A $17.3 million net cash refund of U.S. income tax was received during the year ended December 31, 2002. Cash payments for U.S. income taxes made during the years ended December 31, 2001 and 2000 were $28.8 and $10.7, respectively. Rig Inventory and Supplies Inventories primarily consist of replacement parts and supplies held for use in the operations of the Company. Inventories are stated at the lower of cost or estimated value. Drilling and Other Property and Equipment Drilling and other property and equipment is carried at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which meet certain criteria, are capitalized. Costs incurred for major rig upgrades are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in the results of operations. Depreciation is provided on the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Capitalized Interest Interest cost for construction and upgrade of qualifying assets is capitalized. A reconciliation of the Company's total interest cost to "Interest expense" as reported in the Consolidated Statements of Income is as follows:
Goodwill Prior to January 1, 2002, goodwill from the merger with Arethusa (Off-Shore) Limited ("Arethusa") had been amortized on a straight-line basis over 20 years. The Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" on January 1, 2002 and, accordingly, has suspended amortization of goodwill. On January 1, 2002, goodwill and accumulated amortization was $69.0 million and $30.7 million, respectively. Amortization charged to operating expense during the years ended December 31, 2001 and 2000 totaled $3.3 million and $4.5 million, respectively. Adjustments of $13.6 million during each of the years ended December 31, 2002, 2001 and 2000 were recorded to reduce goodwill. The adjustments represent the tax benefits not previously recognized for the excess of tax deductible goodwill over book goodwill. The Company will continue to reduce goodwill in future periods as the tax benefits of excess tax goodwill over book goodwill are recognized. Goodwill is expected to be reduced to zero during the year 2004. See Note 6. Debt Issuance Costs Debt issuance costs are included in the Consolidated Balance Sheets in "Other assets" and are amortized over the term of the related debt. Deferred Income Taxes Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company's non-U.S. income tax liabilities are based upon the results of operations of the various subsidiaries and foreign branches in those jurisdictions in which they are subject to taxation. Beginning in 2001, the Company decided to indefinitely reinvest a portion of the earnings of its U.K. subsidiaries. Consequently, no U.S. deferred taxes were provided on these earnings in 2002 or in 2001. Treasury Stock and Common Equity Put Options Depending on market conditions, the Company may, from time to time, purchase shares of its common stock or issue put options in the open market or otherwise. The purchase of treasury stock is accounted for using the cost method which reports the cost of the shares acquired in "Treasury stock" as a deduction from stockholders' equity in the Consolidated Balance Sheets. During the year ended December 31, 2002 the Company purchased 1,716,700 shares of its common stock at an aggregate cost of $43.4 million, or at an average cost of $25.30 per share. This includes the Company's purchase of 500,000 shares of its common stock at an aggregate cost of $20.0 million, or at an average cost of $40.00 per share, upon the exercise of put options sold in February 2001. The Company reduced "Additional paid-in-capital" in the Consolidated Balance Sheet by $3.1 million, the amount of the premium received for the sale of these put options, and reported the net cost of the shares, $16.9 million, in "Treasury stock." During the year ended December 31, 2001, the Company purchased 1,403,900 shares of its common stock at an aggregate cost of $37.8 million, or at an average cost of $26.90 per share. As of December 31, 2002, Loews owned 53.8% of the outstanding shares of common stock of the Company. The Company had been a wholly owned subsidiary of Loews prior to its initial public offering in October 1995. The increase of Loews ownership from 53.1% at December 31, 2001 to 53.8% at December 31, 2002 is a result of the Company's purchase of its common stock during 2002. The Company settled put options which covered 1,000,000 shares of its common stock during the year ended December 31, 2002 with cash payments totaling $1.2 million and reduced "Additional paid-in-capital" in the Consolidated Balance Sheet for amounts paid to settle these put options. The Company's remaining put options sold in 2001, which covered 187,321 shares of the Company's common stock, expired during 2002. There were no common equity put options outstanding at December 31, 2002. 42
During the year ended December 31, 2001, the Company received premiums of $6.9 million for the sale of put options covering 1,687,321 shares of common stock. The options gave the holders the right to require the Company to repurchase up to the contracted number of shares of its common stock at the stated exercise price per share at any time prior to their expiration. The Company had the option to settle in cash or shares of common stock. Premiums received for these options were recorded in "Additional paid-in-capital" in the Consolidated Balance Sheets. As of December 31, 2001 there were put options outstanding which covered 1,687,321 shares of the Company's common stock at various stated exercise prices at various expiration dates. Stock-Based Compensation In 2000 the Company adopted a stock option plan ("2000 Stock Option Plan") whereby certain of the Company's employees, consultants and non-employee directors may be granted options to purchase stock. The Company accounts for the 2000 Stock Option Plan under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related Interpretations. See Note 13. No stock-based employee compensation cost is reflected in net income, as all options granted under this plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation.
Revenue Recognition Income from dayrate drilling contracts is recognized currently. In connection with such drilling contracts, the Company may receive lump-sum fees for the mobilization of equipment and personnel. The excess of mobilization fees received over costs incurred to mobilize an offshore rig from one market to another is recognized in income over the primary term of the related drilling contract. Absent a contract, mobilization costs are recognized currently. Lump-sum payments received from customers relating to specific contracts are deferred and amortized to income over the primary term of the drilling contract. Income from offshore turnkey drilling contracts is recognized on the completed contract method, with revenues accrued to the extent of costs until the specified turnkey depth and other contract requirements are met. Provisions for future losses on turnkey drilling contracts are recognized when it becomes apparent that expenses to be incurred on a specific contract will exceed the revenue from that contract. Income from reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of the customer in accordance with a contract or agreement is recorded, for the gross amount billed to the customer, as "Revenues related to reimbursable expenses" in the Consolidated Statements of Income. Prior to 2002 and the guidance provided by the Emerging Issues Task Force ("EITF") 01-14 "Income Statement Characterization of Reimbursements Received for "Out-of-Pocket" Expense Incurred," the Company accounted for reimbursements, in most instances, as a reduction of expenses incurred. All comparative periods presented have been reclassified to comply with this guidance. Accounting Pronouncements In December 2002 the Financial Accounting Standards Board ("FASB") issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements regarding the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. The Company accounts for stock-based employee compensation in accordance with Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees." However, the Company has adopted the provisions of SFAS No. 148 which require prominent disclosure regarding the method of accounting for stock-based employee compensation in its annual financial statements and will be including such disclosure in its future interim financial statements. In July 2002 the FASB issued SFAS No. 146, "Accounting for costs associated with exit or disposal activities." SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company does not expect the adoption of SFAS No. 146 to have a material impact on the Company's consolidated results of operations, financial position or cash flows. In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment to FASB Statement No. 13, and Technical Corrections." The rescission of SFAS No. 4 and 64 by SFAS No. 145 streamlines the reporting of debt extinguishments and requires that only gains and losses from extinguishments meeting the criteria in APB Opinion 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" would be classified as extraordinary. Thus, gains or losses arising from extinguishments that are part of a company's recurring operations would not be reported as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002 with earlier adoption encouraged. The Company adopted SFAS No. 145 in April 2002 and, accordingly, reclassified its April 2001 loss of $7.7 million, net-of-tax, from early extinguishment of debt, as a result of the Company's redemption of the outstanding 3.75% Convertible subordinated note due 2007 (the "3.75% Notes") out of extraordinary 44
items. The pre-tax loss from early extinguishment of debt of $11.9 million was reclassified to "Interest expense" and the related tax benefit was reclassified to "Income tax expense" in the Consolidated Statement of Income. In October 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 replaces SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and provides updated guidance concerning the recognition and measurement of an impairment loss for certain types of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 144 by the Company in January 2002 has not had, nor is it expected to have, a material impact on the Company's consolidated results of operations, financial position or cash flows. In August 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses financial accounting and reporting obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002 with early adoption encouraged. Adoption of SFAS No. 143 in 2003 is not expected to have a material impact on the Company's consolidated results of operations, financial position or cash flows. In June 2001 the FASB issued two new pronouncements, SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires that all business combinations be accounted for by the purchase method and applies to all business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for using the purchase method for which the date of acquisition is July 1, 2001 or later. There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 for all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company adopted SFAS No. 142 on January 1, 2002 and has suspended amortization of goodwill which was $3.3 million and $4.5 million for the years ended December 31, 2001 and 2000, respectively. SFAS No. 142 does not change the SFAS No. 109 "Accounting for Income Taxes" requirement to reduce goodwill for the excess of tax benefits not previously recognized. See Note 6. The adoption of SFAS No. 142 has not had, nor is it expected to have, a material impact on the Company's consolidated results of operations, financial position or cash flows. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated. Reclassifications Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings. Fair Value of Financial Instruments The Company provides fair value information of its financial instruments in the notes to the consolidated financial statements. See Note 11. The carrying amount of the Company's current financial instruments approximate fair value because of the short maturity of these instruments. For non-current financial instruments the Company uses quoted market prices when available and discounted cash flows to estimate fair value. 45
2. EARNINGS PER SHARE A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:
3. MARKETABLE SECURITIES Investments classified as available for sale are summarized as follows:
are derivatives as defined by SFAS No. 133. SFAS No. 133 requires that each derivative be stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for hedge accounting, the gains and losses are reflected in income in the same period as offsetting losses and gains on the qualifying hedged positions. SFAS No. 133 further provides specific criteria necessary for a derivative to qualify for hedge accounting. The forward contracts purchased by the Company in 2002 and 2001 do not qualify for hedge accounting. Contingent Interest On April 11, 2001, the Company issued 1.5% Debentures in the amount of $460.0 million which are due April 15, 2031, and contain a contingent interest provision. See Note 8. The contingent interest component is an embedded derivative as defined by SFAS No. 133 and accordingly must be split from the host instrument and recorded at fair value on the balance sheet. The contingent interest component had no value at issuance or at December 31, 2002 and 2001. 5. DRILLING AND OTHER PROPERTY AND EQUIPMENT Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
The Company's net income and earnings per share, adjusted to exclude amortization expense (net of its related tax benefit) for the years ended December 31, 2002, 2001 and 2000 are as follows:
8. LONG-TERM DEBT Long-term debt consists of the following:
preceding such six-month period equals 120% or more of the principal amount of such 1.5% Debenture and the Company pays a regular cash dividend during such six-month period. The contingent interest payable per $1,000 principal amount of 1.5% Debentures, in respect of any quarterly period, will equal 50% of regular cash dividends paid by the Company per share on its common stock during that quarterly period multiplied by the conversion rate. This contingent interest component is an embedded derivative, which had no fair value at issuance or on December 31, 2002 or December 31, 2001. Holders may require the Company to purchase all or a portion of their 1.5% Debentures on April 15, 2008, at a price equal to 100% of the principal amount of the 1.5% Debentures to be purchased plus accrued and unpaid interest. The Company may choose to pay the purchase price in cash or shares of the Company's common stock or a combination of cash and common stock. In addition, holders may require the Company to purchase, for cash, all or a portion of their 1.5% Debentures upon a change in control (as defined). The Company may redeem all or a portion of the 1.5% Debentures at any time on or after April 15, 2008, at a price equal to 100% of the principal amount plus accrued and unpaid interest. Zero Coupon Convertible Debentures On June 6, 2000, the Company issued Zero Coupon Debentures due 2020 at a price of $499.60 per $1,000 debenture, which represents a yield to maturity of 3.50% per year. The Company will not pay interest prior to maturity unless it elects to convert the Zero Coupon Debentures to interest-bearing debentures upon the occurrence of certain tax events. The Zero Coupon Debentures are convertible at the option of the holder at any time prior to maturity, unless previously redeemed, into the Company's common stock at a fixed conversion rate of 8.6075 shares of common stock per Zero Coupon Debenture, subject to adjustments in certain events. The Zero Coupon Debentures are senior unsecured obligations of the Company. The Company has the right to redeem the Zero Coupon Debentures, in whole or in part, after June 6, 2005, for a price equal to the issuance price plus accrued original issue discount through the date of redemption. Holders have the right to require the Company to repurchase the Zero Coupon Debentures on the fifth, tenth and fifteenth anniversaries of issuance at the accreted value through the date of repurchase. The Company may pay such repurchase price with either cash or shares of the Company's common stock or a combination of cash and shares of common stock. Ocean Alliance Lease-Leaseback In December 2000 the Company entered into a lease-leaseback agreement with a European bank. The lease-leaseback agreement provides for the Company to lease the Ocean Alliance, one of the Company's high specification semisubmersible drilling rigs, to the bank for a lump-sum payment of $55.0 million plus an origination fee of $1.1 million and for the bank to then sub-lease the rig back to the Company. Under the agreement, which has a five-year term, the Company is to make five annual payments of $13.7 million. Two of the five annual payments have been made as of December 31, 2002. This financing arrangement has an effective interest rate of 7.13% and is an unsecured subordinated obligation of the Company. 51
9. COMPREHENSIVE INCOME The income tax effects allocated to the components of other comprehensive income are as follows:
11. FINANCIAL INSTRUMENTS Concentrations of Credit and Market Risk Financial instruments which potentially subject the Company to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash and trade accounts receivable and investments in debt securities, including treasury inflation-indexed protected bonds ("TIP's") and collateralized mortgage obligations ("CMO's"). The Company places its temporary excess cash investments in high quality short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. The Company's periodic evaluations of the relative credit standing of these financial institutions are considered in the Company's investment strategy. Concentrations of credit risk with respect to trade accounts receivable are limited primarily due to the entities comprising the Company's customer base. Since the market for the Company's services is the offshore oil and gas industry, this customer base consists primarily of major oil companies and independent oil and gas producers. The Company provides allowances for potential credit losses when necessary. No such allowances were deemed necessary for the years presented and, historically, the Company has not experienced significant losses on trade receivables. All of the Company's investments in debt securities are U.S. government securities or government-backed with minimal credit risk. However, the Company is exposed to market risk due to price volatility associated with interest rate fluctuations. Fair Values The amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, marketable securities, accounts receivable, and accounts payable approximate fair value. Fair values and related carrying values of the Company's debt instruments are shown below:
12. RELATED PARTY TRANSACTIONS The Company and Loews entered into a services agreement which was effective upon consummation of the Common Stock Offering (the "Services Agreement") pursuant to which Loews agreed to continue to perform certain administrative and technical services on behalf of the Company. Such services include personnel, telecommunications, purchasing, internal auditing, accounting, data processing and cash management services, in addition to advice and assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, the Company is required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the provision of such services. The Services Agreement may be terminated at the Company's option upon 30 days' notice to Loews and at the option of Loews upon six months' notice to the Company. In addition, the Company has agreed to indemnify Loews for all claims and damages arising from the provision of services by Loews under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. The Company was charged $0.3 million, $0.3 million and $0.4 million by Loews for these support functions during the years ended December 31, 2002, 2001 and 2000, respectively. 13. STOCK OPTION PLAN The Company's 2000 Stock Option Plan provides for issuance of either incentive stock options or non-qualified stock options to the Company's employees, consultants and non-employee directors. Options may be granted to purchase stock at no less than 100% of the market price of the stock on the date the option is granted. Such plan reserved for issuance up to 750,000 shares of the Company's common stock, none of which had been issued as of December 31, 2002. Unless otherwise specified by the Board of Directors at the time of the grant, stock options have a maximum term of ten years, subject to earlier termination under certain conditions and vest over four years. The following table summarizes the stock option activity related to the 2000 Stock Option Plan:
prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below:
The difference between actual income tax expense and the tax provision computed by applying the statutory federal income tax rate to income before taxes is attributable to the following:
on these earnings in 2001 or 2002. Undistributed earnings of the U.K. subsidiaries for which no U.S. deferred income tax provision has been made were $21.1 million in 2002 and $14.9 million in 2001. Deferred income taxes are not recorded on differences between financial reporting and tax bases of investments in stock of the Company's subsidiaries, unless realization of the effect is probable in the foreseeable future. The Company believes it is probable that its deferred tax assets of $104.7 million will be realized through carrybacks to prior year tax returns or on future tax returns, primarily from the generation of future taxable income through both profitable operations and future reversals of existing taxable temporary differences. As of December 31, 2002, the Company had net operating loss ("NOL") carryforwards of approximately $114.6 million available to offset taxable income. Approximately $21.5 million of the NOL carryforwards were acquired in 1996 with the Arethusa merger. The utilization of the NOL carryforwards acquired in the Arethusa merger is limited pursuant to Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"). None of the NOL carryforwards acquired from Arethusa were utilized in 2002. The remaining $93.1 million of NOL carryforwards were generated during 2002 and are not subject to a limitation under Code Section 382. The Company expects to fully utilize this portion of the NOL through a carryback to a prior taxable year. The Company has recognized a tax benefit of $32.6 million related to the tax loss generated in 2002. The Company has recorded a deferred tax asset of $40.1 million for the benefit of the NOL carryforwards. The NOL carryforwards will expire as follows:
Deferred Compensation and Supplemental Executive Retirement Plan The Company established its Deferred Compensation and Supplemental Executive Retirement Plan in December 1996. The Company contributes to this plan any portion of the 3.75% of the base salary contribution and the matching contribution to the 401k Plan that cannot be contributed because of the limitations within the Code and because of elective deferrals that the participant makes under the plan. Additionally, the plan provides that participants may defer up to 10% of base compensation and/or up to 100% of any performance bonus. Participants in this plan are a select group of management or highly compensated employees of the Company and are fully vested in all amounts paid into the plan. The Company's provision for contributions for the years ended December 31, 2002, 2001 and 2000 was not material. Pension Plan The defined benefit pension plan established by Arethusa effective October 1, 1992 was frozen on April 30, 1996. At that date, all participants were deemed fully vested in the plan, which covered substantially all U.S. citizens and U.S. permanent residents who were employed by Arethusa. Benefits are calculated and paid based on an employee's years of credited service and average compensation at the date the plan was frozen using an excess benefit formula integrated with social security covered compensation. Pension costs are determined actuarially and at a minimum funded as required by the Code. During 2002 the Company made a voluntary contribution of $3.7 million to this plan. The plan's assets are invested in cash and cash equivalents, equity securities, government and corporate debt securities. As a result of freezing the plan, no service cost has been accrued for the years presented. The following provides a reconciliation of benefit obligations and significant actuarial assumptions:
Geographic Areas At December 31, 2002, the Company had drilling rigs located offshore ten countries outside of the United States. As a result, the Company is exposed to the risk of changes in social, political and economic conditions inherent in foreign operations and the Company's results of operations and the value of its foreign assets are affected by fluctuations in foreign currency exchange rates. Revenues by geographic area are presented by attributing revenues to the individual country where the services were performed.
Major Customers The Company's customer base includes major and independent oil and gas companies and government-owned oil companies. Revenues from major customers for the periods presented that contributed more than 10% of the Company's total revenues as follows:
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. Not applicable. PART III Reference is made to the information responsive to Items 10, 11, 12 (other than information concerning securities authorized for issuance under equity compensation plans) and 13 of this Part III contained in the Company's definitive proxy statement for its 2003 Annual Meeting of Stockholders, which is incorporated herein by reference. ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. ITEM 11. EXECUTIVE COMPENSATION. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. For information concerning securities authorized for issuance under equity compensation plans, see "Market for the Registrant's Common Equity and Related Stockholder Matters -- Equity Compensation Plan Information" in Item 5 of Part II of this report. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. ITEM 14. CONTROLS AND PROCEDURES. The Company's management formed a disclosure controls and procedures committee (the "Disclosure Committee") in 2002. The purpose and responsibility of the Disclosure Committee is to coordinate and review the process by which information is recorded, processed and reported on a timely basis as required to be disclosed by the Company in its reports filed, furnished or submitted under the Exchange Act. In addition, the Disclosure Committee is responsible for ensuring that this information is accumulated and communicated to the Company's management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Evaluation of Disclosure Controls and Procedures Based on their evaluation of the Company's disclosure controls and procedures conducted within 90 days prior to the date of filing this report on Form 10-K, the Company's principal executive officer and principal financial officer have concluded that as of the date of their evaluation, the Company's disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) promulgated under the Exchange Act) are effective. Changes in Internal Controls There were no significant changes in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation. 62
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
(c) Index of Exhibits
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 4, 2003. DIAMOND OFFSHORE DRILLING, INC. By: /s/ GARY T. KRENEK ---------------------------------- Gary T. Krenek 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 and in the capacities and on the dates indicated.
CERTIFICATIONS I, James S. Tisch, certify that: 1. I have reviewed this annual report on Form 10-K of Diamond Offshore Drilling, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ JAMES S. TISCH -------------------------------------- James S. Tisch Chief Executive Officer Date 04-March-2003 67
CERTIFICATIONS I, Gary T. Krenek, certify that: 1. I have reviewed this annual report on Form 10-K of Diamond Offshore Drilling, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ GARY T. KRENEK -------------------------------------- Gary T. Krenek Chief Financial Officer Date 04-March-2003 68
EXHIBIT INDEX
EXHIBIT 12.1 DIAMOND OFFSHORE DRILLING, INC. STATEMENT RE COMPUTATION OF RATIOS (THOUSANDS OF DOLLARS) RATIO OF EARNINGS TO FIXED CHARGES: YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------- 2002 2001 2000 1999 1998 --------- --------- --------- --------- --------- COMPUTATION OF EARNINGS: Pretax income from continuing operations ........... $ 96,174 $ 260,485 $ 110,867 $ 240,363 $ 590,231 Less: Interest capitalized during the period and actual preferred dividend requirements of majority-owned subsidiaries and 50%-owned persons included in fixed charges but not deducted from pretax income from above ................ (2,878) (2,645) (13,844) (6,329) (1,031) Add: Previously capitalized interest amortized during the period .................. 1,304 1,185 334 334 334 --------- --------- --------- --------- --------- Total earnings, before fixed charge addition ........................................... 94,600 259,025 97,357 234,368 589,534 --------- --------- --------- --------- --------- COMPUTATION OF FIXED CHARGES: Interest, including interest capitalized ........... 26,933 29,191 24,500 16,009 16,121 --------- --------- --------- --------- --------- Total fixed charges ................................ 26,933 29,191 24,500 16,009 16,121 --------- --------- --------- --------- --------- TOTAL EARNINGS AND FIXED CHARGES ................... $ 121,533 $ 288,216 $ 121,857 $ 250,377 $ 605,655 ========= ========= ========= ========= ========= RATIO OF EARNINGS TO FIXED CHARGES ................. 4.51 9.87 4.97 15.64 37.57 ========= ========= ========= ========= =========
. . . EXHIBIT 21.1 SUBSIDIARIES SUBSIDIARY JURISDICTION OF ORGANIZATION ---------- ---------------------------- Diamond Offshore Company Delaware Diamond Offshore Team Solutions, Inc. Delaware Diamond Offshore General Company Delaware Diamond Offshore Services Company Delaware Arethusa Off-Shore Company Delaware Diamond Offshore Finance Company Delaware Diamond Offshore Drilling Sdn. Bhd. Malaysia Arethusa/Zapata Off-Shore Brasil Ltda. Brazil Diamond Offshore Drilling (Nigeria) Ltd. Nigeria Z North Sea, Ltd. Bermuda Diamond Offshore Drilling (Netherlands) B.V. Netherlands Afcons Arethusa Off-Shore Services Ltd. India Pt Aqza Dharma Indonesia Diamond Offshore (Singapore) Pte. Ltd. Singapore Diamond Offshore Management Company Delaware Diamond M Corporation Texas Diamond Offshore Development Company Delaware Diamond Offshore (USA) Inc. Delaware Storm Nigeria Ltd. Nigeria Brasdril-Sociedade de Perfuracoes Ltda. Brazil Diamond Offshore Contract Services, S.A. Panama Diamond Offshore Drilling (Overseas) Inc. Delaware Diamond Offshore Drilling Services, Inc. Delaware Diamond Offshore International Limited Cayman Islands Ensenada Internacional, S.A. Panama Diamond Offshore Netherlands B.V. Netherlands Diamond Offshore Drilling Company, N.V. Netherlands Antilles M-S Drilling S.A. Panama Diamond Offshore (Bermuda) Limited Bermuda Diamond Offshore Limited England Diamond Offshore Drilling (UK) Limited England Diamond Offshore Drilling (Bermuda) Limited Bermuda Diamond M Servicios Venezuela, S.A. Venezuela Diamond Offshore (Trinidad) L.L.C. Delaware Diamond Offshore Drilling Limited Cayman Islands Diamond Offshore Services Limited Bermuda Diamond Offshore (Brazil) L.L.C. Delaware Diamond Offshore Holding, L.L.C. Delaware
EXHIBIT 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-19987 on Form S-3, Registration Statement No. 333-22745 on Form S-8, Registration Statement No. 333-23547 on Form S-4, Registration Statement No. 333-63443 on Form S-3, Registration Statement No. 333-42930 on Form S-8, Registration Statement No. 333-44960 on Form S-3 and Registration Statement No. 333-63980 on Form S-3 of Diamond Offshore Drilling, Inc. (the "Company") of our report dated January 28, 2003 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company's change in its method of accounting for goodwill to conform with Statement of Financial Accounting Standards No. 142), appearing in this Annual Report on Form 10-K of the Company for the year ended December 31, 2002. DELOITTE & TOUCHE LLP Houston, Texas March 4, 2003
EXHIBIT 24.1 POWER OF ATTORNEY James S. Tisch hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ JAMES S. TISCH Chief Executive Officer February 14, 2003 - ------------------- James S. Tisch & Chairman of the Board
EXHIBIT 24.1 POWER OF ATTORNEY Herbert C. Hofmann hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ HERBERT C. HOFMANN Director February 14, 2003 - ------------------------ Herbert C. Hofmann
EXHIBIT 24.1 POWER OF ATTORNEY Michael H. Steinhardt hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ MICHAEL H. STEINHARDT Director February 14, 2003 - --------------------------- Michael H. Steinhardt
EXHIBIT 24.1 POWER OF ATTORNEY Arthur L. Rebell hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ ARTHUR L. REBELL Director February 14, 2003 - ---------------------- Arthur L. Rebell
EXHIBIT 24.1 POWER OF ATTORNEY Raymond S. Troubh hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ RAYMOND S. TROUBH Director February 14, 2003 - ---------------------- Raymond S. Troubh
EXHIBIT 24.1 POWER OF ATTORNEY Lawrence R. Dickerson hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ LAWRENCE R. DICKERSON President, Chief Operating February 14, 2003 - --------------------------- Officer and Director Lawrence R. Dickerson
EXHIBIT 24.1 POWER OF ATTORNEY Gary T. Krenek hereby designates and appoints William C. Long as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorney-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as the Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ GARY T. KRENEK Vice President and February 14, 2003 - ------------------- Gary T. Krenek Chief Financial Officer
EXHIBIT 24.1 POWER OF ATTORNEY Alan R. Batkin hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as his attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for him and in his name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ ALAN R. BATKIN Director February 14, 2003 - --------------------------- Alan R. Batkin
EXHIBIT 24.1 POWER OF ATTORNEY Beth G. Gordon hereby designates and appoints William C. Long and Gary T. Krenek and each of them (with full power to each of them to act alone) as her attorney-in-fact, with full power of substitution and re-substitution (the "Attorneys-in-Fact"), for her and in her name, place and stead, in any and all capacities, to execute the Annual report on Form 10-K (the "Annual Report") to be filed by Diamond Offshore Drilling, Inc. with the Securities and Exchange Commission and any amendment(s) to the Annual Report, which amendment(s) may make such changes in the Annual Report as either Attorney-in-Fact deems appropriate, and to file the Annual Report and each such amendment to the Annual Report together with all exhibits thereto and any and all documents in connection therewith. SIGNATURE TITLE DATE - --------- ----- ---- /s/ BETH G. GORDON Controller February 14, 2003 - ------------------- Beth G. Gordon