UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

15415 Katy Freeway

Houston, Texas 77094

(Address and zip code of principal executive offices)

(281) 492-5300

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes þ          No o

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ

      Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2)     Yes þ          No o

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the definitive proxy statement relating to the 2005 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2004, are incorporated by reference in Part III of this form.

DIAMOND OFFSHORE DRILLING, INC.

FORM 10-K for the Year Ended December 31, 2004

TABLE OF CONTENTS

PART I

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” or “Diamond Offshore” mean Diamond Offshore Drilling, Inc. and its consolidated subsidiaries. The Company is a leader in deep water drilling with a fleet of 45 offshore rigs consisting of 30 semisubmersibles, 14 jack-ups and one drillship.

The Fleet

      The Company’s fleet includes some of the most technologically advanced rigs in the world, enabling it to offer a broad range of services worldwide in various markets, including the deep water, harsh environment, conventional semisubmersible and jack-up markets.

      Semisubmersibles. The Company owns and operates 30 semisubmersibles (including nine high specification and 21 other semisubmersible rigs). 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’s high specification semisubmersibles have high-capacity deck loads and are generally capable of working in water depths of 4,000 feet or greater or in harsh environments and have other advanced features. As of January 31, 2005, six of the nine high specification semisubmersibles were located in the U.S. Gulf of Mexico, while the remaining three rigs were located offshore Brazil, Indonesia and Malaysia, respectively.

      The Company’s other semisubmersibles generally work in maximum water depths up to 4,000 feet, and many have diverse capabilities that enable them to provide both shallow and deep water service in the U.S. and in other markets outside the U.S. As of January 31, 2005, the Company was actively marketing 18 of these semisubmersibles. Four of these semisubmersibles were located in the U.S. Gulf of Mexico; four were located offshore Mexico; four were located in the North Sea; three were located offshore Australia; two were located offshore Brazil; and one was located offshore Korea.

      The Company currently has three cold-stacked semisubmersible rigs. When the Company anticipates that a rig will be idle for an extended period of time, it cold stacks the unit by removing the crew and ceasing to actively market the rig. This reduces expenditures associated with keeping the rig ready to go to work. See additional discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations– Operating Income” in Item 7 of this report.

      One of the Company’s semisubmersibles has been cold stacked in the Gulf of Mexico since December 2002, and the Company is marketing another cold-stacked semisubmersible, the Ocean Liberator, for sale to a third party. See “— Fleet Retirements.” The remaining cold-stacked semisubmersible, the Ocean Endeavor, will undergo a major upgrade for ultra-deepwater service commencing in the second quarter of 2005. See “— Fleet Enhancements.”

      Jack-ups. The Company owns 14 jack-ups, all of which were being actively marketed as of January 31, 2005. 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 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 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 January 31, 2005, 12 of the Company’s jack-up rigs were located in the Gulf of Mexico. Of these rigs, nine are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Both of the Company’s remaining jack-up rigs are internationally based and are independent-leg cantilevered rigs; one was located offshore Bangladesh and the other was located offshore India as of January 31, 2005.

      Drillship. The Company has one drillship, the Ocean Clipper, which was located offshore Brazil as of January 31, 2005. 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.

      Fleet Enhancements. The Company’s strategy of economically upgrading its fleet to meet customer demand for advanced, efficient, high-tech rigs, particularly deepwater semisubmersibles, is intended to maximize the utilization and dayrates earned by the rigs in its fleet. Since 1995, the Company has increased the number of rigs capable of operating in 3,500 feet of water or greater from three rigs to 12 (nine of which are high specification units), primarily by upgrading its existing fleet. Five of these upgrades were to its Victory-class semisubmersible rigs, most recently the Ocean Rover which was completed in July 2003 at an approximate cost of $188 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.

      In January 2005, the Company announced the initiation of a major upgrade of its Victory-class semisubmersible, the Ocean Endeavor, for ultra-deepwater service at an estimated upgrade cost of approximately $250 million. The modernized rig will be designed to operate in up to 10,000 feet of water. The Ocean Endeavor will be mobilized to a shipyard in Singapore where work is scheduled to commence in the second quarter of 2005. Delivery of the upgraded rig is expected in approximately two years.

      In the first half of 2004, the Company commenced and completed an upgrade of one of its high specification semisubmersible units, the Ocean America, making it more suitable for developmental drilling. The cost of the upgrade was approximately $13 million.

      In early 2004, the Company completed a two-year program designed to expand the capabilities of its jack-up fleet by significantly upgrading six of its 14 jack-up rigs for a total cost of approximately $94 million. On the Ocean Titan and Ocean Tower, both 350-foot water depth capable independent-leg slot rigs prior to their upgrades, the Company installed cantilever packages. 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 completed its upgrade in March 2003 for approximately $27 million. The Ocean Titan upgrade was completed in January 2004 for approximately $22 million. The Ocean Spartan, Ocean Spur and Ocean Heritage leg extension installations were completed in the fourth quarter of 2002, enabling these rigs to work in water depths up to 300 feet, compared to 250 feet prior to the upgrades, at a combined approximate cost of $34 million. The Ocean Sovereign, a 250-foot water depth independent-leg cantilever rig prior to its upgrade, completed its leg extension installations in May 2003 at an approximate cost of $11 million, allowing 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 attractive levels, particularly during cyclical downturns. The Company most recently purchased two third-generation semisubmersible drilling rigs, the Ocean Vanguard in late 2002 for $68.5 million and the Ocean Patriot, formerly the Omega, in March 2003 for $65.0 million.

      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 — Liquidity and Capital Requirements” in Item 7 of this report.

      Fleet Retirements. In December 2004, the Company decided to market for sale one of its cold-stacked semisubmersibles, the Ocean Liberator.

     More detailed information concerning the Company’s fleet of mobile offshore drilling rigs, as of January 31, 2005, is set forth in the table below.

		Attributes
DP = Dynamically-Positioned/ Self-Propelled		MS = Mat-Supported Slot Rig		3M = Three Mud Pumps
IC = Independent-Leg Cantilevered Rig		VC = Victory — Class		4M = Four Mud Pumps
MC = Mat-Supported Cantilevered Rig		SP = Self-Propelled		15K = 15,000 psi well control system

See the footnotes to this table on the following page.

Markets

      The Company’s principal markets for its offshore contract drilling services are the Gulf of Mexico, including the United States and Mexico, Europe, principally the U.K. and Norway, South America, Africa and Australia/ Southeast Asia. The Company actively markets its rigs worldwide. From time to time the Company’s fleet operates in various other markets throughout the world as the market demands. See Note 15 to the Company’s Consolidated Financial Statements in Item 8 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 or not 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 that include the ability to earn 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 or for an additional length of time 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. However, no assurance can be given that the Company will be able to achieve or maintain such a balance from time to time.

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 2004, the Company performed services for 53 different customers with Petróleo Brasileiro S.A. (“Petrobras”) and PEMEX — Exploración Y Producción (“PEMEX”) accounting for 12.6% and 10.5% of the Company’s annual total consolidated revenues, respectively. During 2003, the Company performed services for 52 different customers with Petrobras and BP p.l.c. (“BP”) accounting for 20.3% and 11.9% of the Company’s annual total consolidated revenues, respectively. During 2002, the Company performed services for 46 different customers with 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 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 office in The Hague, Netherlands with support from its regional offices in Aberdeen, Scotland and Perth, Western Australia. 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, an oversupply of rigs can create 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 often becomes 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.”

Governmental Regulation

      The Company’s operations are subject to numerous international, U.S., 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 certain circumstances or that the Company will continue to carry such insurance or receive such indemnification.

      The Company’s retention of liability for property damage is between $1.0 million and $2.5 million per incident, depending on the value of the equipment, with an additional aggregate annual deductible of $4.5 million.

Operations Outside the United States

      Operations outside the United States accounted for approximately 56.0%, 51.6% and 55.5% of the Company’s total consolidated revenues for the years ended December 31, 2004, 2003 and 2002, respectively. The Company’s non-U.S. operations are subject to certain political, economic and other uncertainties not normally encountered in U.S. operations, including risks of war, terrorist acts 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 — Overview– Results of Operations and Industry Conditions” and “— Other — Currency Risk” in Item 7 of this report and Note 15 to the Company’s Consolidated Financial Statements in Item 8 of this report.

      During 2003, the Company entered into contracts to operate four of its semisubmersible rigs offshore Mexico for PEMEX, the national oil company of Mexico. The terms of these contracts expose the Company to greater risks than it normally assumes, such as exposure to greater environmental liability. While the Company believes that the financial terms of the contracts and the Company’s operating safeguards in place

mitigate these risks, there can be no assurance that the Company’s increased risk exposure will not have a negative impact on the Company’s future operations or financial results.

Employees

      As of December 31, 2004, the Company had approximately 4,200 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, current reports on Form 8-K, amendments to those reports and to other 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 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, two buildings totaling 39,000 square feet 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, Norway, Vietnam, Netherlands, Malaysia, Bangladesh, India, Korea, Singapore and Mexico to support its offshore drilling operations.

      Not applicable.

      Not applicable.

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.

      James S. Tisch has served as Chief Executive Officer of the Company since March 1998. Mr. Tisch has served as Chairman of the Board since 1995 and as a director of the Company since June 1989. Mr. Tisch has served as Chief Executive Officer of Loews Corporation (“Loews”), a diversified holding company and the Company’s controlling stockholder, since November 1998. Mr. Tisch, a director of Loews since 1986, also serves as a director of CNA Financial Corporation, a 91% owned subsidiary of Loews, and BKF Capital Group, Inc.

      Lawrence R. Dickerson has served as President, Chief Operating Officer and Director of the Company since March 1998. Mr. Dickerson has also served on the United States Commission on Ocean Policy from 2001 to 2004.

      David W. Williams has served as Executive Vice President of the Company since March 1998.

      Rodney W. Eads has served as Senior Vice President of the Company since May 1997.

      John L. Gabriel, Jr. has served as Senior Vice President of the Company since November 1999.

      John M. Vecchio has served as Senior Vice President of the Company since April 2002. Previously, Mr. Vecchio served as Technical Services Vice President of the Company from October 2000 through March 2002 and as Engineering Vice President of the Company from July 1997 through September 2000.

      Gary T. Krenek has served as Vice President and Chief Financial Officer of the Company since March 1998.

      Beth G. Gordon has served as Controller and Chief Accounting Officer of the Company since April 2000. Previously, Ms. Gordon was employed by Pool Energy Services Co. from December 1978 through March 2000 where her most recent position was Vice President-Finance — Pool Well Services Co.

      William C. Long has served as Vice President, General Counsel and Secretary of the Company since March 2001. Previously, Mr. Long served as General Counsel and Secretary of the Company from March 1999 through February 2001.

PART II

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.

      As of February 24, 2005 there were approximately 299 holders of record of the Company’s common stock. This number does not include the stockholders for whom shares are held in the name of a “nominee” or “street name.”

Dividend Policy

      In 2004 the Company paid cash dividends of $0.0625 per share of the Company’s common stock on March 1, June 1, September 1 and December 1. In 2003 the Company paid cash dividends of $0.125 per share of the Company’s common stock on March 3, June 2 and September 2 and $0.0625 per share on December 1.

      On January 25, 2005, the Company declared a dividend of $0.0625 per share of the Company’s common stock payable March 1, 2005 to stockholders of record on February 1, 2005. Any future determination as to payment of dividends will be made at the discretion of the Board of Directors of the Company and will depend upon the Company’s operating results, financial condition, capital requirements, general business conditions and such other factors that the Board of Directors deems relevant.

      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. Prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings. 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.

      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.

      The overall market for the Company’s mid-water and deepwater semisubmersible rigs improved dramatically beginning in the third quarter of 2004 and extending into 2005. The increase in demand, which resulted from a combination of customer recognition of high oil and gas prices, increasing oil consumption and declining reserves, among other things, lifted dayrates around the world, but had the greatest impact in the U.S. Gulf of Mexico and the North Sea — two markets where the Company has a significant presence. The Company’s jack-up fleet also experienced steady growth in utilization and dayrates throughout 2004.

      Gulf of Mexico. In the U.S. Gulf of Mexico, commitments for Diamond Offshore’s high-specification rigs have reached as high as $150,000 per day for work beginning in mid-2005 and extending into the first quarter of 2006. This contrasts with dayrates in the $60,000 range earned during the first half of 2004. All six of the Company’s high-specification semisubmersible rigs in the U.S. GOM are currently contracted with backlogs extending at least until the third quarter of 2005 at progressively higher dayrates than previous contracts. In addition, the dayrate for the Company’s four mid-water semisubmersibles operating in the GOM has reached as high as $110,000 for work beginning in early September 2005, with backlog also building in this market at improving dayrates. This contrasts with dayrates in the $40,000 range earned during the first half of 2004. The improving dayrates and high committed utilization were factors in the Company’s decision to reactivate the previously cold-stacked Ocean Voyager for the mid-water U.S. GOM market. The Ocean Voyager, which resumed work in mid-December 2004, is earning a dayrate of $73,000 as of the date of this report and has future commitments to work at dayrates ranging from $95,000 to $110,000 beginning in the second quarter of 2005. The Company views the deepwater and mid-water markets in the GOM as under-supplied, and believes that additional improvement in utilization, backlog and dayrates is likely in these market segments during 2005.

      The Company’s jack-up fleet in the GOM also continued to experience high utilization and improving dayrates during 2004 and into early 2005. The Company views the jack-up market in the U.S. GOM as currently tightly balanced, with effective utilization near 100 percent and demand sporadically exceeding supply. As a result, the Company believes the market and dayrates for this class of equipment could improve further in the near term.

      In the Mexican GOM, the Company’s four semisubmersible rigs that mobilized to that market in the latter half of 2003 continued to operate throughout 2004 under long-term contracts and remain contracted for that market throughout 2005. The Company believes that future work for other of its semisubmersibles and jack-ups in this market is limited. The Company views the market for the Mexican GOM as in balance and expects it to remain so this year.

      Brazil. Two of the Company’s four rigs operating in Brazil, one of which is a high specification semisubmersible, have contracts that expire in the third quarter of 2005. These units were contracted prior to the mid-year market improvement and the Company will seek to obtain new contracts for these rigs reflective of market conditions. The Company views the Brazilian semisubmersible market as firm and expects it to remain so during 2005.

      North Sea. Drilling activity in the North Sea mirrored that in the Gulf of Mexico in 2004. Demand and pricing accelerated in the second half of 2004, and utilization of marketed semisubmersible rigs in the U.K. sector of the North Sea reached 100 percent by the end of June 2004. The Ocean Guardian and Ocean Princess, which began the year earning dayrates between $40,000 and $50,000, each received one-year extensions to their contracts in the U.K. at $80,000 per day. The Ocean Vanguard began work at mid-year in

the U.K. sector for a start-up rate of $30,000 per day. The unit then mobilized to Norway late in 2004, where it began an approximately 15-month series of contracts for a dayrate in the low $140,000s. Also responding to the strong demand in the North Sea, the Ocean Nomad returned to the U.K. from West Africa and is operating under a one year contract, also at $80,000 per day. Effective utilization of marketed semisubmersible rigs in both the U.K and Norwegian sectors of the North Sea remains at 100 percent, and the Company believes this market will remain firm throughout the balance of 2005.

      In February 2005, the Company reached an agreement with a customer to upgrade the Ocean Guardian to high pressure, high temperature capabilities. The upgrade is scheduled to begin in the third quarter of 2005 and is estimated to cost approximately $5.0 million, which will be paid by the customer, in part by a lump-sum payment of $3.5 million with the remainder to be recovered through dayrate increases over a minimum of 120 days.

      Southeast Asia. The Company’s two high-specification semisubmersibles operating in Southeast Asia received new contracts in the first quarter of 2005. The Ocean Baroness was awarded a one-year contract at a dayrate of approximately $200,000 for work in the Gulf of Mexico beginning early in the fourth quarter of 2005. The unit is expected to begin a 90-120 day mobilization back to the U.S. at the conclusion of its current contract in May 2005. Additionally, the Ocean Rover received a 950-day extension to its current contract at a dayrate averaging in the mid $170,000s. The new dayrates contrast with rates in the mid $130,000s and mid $120,000s, respectively, for the rigs’ previous contracts. All of the Company’s other semisubmersible rigs in the Southeast Asian market currently have contracts or commitments for work extending at least into mid-2005 at favorable market dayrates. The Company views demand in the Southeast Asian market as increasing, and with high utilization, the Company believes dayrates could continue improving.

      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, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, the Company may mobilize its rigs from one market to another. However, during periods of mobilization, 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. The two most significant variables affecting revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. As utilization rates increase, dayrates tend to increase as well reflecting the lower supply of available rigs, and vice versa. The same factors, primarily demand for drilling services, which is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development as well as a variety of political and economic factors, and availability of rigs in a particular geographical region, affect both dayrates and utilization rates. These factors are not within the Company’s control and are difficult to predict.

      Revenue from dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, the Company may receive lump-sum fees for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. The Company previously accounted for the excess of mobilization fees received over costs incurred to mobilize an offshore rig from one market to another as revenue over the term of the related drilling contracts. Effective July 1, 2004 the Company changed its accounting to defer mobilization fees received as well as direct and incremental mobilization costs incurred and began to amortize each, on a straight line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). Straight line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. If the Company had used this method of accounting in prior periods, operating income (loss) and net income (loss) would not have changed and the impact on contract drilling revenues and expenses would have been immaterial. Absent a contract, mobilization costs are recognized currently.

      Reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of the Company’s customers 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 Operations.

      Revenue 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. The Company has elected not to pursue contracts for integrated services, which includes turnkey contracts, except in very limited circumstances.

      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, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “ready stacked” 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 costs of the operator when a rig is under contract. 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 incurred, operating expenses related to activities such as inspections, painting projects and routine overhauls that meet certain criteria and, which 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. Higher depreciation expense decreases operating income in periods subsequent to capital upgrades.

      Operating income is negatively impacted when the Company performs certain regulatory inspections (“5-year surveys”) that are due every five years for all of the Company’s rigs. Operating revenue decreases because these surveys are performed during scheduled down-time in a shipyard. Operating expenses increase as a result of these surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance costs may be required resulting from the survey or may have been previously planned to take place during this mandatory down-time. The number of rigs undergoing a 5-year survey will vary from year to year.

      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 meet certain criteria, are capitalized. Depreciation is amortized up to applicable salvage values by applying 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 judgments, assumptions and estimates could produce results that differ from those reported.

      The offshore drilling industry is a relatively young industry which began developing just over 50 years ago. The Company has based its estimates of useful lives and salvage values on the historical industry data available to it as well as its own experience. In April 2003 the Company commissioned a study to evaluate the economic lives of its drilling rigs because several of its rigs had reached or were approaching the end of their depreciable lives, yet were still operating and were expected to operate for many more years. As a result of this study, effective April 1, 2003, the Company recorded changes in accounting estimates by increasing the estimated service lives to 25 years for jack-ups and 30 years for semisubmersibles and the Company’s drillship and by increasing salvage values to 5% for most of the Company’s drilling rigs. The change in estimate was

made to better reflect the remaining economic lives and salvage values of the Company’s fleet. The effect of this change in accounting estimate resulted in a reduction to the Company’s net loss for the years ended December 31, 2004 and 2003 of $19.6 million, or $0.15 per share, and $14.9 million, or $0.11 per share, respectively.

      The Company evaluates its property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company utilizes a probability-weighted cash flow analysis in testing an asset for potential impairment. The assumptions and estimates underlying this analysis include (a) dayrate by rig, (b) utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used), (c) the per day operating cost for each rig if active, ready stacked or cold stacked and (d) salvage value for each rig. Based on these assumptions and estimates a matrix is developed assigning probabilities to various combinations of assumed utilization rates and dayrates. The impact of a 5% reduction in assumed dayrates for the cold stacked rigs (holding all other assumptions and estimates in the model constant), or alternatively the impact of a 5% reduction in utilization (again holding all other assumptions and estimates in the model constant) is also considered as part of this analysis.

      At December 31, 2004, the Company considered its three cold-stacked rigs for impairment testing and determined that none of the drilling units was impaired. On January 10, 2005, the Company announced that one of its cold stacked rigs, the Ocean Endeavor, would be upgraded to a high specification drilling unit for an estimated cost of $250 million. As a result of this decision and the low net book value of this rig, the Company does not consider this asset to be impaired. At December 31, 2004, the Company had elected to market one of its cold-stacked rigs, the Ocean Liberator, for sale to a third party and classified the rig as an asset-held-for-sale in the Company’s Consolidated Balance Sheet included in Item 8 of this report. The estimated market value of this rig, based on offers from third parties, is higher than its current carrying value; therefore, no write-down was deemed necessary as a result of the reclassification to held-for-sale. The remaining cold stacked rig was evaluated for impairment using the probability-weighted cash flow analysis discussed above. At December 31, 2004 the probability-weighted cash flow for the Ocean New Era significantly exceeded its net carrying value of $3.2 million.

      At December 31, 2003 the Company determined that all five of its cold stacked rigs should be tested for impairment. The impairment analysis at December 31, 2003 consisted of a probability-weighted cash flow analysis for each of the five cold stacked rigs. In all cases, the probability-weighted cash flows significantly exceeded the carrying value of each rig. Two of the Company’s cold stacked rigs that were tested and found not to be impaired at December 31, 2003 were subsequently reactivated and these rigs currently have contracted dayrates that are within the range of dayrates used in the Company’s 2003 impairment analysis.

      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 uninsured 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 additional aggregate annual deductible of $1.5 million. The Company’s in-house claims department estimates the amount of its liability for its retention. This department establishes a reserve for each of the Company’s personal injury claims by evaluating the existing facts and circumstances of each claim and comparing the circumstances of each claim to historical experiences with similar past personal injury claims. The claims department also estimates the Company’s liability for claims which are incurred but not reported by using historical data. Historically, the Company’s ultimate liability for personal injury claims has not differed materially from the Company’s recorded estimates. At December 31, 2004 the Company’s estimated liability for personal injury claims was $33.4 million. Due to uncertainties such as (a) the severity of personal injuries claimed, (b) significant changes in the volume of personal injury claims, (c) the unpredictability of legal jurisdictions where the claims will ultimately be litigated, (d) inconsistent court decisions and (e) the risks and lack of predictability inherent in personal injury litigation, eventual settlement or adjudication of these claims could differ materially from the estimated amounts.

      Income Taxes. The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” which requires the recognition of

the amount of taxes payable or refundable for the current year; and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in its financial statements or tax returns. In each of its tax jurisdictions the Company recognizes a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. For interim periods, the Company estimates its annual effective tax rate by forecasting its annual income before income tax, taxable income and tax expense in each of its tax jurisdictions. The Company makes judgments regarding future events and related estimates especially as they pertain to forecasting of the Company’s effective tax rate, the potential realization of deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.

      Certain of the Company’s foreign tax credit carryforwards are scheduled to expire in 2011. Although the Company intends to make use of all available tax planning strategies in order to be able to utilize these carryforwards, under the “more likely than not” approach of evaluating the associated deferred tax asset the Company determined that a valuation allowance was necessary. In December 2003 the Company established a valuation allowance of $10.2 million, which resulted in a charge against earnings. At December 31, 2004, the Company’s valuation allowance related to the potential realization of deferred tax assets was $10.3 million.

Years Ended December 31, 2004 and 2003

      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.

      Revenues. Revenues from high specification floaters decreased $9.0 million during the year ended December 31, 2004, compared to the same period in 2003.

      Utilization fell to 80% during 2004 from 87% in 2003 (excluding the Ocean Rover) and negatively impacted revenue by $24.6 million. Each of the following rigs operated during all or most of 2003 but their utilization in 2004 declined primarily due to:

      Partially offsetting the overall decline in utilization were improvements in utilization from the Ocean Valiant, which operated all of 2004, compared to 2003, when this rig was in a shipyard for approximately three months for a 5-year survey and scheduled maintenance.

      Lower overall average operating dayrates in 2004, as compared to 2003, resulted in a $6.0 million reduction in revenue. Average operating dayrates fell to $90,300 during 2004 from $95,300 during 2003 (excluding the Ocean Rover). The lower average dayrates in 2004 were primarily the result of soft market conditions in the U.S. GOM in the first half of 2004 as several of these high specification floaters accepted jobs in the mid-water depth market.

      The unfavorable revenue variance for high specification rigs in 2004 compared to 2003 was also partially offset by $22.7 million in additional revenue in 2004 contributed by the Ocean Rover as it continued its drilling program offshore Malaysia. This rig commenced drilling operations in July 2003 after completion of its upgrade to high specification capabilities which began in 2002.

      Contract Drilling Expense. Contract drilling expense for high specification floaters for the year ended December 31, 2004 increased $15.3 million compared to the same period in 2003. Higher contract drilling expenses were primarily due to:

      Partially offsetting the overall higher contract drilling expenses during 2004 were lower expenses for the Ocean Valiant, which incurred higher costs during 2003 for a 5-year survey and maintenance repairs.

      Revenues. Revenues from other semisubmersibles for the year ended December 31, 2004 increased $58.8 million compared to the same period in 2003.

      Improvements in utilization contributed $43.0 million to the higher revenues in 2004. Utilization rose to 75% during 2004 (excluding the Ocean Liberator) compared to 64% in 2003 (excluding the Ocean Century, Ocean Prospector, Ocean Liberator and Ocean Vanguard). Utilization improved for:

      These utilization improvements were partially offset by a decline in utilization for the Ocean Concord, which was stacked for six months in 2004 for a 5-year survey and various repairs. The rig then entered a shipyard for life enhancement maintenance, as compared to 2003 when it worked most of the year.

      The average operating dayrate for other semisubmersibles fell from $57,800 during 2003 (excluding the Ocean Vanguard) to $56,500 during 2004, reducing revenues by $7.2 million. The most significant reductions in average operating dayrates were to:

      Partially offsetting the overall lower average operating dayrates was an improvement in the average operating dayrate for the Ocean Worker (from $55,700 to $67,000). The Ocean Worker operated in the Mexican GOM throughout 2004. In 2003 the rig operated in the U.S. GOM for seven months at a lower average dayrate before moving to the Mexican GOM.

      Revenues for the Ocean Vanguard improved $13.8 million in 2004 compared to 2003 due to a higher average operating dayrate in 2004. This semisubmersible rig had an average operating dayrate of $77,300 during 2004, compared to $10,000 in 2003 which was earned under a bareboat charter.

      Contract Drilling Expense. Contract drilling expense for other semisubmersibles increased $47.9 million during 2004, as compared to 2003, primarily due to:

      Partially offsetting the increase in contract drilling expense in 2004 were lower costs compared to 2003 due to:

      Revenues. Revenues from jack-ups increased $80.6 million during 2004 compared to 2003.

      The average operating dayrate for jack-ups rose to $37,800 in 2004 from $28,100 in 2003 resulting in a $34.3 million improvement in revenues. All of the Company’s jack-ups in the GOM experienced an increase in average dayrate primarily due to a tighter market for this class of equipment in the U.S. GOM.

      Utilization rose to 86% during 2004 from 68% during 2003, resulting in a $35.4 million increase in revenue. Significant increases in utilization were primarily due to:

      Partially offsetting the improvement in utilization was:

      In addition, revenues in 2004 included $10.9 million related to the amortization of lump-sum mobilization fees.

      Contract Drilling Expense. Contract drilling expense for jack-ups during 2004 increased $17.2 million from 2003 primarily due to:

      Partially offsetting the higher contract drilling expenses in 2004 were higher comparative expenses during 2003 for:

      Revenues related to reimbursable items, offset by the related expenditures for these items, were $3.4 million in 2004 compared to $2.8 million in 2003. Reimbursable expenses include items that the Company purchases, and/or services it performs, at the request of its customers. The Company charges its customers for purchases and/or services performed on their behalf at cost, plus a mark-up where applicable. Therefore, net reimbursables fluctuate based on customer requirements which vary.

      Depreciation expense for the year ended December 31, 2004 increased $3.2 million to $178.8 million, compared to $175.6 million in 2003, primarily due to additional depreciation expense associated with:

      Partially offsetting the increases noted above was higher depreciation expense of $5.3 million during the first quarter of 2003 prior to the Company’s adjustment of the estimated service lives and salvage values for most of its drilling rigs, effective April 1, 2003, to better reflect their remaining economic lives and salvage values. See “— Critical Accounting Estimates.”

      General and administrative expense for 2004 of $32.8 million increased $3.9 million, as compared to $28.9 million for 2003. This increase was primarily due to higher payroll costs, costs related to compliance with the Sarbanes-Oxley Act of 2002, higher external audit fees and higher net building expenses due to lower rental income from tenants.

      The $1.6 million loss on the sale and disposition of assets in 2004 primarily related to the write-off of equipment that was lost during Hurricane Ivan.

      The loss on the sale and disposition of assets of $0.9 million during 2003 primarily related to the sale of two of the Company’s semisubmersible drilling rigs, the Ocean Century and Ocean Prospector. These rigs, which had been cold stacked since July 1998 and October 1998, respectively, were permanently retired from service as offshore drilling rigs and written down by $1.6 million to their fair market values in September 2003 and subsequently sold for $375,000 each (pre-tax) in December 2003.

      Interest expense of $30.3 million in 2004 was $6.4 million higher than interest expense of $23.9 million in 2003 primarily due to interest on the 5.15% Senior Notes issued August 27, 2004 and lower interest expense in 2003 as a result of interest capitalized relating to the upgrade of the Ocean Rover which was completed in July 2003. See Note 1 “— General Information — Capitalized Interest” and Note 7 “— Long-Term Debt” in Item 8 of this report.

      A gain on the sale of marketable securities of $0.3 million occurred in 2004 compared to a $6.9 million loss on the sale of marketable securities in 2003. See Note 3 “Marketable Securities” in Item 8 of this report.

      The Company recognized an $11.4 million gain as a result of the settlement of its lawsuit against an equipment manufacturer. The lawsuit was the result of an incident that had occurred in 2002 on the Ocean Baroness.

      Other income of $1.1 million for the year ended December 31, 2004 included $1.4 million in foreign currency transaction losses Other income of $2.9 million for the year ended December 31, 2003 related primarily to pre-tax gains 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 this report.

      Net income tax benefit (expense) is a function of the mix between the Company’s domestic and international pre-tax earnings (losses), as well as the mix of international tax jurisdictions in which the Company operates. Income tax expense of $3.7 million was recognized on a pre-tax loss of $3.5 million for the year ended December 31, 2004, compared to a tax benefit of $5.8 million recognized on a pre-tax loss of $54.2 million in 2003.

      In 2002 the Company formed a Cayman Island corporation, Diamond Offshore International Limited, which is a wholly owned subsidiary. Certain of the Company’s rigs that operate internationally are now owned and operated, directly or indirectly, by Diamond Offshore International Limited. Effective January 1, 2003, the Company began to postpone remittance of the earnings from this subsidiary to the U.S. and to indefinitely reinvest these earnings internationally. Consequently, no U.S. taxes were provided on these earnings and no U.S. tax benefits were recognized on losses during 2004 or 2003.

      The Company recognized tax expense of $3.7 million for 2004 despite a $3.5 million pre-tax loss primarily as a result of $20.5 million of unrepatriated losses in international tax jurisdictions for which no U.S benefits were recognized. Tax expense for 2004 also included $2.5 million associated with a revision to estimates in tax balance sheet accounts, a tax benefit of $5.2 million related to goodwill arising from the merger with Arethusa (Off-Shore) Limited in 1996 and a tax benefit of $4.5 million due to the reversal of a tax liability associated with the Ocean Alliance Lease-Leaseback.

      In 2003 a valuation allowance of $10.2 million, which resulted in a charge against earnings, was established for certain of the Company’s foreign tax credit carryforwards which will begin to expire in 2011. Although the Company intends to make use of all available tax planning strategies in order to be able to utilize these carryforwards, under the “more likely than not” approach of evaluating the associated deferred tax asset the Company determined that a valuation allowance was necessary. In addition, in 2003 the Company reduced its deferred tax liability by $3.7 million related to the deductibility of goodwill associated with a 1996 acquisition.

      On October 22, 2004, the American Jobs Creation Act (“AJCA”) was signed into law. The AJCA includes a provision allowing a deduction of 85% for certain foreign earnings that are repatriated. The AJCA provides the Company the opportunity to elect to apply this provision to qualifying earnings repatriations in 2005. Based on the existing language in the AJCA and current guidance, the Company does not expect to repatriate undistributed earnings. To the extent Congress or the Treasury Department provides additional clarifying language on key elements of the provision, the Company will consider the effects, if any, of such information and will re-evaluate, as necessary, its intentions with respect to the repatriation of certain foreign earnings. Should the Company, upon consideration of any such potential clarifying language, ultimately elect to apply the repatriation provision of the AJCA, the Company does not expect that the impact of such an election would be material to its results of operations.

Years Ended December 31, 2003 and 2002

      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.

      Revenues. Revenues from high specification floaters decreased $1.0 million during the year ended December 31, 2003, compared to the same period in 2002.

      Lower average operating dayrates for most of the rigs in this classification resulted in a $39.0 million reduction in revenue. Average operating dayrates fell from $109,500 during 2002 to $95,300 (excluding the

Ocean Rover) during 2003. Significant reductions in average operating dayrates were experienced by certain rigs located in:

      An overall improvement in utilization for high specification floaters during 2003 contributed $18.7 million to revenues and partially offset the negative effect of lower average operating dayrates. Utilization improved to 87% for the year ended December 31, 2003 from 83% for the same period in 2002 (excluding the Ocean Rover). Utilization improved for:

      Partially offsetting the overall improvement in utilization was a decline in utilization for the Ocean Valiant, which was stacked in 2003 for approximately three more months than in 2002.

      The unfavorable revenue variance for high specification rigs in 2003 compared to 2002 was also partially offset by $12.7 million in revenue contributed by the Ocean Rover, which began its drilling program offshore Malaysia in July 2003 upon completion of its upgrade to high specification capabilities. The rig spent all of 2002 undergoing its upgrade.

      Contract Drilling Expense. Contract drilling expense for high specification floaters for the year ended December 31, 2003 increased $3.7 million compared to the same period in 2002. Higher contract drilling expenses were primarily due to:

      These higher contract drilling expenses were partially offset by lower expenses in 2003 compared to 2002 primarily due to:

      Revenues. Revenues from other semisubmersibles for the year ended December 31, 2003 were $57.1 million lower compared to the same period in 2002.

      A decline in the average operating dayrate (excluding the Ocean Patriot and the Ocean Vanguard), from $67,900 during 2002 to $60,900 during 2003, resulted in lower revenues of $42.5 million. The most significant decreases in average operating dayrates were to certain rigs located in:

      Lower utilization of 57% (excluding the Ocean Patriot and the Ocean Vanguard) during 2003 compared to 61% during 2002 resulted in a $27.3 million revenue decrease. Utilization declined primarily due to:

      Partially offsetting the decline in revenue in 2003 compared to 2002 were improvements in revenue from:

      Contract Drilling Expense. Contract drilling expense for other semisubmersibles during the year ended December 31, 2003 was higher by $16.4 million compared to the same period in 2002 primarily due to additional costs during 2003 associated with:

      Partially offsetting the higher contract drilling expenses during 2003 were lower expenses from the Ocean Liberator, Ocean New Era, Ocean Voyager and Ocean Endeavor, which were cold stacked all of 2003 but were ready stacked during most or part of 2002.

      Revenues. Revenues from jack-ups decreased $1.6 million during the year ended December 31, 2003, compared to the same period in 2002.

      Utilization fell to 68% during 2003 from 71% during 2002, resulting in a $6.3 million reduction in revenue. The decline in utilization was primarily from:

      The lower overall revenue in 2003 was partially offset by a $13.6 million increase in revenue due to utilization improvements from:

      Also offsetting the unfavorable revenue variance for jack-up rigs was an overall improvement in the average operating dayrate, from $27,300 during 2002 to $28,100 during 2003, which increased revenue by $4.7 million in 2003.

      Contract Drilling Expense. Contract drilling expense for jack-ups during 2003 increased $4.6 million from 2002 primarily due to:

      Partially offsetting the higher contract drilling expenses were:

      Integrated services had an operating loss of $0.5 million in 2003 comprised of project income of $0.4 million from the completion of one turnkey plug and abandonment project in the Gulf of Mexico during the first quarter of 2003 that was more than offset by operating overhead costs. During 2002, an operating loss of $0.6 million resulted primarily from an unprofitable turnkey project in the Gulf of Mexico. The Company has elected not to pursue contracts for integrated services except in very limited circumstances.

      Other operating expense of $136,000 for the year ended December 31, 2003 decreased $7.4 million compared to operating income of $7.3 million for the year ended December 31, 2002. For the year ended December 31, 2003 other operating expense of $2.4 million was primarily due to the write off of a contract dispute with a customer and a reserve for pending litigation. These operating expenses in 2003 were partially offset by operating income of $2.3 million primarily from the reimbursement of foreign taxes paid by the Company’s customers on its behalf, settlements with the Company’s customers related to prior years’ disputes and the reversal of a reserve related to a prior year customer contract audit.

      Other operating income of $7.3 million for the year ended December 31, 2002 resulted primarily from a $5.9 million reimbursement of prior year foreign income tax to be received by the Company from its customers and related 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 benefit (expense)” in the Company’s Consolidated Statement of Operations.

      Other operating income in 2002 also included 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.

      Reimbursable expenses include items that the Company purchases, and/or services it performs, at the request of its customers. Revenues related to reimbursable items, offset by the related expenditures for these items, were $2.8 million in 2003 compared to $2.5 million in 2002.

      Depreciation expense for the year ended December 31, 2003 decreased $1.9 million to $175.6 million compared to $177.5 million in 2002. A $22.9 million pre-tax reduction in depreciation expense resulted from increasing the estimated service lives and salvage values of most of the Company’s drilling rigs, effective April 1, 2003, to better reflect their remaining economic lives and salvage values. This decrease was partially offset by additional depreciation from the Ocean Vanguard and the Ocean Patriot, which the Company acquired in December 2002 and March 2003, respectively. Depreciation also increased due to additional depreciation for five of the Company’s recently upgraded jack-up rigs, additional depreciation for the Ocean Rover, which completed its upgrade in July 2003 and additional depreciation for the Ocean Baroness, which completed its upgrade in March 2002.

      A loss on the sale and disposition of assets of $0.9 million occurred during 2003 primarily due to the sale of two of the Company’s semisubmersible drilling rigs, the Ocean Century and Ocean Prospector. These rigs, which had been cold stacked since July 1998 and October 1998, respectively, were permanently retired from service as offshore drilling rigs and written down by $1.6 million to their fair market values in September 2003 and subsequently sold for $375,000 each (pre-tax) in December 2003. A gain on the sale of assets of approximately $84,000 occurred in 2002.

      Interest income of $12.0 million earned in 2003 declined $17.8 million, from $29.8 million earned in 2002. These earnings were lower primarily due to lower interest rates earned on cash and marketable securities compared to 2002 and less cash investment during 2003.

      A loss on the sale of marketable securities of $6.9 million occurred in 2003 compared to a $36.5 million gain on the sale of marketable securities in 2002. See Note 3 “Marketable Securities” in Item 8 of this report.

      Other income of $2.9 million for the year ended December 31, 2003 increased $1.4 million from other income of $1.5 million for the same period in 2002. Other income for both years ended December 31, 2003 and 2002 was primarily from a pre-tax gain on foreign exchange forward contracts of $2.5 million and $1.1 million, respectively. See Note 4 “— Derivative Financial Instruments — Forward Exchange Contracts” in Item 8 of this report.

      An income tax benefit of $5.8 million was recognized on a pre-tax loss of $54.2 million for the year ended December 31, 2003, compared to tax expense of $33.7 million recognized on pre-tax income of $96.2 million in 2002.

      In 2002 the Company formed a Cayman Island corporation, Diamond Offshore International Limited, which is a wholly owned subsidiary of the Company. Certain of the Company’s rigs that operate internationally are now owned and operated, directly or indirectly, by Diamond Offshore International Limited. Effective January 1, 2003, the Company began to postpone remittance of the earnings from this subsidiary to the U.S.

and to indefinitely reinvest these earnings internationally. Consequently, no U.S. taxes were provided on these earnings and no U.S. tax benefits were recognized on losses during 2003.

      In 2003 a valuation allowance of $10.2 million, which resulted in a charge against earnings, was established for certain of the Company’s foreign tax credit carryforwards which will begin to expire in 2011. Although the Company intends to make use of all available tax planning strategies in order to be able to utilize these carryforwards, under the “more likely than not” approach of evaluating the associated deferred tax asset the Company determined that a valuation allowance was necessary. In addition, in 2003 the Company reduced its deferred tax liability by $3.7 million related to the deductibility of goodwill associated with a 1996 acquisition.

      In the first quarter of 2002, a portion of the earnings from the Company’s U.K. subsidiaries was considered to be indefinitely reinvested and no U.S. taxes were provided on those earnings. The effect of the indefinite reinvestment of the U.K. 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.” These U.K. subsidiaries are now owned, directly or indirectly, by Diamond Offshore International Limited. Consequently, earnings and losses from the U.K. subsidiaries for 2003 are part of the earnings and losses of the Cayman Island subsidiary on which no U.S. taxes are provided.

Sources of Liquidity and Capital Resources

      The Company’s principal sources of liquidity and capital resources are its cash flows from operations, proceeds from the issuance of debt securities and other borrowings and its cash reserves. At December 31, 2004, the Company had $266.0 million in “Cash and cash equivalents” and $661.8 million in “Investments and marketable securities,” representing the Company’s investment of cash available for current operations.

      Cash Flows from Operations. The Company operates in an industry that has been, and is expected to continue to be, extremely competitive and highly cyclical. The dayrates received by the Company’s drilling rigs and rig utilization rates are a function of rig supply and demand in the marketplace which is generally correlated with the price of oil and natural gas. As utilization rates increase, dayrates tend to increase as well reflecting the lower supply of available rigs, and vice versa. The same factors, primarily demand for drilling services, which is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development as well as a variety of political and economic factors, and availability of rigs in a particular geographical region, affect both dayrates and utilization rates. These factors are not within the Company’s control and are difficult to predict. For a description of other factors that could affect the Company’s cash flows from operations, see “— Overview — Results of Operations and Industry Conditions” and “— Forward-Looking Statements.”

      Shelf Registration. The Company has the ability to issue an aggregate of approximately $117.5 million in debt, equity and other securities under a shelf registration statement. In addition, the Company may issue, from time to time, up to eight million shares of common stock, shares which are registered under an acquisition shelf registration statement (upon effectiveness of an amendment thereto reflecting the effect of the two-for-one stock split declared in July 1997), in connection with one or more acquisitions by the Company of securities or assets of other businesses.

Liquidity and Capital Requirements

      The Company’s liquidity and capital requirements are primarily a function of the Company’s working capital needs, capital expenditures and debt service requirements. Cash required to meet the Company’s capital commitments is determined by evaluating the need to upgrade rigs to meet specific customer requirements and by evaluating the Company’s ongoing rig equipment replacement and enhancement programs, including water depth and drilling capability upgrades. It is management’s opinion that operating cash flows and the Company’s cash reserves will be sufficient to meet these capital commitments; however, the Company will continue to make periodic assessments based on industry conditions. In addition, the Company may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital

expenditures, the acquisition of assets and businesses or for general corporate purposes. The Company’s ability to effect any such issuance will be dependent on the Company’s results of operations, its current financial condition, current market conditions and other factors beyond its control.

      The Company believes it has the financial resources needed to meet its business requirements in the foreseeable future, including capital expenditures for rig upgrades and continuing rig enhancements, and working capital requirements.

      Contractual Cash Obligations. The following table sets forth the Company’s contractual cash obligations at December 31, 2004.

      Purchase obligations at December 31, 2004 related to direct rig operations are excluded from the above table as there are no purchase obligations for major rig upgrades or any other significant obligations other than those necessary for the normal course of business that existed at December 31, 2004.

      Payments of the Company’s long-term debt, including interest, could be accelerated due to certain rights that holders of the Company’s debentures have to put the securities to the Company. See the discussion below.

      On August 27, 2004, the Company issued $250.0 million aggregate principal amount of 5.15% Senior Notes Due September 1, 2014 (the “5.15% Senior Notes”). The 5.15% Senior Notes were issued at an offering price of 99.759% of the principal amount and resulted in net proceeds to the Company of $247.8 million.

      The 5.15% Senior Notes bear interest at 5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year, beginning March 1, 2005, and mature on September 1, 2014. The 5.15% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. The Company has the right to redeem all or a portion of the 5.15% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.

      On April 11, 2001, the Company issued $460.0 million principal amount of 1.5% Convertible Senior Debentures Due 2031 (the “1.5% Debentures”) which are due April 15, 2031. The 1.5% Debentures are convertible into shares of the Company’s common stock at an initial conversion rate of 20.3978 shares per $1,000 principal amount of the 1.5% Debentures, subject to adjustment in certain circumstances. Upon conversion, the Company has the right to deliver cash in lieu of shares of the Company’s common stock.

      Interest of 1.5% per year on the outstanding principal amount of the 1.5% Debentures is payable semiannually in arrears on April 15 and October 15 of each year. In addition, under certain circumstances the Company will pay contingent interest to holders of the 1.5% Debentures during any six-month period commencing after April 14, 2008. See “1.5% Debentures” in Note 7 to the Company’s Consolidated Financial

Statements in Item 8 of this report. The 1.5% Debentures are unsecured obligations of Diamond Offshore Drilling, Inc.

      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) for a purchase price equal to 100% of the principal amount plus accrued and unpaid interest.

      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.

      The Company’s Zero Coupon Convertible Debentures Due 2020 (the “Zero Coupon Debentures”) issued on June 6, 2000 at a price of $499.60 per $1,000 debenture are due June 6, 2020, 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. In addition, holders may require the Company to purchase, for cash, all or a portion of their Zero Coupon Debentures upon a change in control (as defined) for a purchase price equal to the accreted value through the date of repurchase. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

      The Company has the right to redeem the Zero Coupon Debentures, in whole or in part, on or 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 June 6, 2005, June 6, 2010 and June 6, 2015 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. As of December 31, 2004, the aggregate accreted value of the Zero Coupon Debentures was $471.3 million. Because the holders of the debentures have the right to require the Company to repurchase the debentures within one year, the aggregate accreted value of $471.3 million is classified as a current liability in the Company’s Consolidated Balance Sheet at December 31, 2004. The net proceeds from the 5.15% Senior Notes issued in August 2004 are available to partially fund a refinancing of these debentures.

      On June 6, 2005, the aggregate accreted value of the Zero Coupon Debentures outstanding as of the date of this report will be approximately $478 million. The aggregate principal amount at maturity will be $805.0 million assuming no conversions or redemptions occur prior to the maturity date.

      The Company is contingently liable as of December 31, 2004 in the amount of $76.1 million under certain performance, bid, supersedeas and custom bonds and letters of credit. Agreements related to approximately $34.0 million of multi-year performance bonds can require cash collateral for the full line at any time for any reason. Holders of agreements related to another $4.6 million currently have the option to require cash collateral due to the lowering of the Company’s credit rating on April 27, 2004. As of December 31, 2004 the Company had not been required to make any cash collateral deposits with respect to these agreements. The remaining agreements cannot require cash collateral except in events of default. On the Company’s behalf, banks have issued letters of credit securing certain of these bonds.

      The Company’s current credit rating is Baa2 for Moody’s Investors Services (“Moody’s”) and A- for Standard & Poor’s (“S&P”). In 2003 Moody’s lowered its ratings of the Company’s long-term debt to Baa1 from A3 and on April 27, 2004 lowered its rating from Baa1 to Baa2 and changed the rating outlook from negative to stable. On July 27, 2004, S&P lowered the Company’s debt rating from A to A- and rated its outlook as stable. Although the Company’s long-term ratings continue at investment grade levels, lower ratings could result in higher interest rates on future debt issuances.

      In January 2005, the Company announced the initiation of a major upgrade of its Victory-class semisubmersible, the Ocean Endeavor, for ultra-deepwater service. The modernized rig will be designed to operate in up to 10,000 feet of water at an estimated upgrade cost of approximately $250 million of which approximately $110 million is expected to be expended in 2005. The rig will be mobilized to a shipyard in Singapore where work is scheduled to commence in the second quarter of 2005. Delivery of the upgraded rig is expected in approximately two years.

      The Company has budgeted an additional $115 million of capital expenditures in 2005 associated with its ongoing rig equipment replacement and enhancement programs, and other corporate requirements. The Company expects to finance its 2005 capital expenditures through the use of existing cash balances or internally generated funds.

      During the year ended December 31, 2004, the Company spent approximately $13 million to upgrade one of its high specification semisubmersible units, the Ocean America, with capabilities making it more suitable for developmental drilling. In addition, the Company spent $76.2 million on its continuing rig capital maintenance program (other than rig upgrades) and to meet other corporate capital expenditure requirements in 2004.

      The Company has completed its two-year program to expand the capabilities of its jack-up fleet by significantly upgrading six of its 14 jack-up rigs at an aggregate cost of approximately $94 million. Three of these upgrades were completed in 2002, two in 2003 and one in early 2004.

      At December 31, 2004 and 2003, the Company had no off-balance sheet debt.

Historical Cash Flows

      The following is a discussion of the Company’s historical cash flows from operating, investing and financing activities for the year ended December 31, 2004 compared to the same period in 2003.

      Cash flows from operations in 2004 increased $45.8 million or 28% over cash generated by operating activities in 2003. The increase in cash flow from operations in 2004 is the result of higher utilization and average dayrates earned by the Company’s offshore drilling units as a result of an increase in overall demand

for offshore contract drilling services, particularly in the second half of the year. These favorable trends were negatively impacted by reactivation costs for previously cold-stacked rigs and repair costs of damages caused by Hurricane Ivan in the third quarter of 2004.

      The Company used $233.7 million for investing activities in 2004 compared to $152.2 million in 2003. In 2004 the Company used $229.3 million for net purchases of marketable securities and capital expenditures compared to a use of $156.9 million in 2003. The increase in cash usage in 2004 compared to 2003 was primarily due to higher cash outflows related to the net sale and maturity of certain of the Company’s investments in marketable securities, which more than offset the cash flow effect of reduced capital spending in 2004.

      In early 2004 the Company completed its two-year program to expand the capabilities of its jack-up fleet (see “— Liquidity and Capital Requirements — Capital Expenditures”) and focused primarily on its ongoing capital maintenance program. During 2003 the Company spent $65.0 million (including $1.5 million of inventory) for the purchase of the semisubmersible rig, the Ocean Patriot, and $208.5 million for capital projects including the Ocean Rover upgrade which was completed in July 2003, and the upgrade of three jack-up rigs under the two-year upgrade program.

      In the second quarter of 2004, based on the expectation that higher interest rates could be achieved by investing in Australian dollar-based securities, the Company invested $42.1 million (equivalent to 60.0 million Australian dollars) in Australian dollar time deposits with expirations ranging from May 5, 2004 to March 9, 2005, of which $31.2 million (equivalent to 45.0 million Australian dollars) matured during 2004. In 2003, the Company settled its remaining forward exchange contracts, which it entered into in 2002, and received $2.5 million in cash. The Company did not enter into any similar forward exchange contracts in 2004.

      The Company may utilize forward exchange contracts from time to time to hedge its exposure to changes in exchange rates between U.S. dollars and the local currencies. In February 2005, the Company entered into a forward exchange contract requiring it to purchase the equivalent of approximately $3.0 million in Mexican pesos monthly beginning in March 2005 through May 2005.

      On August 27, 2004, the Company issued $250 million aggregate principal amount of its 5.15% Senior Notes at an offering price of 99.759% of the principal amount, which resulted in net proceeds to the Company of $247.8 million. See “— Liquidity and Capital Requirements — 5.15% Senior Notes.”

      Cash dividends paid to stockholders were $32.3 million in 2004 compared to $57.0 million in 2003. In the second half of 2003, the Company decided to reduce its quarterly cash dividend from $0.125 per share of common stock to $.0625 per share of common stock. Quarterly dividends have continued to be paid at the reduced rate. On January 25, 2005, the Company declared a dividend of $0.0625 per share of the Company’s common stock payable March 1, 2005 to stockholders of record on February 1, 2005.

      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. During the years ended December 31, 2004 and 2003, the Company purchased 782,200 shares of its common stock at an aggregate cost of $18.1 million (or $23.11 average cost per share) and 1,014,000 shares of its common stock at an aggregate cost of $18.2 million (or $17.96 average cost per share), respectively.

      Cash used in financing activities in 2004 and 2003 also included payments of $12.0 million and $11.2 million, respectively, in accordance with the Company’s December 2000 lease-leaseback agreement for the Ocean Alliance with a European bank. As of December 31, 2004, one installment of $13.7 million remains and is payable in December 2005. This financing agreement has an effective interest rate of 7.13% and is an unsecured obligation of the Company.

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 Mexico, Brazil, the U.K., Australia, Indonesia and Malaysia. When possible, the Company 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. At present, however, only a limited number of the Company’s contracts are payable both in U.S. dollars and the local currency.

      Currency translation adjustments are generally accumulated in a separate section of stockholders’ equity. If the Company ceases its operations in a currency environment, the accumulated adjustments would be 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.

Recent Accounting Pronouncements

      In December 2004 the Financial Accounting Standards Board (“FASB”) revised SFAS 123, “Accounting for Stock-Based Compensation” (“SFAS 123®”). This statement supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. This statement requires that the compensation cost relating to share-based payment transactions be

recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS 123® is effective as of the first interim or annual reporting period beginning after June 15, 2005. This statement applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date. The Company’s adoption of SFAS 123® is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

      In December 2004 the FASB issued SFAS 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions” (“SFAS 153”). The amendments made by SFAS 153 are based on the principle that exchanges of nonmonetary assets should be based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 with earlier adoption permitted. The provisions of this statement shall be applied prospectively. The Company’s adoption of SFAS 153 is not 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 Securities Exchange Act of 1934, as amended (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,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. Statements 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:

      Such statements inherently are subject to a variety of risks and uncertainties that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. Such risks and uncertainties include, among others, the following:

      The risks included here are not exhaustive. Other sections of this report and the Company’s other filings with the Securities and Exchange Commission 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.

      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, 2004 and December 31, 2003, 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 or 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.

      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 stockholders’ 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, 2004 and December 31, 2003, 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 in market interest rates on the Company’s earnings or stockholders’ 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, 2004 and December 31, 2003 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 $177.8 million and $150.5 million as of December 31, 2004 and 2003, respectively. A 100-basis point decrease would result in an increase in market value of $217.3 million and $186.8 million as of December 31, 2004 and 2003, respectively.

      Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. During 2004 the Company invested in fixed-rate Australian dollar

time deposits and at December 31, 2004 15.0 million Australian dollars (equivalent to $11.6 million) of time deposits were included in “Investments and marketable securities” in the Consolidated Balance Sheet. The sensitivity analysis assumes an instantaneous 20% change in foreign currency exchange rates versus the U.S. dollar from their levels at December 31, 2004.

      The following table presents the Company’s market risk by category (interest rates and foreign currency exchange rates):

      (a) The fair market value of the Company’s investment in marketable securities is based on the quoted closing market prices on December 31, 2004 and December 31, 2003.

      (b) The fair values of the Company’s 5.15% Senior Notes, which were issued in August 2004, 1.5% Debentures due 2031 and Zero Coupon Debentures due 2020 are based on the quoted closing market prices on December 31, 2004 and December 31, 2003. The fair value of the Company’s Ocean Alliance lease-leaseback agreement is based on the present value of estimated future cash flows using a discount rate of 4.27% for December 31, 2004 and 2.08% for December 31, 2003.

      (c) The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at December 31, 2004 and December 31, 2003.

      (d) The calculation of estimated foreign exchange risk is based on assumed adverse changes in the underlying reference price or index of a decrease in foreign exchange rates of 20% at December 31, 2004.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

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, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Diamond Offshore Drilling, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting (such management assessment is included in Item 9A of this Form 10-K) and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Deloitte & Touche LLP

Houston, Texas

March 2, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Diamond Offshore Drilling, Inc. and Subsidiaries

Houston, Texas

      We have audited management’s assessment, included in Item 9A of this Form 10-K under the heading “Management’s Annual Report on Internal Control Over Financial Reporting,” that Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

      A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

      Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 2, 2005 expressed an unqualified opinion on those financial statements.

Deloitte & Touche LLP

Houston, Texas

March 2, 2005

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS