Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yesþ Noo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ

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.
Yesþ Noo

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.oþ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filerþ Accelerated Filero Non-Accelerated Filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

     Portions of the definitive proxy statement relating to the 20062007 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2005,2006, are incorporated by reference in Part III of this report.

     Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a current fleet of 44 offshore rigs consisting of 30 semisubmersibles, 13 jack-ups and one drillship. In addition, we have two jack-up drilling units on order at shipyards in Brownsville, Texas and Singapore, which weSingapore. We expect to be completed indelivery of both of these units during the first quarter of 2008. Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.

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

     Semisubmersibles.  We own and operate 30 semisubmersibles, (includingconsisting of nine high-specification and 21 intermediate semisubmersible rigs, of which 19 are currently operating and the remaining two units are currently undergoing or will commence a major upgrade).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. We have three semisubmersible rigs in our fleet with this capability.

     Our 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 compared to intermediate semisubmersibles. As of January 30, 2006,29, 2007, seven of our nine high-specification semisubmersibles were located in the U.S. Gulf of Mexico, or GOM, while the remaining two rigs were located offshore Brazil and Malaysia, respectively.Malaysia.

     Our intermediate 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 30, 2006,29, 2007, we had 19 intermediate semisubmersible rigs including the recently reactivatedOcean New Era,drilling offshore various locations around the world. Five of these semisubmersibles were located in the GOM; fourthree were located in the Gulf of Mexico offshore Mexico, or Mexican GOM, four were located in the North Sea, and two each were located offshore Australia, two were located offshore Brazil and Malaysia, respectively.one was located offshore each of New Zealand, Vietnam and Egypt.

     In January 2006, we announced that we would begin a majorOur remaining two intermediate semisubmersibles, theOcean EndeavorandOcean Monarch,are currently in Singapore. The shipyard portion of the upgrade of theOcean Endeavorhas been completed, and the rig is currently undergoing sea trials and commissioning. The upgrade of theOcean Monarch (formerly theEnserch Garden Banks)commenced in mid-2006. We acquired this Victory-class, intermediate semisubmersible rig in August 2005 and are currently preparing to mobilize the rig from the GOM to a shipyard in Singapore for an upgrade to ultra-deepwater capability. TheOcean Endeavor, also a Victory-class semisubmersible, is currently in a shipyard in Singapore for a similar upgrade. Victory-class semisubmersible rigs were originally constructed as intermediate class units with a cruciform hull configuration, which lends itself well to modernization because of the unit’s characteristically long fatigue-life and advantageous stress characteristics. See “ —Fleet Enhancements and Additions.”

     Jack-ups.  We currently own and operate 13 jack-up drilling rigs. 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. Our 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

     Most of our jack-up rigs are equipped with a cantilever system that enables the 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 enjoyedearned higher dayrates and achieved greater utilization compared to slot rigs.

     As of January 30, 2006, 1129, 2007, nine of our 13 jack-up rigs were located in the GOM. Of theseSix of those rigs eight are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Both ofOf our four remaining jack-up rigs, three are internationally based and are independent-leg cantilevered rigs; one was located offshore Indonesia, one was located offshore Africa and the other rig was located offshore Qatar as of January 30, 2006.Qatar. Our remaining jack-up rig was located in the Mexican GOM and is also an independent-leg cantilever unit.

     In addition, we have two premium jack-up rigs currently under construction. We expect delivery of both drilling rigs inof these units during the first quarter of 2008. See “ —Fleet Enhancements and Additions.”

     Drillship.  We have one high-specification drillship, theOcean Clipper,which was located offshore Brazil as of January 30, 2006.29, 2007. 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. Deepwater drillships compete in many of the same markets as do high-specification semisubmersible rigs.

     Fleet Enhancements and Additions.  Our strategy is to economically upgrade our fleet to meet customer demand for advanced, efficient, high-tech rigs, particularly deepwater semisubmersibles, in order to maximize the utilization and dayrates earned by the rigs in our fleet. Since 1995, we have increased the number of our rigs capable of operating in 3,500 feet or more of water from three rigs to 12 (nine of which are high-specification units), primarily by upgrading our existing fleet. Five of these upgrades were to our Victory-class semisubmersible rigs. Onerigs, the design of which we believe is well-suited for significant upgrade projects. We have recently completed the shipyard portion of the upgrade of one of our otherremaining Victory-class rigs and another upgrade is currently being upgraded and another is scheduled for upgrade laterunderway in 2006.Singapore. We have two additional Victory-class rigs that are currently operating as intermediate semisubmersibles.

     In January 2006, we announced the initiation of a major upgrade of the Victory-class semisubmersible, theOcean Monarch, at an estimated cost of approximately $300 million. We acquired theOcean Monarchand its related equipment in August 2005 for $20 million, and we expect to mobilize the rig and equipment to a shipyard in Singapore in mid-2006. The modernized rig will be designed to operate in up to 10,000 feet of water in a moored configuration. We expect theOcean Monarchto be ready for deep water service in the fourth quarter of 2008.

     In the second quarter of 2005, we entered into agreements to construct two high-performance, premium jack-up rigs. The two new drilling units, theOcean Scepterand theOcean Shield,will beare being constructed in Brownsville, Texas and in Singapore, respectively, at an aggregate expected cost of approximately $300$320 million, including drill pipe and capitalized interest, of which $85.9$176.1 million hashad been spent through December 31, 2005.2006. Each newbuild jack-up rig will be equipped with a 70-foot cantilever package, be capable of drilling depths of up to 35,000 feet and have a hook load capacity of two million pounds. We expect delivery of both of these units induring the first quarter of 2008. See “Risk Factors” in Item 1A of this report.

     We will evaluate further rig acquisition and upgrade opportunities as they arise. However, we can provide no assurance whether or to what extent we will continue to make rig acquisitions or upgrades to our fleet. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Requirements” in Item 7 of this report.

     More detailed information concerning our fleet of mobile offshore drilling rigs, as of January 30, 2006,29, 2007, is set forth in the table below.

     The principal markets for our offshore contract drilling services are the following:

     We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the world as the market demands. See Note 16 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.

     We believe our presence in multiple markets is valuable in many respects. For example, we believe that our 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 we have gained through our Brazilian and North Sea operations has potential application worldwide. Additionally, we believe our performance for a customer in one market segment or area enables us to better understand that customer’s needs and better serve that customer in different market segments or other geographic locations.

     Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through competitive bidding, although it is not unusual for us to be awarded drilling contracts without competitive bidding. Our 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 our control. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for a substantial portion of our revenues. In addition, from time to time, our dayrate contracts may also provide for the ability to earn an incentive bonus from our customer 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, which we refer to as a well-to-well contract, or a fixed term, which we refer to as 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 to the contract. In addition, certain of our 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 also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension. See “Risk Factors —The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market”and “Risk

“Risk Factors —Our business involves numerous operating hazards, and we are not fully insured against all of them”in Item 1A of this report, which are incorporated herein by reference.

statements and other information with the United States Securities and Exchange Commission, or SEC. You may read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 450 Fifth100 F Street, N.W.N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the

lower demand, excess rig supply and low dayrates. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time.

     The majority of ourOur contracts with our customers for our drilling units provide for the payment of a fixed dayrate per rig operating day. However, manyday, although some contracts do provide for a limited escalation in dayrate due to increased operating costs incurred by us. Many of our operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond our control. The gross margin that we realize on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the terms of the contracts. WeIn addition, for contracts with dayrate escalation clauses, we may not be unableable to fully recover increased or unforeseen costs from our customers. Our inability to recover these increased or unforeseen costs from our customers which could adversely affect our financial position, results of operations and cash flows.

     Our customers may terminate some of our term drilling contracts if the drilling unit is destroyed or lost or if drilling operations are suspended for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial position, results of operations and cash flows.

hurricanes or fires. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations and environmental damage. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. In addition, offshore drilling operators are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to damage claims by oil and gas companies.companies or other parties.

     Although we maintain insurance, pollutionPollution and environmental risks generally are not fully insurable, and we do not typically retain loss-of-hire insurance policies to cover our rigs. Our insurance policies and contractual rights to indemnity may not adequately cover our losses, or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including, among other things, war risk, liability risk for certain amounts of excess coverage and certain physical damage risk. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position, results of operations or cash flows. In addition, thereThere can be no assurance that we will continue to carry the insurance we currently maintain or that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks.

     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 actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete.

     In 2003,As of the date of this report, we entered into contracts to operate four of ourhave three intermediate semisubmersible rigs and one jack-up rig drilling offshore Mexico for PEMEX, the national oil company of Mexico.Mexico, and have two additional intermediate semisubmersibles contracted to begin working for PEMEX in the third quarter of 2007. The terms of these contracts expose us to greater risks than we normally assume, such as exposure to greater environmental liability. In addition, each contract can be terminated by PEMEX on short-term notice, contractually or by statute, subject to certain conditions. While we believe that the financial terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have a negative impact on our future operations or financial results.

     Due to our international operations, we may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.

     Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, our wholly-owned Cayman Islands subsidiary. We do not intend to remit earnings from this subsidiary to the U.S., and we plan to indefinitely reinvest these earnings internationally. We have not provided for U.S. taxes on these earnings nor have we recognized any U.S. tax benefits on losses generated by the subsidiary. Should a distribution be made from the unremitted earnings of our subsidiary, we may be required to record additional U.S. income taxes that, if material, could have an adverse effect on our financial position, results of operations and cash flows.

     We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment and tax matters and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our management’s resources and other factors.

and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.

     In the United States, regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment apply to some of our operations. For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those operations. Laws and regulations protecting the environment have become moreincreasingly stringent, in recent years, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed.

     The United States Oil Pollution Act of 1990, or 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 us 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.

     The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations or cash flows.

     Loews Corporation, which we refer to as Loews, beneficially owns approximately 54.3%50.7% of our outstanding shares of common stock as of February 20, 2007 and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. One of those, James S. Tisch, the Chief Executive Officer and Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews and we may in the future enter into other agreements with Loews.

     Loews and its subsidiaries and we are generally engaged in businesses sufficiently different from each other as to make conflicts as to possible corporate opportunities unlikely. However, it is possible that Loews may in some circumstances be in direct or indirect competition with us, including competition with respect to certain business strategies and transactions that we may propose to undertake. In addition, potential conflicts of interest exist or could arise in the future for our directors that are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations. We cannot assure you that these conflicts of interest will not materially adversely affect us.

     We own 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 our corporate headquarters are located, two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, and a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, The Netherlands, Malaysia, Qatar, Singapore and Mexico to support our offshore drilling operations.

     Not applicable.

     Not applicable.

     We have included information on our executive officers in Part I of this report in reliance on General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors to serve until the next annual meeting of our 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 our executive officers is set forth below.

     James S. Tischhas served as our Chief Executive Officer since March 1998. Mr. Tisch has also served as Chairman of the Board since 1995 and as a director since June 1989. Mr. Tisch has served as Chief Executive Officer of Loews, a diversified holding company and our controlling stockholder, since January 1999. Mr. Tisch, a director of Loews since 1986, also serves as a director of CNA Financial Corporation, a 91%an 89% owned subsidiary of Loews.

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

     David W. WilliamsGary T. Krenekhas served as a Senior Vice President and our Chief Financial Officer since October 2006. Mr. Krenek previously served as our Vice President and Chief Financial Officer since March 1998.

Beth G. Gordonhas served as our Executive Vice PresidentController and Chief Accounting Officer since March 1998.April 2000.

     Rodney W. EadsMark F. Baudoinhas served as a Senior Vice President since May 1997.October 2006. Mr. Baudoin previously served as our Vice President — Administration and Operations Support since March 1996.

     John L. Gabriel, Jr. has served as a Senior Vice President since November 1999.

     Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol “DO.” The following table sets forth, for the calendar quarters indicated, the high and low closing prices of our common stock as reported by the NYSE.

     The following table sets forth certain historical consolidated financial data relating to Diamond Offshore. We prepared the selected consolidated financial data from our consolidated financial statements as of and for the periods presented. Prior periods have been reclassified to conform to the classifications we currently follow. 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 our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.

     The following discussion should be read in conjunction with our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.

     We provide contract drilling services to the energy industry around the globe and are a leader in deepwater drilling with a fleet of 44 offshore drilling rigs. Our fleet currently consists of 30 semisubmersibles, 13 jack-ups and one drillship. In August 2005,addition, we purchasedhave two jack-up drilling units on order at shipyards in Brownsville, Texas and Singapore. We expect both of these units to be delivered during theOcean Monarch (formerly theEnserch Garden Banks), a Victory-class semisubmersible drilling rig and related equipment, for $20 million and removed from service one first quarter of our jack-up rigs, theOcean Warwick,as a result of damages it sustained during Hurricane Katrina. See “— Overview —Impact of 2005 Hurricanes.” In June 2005, we completed the sale of theOcean Liberatorand received net cash proceeds of $13.6 million.2008.

     The steadily risingWorldwide demand for our mid-water (intermediate) and deepwater (high-specification) semisubmersible rigs that characterized the first nine months of 2005 continuedand international jack-up rigs remained strong during the fourth quarter of 2006. However, the year, whilejack-up market in the GOM continues to experience downward pricing pressure, with the potential for a given rig to be ready-stacked for a period of time between wells. As of January 29, 2007, we had one ready-stacked jack-up unit. Exclusive of the GOM jack-up market, which accounted for 12 percent of our jack-up fleet reflected particular strength. Supported bytotal revenue for the quarter ended December 31, 2006, solid fundamental market conditions remain in place for all classes of offshore drilling rigs worldwide, and both dayrates and term contract opportunities have in many cases more than doubled previous-cycle peaks, and our customers are increasingly seeking longer term contracts. As a result, we increased our revenue backlog from approximately $900 million, or 31.4 rig years, at the beginning of 2005continued to a current backlog of approximately $4.5 billion, or 69.1 rig years, as of early February 2006. Generally rig utilization rates approach 95-98% during contracted periods; however, utilization rates can be adversely impacted by additional downtime due to various operating factors including, but not limited to, unscheduled repairs, maintenance and weather.slowly increase.

     Gulf of Mexico. In the GOM, dayrates continue to escalate. A contractthe market for one of our high-specification rigs has reached as high as $395,000 per day for work beginning in the first quarter of 2007 and extending until the first quarter of 2008. This contrasts with asemisubmersible equipment remains firm. The dayrate of $150,000 that the unit is currently earning. Sixon one of our seven high-specification semisubmersible rigsfloaters in the GOM, including the recently relocatedOcean Baroness,for which we have future contracts orreceived a letter of intent, or LOI, at dayrates at least 100 percent higher thanis as high as $500,000 for future work. However, the average dayratepace of contracting for these rigs earned duringhas slowed due to the first quarterbacklog of 2005. An LOI is subject to customary conditions, includingour existing agreements, all of which extend into 2008 or 2009, except for the execution of a definitivemost recent agreement and actual revenues received could be reduced by various operating factors, including utilization rates.which extends into 2012.

     The dayratesDayrates for our five intermediate semisubmersibles currently operatinglocated in the GOM have reachedare as high as $200,000$300,000 for a current one-well contract beginning in the third quarter of 2006. This contrasts with an average dayrate in the low $60,000 range earned during the first quarter of 2005 by our intermediate drilling units in the GOM.and a future three-well contract. We continue to view the deepwater and intermediate markets in the GOM as under-supplied and believe that additional improvementsthe GOM semisubmersible market will remain strong in backlog and dayrates are possible in these market segments during 2006.2007.

     Our jack-up fleet in the GOM also continued to experience highexperienced somewhat lower utilization and improving dayrates during the fourth quarter of 2005,2006, coupled with increasing downward pressure on dayrates, compared to the first nine months of 2005. Dayrates for our jack-up fleet operating in the GOM have reached as high as $125,000 for a two-well contract beginning late in the firstthird quarter of 2006. This contrasts with an average dayratesituation began in the low $40,000 range earned by oursecond quarter of 2006. We believe that the current pricing pressure on jack-up rigs in the GOM duringwill extend at least until the firstsecond quarter of 2005. Industry-wide, we believe that nine jack-up units were lost due to hurricanes in 2004 and 2005, and we2007.

     We expect up to six additional jack-up units to leave the GOM for other international markets by mid-2006. Among the six jack-up rigs that are expected to leave the GOM istwo of our intermediate semisubmersibles, theOcean Spur.New EraWe expectandOcean Voyager, to mobilize the rig from the GOM to Tunisiathe Mexican GOM in the firstthird quarter of 2006, where the unit has a commitment2007 under approximately 2¹/2-year contracts both ending in early 2010. The rigs have commitments at a dayratedayrates of $125,000$265,000 and $335,000, respectively. The terms of our drilling contracts with PEMEX for a period of 12 months beginning in mid-March.these rigs expose us to greater risks than we normally assume, such as exposure to increased environmental liability. In addition, each contract can be terminated by PEMEX on short-term notice, contractually or by statute, subject to certain conditions, although we view this eventuality as unlikely. We view the jack-up market in the GOM as under-supplied and believe that additional improvement in backlog and dayrates is possible in this market segment during 2006.

East/Mediterranean sector. All nine of these rigs are operating under contracts or commitments for work extending well into 2006, and in some instances 2007, 2008 or 2008, at increasing dayrates, compared to dayrates averaging in2009. During the low $100,000 range at the endthird quarter of 2005. A commitment for2006, one of our intermediatenew-build jack-up rigs, theOcean Shield, which is currently under construction in the sector has reached as high as $235,000 per day for one well beginning in the second quarter of 2006. This contrasts withSingapore, received a one-year term contract at a dayrate of $90,000 that$265,000, with the unitoption until late March 2007 to convert to a two-year contract, but at a slightly lower dayrate. Under the agreement, the rig is currently earning. Withscheduled to begin work offshore Australia upon completion of construction and commissioning of the relocation of theOcean Heritage from Southeast Asiarig, which is estimated to Qatar in the second quarter of 2005 and the expected mobilization of theOcean Spurto the Mediterraneanoccur in the first quarter of 2006, we are continuing to strategically redeploy our fleet in response to rising market demand and dayrates.2008. We believe that the AustralasianAustralia/Asia and Middle East/Mediterranean markets will continueremain strong in 2007.

     The following table reflects our contract drilling backlog as of February 19, 2007 and February 6, 2006 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2005) and reflects both firm commitments (typically represented by signed contracts), as well as LOIs. An LOI is subject to improvecustomary conditions, including the execution of a definitive agreement. Contract drilling backlog is based on the full contractual dayrate for our drilling rigs and is calculated assuming full utilization of our drilling equipment for the contract period. The amount of actual revenue earned and the actual periods during 2006.which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 95-98% can be adversely impacted by downtime due to various operating factors including, but not limited to, unscheduled repairs, maintenance and weather. Our contract backlog is calculated by multiplying the contracted operating dayrate by the firm contract period, excluding revenues for mobilization, demobilization, contract preparation and customer reimbursables. Changes in our contract drilling backlog between periods is a function of both the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.

     In the third quarter of 2005, two major hurricanes, Katrina and Rita, struck the U.S. Gulf Coast and GOM.Gulf of Mexico. In late August 2005, one of our jack-up drilling rigs, theOcean Warwick, was seriously damaged during Hurricane Katrina and other rigs in our fleet, as well as our warehouse in New Iberia, Louisiana, sustained lesser damage in HurricanesHurricane Katrina or Rita, or in some cases from both storms. We believe that the physical damage to our rigs, as well as related removal and recovery costs, are primarily covered by insurance, after applicable deductibles. At December 31, 2006, we had filed several insurance claims related to the 2005 storms which are currently under review by insurance adjusters or are pending underwriter approval. Our results for 2005, and to a lesser extent 2006, reflect the impact of Hurricanes Katrina and Rita.

     TheOcean Warwick, with a net book value of $14.0 million, was declared a constructive total loss effective August 29, 2005. We issued a proof of loss in the amount of $50.5 million to our insurers, representing the insured value of the rig less a $4.5 million deductible, anddeductible. We received all insurance proceeds related to this insurance claim in 2005. Recovery and removal of theOcean Warwickare subject to separate insurance deductibles totalingwhich were estimated at the time of loss to be $2.5 million.million in the aggregate.

     In the third quarter of 2005, we recorded a net $33.6 million pre-tax, net casualty gain ($21.8 million, after-tax, or $0.15 per share of common stock on a diluted basis) onfor theOcean Warwick, representing net insurance proceeds of $50.5 million, less the write-off of the $14.0 million net carrying value of the drilling rig and $0.4 million in rig-based inventory,spare parts and supplies, and estimated insurance deductibles aggregating $2.5 million in insurance deductibles for salvage and wreck removal as a result of Hurricanes Katrina and Rita.removal. We have presented this as “Casualty Gain onOcean Warwick” in our Consolidated Statements of Operations for the year ended December 31, 2005 included in Item 8 of this report.

     During 2006, we subsequently revised our estimate of expected deductibles related to salvage and wreck removal of theOcean Warwickto $2.0 million and recorded a $0.5 million adjustment to “Casualty Gain onOcean Warwick” in our Consolidated Statements of Operations for the year ended December 31, 2006 included in Item 8 of this report.

Damage to our other affected rigs and warehouse in New Iberia, Louisiana was less severe, andsevere. At the time of loss, we believe that repair costs for such damage and lost equipment will be covered byestimated insurance less estimated deductibles. All of our damaged rigs have now been repaired and returned to service. Insurance deductibles relatingrelated to the remaining rigs damaged during Hurricane Katrina and our rigs and facility damaged by Hurricane Rita to total $2.6 million in the aggregate, of which $1.2 million and $1.4 million have beenwere recorded as additional contract drilling expense and loss on disposition of assets, respectively, for the year ended December 31, 2005 in our Consolidated Statements of Operations included in Item 8 of this report. Subsequently, during 2006, we revised our estimate of the applicable deductibles related to these damages and recorded a $0.4 million gain on disposition of assets in our Consolidated Statements of Operations for the year ended December 31, 2006 included in Item 8 of this report.

     In addition, in the third quarter of 2005 and during 2006, we wrote-offwrote off the aggregate net book value of approximately $4.2$14.3 million pre-tax, in rig equipment that was either lost or damaged beyond repair during these storms as loss on disposition of assets

     Revenues.Our revenues vary based upon demand, which affects the number of days our drilling fleet is utilized and the dayrates earned by our rigs.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, we may mobilize our rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, we 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 our revenues are dayrates for rigs and rig utilization rates, each of which is ultimately 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. Demand for drilling services 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. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within our control and are difficult to predict.

     We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive lump-sum fees for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We 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 we changed our accounting to defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and began to amortize each, on a straight linestraight-line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). We believe that the straight lineStraight-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 we had used this method of accounting in prior periods, our operating income (loss) and net income (loss) would not have changed and the impact on our contract drilling revenues and expenses would have been immaterial. Absent a contract, mobilization costs are recognized currently.

     From time to time, we may receive fees from our customers for capital improvements to our rigs. We defer such fees received in “Other liabilities” on our Consolidated Balance Sheets included in Item 8 of this report and recognize these feesthem into income on a straight-line basis over the period of the related drilling contract.contract as a component of contract drilling revenue. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.

     We receive reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement. We record these reimbursements at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations included in Item 8 of this report.

     Operating Income.Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements, inflation and costs associated with labor regulations in the geographic regions in which our rigs operate. We have experienced and continue to experience upward pressure on salaries and wages as a result of the strengthening offshore drilling market and increased competition for skilled workers. In response to these market conditions we have implemented retention programs, including increases in compensation.

Operating expenses generally are not affected by changes in dayrates and may not be significantly affected by short-term 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, we are 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, we may reduce the size of a rig’s crew and

     Our significant accounting policies are included in Note 1 “Summary of Significant Accounting Policies”“General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:

     Property, Plant and Equipment.We carry our drilling and other property and equipment 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. Our 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. We have based our estimates of useful lives and salvage values on the historical industry data available to us, as well as our own experience. In April 2003, we commissioned a study to evaluate the economic lives of our drilling rigs because several of our 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, we recorded changes in accounting estimates by increasing the estimated service lives to 25 years for our jack-ups and 30 years for our semisubmersibles and drillship and by increasing salvage values to 5% for most of our drilling rigs. We made the change in estimates to better reflect the remaining economic lives and salvage values of our fleet. The effect of this change in accounting estimates resulted in an increase in our net income for the year ended December 31, 2005 of $15.7 million, or $0.11 per share, and a reduction of our 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.

Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various combinations of assumed utilization rates and dayrates. We also consider the impact of a 5% reduction in assumed dayrates for

     AtAs of December 31, 2005, we reviewed2006, all of our single cold-stacked rig, theOcean Monarch,drilling rigs were either under contract, in shipyards for impairment.surveys and/or life extension projects or undergoing a major upgrade. Based on this knowledge, we determined that an impairment test of our recent decision to upgrade this drilling unit to high-specification capabilities at an estimated costequipment was not needed as we are currently marketing all of approximately $300 million and the low net book value of this rig, we doour drilling units. We did not consider this asset to be impaired.

     Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from those reported.

     Personal Injury Claims.OurEffective May 1, 2006, in conjunction with our insurance policy renewals, we increased our deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, to $5.0 million per occurrence, with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. Prior to this renewal, our uninsured retention of liability for personal injury claims which primarily results from Jones Act liability in the GOM, iswas $0.5 million per claim with an additional aggregate annual deductible of $1.5 million. Our in-house claims department estimates the amount of our liability for our retention. This department establishes a reserve for each of our personal injury claims by evaluating the existing facts and circumstances of each claim and comparing the circumstances of each claim to our historical experiences with similar past personal injury claims. Our claims department also estimates our liability for claims whichpersonal injuries that are incurred but not reported by using historical data. Historically,From time to time, we may also engage experts to assist us in estimating our ultimatereserve for such personal injury claims. In 2006 we engaged an actuary to estimate our liability for personal injury claims has not differed materially frombased on our recorded estimates. At December 31, 2005historical losses and utilizing various actuarial models. We reduced our estimated liabilityreserve for personal injury claims was $38.9 million.by $8.0 million during the fourth quarter of 2006 based on an actuarial review from which we determined that our aggregate reserve for personal injury claims should be $35.0 million at December 31, 2006.

     The eventual settlement or adjudication of these claims could differ materially from theour estimated amounts due to uncertainties such as:

     Income Taxes. We account for income taxes in accordance with Statement of Financial Accounting Standards, or SFAS No. 109, “Accounting for Income Taxes,” or SFAS 109, 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 our financial statements or tax returns. In each of our tax jurisdictions we recognize 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

and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the guidance provided in FIN 48 and expect to adopt FIN 48 in the first quarter of 2007. Although our assessment has not yet been finalized, upon adoption of FIN 48 we expect to recognize a cumulative effect adjustment for uncertain tax positions of approximately $30 million, which will beginbe charged to results of operations and equity.

Mexican GOM.Revenues generated by our intermediate semisubmersibles operating in the Mexican GOM during 2006 decreased $5.1 million compared to 2005, primarily due to PEMEX’s early cancellation of its contract for theOcean Whittingtonin July 2006, partially offset by increased revenues for theOcean Workeras a result of a small dayrate increase received in December 2005. Our remaining three rigs in this market continue operating under contracts with PEMEX, two of which expire in 2011. Atmid-2007 and one that extends until late 2007. Operating costs in the Mexican GOM increased $3.2 million during 2006 compared to 2005, primarily due to the effect of 2005 and March 2006 wage increases for our rig-based personnel, as well as higher repair and maintenance costs, other miscellaneous operating costs and overheads, partially offset by lower operating costs for theOcean Whittingtonpursuant to its third quarter relocation to the GOM after termination of its drilling contract by PEMEX. In addition, we incurred $1.9 million in costs associated with the demobilization of theOcean Whittingtonfrom offshore Mexico to the GOM.

     Effective October 1, 2005, we changed the functional currency of certain of our subsidiaries operating outside the United States to the U.S. dollar to more appropriately reflect the primary economic environment in which these subsidiaries operate. Prior to this date, these subsidiaries utilized the local currency of the country in which they conducted business as their functional currency. During the years ended December 31, 2006 and 2005, we had $15.3recognized net foreign currency exchange gains of $10.3 million and net foreign currency exchange losses of $0.8 million, respectively. Prior to the fourth quarter of 2005, we accounted for foreign currency translation gains and losses as a component of “Accumulated other comprehensive losses” in our Consolidated Balance Sheets included in Item 8 of this report.

     Our net income tax expense is a function of the mix of our domestic and international pre-tax earnings, as well as the mix of earnings from the international tax jurisdictions in which we operate. We recognized $259.5 million of foreign tax credit carryforwards.expense on pre-tax income of $966.3 million for the year ended December 31, 2006 compared to tax expense of $96.1 million on a pre-tax income of $356.4 million in 2005.

     During 2005,2006 we were able to utilize mostall of our net operating loss carryforwardsthe foreign tax credits available to offset taxable income generated during the year. As a result,us and we now expect to be able to utilize $14.5 million of our availablehad no foreign tax credit carryforwards prior to their expiration dates andas of December 31, 2006. At the end of 2005, we believe thathad a valuation allowance isof $0.8 million for certain of our foreign tax credit carryforwards which was reversed during 2006 as the valuation allowance was no longer necessary for those credits. Consequently,necessary. During 2005, we reversed $9.6 million of the previously established $10.3 million valuation allowance during 2005. With respect to the remaining $0.8 millionfor certain of our foreign tax credit carryforwards,carryforwards.

     During 2006 we believerecorded an $8.3 million tax benefit related to the deduction allowable under Internal Revenue Code Section 199 for domestic production activities. During the second quarter of 2006, the Treasury Department and Internal Revenue Service issued guidelines regarding the deduction allowable under Internal Revenue Code Section 199 which was previously believed to be unavailable to the drilling industry with respect to qualified production activities income. The $8.3 million tax benefit recognized included $2.2 million related to the year 2005.

     During 2005, we settled an income tax dispute in East Timor (formerly part of Indonesia) for approximately $0.2 million. At December 31, 2004, our books reflected an accrued liability of $4.4 million related to potential East Timor and Indonesian income tax liabilities covering the period 1992 through 2000. Subsequent to the tax settlement, we determined that a valuation allowance isthe accrual was no longer necessary and asreversed the accrued liability in the fourth quarter of 2005.

     During 2004 and 2005, the Internal Revenue Service, or IRS, examined our federal income tax returns for tax years 2000 and 2002. The examination was concluded during the fourth quarter of 2005. We and the IRS agreed to a result have a valuation allowancelimited number of $0.8adjustments for which we recorded additional income tax of $1.9 million at December 31,in 2005.

     Comparative data relating to our revenues and operating expenses by equipment type are presented below. We have reclassified certain amounts applicable to the prior periods to conform to the classifications we currently follow. These reclassifications do not affect earnings.