UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

Delaware		76-0321760
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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 :

Title of each class		Name of each exchange on which registered
Common Stock, $0.01 par value per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act : None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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

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

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 Filer þ Accelerated Filer o Non-Accelerated Filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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.

As of June 30, 2006				$4,956,973,448

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

As of February 20, 2007		Common Stock, $0.01 par value per share		138,347,072 shares

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the definitive proxy statement relating to the 2007 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2006, are incorporated by reference in Part III of this report.

 

 

DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2006

TABLE OF CONTENTS

				Page No .
Cover Page					1
Document Table of Contents					2
Part I
Item 1 .		Business			3
Item 1A .		Risk Factors			8
Item 1B .		Unresolved Staff Comments			13
Item 2 .		Properties			14
Item 3 .		Legal Proceedings			14
Item 4 .		Submission of Matters to a Vote of Security Holders			14
Part II
Item 5 .		Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			16
Item 6 .		Selected Financial Data			18
Item 7 .		Management's Discussion and Analysis of Financial Condition and Results of Operations			19
Item 7A .		Quantitative and Qualitative Disclosures About Market Risk			52
Item 8 .		Financial Statements and Supplementary Data			54
		Consolidated Financial Statements			56
		Notes to Consolidated Financial Statements			61
Item 9 .		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			90
Item 9A .		Controls and Procedures			90
Item 9B .		Other Information			91
Part III
		Information called for by Part III Items 10, 11, 12, 13 and 14 has been omitted as the Registrant intends to file with the Securities and Exchange Commission not later than 120 days after the end of its fiscal year a definitive Proxy Statement pursuant to Regulation 14A.
Part IV
Item 15 .		Exhibits and Financial Statement Schedules			91
Signatures					94
Exhibit Index					95
Supplemental Executive Retirement Plan
Employment Agreement - John M. Vecchio
Employment Agreement - William C. Long
Employment Agreement - Lyndol L. Dew
Employment Agreement - Mark F. Baudoin
Employment Agreement - Beth G. Gordon
Statement Re: Compuation of Ratios
List of Subsidiaries
Consent of Deloitte & Touche LLP
Powers of Attorney
Rule 13a-14(a) Certification of Chief Executive Officer
Rule 13a-14(a) Certification of Chief Financial Officer
Section 1350 Certification of the CEO and CFO

PART I

     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 earned higher dayrates and achieved greater utilization compared to slot rigs.

     As of January 29, 2007, nine of our 13 jack-up rigs were located in the GOM. Six of those rigs are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Of 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. 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 of these units during the first quarter of 2008. See “ — Fleet Enhancements and Additions. ”

      Drillship .  We have one high-specification drillship, the Ocean Clipper, which was located offshore Brazil as of January 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, 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 remaining Victory-class rigs and another upgrade is currently underway in Singapore. We have two additional Victory-class rigs that are currently operating as intermediate semisubmersibles.

     In 2006, we began a major upgrade of the Ocean Monarch , a Victory-class semisubmersible that we acquired in August 2005 for $20.0 million. The modernized rig is being designed to operate in up to 10,000 feet of water in a moored configuration for an estimated cost of approximately $300 million. Through December 31, 2006, we had spent $33.9 million related to this project. The Ocean Monarch is expected to be ready for deepwater service in the fourth quarter of 2008.

     In addition, the shipyard portion of the upgrade of the Ocean Endeavor has been completed. The rig is currently undergoing sea trials and commissioning. The unit will remain in Singapore until the arrival of a heavy-lift vessel, anticipated late in the first quarter of 2007, which will return the rig to the GOM. The Ocean Endeavor is expected to commence drilling operations in the GOM in mid-2007. We estimate that the total cost of the upgrade will be approximately $253 million of which $208.4 million had been spent through December 31, 2006.

     In the second quarter of 2005, we entered into agreements to construct two high-performance, premium jack-up rigs. The two new drilling units, the Ocean Scepter and the Ocean Shield, are being constructed in Brownsville, Texas and Singapore, respectively, at an aggregate expected cost of approximately $320 million, including drill pipe and capitalized interest, of which $176.1 million had been spent through December 31, 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 during 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 29, 2007, is set forth in the table below.

See the footnotes to this table on the following page.

(a)

Nominal water depth (in feet), as described above for semisubmersibles and drillships, reflects the current outfitting for each drilling unit. In many cases, individual rigs are capable of achieving, or have achieved, greater water depths. In all cases, floating rigs are capable of working successfully at greater depths than their nominal water depth. On a case by case basis, we may achieve a greater depth capacity by providing additional equipment.

(b)		Such enhancements may include the installation of top-drive drilling systems, water depth upgrades, mud pump additions and increases in deck load capacity. Top-drive drilling systems are included on all rigs included in the table above.
(c)		GOM means U.S. Gulf of Mexico. Mexican GOM means the Gulf of Mexico offshore Mexico.
(d)		For ease of presentation in this table, customer names have been shortened or abbreviated.

Markets

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

	•		the Gulf of Mexico, including the United States and Mexico;
	•		Europe, principally in the United Kingdom, or U.K., and Norway;
	•		the Mediterranean Basin, including Egypt, Libya and Tunisa and other parts of Africa;
	•		South America, principally in Brazil;
	•		Australia and Asia, including Malaysia, Indonesia and Vietnam; and
	•		the Middle East, including Kuwait, Qatar and Saudi Arabia.

     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.

Offshore Contract Drilling Services

     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 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.

Customers

     We provide 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 our annual consolidated revenues, although the specific customers may vary from year to year. During 2006, we performed services for 51 different customers with Anadarko Petroleum Corporation (which acquired Kerr-McGee Oil & Gas Corporation, or Kerr-McGee, in mid-2006) and Petróleo Brasileiro S.A., or Petrobras, accounting for 10.6% and 10.4% of our annual total consolidated revenues, respectively. During 2005, we performed services for 53 different customers with Petrobras and Kerr-McGee accounting for 10.7% and 10.3% of our annual total consolidated revenues, respectively. During 2004, we performed services for 53 different customers with Petrobras and PEMEX — Exploración Y Producción, or PEMEX, accounting for 12.6% and 10.5% of our annual total consolidated revenues, respectively.

     We principally market our services in North America through our Houston, Texas office, with support for activities in the GOM provided by our regional office in New Orleans, Louisiana. We market our services in other geographic locations principally from our office in The Hague, The Netherlands with support from our regional offices in Aberdeen, Scotland and Perth, Western Australia. We provide technical and administrative support functions from our Houston office.

Competition

     The offshore contract drilling industry is highly competitive and is influenced by a number of factors, including current and anticipated prices of oil and natural gas, expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling rigs. See “Risk Factors — Our industry is highly competitive and cyclical, with intense price competition ” in Item 1A of this report, which is incorporated herein by reference.

Governmental Regulation

     Our operations are subject to numerous international, U.S., state and local laws and regulations that relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment. See “Risk Factors — Compliance with or breach of environmental laws can be costly and could limit our operations ” in Item 1A of this report, which is incorporated herein by reference.

Operations Outside the United States

     Our operations outside the United States accounted for approximately 43%, 45% and 56% of our total consolidated revenues for the years ended December 31, 2006, 2005 and 2004, respectively. See “Risk Factors — A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations ,” “Risk Factors — Our drilling contracts in the Mexican GOM expose us to greater risks than we normally assume ” and “Risk Factors — Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us ” in Item 1A of this report, which are incorporated herein by reference.

Employees

     As of December 31, 2006, we had approximately 4,800 workers, including international crew personnel furnished through independent labor contractors. We have experienced satisfactory labor relations and provide comprehensive benefit plans for our employees.

Access to Company Filings

     We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy

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 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Our SEC filings are also available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our 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 we have electronically filed such material with, or furnished it to, the SEC. The information contained on our website, or on other websites linked to our website, is not part of this report.

Item 1A. Risk Factors.

     Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that we currently believe are not as significant as the risks described below. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected.

Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.

     Our business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher commodity prices do not necessarily translate into increased drilling activity since our customers’ expectations of future commodity prices typically drive demand for our rigs. Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including:

	•		the political environment of oil-producing regions, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East or other geographic areas or further acts of terrorism in the United States or elsewhere;
	•		worldwide demand for oil and gas;
	•		the cost of exploring for, producing and delivering oil and gas;
	•		the discovery rate of new oil and gas reserves;
	•		the rate of decline of existing and new oil and gas reserves;
	•		available pipeline and other oil and gas transportation capacity;
	•		the ability of oil and gas companies to raise capital;
	•		weather conditions in the United States and elsewhere;
	•		the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing;
	•		the level of production in non-OPEC countries;
	•		the policies of the various governments regarding exploration and development of their oil and gas reserves; and
	•		advances in exploration and development technology.

Our industry is highly competitive and cyclical, with intense price competition.

     The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered. Mergers among oil and natural gas exploration and production companies have reduced the number of available customers.

     Our industry has historically been cyclical. There have been periods of high demand, short rig supply and high dayrates (such as we are currently experiencing in many of the markets in which we operate), followed by periods of

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.

     Current oil and natural gas prices are significantly above historical averages, which has resulted in higher utilization and dayrates earned by our drilling units, generally beginning in the third quarter of 2004. However, we can provide no assurance that the current industry cycle of high demand, short rig supply and higher dayrates will continue. We may be required to idle rigs or to enter into lower rate contracts in response to market conditions in the future.

     Significant new rig construction and upgrades of existing drilling units could also intensify price competition. We believe that there are currently more than 100 jack-up rigs and floaters (semisubmersible rigs and drillships) on order and scheduled for delivery between 2007 and 2010. Improvements in dayrates and expectations of sustained improvements in rig utilization rates and dayrates may result in the construction of additional new rigs. These increases in rig supply could result in depressed rig utilization and greater price competition from both existing competitors, as well as new entrants into the offshore drilling market. As of the date of this report, not all of the rigs currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. In addition, competing contractors are 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.

     Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

Failure to obtain and retain highly skilled personnel could hurt our operations.

     We require highly skilled personnel to operate and provide technical services and support for our business. To the extent that demand for drilling services and the size of the worldwide industry fleet increase (including the impact of newly constructed rigs), shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs, which could adversely affect our results of operations. In addition, the entrance of new participants into the offshore drilling market would cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry.

     We have experienced and continue to experience upward pressure on salaries and wages and increased competition for skilled workers as a result of the strengthening offshore drilling market. We have also sustained the loss of experienced personnel to our competitors. In response to these market conditions we have implemented retention programs, including increases in compensation. The heightened competition for skilled personnel could adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.

The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market.

     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 them 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, we seek to have a foundation of long-term contracts with a reasonable balance of single-well, well-to-well and short-term contracts to attempt to limit the downside impact of a decline in the market while still participating in the benefit of increasing dayrates in an improving market. However, we can provide no assurance that we will be able to achieve or maintain such a balance from time to time. Our inability to fully benefit from increasing dayrates in an improving market, due to the long-term nature of some of our contracts, may adversely affect our profitability.

Contracts for our drilling units are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability on those contracts.

     Our contracts for our drilling units provide for the payment of a fixed dayrate per rig operating day, 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. In addition, for contracts with dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers. Our inability to recover these increased or unforeseen costs from our customers could adversely affect our financial position, results of operations and cash flows.

Our drilling contracts may be terminated due to events beyond our control.

     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.

     During depressed market conditions, our customers may also seek renegotiation of firm drilling contracts to reduce their obligations. The renegotiation of our drilling contracts could adversely affect our financial position, results of operations and cash flows.

We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.

     As of the date of this report, our contract drilling backlog was $7.4 billion for expected future work extending until 2013, which includes future earnings under both firm commitments and anticipated commitments for which definitive agreements have not yet been executed. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement where one does not currently exist. Our inability to perform under our contractual obligations or to execute definitive agreements may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Contract Drilling Backlog ” included in Item 7 of this report.

Rig conversions, upgrades or newbuilds may be subject to delays and cost overruns.

     From time to time we may undertake to add new capacity through conversions or upgrades to our existing rigs or through new construction. We have entered into agreements to upgrade two of our semisubmersible drilling units to ultra-deepwater capability at an estimated aggregate cost of approximately $553 million. The shipyard portion of the upgrade of one rig has been completed, and we expect that the unit will return to the GOM in mid-2007. We expect delivery of our other semisubmersible unit during the fourth quarter of 2008. We have also entered into agreements to construct two new jack-up drilling units with expected delivery dates in the first quarter of 2008 at an aggregate cost of approximately $320 million, including drill pipe and capitalized interest. These projects and other projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:

	•		shortages of equipment, materials or skilled labor;
	•		work stoppages;
	•		unscheduled delays in the delivery of ordered materials and equipment;
	•		unanticipated cost increases;
	•		weather interferences;
	•		difficulties in obtaining necessary permits or in meeting permit conditions;
	•		design and engineering problems;
	•		shipyard failures; and
	•		failure or delay of third party service providers and labor disputes.

     Failure to complete a rig upgrade or new construction on time, or failure to complete a rig conversion or new construction in accordance with its design specifications may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling contract.

Our business involves numerous operating hazards, and we are not fully insured against all of them.

     Our operations are subject to the usual hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings and natural disasters such as

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 or other parties.

     Pollution 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. There 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. In addition, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks.

We have significantly increased our insurance deductibles and have elected to self-insure for a portion of our liability exposure and for physical damage to rigs and equipment caused by named windstorms in the GOM.

     Because the amount of insurance coverage available to us has been significantly limited and the cost for such coverage has increased substantially, we have elected to self-insure for a portion of our liability exposure and for physical damage to rigs and equipment caused by named windstorms in the GOM. Although we continue to carry physical damage insurance for certain other losses, we have significantly increased our deductibles to offset or mitigate premium increases. Our deductible for physical damage insurance is currently $150.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss). We continue to carry liability insurance with coverages similar to prior years, except that we have elected to self-insure for a portion of our excess liability coverage related to named windstorms in the GOM. Our deductible for liability coverage generally has increased to $5.0 million per occurrence, but our deductibles arising in connection with certain liabilities relating to named windstorms in the GOM have increased to $10.0 million per occurrence, with no annual aggregate deductible. To the extent that we incur certain liabilities related to named windstorms in the GOM in excess of $75.0 million, we are self-insured for up to a maximum retention of $17.5 million per occurrence in addition to these deductibles. These changes result in a higher risk of losses that are not covered by third party insurance contracts. If named windstorms in the GOM cause significant damage to our rigs or equipment or to the property of others for which we may be liable, it could have a material adverse effect on our financial position, results of operations or cash flows.

A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations.

     We operate in various regions throughout the world which may expose us to political and other uncertainties, including risks of:

	•		terrorist acts, war and civil disturbances;
	•		piracy;
	•		kidnapping of personnel;
	•		expropriation of property or equipment;
	•		foreign and domestic monetary policy;
	•		the inability to repatriate income or capital;
	•		regulatory or financial requirements to comply with foreign bureaucratic actions; and
	•		changing taxation policies.

     In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:

	•		the equipping and operation of drilling units;
	•		repatriation of foreign earnings;
	•		oil and gas exploration and development;
	•		taxation of offshore earnings and earnings of expatriate personnel; and
	•		use and compensation of local employees and suppliers by foreign contractors.

     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.

Our drilling contracts in the Mexican GOM expose us to greater risks than we normally assume.

     As of the date of this report, we have three intermediate semisubmersible rigs and one jack-up rig drilling offshore Mexico for PEMEX, the national oil company of 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.

Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.

     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.

We may be required to accrue additional tax liability on certain of our foreign earnings.

     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 may be subject to litigation that could have an adverse effect on us.

     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.

Governmental laws and regulations may add to our costs or limit our drilling activity.

     Our operations are affected from time to time in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws

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

     Hurricanes Katrina and Rita caused damage to a number of rigs in the GOM and rigs that were moved off location by the storms may have done damage to platforms, pipelines, wellheads and other drilling rigs. We believe that we are currently in compliance with the existing regulations set forth by the Minerals Management Service of the U.S. Department of the Interior regarding our operations in the GOM. However, these regulations are currently under review by various other government agencies and industry groups. We can provide no assurance that these groups will not take other steps or implement additional requirements that could increase the cost of operating, or reduce the area of operation, in the GOM.

Compliance with or breach of environmental laws can be costly and could limit our operations.

     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 increasingly stringent, 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.

We are controlled by a single stockholder, which could result in potential conflicts of interest.

     Loews Corporation, which we refer to as Loews, beneficially owns approximately 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.

Item 1B . Unresolved Staff Comments .

     Not applicable.

      Mark F. Baudoin has served as a Senior Vice President since October 2006. Mr. Baudoin previously served as our Vice President — Administration and Operations Support since March 1996.

      Lyndol L. Dew has served as a Senior Vice President since September 2006. Previously, Mr. Dew served as our Vice President — International Operations from January 2006 to August 2006 and as our Vice President — North American Operations from January 2003 to December 2005. Mr. Dew previously served as an Area Manager for our domestic operations since February 2002.

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

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

PART II

CUMULATIVE TOTAL STOCKHOLDER RETURN

     The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Index, a Competitor/Service Industry Group Index and a Peer Group Index over the five year period ended December 31, 2006.

Comparison of 2002 — 2006 Cumulative Total Return (1)

Item 6. Selected Financial Data.

     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.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     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 addition, we have two jack-up drilling units on order at shipyards in Brownsville, Texas and Singapore. We expect both of these units to be delivered during the first quarter of 2008.

Overview

Industry Conditions

     Worldwide demand for our mid-water (intermediate) and deepwater (high-specification) semisubmersible rigs and international jack-up rigs remained strong during the fourth quarter of 2006. However, the jack-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 total 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 continued to slowly increase.

      Gulf of Mexico . In the GOM, the market for our semisubmersible equipment remains firm. The dayrate on one of our seven high-specification floaters in the GOM, for which we have received a letter of intent, or LOI, is as high as $500,000 for future work. However, the pace of contracting for these rigs has slowed due to the backlog of our existing agreements, all of which extend into 2008 or 2009, except for the most recent agreement which extends into 2012.

     Dayrates for our five intermediate semisubmersibles currently located in the GOM are as high as $300,000 for a current one-well contract and a future three-well contract. We continue to view the deepwater and intermediate markets in the GOM as under-supplied and believe that the GOM semisubmersible market will remain strong in 2007.

     Our jack-up fleet in the GOM experienced somewhat lower utilization during the fourth quarter of 2006, coupled with increasing downward pressure on dayrates, compared to the third quarter of 2006. This situation began in the second quarter of 2006. We believe that the current pricing pressure on jack-up rigs in the GOM will extend at least until the second quarter of 2007.

     We expect two of our intermediate semisubmersibles, the Ocean New Era and Ocean Voyager , to mobilize from the GOM to the Mexican GOM in the third quarter of 2007 under approximately 2 ¹ / 2 -year contracts both ending in early 2010. The rigs have commitments at dayrates of $265,000 and $335,000, respectively. The terms of our drilling contracts with PEMEX for 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 expect the market for the Mexican GOM to remain strong in 2007.

      Brazil . Two of our rigs operating in Brazil are currently working under term contracts with Petrobras that expire in 2009, and two additional rigs are operating under contracts expiring in 2010. Petrobras is continuing to seek additional intermediate semisubmersible rigs, and we expect the Brazilian semisubmersible demand to remain strong in 2007.

      North Sea . Effective industry utilization remains at 100 percent in the North Sea where we have three intermediate semisubmersible rigs in the U.K. and one intermediate unit in Norway. Indicating the strength of this market, one of our four rigs in the North Sea recently received a term contract extending until the second quarter of 2009, with an option until late March 2007 to convert to a two-year contract ending in 2010. The other three rigs have term contracts that extend into 2010.

      Australia/Asia/Middle East/Mediterranean . We currently have five semisubmersible rigs and one jack-up unit operating in the Australia/Asia market, and two jack-up rigs and one intermediate floater operating in the Middle

East/Mediterranean sector. All nine of these rigs are operating under contracts for work extending into 2007, 2008 or 2009. During the third quarter of 2006, one of our new-build jack-up rigs, the Ocean Shield , which is currently under construction in Singapore, received a one-year term contract at a dayrate of $265,000, with the option until late March 2007 to convert to a two-year contract, but at a slightly lower dayrate. Under the agreement, the rig is scheduled to begin work offshore Australia upon completion of construction and commissioning of the rig, which is estimated to occur in the first quarter of 2008. We believe that the Australia/Asia and Middle East/Mediterranean markets will remain strong in 2007.

Contract Drilling Backlog

     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 customary 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 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.

     The following table reflects the amount of our contract drilling backlog by year as of February 19, 2007.

     The following table reflects the percentage of rig days committed by year as of February 19, 2007. The percentage of rig days committed is calculated as the ratio of total days committed under contracts and LOIs and scheduled shipyard and survey days for all rigs in our fleet to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected delivery dates for the Ocean Endeavor , Ocean Monarch , and our two newbuild jack-up rigs, the Ocean Scepter and Ocean Shield .

Impact of 2005 Hurricanes

     In the third quarter of 2005, two major hurricanes, Katrina and Rita, struck the U.S. Gulf Coast and Gulf of Mexico. In late August 2005, one of our jack-up drilling rigs, the Ocean 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 Hurricane Katrina or Rita, or 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.

     The Ocean 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. We received all insurance proceeds related to this claim in 2005. Recovery and removal of the Ocean Warwick are subject to separate insurance deductibles which were estimated at the time of loss to be $2.5 million in the aggregate.

     In the third quarter of 2005, we recorded a net $33.6 million casualty gain for the Ocean 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 spare parts and supplies, and estimated insurance deductibles aggregating $2.5 million for salvage and wreck removal. We have presented this as “Casualty Gain on Ocean 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 the Ocean Warwick to $2.0 million and recorded a $0.5 million adjustment to “Casualty Gain on Ocean 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 was less severe. At the time of loss, we estimated insurance deductibles related 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 were 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 off the aggregate net book value of approximately $14.3 million in rig equipment that was either lost or damaged beyond repair during these storms as loss on disposition of assets and recorded a corresponding insurance receivable in an amount equal to our expected recovery from insurers. The write-off of this equipment and recognition of insurance receivables had no net effect on our consolidated results of operations for the years ended December 31, 2006 and 2005.

     During the third and fourth quarters of 2005, we incurred additional operating expenses, including but not limited to the cost of rig crew over-time and employee assistance, hurricane relief supplies, temporary housing and office space and the rental of mooring equipment, of $5.1 million relating to relief and recovery efforts in the aftermath of Hurricanes Katrina and Rita, which we do not expect to be recoverable through our insurance.

     In late 2006 we received $3.1 million from certain of our customers primarily related to the replacement or repair of equipment damaged during the 2005 hurricanes. We recorded $0.3 million of this recovery as a credit to

contract drilling expense, $1.1 million as a gain on disposition of assets and the remaining $1.8 million as other income in our Consolidated Statements of Operations for the year ended December 31, 2006 included in Item 8 of this report.

General

     Our revenues vary based upon demand, which affects the number of days our 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, 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 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. 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 defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and 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. 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 and recognize them into income on a straight-line basis over the period of the related drilling 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.

     Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and condition of the equipment.

     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 take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. We recognize, 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 our 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.

     Periods of high, sustained utilization may result in cost increases for maintenance and repairs in order to maintain our equipment in proper, working order. In addition, during periods of high activity and dayrates, higher prices generally pervade the entire offshore drilling industry and its support businesses, which cause our costs for goods and services to increase.

     Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. Operating revenue decreases because these surveys are performed during scheduled downtime 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 downtime. The number of rigs undergoing a 5-year survey will vary from year to year.

     In addition, operating income may be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time.

     During 2007, we expect to spend an aggregate of approximately $46 million for 5-year surveys and intermediate surveys, including estimated mobilization costs, but excluding any resulting repair and maintenance costs, which could be significant. Costs of mobilizing our rigs to shipyards for scheduled surveys, which were a major component of our survey-related costs during 2006, are indicative of higher prices commanded by support businesses to the offshore drilling industry. We expect mobilization costs to be a significant component of our survey-related costs in 2007.

     When we renewed our principal insurance policies effective May 1, 2006, coverage for offshore drilling rigs, if available, was offered at substantially higher premiums than in the past and was subject to an increasing number of coverage limitations, due in part to underwriting losses suffered by the insurance industry as a result of damage caused by hurricanes in the Gulf of Mexico in 2004 and 2005. In some cases, quoted renewal premiums increased by more than 200%, with the addition of substantial deductibles and limits on the amount of claims payable for losses arising from named windstorms. In light of these factors, we determined that retention of additional risk was preferable to paying dramatically higher premiums for limited coverage. Accordingly, we have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. For our other physical damage coverage, our deductible is $150.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss). As a result of our reduced coverage, our premiums for this coverage were reduced from the amounts we paid in 2005 and were lower than the renewal rates quoted by our insurance carriers. We also renewed our liability policies in May 2006, with an increase in premiums and deductibles. Our new deductibles under these policies have generally increased to $5.0 million per occurrence, but our deductibles arising in connection with certain liabilities relating to named windstorms in the U.S. Gulf of Mexico have increased to $10.0 million per occurrence, with no annual aggregate deductible. In addition, we elected to self-insure a portion of our excess liability coverage related to named windstorms in the U.S. Gulf of Mexico. To the extent that we incur certain liabilities related to named windstorms in the U.S. Gulf of Mexico in excess of $75.0 million, we are self-insured for up to a maximum retention of $17.5 million per occurrence in addition to these deductibles. We are currently in the early stages of renewing our insurance policies that expire on May 1, 2007. Currently we are unable to predict what changes, if any, we may make to our insurance coverage on or after May 1, 2007.

     If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment or to the property of others for which we may be liable, it could have a material adverse effect on our financial position, results of operations or cash flows.

     Insurance premiums will be amortized as expense over the applicable policy periods which generally expire at the end of April 2007.

      Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with Statement of Financial Accounting Standards, or SFAS, No. 34, “Capitalization of Interest Cost,” or SFAS 34. During 2006 and 2005, we began capitalizing interest on our two capital upgrade projects and the construction of our two new jack-up rigs. Pursuant to SFAS 34, the period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. In 2006 we began capitalizing interest on expenditures related to the capital upgrade of the Ocean Monarch and the construction of our two jack-up rigs, and in 2005, we began capitalizing interest on expenditures related to the upgrade of the Ocean Endeavor . See Note 1 “General Information — Capitalized Interest ” to our Consolidated Financial Statements included in Item 8 of this report.

     As of December 31, 2006, the shipyard portion of the Ocean Endeavor ’s upgrade had been completed, and the rig is currently undergoing sea trials and commissioning in Singapore. We will continue to capitalize interest costs related to this upgrade until sea trials and commissioning are completed and the rig is loaded-out on a heavy-lift vessel for its return to the GOM, which we anticipate will occur at the end of the first quarter of 2007. We believe that this point in time represents the completion of the construction phase of the upgrade project, as the newly upgraded rig will be ready for its intended use. Accordingly, we will then cease capitalizing interest costs related to this upgrade and will begin depreciating the newly upgraded rig. As a result of the scheduled delivery of the Ocean Endeavor , we anticipate that depreciation and interest expense in 2007 will increase by approximately $6 million (representing nine months of expense) and $2.5 million, respectively.

Critical Accounting Estimates

     Our significant accounting policies are included in Note 1 “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.

     We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

	•		dayrate by rig;
	•		utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);
	•		the per day operating cost for each rig if active, ready-stacked or cold-stacked; and
	•		salvage value for each rig.

     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 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) as part of our analysis.

     As of December 31, 2006, all of our drilling rigs were either under contract, in shipyards for surveys and/or life extension projects or undergoing a major upgrade. Based on this knowledge, we determined that an impairment test of our drilling equipment was not needed as we are currently marketing all of our drilling units. We did not have any cold-stacked rigs at December 31, 2006. We do not believe that current circumstances indicate that the carrying amount of our property and equipment may not be recoverable.

     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. Effective 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 was $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 historical experiences with similar past personal injury claims. Our claims department also estimates our liability for personal injuries that are incurred but not reported by using historical data. From time to time, we may also engage experts to assist us in estimating our reserve for such personal injury claims. In 2006 we engaged an actuary to estimate our liability for personal injury claims based on our historical losses and utilizing various actuarial models. We reduced our reserve for personal injury claims 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 our estimated amounts due to uncertainties such as:

	•		the severity of personal injuries claimed;
	•		significant changes in the volume of personal injury claims;
	•		the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
	•		inconsistent court decisions; and
	•		the risks and lack of predictability inherent in personal injury litigation.

      Income Taxes . We account for income taxes in accordance with 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 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, we estimate our annual effective tax rate by forecasting our annual income before income tax, taxable income and tax expense in each of our tax jurisdictions. We make judgments regarding future events and related estimates especially as they pertain to forecasting of our 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.

     During 2006 we were able to utilize all of the foreign tax credits available to us and we had no foreign tax credit carryforwards as of December 31, 2006. At the end of 2005, we had a valuation allowance of $0.8 million for certain of our foreign tax credit carryforwards which was reversed during 2006 as the valuation allowance was no longer necessary.

     In June 2006, the Financial Accounting Standards Board, or FASB, issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold

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 be charged to results of operations and equity.

Results of Operations

Years Ended December 31, 2006 and 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.

     Continued strong demand for our rigs in all markets and geographic regions resulted in high utilization and historically high dayrates during 2006. Due to this continuing strong demand, our operating income in 2006 increased $566.0 million, or 151%, to $940.4 million, compared to $374.4 million in 2005. Dayrates have generally increased during 2006, compared to 2005, resulting in the generation of additional contract drilling revenues by our fleet. However, overall revenue increases were negatively impacted by the effect of downtime associated with mandatory surveys and related repair time and lower dayrates earned by some of our semisubmersible rigs due to

previously established job sequencing that caused the units to temporarily roll to older contracts with lower dayrates. Total contract drilling revenues in 2006 increased $808.1 million, or 69%, to $1,987.1 million compared to 2005.

     Our results in 2006 were also impacted by higher expenses related to our mooring enhancement and other hurricane preparedness activities, wage increases in late 2005 and the first quarter of 2006 and surveys performed during 2006. The increase in survey costs included higher expenses for survey-related services and higher boat charges associated with moving rigs to and from shipyards. In addition, overall cost increases for maintenance and repairs between 2005 and 2006 reflect the impact of high, sustained utilization of our drilling units across our fleet and in all geographic locations in which we operate. The increase in overall operating and overhead costs also reflects the impact of higher prices throughout the offshore drilling industry and its support businesses. Total contract drilling expenses in 2006 increased $173.5 million, or 27%, to $812.1 million, compared to the same period in 2005. The increase in our operating expenses in 2006, as compared to 2005, was partially offset by an $8.0 million reduction in our reserve for personal injury claims based on an actuarial review.

     Our operating results in 2005 included a $33.6 million casualty gain due to the constructive total loss of the Ocean Warwick as a result of Hurricane Katrina in August 2005 and an $8.0 million gain related to the June 2005 sale of the Ocean Liberator .

customer for damages sustained by one of our GOM rigs during Hurricane Ivan in 2004, partially offset by the recognition of $0.5 million in deductibles for damages sustained during Hurricane Katrina in 2005.

      Australia/Asia. Revenues generated by our high-specification rigs in the Australia/Asia/Middle East market decreased $2.7 million in 2006 compared to 2005, primarily due to the relocation of the Ocean Baroness from this market to the GOM in the latter half of 2005. Prior to its relocation to the GOM, the Ocean Baroness generated $18.2 million in revenues during 2005. The decrease in revenues in 2006 was partially offset by additional revenue ($13.7 million) generated by an increase in the dayrate earned by the Ocean Rover compared to the prior year. The average operating revenue per day for this rig increased from $143,500 in 2005 to $181,500 in 2006 as a result of a new drilling program which began in the second quarter of 2006. Utilization improvements for the Ocean Rover during 2006, as compared to 2005 when the unit had 11 days of downtime for repairs, generated an additional $1.8 million in revenues.

     Operating costs for our rigs in the Australia/Asia/Middle East market decreased $11.4 million in 2006 compared to 2005 primarily due to the relocation of the Ocean Baroness to the GOM ($15.5 million). This decrease was partially offset by an increase in operating costs for the Ocean Rover during 2006, compared to the prior year, primarily related to higher personnel-related costs as a result of late 2005 and March 2006 pay increases, increased agency fee costs (which are based on a percentage of revenues) and higher other miscellaneous operating expenses.

      South America. Revenues for our high-specification rigs operating offshore Brazil increased $50.7 million in 2006 compared to 2005, primarily due to higher average dayrates earned by our rigs in this market ($44.1 million). Average operating revenue per day earned by the Ocean Alliance and the Ocean Clipper increased to $180,100 during 2006 up from $117,300 during the prior year as a result of contract renewals for both rigs in the latter part of 2005. Utilization for our rigs offshore Brazil increased from 89% in 2005 to 96% in 2006, contributing $6.6 million in additional revenues in 2006, primarily due to less downtime during 2006 for repairs.

     Contract drilling expenses for our operations offshore Brazil increased $13.1 million in 2006 compared to 2005. The increase in costs is primarily due to higher labor, benefits and other personnel-related costs as a result of 2005 and March 2006 pay increases and other compensation enhancement programs, increased agency fee costs (which are based on a percentage of revenues), higher freight costs and higher maintenance and project costs.

      GOM. Revenues generated by our intermediate semisubmersible rigs operating in the GOM during 2006 increased $124.8 million over the prior year primarily due to higher average operating dayrates and the operation of the Ocean New Era ($53.9 million) which was reactivated in December 2005. Average operating dayrates for the remainder of our GOM fleet of intermediate rigs increased from $77,300 in 2005 to $149,300 in 2006 and generated additional revenues of $82.2 million during 2006. Excluding the Ocean New Era , utilization fell from 87% in 2005 to 75% in 2006, resulting in an $11.3 million reduction in revenues generated in 2006 compared to 2005. Average utilization in 2006 was negatively impacted by approximately five months of downtime for the Ocean Saratoga in connection with its survey and related repairs, as well as a life enhancement upgrade that commenced in the third quarter of 2006 and approximately one month of downtime for both the Ocean Voyager and Ocean Concord for mooring upgrades. Partially offsetting the decline in average utilization in 2006 was an improvement in utilization for the Ocean Lexington, which worked nearly all of 2006 prior to its move to Egypt at the beginning of the fourth quarter. During 2005, the Ocean Lexington incurred over four months of downtime for a survey and life enhancement upgrade.

     Contract drilling expense for our GOM operations increased $30.6 million in 2006 compared to 2005, primarily due to normal operating costs for the Ocean New Era in 2006 ($7.6 million) and repair and other normal operating costs for the Ocean Whittington ($6.4 million) in the latter half of 2006 after its return from the Mexican GOM. Higher operating costs in 2006, as compared to 2005, reflect higher labor and benefits costs as a result of September 2005 and March 2006 wage increases for our rig-based personnel, mobilization costs associated with mooring upgrades for the Ocean Concord and Ocean Voyager, survey and related repair costs for the Ocean Saratoga and higher maintenance and other miscellaneous operating costs for our semisubmersible rigs in this market segment. In addition, during 2006, we incurred $2.4 million in costs associated with the rental of mooring lines and chains as temporary replacements for equipment lost during the 2005 hurricanes in the GOM. Partially offsetting the increased operating costs in 2006 was the absence of reactivation costs for the Ocean New Era, which returned to service in December 2005.

      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 the Ocean Whittington in July 2006, partially offset by increased revenues for the Ocean Worker as 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 mid-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 the Ocean Whittington pursuant 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 the Ocean Whittington from offshore Mexico to the GOM.

      Australia/Asia . Our intermediate semisubmersible rigs operating in the Australia/Asia market during 2006 generated an additional $84.4 million in revenues compared to 2005 primarily due to higher average operating dayrates ($84.3 million). Average operating dayrates increased from $76,300 in 2005 to $135,600 in 2006. In addition, the over 95% utilization of both the Ocean Epoch and Ocean Patriot during 2006, as compared to 2005 when the average utilization for these two rigs was 84%, contributed an additional $6.6 million to 2006 revenues. During 2005 the Ocean Epoch had over two months of downtime associated with a scheduled 5-year survey, other regulatory inspections and contract preparation work prior to its relocation to Malaysia and the Ocean Patriot incurred over one month of downtime associated with an intermediate inspection and repairs.

     These favorable revenue variances in 2006 were partially offset by the lower recognition of deferred mobilization, capital upgrade and other fees in 2006 compared to 2005. During 2006, we recognized $2.3 million in lump-sum mobilization revenue related to the Ocean Patriot ’s move offshore New Zealand at the beginning of the fourth quarter of 2006 and equipment upgrade fees from two customers in connection with customer-requested capital improvements to the Ocean Patriot . However, during 2005, we recognized $5.7 million and $0.9 million in connection with the Ocean Patriot ’s 2004 mobilization from South Africa to New Zealand and the Bass Strait and equipment upgrade fees, respectively. Additionally, we received a fee from another customer in this market for a drilling option for another rig, of which $0.6 million and $3.7 million were recognized in 2006 and 2005, respectively.

     Contract drilling expense for the Australia/Asia/Middle East region increased slightly from $83.8 million in 2005 to $87.5 million in 2006. The $3.8 million net increase in costs for 2006 is primarily the result of higher labor costs (due to wage increases in late 2005 and March 2006), higher repair and maintenance costs, higher revenue-based agency fees and higher other operating costs. These unfavorable cost trends were partially offset by lower survey and inspection costs in 2006 and the recognition of an insurance deductible in 2005 related to an anchor winch failure on the Ocean Patriot . In addition, we recognized $1.1 million and $5.2 million in mobilization expenses for our rigs in this region during 2006 and 2005, respectively. The amount of mobilization expenses recognized during a period is dependent upon the duration of the rig move and the contract period over which the mobilization costs are to be recognized.

      Europe/Africa. Revenues generated by our intermediate semisubmersibles operating in this market increased $101.0 million in 2006 compared to 2005, primarily due to an increase in the average operating revenue per day earned by our rigs in this market. Excluding the Ocean Lexington , which began operating in this market sector during the fourth quarter of 2006 and contributed revenues of $5.6 million, the average operating revenue per day for our rigs operating in this market increased from $87,500 in 2005 to $144,500 in 2006. This increase in average revenue per day generated additional revenues of $70.6 million in 2006 compared to 2005. All three of our rigs operating in the U.K. sector of the North Sea received operating dayrate increases during 2006 and the Ocean Vanguard began a drilling program in the fourth quarter of 2006 at a higher dayrate than it previously earned.

     Average utilization for our rigs in the Europe/Africa region increased from 83% in 2005 to 94% in 2006, excluding the Ocean Lexington , generating $20.7 million in additional revenues. The increase in average utilization is primarily due to higher utilization in 2006 for the Ocean Vanguard , compared to 2005 when this unit incurred more than five months of downtime due to an anchor winch failure and for a 5-year survey and related repairs. Additionally, average utilization for our three rigs operating in the U.K. sector of the North Sea increased slightly, reflecting the nearly full utilization of the Ocean Nomad during 2006 compared to 2005, when the rig was ready-stacked for almost three weeks and incurred nearly a full month of downtime for repairs. These favorable utilization trends were partially offset by 48 days of downtime for the Ocean Princess which was in a shipyard for an intermediate survey during 2006. In comparison, the Ocean Princess operated for nearly all of 2005.

     During 2006, we also recognized $4.4 million in revenues related to the amortization of lump-sum fees received from customers for capital improvements to the Ocean Guardian and Ocean Vanguard.

     Contract drilling expenses for our intermediate semisubmersible rigs operating in the Europe/Africa region increased $16.5 million during 2006 compared to 2005, primarily due to the inclusion of $4.2 million of normal operating costs for the Ocean Lexington in Egypt and costs associated with scheduled surveys for the Ocean Guardian and Ocean Princess , including mobilization and related repair costs during 2006. Also contributing to the increase in costs during 2006 were higher personnel and related costs (including administrative and support personnel in the region), reflecting the impact of wage increases after September 2005 and higher overall other operating costs. These cost increases in 2006 were partially offset by lower maintenance costs for the Ocean Vanguard in 2006 compared to 2005 and the absence of mobilization costs in 2006 related to the Ocean Nomad ’s relocation from Gabon to the North Sea at the end of 2004, which were fully recognized in 2005, as well as the 2005 recognition of mobilization costs incurred in connection with the Ocean Guardian ’s first quarter 2006 survey.

      South America . Revenues generated by our two intermediate semisubmersible rigs operating in Brazil increased $23.2 million to $76.7 million in 2006 from $53.6 million in 2005, primarily due to higher average operating dayrates earned by both of our rigs in this market. Average operating revenue per day rose from $75,100 in 2005 to $113,700 in 2006, contributing $26.4 million in additional revenues.

     Reduced utilization for our two intermediate semisubmersible rigs operating offshore Brazil during 2006, compared to 2005, is primarily the result of additional downtime for repairs during 2006, including 45 days of downtime for a thruster change-out on the Ocean Yatzy . This overall decrease in average utilization in 2006 resulted in a $3.2 million reduction in revenues compared to the prior year.

     Operating expenses for the Ocean Yatzy and Ocean Winner increased $11.5 million in 2006 compared to the prior year, primarily due to increased labor costs for our rig-based and shore-based personnel as a result of wage increases and other compensation enhancement programs implemented after the third quarter of 2005, higher

revenue-based agency fees, as well as higher repair, maintenance and freight costs and increases in other routine operating costs in 2006 compared to 2005.

Jack-Ups.

		Year Ended
		December 31,								Favorable/
		2006				2005				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
GOM		$	315,279			$	222,365			$	92,914
Mexican GOM			15,966				—				15,966
Australia/Asia/Middle East			61,141				49,444				11,697
Europe/Africa			42,808				—				42,808
Total Contract Drilling Revenue		$	435,194			$	271,809			$	163,385
CONTRACT DRILLING EXPENSE
GOM		$	112,524			$	98,866			$	(13,658	)
Mexican GOM			4,373				—				(4,373	)
Australia/Asia/Middle East			27,721				24,967				(2,754	)
Europe/Africa			14,806				—				(14,806	)
Total Contract Drilling Expense		$	159,424			$	123,833			$	(35,591	)
OPERATING INCOME		$	275,770			$	147,976			$	127,794

      GOM. Revenues generated by our jack-up rigs in the GOM increased $92.9 million in 2006 compared to 2005 primarily due to an improvement in average operating dayrates for our rigs in this region. Excluding the Ocean Warwick, which was declared a constructive total loss in the third quarter of 2005, our average operating revenue per day increased to $100,800 in 2006 from $59,100 in 2005, generating additional revenues of $141.9 million. GOM revenues were reduced $37.2 million due to changes in average utilization which fell to 79% in 2006 from 96% in 2005 (excluding the Ocean Warwick ). During 2006, utilization in the GOM was negatively impacted primarily by the relocation of the Ocean Spur to Tunisia in the first quarter of 2006 and over five months of downtime for the Ocean Nugget for a special survey, related repairs and contract preparation work prior to its relocation to the Mexican GOM in the fourth quarter of 2006. Also during 2006, the Ocean Spartan underwent leg repairs and was ready-stacked from mid-September 2006 until mid-December 2006 for total downtime of approximately four months, and the Ocean Summit incurred over three months of downtime for a special survey and related repairs. During 2005, the Ocean Warwick generated revenues of $11.8 million.

     Contract drilling expense in the GOM during 2006 increased $13.7 million compared to 2005. The increase in 2006 operating costs is primarily due to higher labor and other personnel-related costs as a result of late 2005 and March 2006 wage increases, costs associated with special surveys and related repairs for the Ocean Summit and Ocean Nugget , leg repairs for the Ocean Nugget , leg/spud can repairs for the Ocean Spartan and higher overhead, catering and other miscellaneous operating expenses. The overall increase in contract drilling expenses was partially offset by the absence of operating costs for the Ocean Warwick during 2006 and reduced operating costs in the GOM for the Ocean Spur (which only operated in the GOM for 45 days in 2006 before relocating to Tunisia) and the Ocean Nugget (which was relocated to the Mexican GOM at the beginning of the fourth quarter of 2006). Both the Ocean Spur and Ocean Nugget operated solely in the GOM during 2005. Also partially offsetting these negative cost trends was a reduction in survey and related mobilization costs during 2006 associated with the Ocean Spartan ’s survey in late 2005. We also recognized a $1.0 million insurance deductible for a leg punchthrough incident on the Ocean Spartan in 2005.

      Mexican GOM. Our jack-up rig the Ocean Nugget , which relocated to the Mexican GOM at the beginning of the fourth quarter of 2006, generated $16.0 million there in 2006. This unit is contracted to work for PEMEX through March 2009. Contract drilling expenses related to this rig were $4.4 million. We had no jack-up units operating in this market during 2005.

      Australia/Asia/Middle East. Revenues generated by our jack-up rigs in the Australia/Asia and Middle East regions were $61.1 million in 2006 compared to $49.4 million in 2005. The $11.7 million increase in revenues in this region during 2006 compared to the prior year is primarily attributable to higher average operating dayrates for both of our jack-up rigs in this region ($15.1 million). Average dayrates for our jack-up rigs in this region increased from $71,900 in 2005 to $95,600 in 2006. The favorable contribution to operating revenues by the increase in average operating dayrates was partially offset by the reduced recognition of deferred mobilization revenues in 2006, as compared to 2005 ($3.1 million) and the effect of slightly lower average utilization in this region in 2006 compared to 2005 ($0.3 million).

     Contract drilling expenses for our jack-up rigs in the Australia/Asia and Middle East regions increased slightly from $25.0 million in 2005 to $27.7 million in 2006. Higher labor costs in 2006 (resulting from late 2005 and early 2006 wage increases), higher maintenance, inspection costs and revenue-based agency fees were partially offset by the 2005 recognition of an insurance deductible for leg damage to the Ocean Heritage and the recognition of mobilization costs related to relocation of the Ocean Sovereign to locations offshore Bangladesh and Indonesia during 2005.

      Europe/Africa. The Ocean Spur began operating offshore Tunisia in mid-March 2006 and generated $42.8 million in revenues, including the recognition of $5.3 million in deferred mobilization revenue, and incurred operating expenses of $14.8 million during 2006. We did not have any of our jack-up rigs working in this region during 2005.

Other Contract Drilling.

     Other contract drilling expenses increased $15.4 million during 2006 compared to 2005, primarily due to the inclusion of $12.7 million in costs related to anchor boat rental and other costs associated with our mooring enhancement and hurricane preparedness activities, which were implemented in response to mooring issues which arose during the 2005 hurricane season.

Reimbursable expenses, net.

     Revenues related to reimbursable items, offset by the related expenditures for these items, were $8.0 million and $6.4 million for 2006 and 2005, respectively. Reimbursable expenses include items that we purchase, and/or services we perform, at the request of our customers. We charge our 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.

     Depreciation expense increased $16.8 million to $200.5 million during 2006 compared to $183.7 million during the same period in 2005 primarily due to depreciation associated with capital additions in 2005 and 2006, partially offset by lower depreciation expense resulting from the declaration of a constructive total loss of the Ocean Warwick in the third quarter of 2005.

General and Administrative Expense.

     We incurred general and administrative expense of $41.6 million during 2006 compared to $37.2 million during 2005. The $4.4 million increase in overhead costs between the periods was primarily due to the recognition of stock-based compensation expense pursuant to our adoption of SFAS No. 123(R), effective January 1, 2006.

Gain (Loss) on Sale of Assets.

     We recognized a net loss of $1.1 million on the sale and disposal of assets, including disposal costs, during 2006 compared to a net gain of $14.8 million during 2005. The loss recognized in 2006 is primarily the result of costs associated with the removal of production equipment from the Ocean Monarch, which was subsequently sold to a third party, partially offset by a $1.1 million recovery from certain of our customers related to the involuntary conversion of assets damaged during the 2005 hurricanes . Results for 2005 included a gain of $8.0 million related to the June 2005 sale of the Ocean Liberator , $5.6 million in insurance proceeds related to the involuntary conversion of certain assets damaged during Hurricane Ivan in 2004 and gains on the sale of used drill pipe during the period, partially offset by a $1.4 million loss due to the retirement of equipment lost or damaged during

Hurricanes Katrina and Rita in 2005.

Casualty Gain on Ocean Warwick.

     We recorded a $33.6 million casualty gain in 2005 as a result of the constructive total loss of the Ocean Warwick, resulting from damages sustained during Hurricane Katrina in August 2005. Subsequently in 2006, we revised our estimate of expected deductibles related to this incident and recorded a $0.5 million favorable adjustment to “Casualty Gain on Ocean Warwick .” See “—Overview—Impact of 2005 Hurricanes.”

Interest Income.

     We earned interest income of $37.9 million during 2006 compared to $26.0 million in 2005. The $11.9 million increase in interest income is primarily the result of the combined effect of slightly higher interest rates earned on higher average invested cash balances in 2006, as compared to 2005. See “— Liquidity and Capital Requirements” and “— Historical Cash Flows.”

Interest Expense.

     We recorded interest expense of $24.1 million during 2006, reflecting a $17.7 million decrease in interest cost compared to 2005. The decrease in interest cost was primarily attributable to lower interest expense in 2006 related to our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, as a result of our June 2005 repurchase of $774.1 million in aggregate principal amount at maturity of Zero Coupon Debentures, the associated write-off of $6.9 million of debt issuance costs in June 2005 and the conversion of $22.4 million in aggregate principal amount at maturity of Zero Coupon Debentures into shares of our common stock during 2006. In addition we capitalized an additional $9.1 million in interest costs in connection with qualifying upgrades and construction projects during 2006 compared to 2005. The decrease in interest cost was partially offset by additional interest expense on our 4.875% Senior Notes due July 1, 2015, or 4.875% Senior Notes, which we issued in June 2005.

Other Income and Expense (Other, net).

     Included in “Other, net” are foreign currency translation adjustments and transaction gains and losses and other income and expense items, among other things, which are not attributable to our drilling operations. The components of “Other, net” fluctuate based on the level of activity, as well as fluctuations in foreign currencies. We recorded other income, net, of $12.1 million during 2006 and other expense, net, of $1.1 million in 2005.

     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 recognized 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.

Income Tax Expense.

     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 tax 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.

     Certain of our rigs that operate internationally are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary that we wholly own. We do not intend to remit earnings from this subsidiary to the U.S. and we plan to indefinitely reinvest these earnings internationally. Consequently, we provided no U.S. taxes on earnings and recognized no U.S. benefits on losses generated by this subsidiary during 2006 and 2005.

     During 2006 we were able to utilize all of the foreign tax credits available to us and we had no foreign tax credit carryforwards as of December 31, 2006. At the end of 2005, we had a valuation allowance of $0.8 million for certain of our foreign tax credit carryforwards which was reversed during 2006 as the valuation allowance was no longer necessary. During 2005, we reversed $9.6 million of the previously established $10.3 million valuation allowance for certain of our foreign tax credit carryforwards.

     During 2006 we recorded 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 reversed a previously established reserve of $8.9 million ($1.7 million included with Current Taxes Payable and $7.2 million in Other Liabilities in our Consolidated Balance Sheets) associated with exposure related to the disallowance of goodwill deductibility associated with a 1996 acquisition which we believed was no longer necessary.

     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 the accrual was no longer necessary and reversed 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 limited number of adjustments for which we recorded additional income tax of $1.9 million in 2005.

Results of Operations

      South America. Revenues for our high-specification rig operations offshore Brazil increased $18.8 million in 2005, as compared to 2004, primarily as a result of increased utilization for the Ocean Alliance in 2005 as compared to the prior year, when this rig experienced approximately five months of unpaid downtime. Utilization for these rigs offshore Brazil increased from 76% in 2004 to 89% in 2005 and contributed $9.5 million in additional revenues. Additionally, we negotiated a contract extension, including a dayrate increase, for the Ocean Alliance in the third quarter of 2005. Average dayrates earned by our high-specification rigs in this region increased to $117,300 in 2005 from $102,900 in 2004, which contributed $9.3 million in additional revenues during 2005.

     Contract drilling expense for these operations in Brazil increased $4.9 million in 2005 compared to the prior year. The increase in costs in 2005 was primarily due to higher labor and benefit costs as a result of December 2004 and September 2005 pay increases, increased local shorebase support costs due to the completion of a local training program in Brazil and higher insurance costs associated with increased premiums for the 2005/2006 policy year and additional loss-of-hire insurance.

     Contract drilling expense for our intermediate semisubmersibles’ operations in the GOM increased $12.6 million in 2005, as compared to 2004, primarily due to higher labor and benefits costs as a result of December 2004 and September 2005 wage increases for our rig-based personnel, normal operating costs for the Ocean Voyager and Ocean New Era in 2005 and higher inspection and maintenance project costs for the Ocean Lexington, which was in a shipyard for inspections and a life enhancement project during 2005. These cost increases were partially offset by lower reactivation costs for the Ocean New Era in 2005, as compared to costs incurred to reactivate the Ocean Voyager in 2004.

      Australia/Asia . Our intermediate semisubmersibles working offshore Australia/Asia generated revenues of $111.8 million in 2005 compared to revenues of $77.2 million in 2004. The $34.6 million increase in operating revenues was primarily due to an increase in average operating dayrates to $76,300 in 2005 compared to $62,900 in 2004, which generated $16.9 million in additional revenues in 2005. Our results in this region in 2005 also reflect the favorable impact of the Ocean Patriot operating for the majority of the year following its relocation to the region in the second half of 2004. However, excluding the Ocean Patriot , our average utilization for these rigs in the Australia/Asia region decreased from 96% in 2004 to 92% in 2005, primarily due to unpaid downtime for the Ocean Epoch which was in a shipyard for approximately 70 days in 2005 for a scheduled 5-year survey and associated repairs. The net effect of changes in utilization in this region was the generation of $10.7 million in additional revenues in 2005 compared to 2004.

     During 2005 we recognized $5.7 million in lump-sum mobilization fees for the Ocean Patriot related to its 2004 mobilization from South Africa to New Zealand and the Bass Strait, compared to $3.3 million in similar fees recognized in 2004. In 2005 we also recognized $3.7 million in revenue related to the extension of a contract option period for one of our rigs in this region and $0.9 million in revenues for the amortization of lump-sum fees received from a customer for rig modifications.

     Contract drilling expense for the Australia/Asia region increased $19.8 million from 2004 to 2005, primarily due to costs associated with the Ocean Patriot operating offshore Australia for all of 2005, including the amortization of deferred mobilization expenses.

      Europe/Africa. Operating revenues for our intermediate semisubmersibles working in this region increased $37.0 million in 2005 primarily due to an increase in the average operating dayrates from $54,400 in 2004 to $87,500 in 2005. This increase in average operating dayrates contributed $40.6 million in additional revenues in 2005, as compared to 2004.

     With the exception of the Ocean Patriot, which relocated from this region to Australia in mid-2004, average utilization increased slightly in 2005 compared to 2004, primarily due to higher utilization of the Ocean Nomad in 2005 as compared to 2004, when this drilling unit was both ready-stacked and mobilizing between Africa and the U.K. for a total of approximately five months during the year. The net effect of changes in average utilization between 2005 and 2004 was a $1.9 million decrease in operating revenues in 2005. In 2004, we also recognized $2.0 million in mobilization revenue for the Ocean Nomad .

     Contract drilling expense for our intermediate semisubmersible rigs operating offshore Europe increased $10.4 million in 2005 primarily due to increased labor and related costs and shorebase support costs for our operations in Norway, mostly due to Norwegian pay allowances and additional personnel required to comply with Norwegian regulations. Normal operating expenses for the Ocean Nomad increased in 2005, as compared to 2004, mainly due to higher labor costs associated with its operations in the U.K., as compared to the prior year when this unit worked a portion of the year offshore western Africa, as well as the recognition of mobilization expenses in 2005 related to the rig’s relocation from western Africa to the U.K. Our operating costs in this region in 2004 included $8.7 million in costs for the Ocean Patriot which relocated to the Australia/Asia region in mid-2004.

      South America . Our intermediate semisubmersibles working in Brazil generated revenues of $53.6 million in 2005 compared to revenues of $44.8 million in 2004. The $8.8 million increase in operating revenues was primarily due to a contract extension for the Ocean Yatzy at a higher average dayrate than it previously earned. Average operating dayrates increased to $75,100, as compared to an average dayrate of $70,300 in 2004, and resulted in additional revenues of $4.3 million in 2005. Average utilization of our rigs in this region increased from 87% in

2004 to 98% in 2005, which resulted in additional revenues in 2005 of $4.5 million. The lower utilization in 2004 was primarily due to additional downtime for special surveys and inspections of both of our rigs in this region.

     Operating expenses for the Ocean Yatzy and Ocean Winner increased $4.7 million in 2005, as compared to 2004, primarily due to increased labor costs for our rig-based personnel as a result of December 2004 and September 2005 wage increases and higher national labor and local shorebase support costs resulting from completion of a local competency program in Brazil.

Jack-Ups.

		Year Ended
		December 31,								Favorable/
		2005				2004				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
GOM		$	222,365			$	138,886			$	83,479
Australia/Asia/Middle East			49,444				21,290				28,154
South America			—				18,215				(18,215	)
Total Contract Drilling Revenue		$	271,809			$	178,391			$	93,418
CONTRACT DRILLING EXPENSE
GOM		$	98,866			$	89,906			$	(8,960	)
Australia/Asia/Middle East			24,967				15,546				(9,421	)
South America			—				9,014				9,014
Total Contract Drilling Expense		$	123,833			$	114,466			$	(9,367	)
OPERATING INCOME		$	147,976			$	63,925			$	84,051

      GOM. Our operating results in this region reflected the improvement in average operating dayrates and utilization for jack-up rigs in the GOM during 2005. Average operating dayrates increased to $54,600 in 2005 from $36,300 in 2004, which resulted in additional revenues of $75.5 million in 2005. Utilization of our jack-up fleet in the GOM continued to improve in 2005 compared to the average utilization achieved by our rigs in 2004. Average utilization in 2005 increased to 96% from 87% in 2004, resulting in additional revenues of $8.0 million in 2005. The improvement in utilization was primarily due to the nearly full utilization of the Ocean Champion in 2005 as compared to 2004, when it completed its reactivation from cold-stacked status, and the full utilization of the Ocean Nugget in 2005, as compared to 60 days of unpaid downtime in 2004 for a spud can inspection and related repair work.

     In late August 2005, the Ocean Warwick was declared a constructive total loss by our insurers as a result of damage it sustained during Hurricane Katrina. During 2005 and 2004, this drilling rig generated $11.8 million and $9.3 million in revenues, respectively, which are included in the revenue variances discussed above. See “—Overview — Impact of 2005 Hurricanes. ”

     Contract drilling expenses for our jack-up rigs operating in the GOM increased $9.0 million in 2005 compared to 2004, primarily due to higher labor and benefits costs for our rig-based personnel as a result of December 2004 and September 2005 wage increases, higher normal operating costs in 2005 for the Ocean Champion compared to 2004 when the rig was being reactivated and higher operating and overhead costs for most of our jack-ups in this region due to increased utilization.

      Australia/Asia/Middle East . Revenues for jack-up rigs in the Australasian and Middle East regions were $49.4 million in 2005 compared to $21.3 million in 2004. The $28.2 million increase in revenues in this region in 2005 is primarily attributable to revenues generated by the Ocean Heritage ($17.0 million), which worked in this region for the entire year, compared to working in this region during only the last quarter of 2004, and an operating dayrate increase for the Ocean Sovereign ($11.2 million) after its second quarter 2005 relocation within the region to Indonesia.

     Contract drilling expense for our jack-up rigs in the Australasian and Middle East regions increased $9.4 million to $25.0 million in 2005, as compared 2004, primarily due to normal operating costs associated with the Ocean Heritage operating in the region for the entire year, and higher normal repair and maintenance, travel and shore-based costs for the Ocean Sovereign .

      South America . The Ocean Heritage operated offshore Ecuador for almost eight months in 2004. During its contract the rig generated $18.2 million in revenues, including the recognition of $8.5 million in lump-sum mobilization fees, and incurred operating expenses of $9.0 million before returning to the Australasia/Middle East region in the fourth quarter of 2004.

Other Operating Revenue and Expenses, net.

     Other operating expenses, net of other revenues, were $8.3 million in 2005 compared to $1.2 million in 2004. The $7.2 million increase in net costs in 2005, as compared to 2004, relates primarily to costs associated with relief and recovery efforts in the aftermath of the 2005 GOM hurricanes, increased rig crew training costs due to higher staffing and recruiting levels in 2005 and higher costs in 2005 to repair and replace non-rig-specific spare equipment.

Reimbursable expenses, net.

     Revenues related to reimbursable items, offset by the related expenditures for these items, were $6.4 million and $3.4 million in 2005 and 2004, respectively. Reimbursable expenses include items that we purchase, and/or services we perform, at the request of our customers. We charge our 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.

     Depreciation expense increased $4.9 million to $183.7 million in 2005 compared to $178.8 million in 2004 primarily due to depreciation recorded in 2005 associated with capital additions in 2004 and 2005. The increase in depreciation expense attributable to capital additions was partially offset by lower depreciation due to the constructive total loss of the Ocean Warwick in the third quarter of 2005 and the transfer of the Ocean Liberator to assets held for sale in December 2004.

General and Administrative Expense.

     We incurred general and administrative expense of $37.2 million in 2005 compared to $32.8 million in 2004. The $4.4 million increase in overhead costs between the periods was primarily due to higher compensation expense related to our management bonus plan, higher fees paid to our external auditors and higher engineering consulting fees. Partially offsetting these higher expenses were lower legal fees in 2005 compared to 2004, primarily due to the settlement of litigation in December 2004, and the capitalization of certain costs associated with the upgrade of the Ocean Endeavor , which commenced in 2005.

Gain on Sale and Disposition of Assets.

     We recognized a net gain of $14.8 million on the sale and disposition of assets in 2005 compared to a net loss of $1.6 million in 2004. Net gains recognized in 2005 include an $8.0 million gain on the June 2005 sale of the Ocean Liberator, $5.6 million in insurance proceeds related to the involuntary conversion of certain assets damaged during Hurricane Ivan in 2004 and gains on the sale of used drill pipe during the period. Partially offsetting the net gain in 2005 was a $1.4 million loss due to the retirement of equipment lost or damaged during Hurricanes Katrina and Rita. The loss on sale of assets in 2004 relates primarily to the retirement of equipment damaged during Hurricane Ivan.

Casualty Gain on Ocean Warwick.

     We recorded a $33.6 million casualty gain in 2005 as a result of the constructive total loss of one of our jack-up rigs, the Ocean Warwick , resulting from damages sustained during Hurricane Katrina in August 2005. See “— Overview — Impact of 2005 Hurricanes.”

Interest Income.

     We earned interest income of $26.0 million in 2005 compared to $12.2 million in 2004. The $13.8 million increase in interest income is primarily the result of the combined effect of slightly higher interest rates earned on higher average cash and investment balances in 2005, as compared to 2004. See “— Liquidity and Capital Requirements” and “— Historical Cash Flows.”

Interest Expense.

     Interest expense for 2005 was $41.8 million, or an $11.5 million increase in interest cost compared to 2004. This increase was primarily attributable to interest related to our 4.875% Senior Notes and our 5.15% Senior Notes Due September 1, 2014, or 5.15% Senior Notes, which we issued in June 2005 and August 2004, respectively. In addition, interest expense for 2005 included a write-off of $6.9 million in debt issuance costs associated with our June 2005 repurchase of approximately 96% of our then outstanding Zero Coupon Debentures. This increase in interest cost was partially offset by lower interest expense on our Zero Coupon Debentures subsequent to our partial repurchase of the outstanding debentures in June 2005 and approximately $0.7 million in interest costs which were capitalized in 2005 related to qualifying upgrade and construction projects. See “— Liquidity and Capital Requirements — Contractual Cash Obligations .”

Other Income and Expense (Other, net).

     Included in “Other, net” are foreign currency translation adjustments and transaction gains and losses and other income and expense items, among other things, which are not attributable to our drilling operations. The components of “Other, net” fluctuate based on the level of activity, as well as fluctuations in foreign currencies. We recorded other expense, net, of $1.1 million in both 2005 and 2004.

     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 conduct business as their functional currency. During 2005 and 2004, we recognized net foreign currency exchange losses of $0.8 million and $1.4 million, respectively, including $3.5 million in additional expense in 2005 as a result of our change in functional currency to the U.S. dollar. 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.

Income Tax Expense.

     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 $96.1 million of tax expense on pre-tax income of $356.4 million for the year ended December 31, 2005 compared to tax expense of $3.7 million on a pre-tax loss of $3.5 million in 2004.

     Certain of our rigs that operate internationally are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary that we wholly own. We do not intend to remit earnings from this subsidiary to the U.S. and we plan to indefinitely reinvest these earnings internationally. Consequently, we provided no U.S. taxes on earnings and recognized no U.S. benefits on losses generated by this subsidiary during 2005 and 2004.

     At the end of 2004 we had established a valuation allowance of $10.3 million for certain of our foreign tax credit carryforwards which were scheduled to expire beginning in 2011. At December 31, 2005, we had $15.3 million of foreign tax credit carryforwards. During 2005, we were able to utilize most of our net operating loss carryforwards to offset taxable income generated during the year. As a result, we expected to be able to utilize $14.5 million of our available foreign tax credit carryforwards prior to their expiration dates, and determined that a valuation allowance was no longer necessary for those credits. Consequently, we reversed $9.6 million of the previously established valuation allowance during 2005. With respect to the remaining $0.8 million of foreign tax credit carryforwards, we determined that a valuation allowance was necessary and as a result had a valuation allowance of $0.8 million at December 31, 2005.

     At December 31, 2004 we had a reserve of $8.9 million ($1.7 million included with Current Taxes Payable and $7.2 in Other Liabilities in our Consolidated Balance Sheets) for the exposure related to the disallowance of goodwill deductibility associated with a 1996 acquisition. During 2005 we concluded that the reserve was no longer necessary and eliminated the reserve, which resulted in an income tax benefit of $8.9 million.

     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 the accrual was no longer necessary and wrote off the accrued liability in the fourth quarter of 2005.

     During 2004 and 2005, the 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 limited number of adjustments for which we recorded additional income tax of $1.9 million in 2005.

     Our tax expense in 2004 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 a 1996 merger, and a tax benefit of $4.5 million due to the reversal of a tax liability associated with the Ocean Alliance lease-leaseback.

     On October 22, 2004, the American Jobs Creation Act, or AJCA, was signed into law. The AJCA includes a provision allowing a deduction of 85% for certain foreign earnings that are repatriated. The AJCA provided us a potential opportunity to elect to apply this provision to qualifying earnings repatriations in 2005. Based on the language in the AJCA and subsequent guidance issued by the U.S. Treasury Department, and after considering our history of foreign earnings, we did not have undistributed foreign earnings that would qualify for the 85% deduction upon repatriation. Consequently, we did not repatriate any undistributed earnings in 2005 pursuant to the AJCA.

Sources of Liquidity and Capital Resources

     Our principal sources of liquidity and capital resources are cash flows from our operations, proceeds from the issuance of debt securities and our cash reserves. We may also make use of our $285 million credit facility for cash liquidity. See “— $285 Million Revolving Credit Facility .”

     At December 31, 2006, we had $524.7 million in “Cash and cash equivalents” and $301.2 million in “Investments and marketable securities,” representing our investment of cash available for current operations.

      Cash Flows from Operations. We operate in an industry that has been, and we expect to continue to be, extremely competitive and highly cyclical. The dayrates we receive for our 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. Demand for drilling services is dependent upon the level of expenditures by oil and gas companies for offshore exploration and development, a variety of political and economic factors and availability of rigs in a particular geographic region. As utilization rates increase, dayrates tend to increase as well reflecting the lower supply of available rigs, and vice versa. These factors are not within our control and are difficult to predict. For a description of other factors that could affect our cash flows from operations, see “— Overview — Industry Conditions,” “ — Forward-Looking Statements” and “Risk Factors” in Item 1A of this report.

      $285 Million Revolving Credit Facility. In November 2006, we entered into a $285 million syndicated, 5-year senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit.

     Loans under the Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.

     The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.

     Based on our current credit ratings at December 31, 2006, the applicable margin on LIBOR loans would have been 0.27%. As of December 31, 2006, there were no amounts outstanding under the Credit Facility.

      Shelf Registration. We have the ability to issue an aggregate of approximately $117.5 million in debt, equity and other securities under a shelf registration statement. In addition, from time to time we may issue up to eight million shares of common stock which are registered under an acquisition shelf registration statement, after giving effect to the two-for-one stock split we declared in July 1997, in connection with one or more acquisitions by us of securities or assets of other businesses.

Liquidity and Capital Requirements

     Our liquidity and capital requirements are primarily a function of our working capital needs, capital expenditures and debt service requirements. We determine the amount of cash required to meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements and by evaluating our ongoing rig equipment replacement and enhancement programs, including water depth and drilling capability upgrades. We believe that our operating cash flows and cash reserves will be sufficient to meet these capital commitments; however, we will continue to make periodic assessments based on industry conditions. In addition, we 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. Our ability to effect any such issuance will be dependent on our results of operations, our current financial condition, current market conditions and other

factors beyond our control. Additionally, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes.

     We believe that we have the financial resources needed to meet our business requirements in the foreseeable future, including capital expenditures for rig upgrades and enhancements, as well as our working capital requirements.

      Contractual Cash Obligations. The following table sets forth our contractual cash obligations at December 31, 2006.

     Payments of our long-term debt, including interest, could be accelerated due to certain rights that holders of our debentures have to put the securities to us. See the discussion below related to our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, and Zero Coupon Debentures.

     As of December 31, 2006, we had purchase obligations aggregating approximately $456 million related to the major upgrades of the Ocean Endeavor and Ocean Monarch and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield . We anticipate that expenditures related to these shipyard projects will be approximately $263 million and $193 million in 2007 and 2008, respectively. However, the actual timing of these expenditures will vary based on the completion of various construction milestones, which are beyond our control.

     We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2006, except for those related to our direct rig operations, which arise during the normal course of business.

4.875% Senior Notes.

     On June 14, 2005, we issued $250.0 million aggregate principal amount of 4.875% Senior Notes at an offering price of 99.785% of the principal amount, which resulted in net proceeds to us of $247.6 million. These notes bear interest at 4.875% per year, payable semiannually in arrears on January 1 and July 1 of each year and mature on July 1, 2015. The 4.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. We have the right to redeem all or a portion of the 4.875% 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.

5.15% Senior Notes.

     On August 27, 2004, we issued $250.0 million aggregate principal amount of 5.15% Senior Notes at an offering price of 99.759% of the principal amount, which resulted in net proceeds to us of $247.6 million. These notes bear interest at 5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year and mature on September 1, 2014. The 5.15% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. We have 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.

1.5% Debentures.

     On April 11, 2001, we issued $460.0 million principal amount of 1.5% Debentures, which are due April 15, 2031. The 1.5% Debentures are convertible into shares of our common stock at an initial conversion rate of 20.3978 shares per $1,000 principal amount of the 1.5% Debentures, or $49.02 per share, subject to adjustment in certain circumstances. Upon conversion, we have the right to deliver cash in lieu of shares of our common stock. Holders may require us 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. We may choose to pay the purchase price in cash or shares of our common stock or a combination of cash and common stock. See “1.5% Debentures” in Note 8 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The 1.5% Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

     During 2006 and 2005, the holders of $20,000 and $13,000, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock, resulting in the issuance of 404 shares and 264 shares of our common stock in 2006 and 2005, respectively.

     Subsequent to December 31, 2006 and through February 14, 2007, the holders of $438.4 million in principal amount of our 1.5% Debentures converted their outstanding debentures into 8,943,284 shares of our common stock. As a result of these conversions, $21.5 million aggregate principal amount of the 1.5% Debentures remained outstanding as of February 14, 2007. The cash requirements for the interest payable to holders of our 1.5% Debentures will decrease due to the decrease in the outstanding principal amount.

Zero Coupon Debentures.

     We issued our Zero Coupon Debentures on June 6, 2000 at a price of $499.60 per $1,000 principal amount at maturity, which represents a yield to maturity of 3.50% per year. The Zero Coupon Debentures mature on June 6, 2020, and, as of December 31, 2006, the aggregate accreted value of our outstanding Zero Coupon Debentures was $5.3 million. We will not pay interest prior to maturity unless we elect 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 our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. See “Zero Coupon Debentures” in Note 8 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

     On June 7, 2005, we repurchased $460.0 million accreted value, or $774.1 million in aggregate principal amount at maturity, of our Zero Coupon Debentures at a purchase price of $594.25 per $1,000 principal amount at maturity, which represented 96% of our then outstanding Zero Coupon Debentures. Additionally, in connection with the June 2005 repurchase, we expensed $6.9 million in debt issuance costs associated with the retired debentures, which we have included in interest expense in our Consolidated Statements of Operations for the year ended December 31, 2005.

     During 2006, holders of $13.7 million accreted value, or $22.4 million in aggregate principal amount at maturity, of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 193,147 shares of our common stock upon conversion of these debentures.

     Subsequent to December 31, 2006 and through February 14, 2007, the holders of $1.5 million accreted value at the dates of conversion, or $2.4 million aggregate principal amount at maturity, of our Zero Coupon Debentures converted their outstanding debentures into 20,658 shares of our common stock. As a result of these conversions, $3.8 million in accreted value, or $6.0 million aggregate principal amount at maturity, of the Zero Coupon Debentures remained outstanding as of February 14, 2007.

Letters of Credit.

     We are contingently liable as of December 31, 2006 in the amount of $122.0 million under certain performance, bid, supersedeas and custom bonds and letters of credit. We purchased three of these performance bonds totaling $73.2 million from a related party after obtaining competitive quotes. Agreements relating to approximately $107.3

million of performance bonds can require collateral at any time. As of December 31, 2006, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds. See Note 12 “Related-Party Transactions” to our Consolidated Financial Statements included in Item 8 of this report.

Credit Ratings.

     Our current credit rating is Baa2 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings would result in higher rates for borrowings under our Credit Facility and could also result in higher interest rates on future debt issuances.

Capital Expenditures.

     In 2006, we began a major upgrade of the Ocean Monarch , a Victory-class semisubmersible that we acquired in August 2005 for $20.0 million. The modernized rig will be designed to operate in up to 10,000 feet of water in a moored configuration for an estimated cost of approximately $300 million of which we had spent $33.9 million through December 31, 2006. We expect to spend an additional $150.0 million and $116.1 million on this upgrade in 2007 and 2008, respectively.

     In addition, the shipyard portion of the upgrade of the Ocean Endeavor has been completed. The newly upgraded rig is currently undergoing sea trials and commissioning. The unit will remain in Singapore until the arrival of a heavy-lift vessel, anticipated late in the first quarter of 2007, which will return the rig to the GOM. The Ocean Endeavor is expected to commence drilling operations in the GOM in mid-2007. We estimate that the total cost of the upgrade will be approximately $253 million of which $208.4 million had been spent through December 31, 2006. We expect to spend the remaining $44.0 million in 2007.

     In the second quarter of 2005, we entered into agreements to construct two high-performance, premium jack-up rigs. The two new drilling units, the Ocean Scepter and the Ocean Shield, are being constructed in Brownsville, Texas and Singapore, respectively, at an aggregate expected cost of approximately $320 million, including drill pipe and capitalized interest, of which $176.1 million had been spent through December 31, 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 to spend approximately $69 million and $77 million towards the construction of these two units in 2007 and 2008, respectively. Delivery of both the Ocean Scepter and Ocean Shield are expected in the first quarter of 2008.

     We have budgeted approximately $316 million in additional capital expenditures in 2007 associated with our ongoing rig equipment replacement and enhancement programs, and other corporate requirements. We expect to finance our 2007 capital expenditures through the use of our existing cash balances or internally generated funds. From time to time, however, we may also make use of our Credit Facility to finance capital expenditures.

     During 2006, we spent approximately $273.2 million on our continuing rig capital maintenance program (other than rig upgrades and new construction) and to meet other corporate capital expenditure requirements.

Off-Balance Sheet Arrangements.

     At December 31, 2006 and 2005, we had no off-balance sheet debt or other arrangements.

Historical Cash Flows

     The following is a discussion of our historical cash flows from operating, investing and financing activities for the year ended December 31, 2006 compared to 2005.

     Our cash flows from operations in 2006 increased $371.5 million or 96% over net cash generated by our operating activities in 2005. The increase in cash flow from operations in 2006 is primarily the result of higher average dayrates and, to a lesser extent, higher utilization earned by our offshore drilling units as a result of an increase in worldwide demand for offshore contract drilling services in 2006 as compared to 2005. These favorable trends were impacted by an increase in cash required to satisfy our working capital requirements, including an increase in our trade accounts receivable, which is primarily driven by higher dayrates earned by our drilling rigs in 2006 as compared to 2005. These trade receivables generate cash as the billing cycle is completed, customarily within 30 to 45 days of invoicing. In addition, we paid $248.7 million and $10.8 million in U.S. federal and foreign income taxes, respectively, each net of refunds received, during 2006. We received $7.7 million in refunds of U.S. federal income taxes and paid $5.3 million in foreign income taxes, net of refunds received, during 2005.

     Our investing activities used $823.9 million in 2006, as compared to generating $450.0 million in 2005. During 2006, we purchased marketable securities, net of sales, of $284.7 million compared to net sales of $654.3 million during 2005. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets. The high level of marketable securities transactions during 2005, primarily during the first half of the year, was primarily in response to an increase in our short-term cash requirements in 2005 to partially fund the repurchase of $460.0 million accreted value of Zero Coupon Debentures in June 2005 and capital additions.

     During 2006, we spent approximately $278.0 million related to the major upgrades of the Ocean Endeavor and Ocean Monarch and construction of the Ocean Scepter and Ocean Shield . During 2005, we spent approximately $140.4 million related to the major upgrade of the Ocean Endeavor and construction of our two new jack-up drilling rigs . Expenditures for our ongoing capital maintenance programs were $273.2 million in 2006 compared to $133.4 million in 2005. The increase in expenditures related to our ongoing capital maintenance program in 2006 compared to 2005 is related to an increase in discretionary funds available for capital spending in 2006, and, to a lesser extent, in response to the high sustained utilization of our drilling rigs in 2006. Our capital expenditures in 2005 also included $20.0 million for the purchase of the Ocean Monarch and its related equipment. See “— Liquidity and Capital Requirements — Capital Expenditures .”

     We collected $50.5 million in insurance proceeds related to the casualty loss of the Ocean Warwick in 2005. Additionally, in 2005 we sold one of our then cold-stacked intermediate semisubmersible rigs, the Ocean Liberator , for net cash proceeds of $13.6 million and received $5.6 million in insurance proceeds (total proceeds of $14.5 million of which $8.9 million is included in net cash provided by operating activities) related to the involuntary conversion of assets damaged during Hurricane Ivan in 2004.

     During 2006, we received $2.1 million in insurance proceeds (total proceeds of $10.8 million of which $8.7 million is included in net cash provided by operating activities) related to the involuntary conversion of riser equipment damaged on the Ocean Vanguard in December 2004 and recovered an additional $1.1 million from our customers (total recovery of $3.1 million of which $2.0 million is included in net cash provided by operating activities) related to the involuntary conversion of assets damaged during the 2005 hurricanes.

     During 2005, our remaining investments in Australian dollar time deposits, which we originally entered into in 2004, matured, resulting in proceeds to us of $11.8 million. In the latter half of 2005, we stepped up our ongoing program of entering into foreign currency forward exchange contracts to reduce our forward exchange risk. During 2006, we realized net gains totaling $7.3 million on the settlement of several forward exchange contracts in various currencies. We realized net gains of $1.1 million on similar forward exchange transactions during 2005.

     As of December 31, 2006, we had foreign currency exchange contracts outstanding, which aggregated $22.5 million, that require us to purchase the equivalent of $5.7 million in Brazilian reais, $2.7 million in British pounds sterling, $10.3 million in Mexican pesos and $3.8 million in Norwegian kroner at various times through June 2007.