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, 2007

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

For the transition period from                      to                     

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
		(Do not check if a smaller reporting company)

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, 2007		$6,963,153,673

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, 2008                    Common Stock, $0.01 par value per share                     138,873,545 shares

     Portions of the definitive proxy statement relating to the 2008 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2007, are incorporated by reference in Part III of this report.

 

 

DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2007

TABLE OF CONTENTS

				Page No.
Cover Page
Document Table of Contents					2
Part I
Item 1.		Business			3
Item 1A.		Risk Factors			8
Item 1B.		Unresolved Staff Comments			14
Item 2.		Properties			15
Item 3.		Legal Proceedings			15
Item 4.		Submission of Matters to a Vote of Security Holders			15
Part II
Item 5.		Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			17
Item 6.		Selected Financial Data			19
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
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			88
Item 9A.		Controls and Procedures			88
Item 9B.		Other Information			89
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			89
Signatures					93
Exhibit Index					94
Second Amended and Restated 2000 Stock Option Plan
Summary Sheet of Base Salary Increases
Statement re Computation of Ratios
List of Subsidiaries
Consent of Deloitte & Touche LLP
Powers of Attorney
Rule 13a-14(a) Certification of CEO
Rule 13a-14(a) Certification of CFO
Section 1350 Certification of CEO and CFO

PART I

Item 1. Business.

General

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

The Fleet

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

     Semisubmersibles. We own and operate 30 semisubmersibles, consisting of 10 high-specification and 20 intermediate rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles are typically anchored in position and remain stable for drilling in the semi-submerged floating position due in part to their wave transparency characteristics at the water line. Semisubmersibles can also be held in position through the use of a computer controlled thruster (dynamic-positioning) system to maintain the rig’s position over a drillsite. We have three semisubmersible rigs in our fleet with this capability.

     Our high specification semisubmersibles are generally capable of working in water depths of 4,000 feet or greater or in harsh environments and have other advanced features, as compared to intermediate semisubmersibles. As of January 28, 2008, eight of our 10 high-specification semisubmersibles were located in the U.S. Gulf of Mexico, or GOM, while the remaining two rigs were located offshore Brazil and Malaysia.

     Our intermediate semisubmersibles generally work in maximum water depths up to 4,000 feet. As of January 28, 2008, we had 19 intermediate semisubmersible rigs drilling offshore or undergoing contract preparation activities in various locations around the world. Two of these semisubmersibles were located in the GOM; three were located offshore Mexico, four were located in the North Sea, three were located offshore Australia, four were located offshore Brazil and one each was located offshore Egypt, Indonesia and Trinidad and Tobago.

     Our remaining intermediate semisubmersible, the Ocean Monarch, is currently in Singapore where construction activities are underway to upgrade this rig to a high-specification unit which will be able to operate in up to 10,000 feet of water in a moored configuration. See “ — Fleet Enhancements and Additions.”

     Drillship. We have one high-specification drillship, the Ocean Clipper, which was located offshore Brazil as of January 28, 2008. 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.

     Both semisubmersible rigs and drillships are commonly referred to as floaters in the offshore drilling industry.

     Jack-ups. We currently own 13 jack-up drilling rigs. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is principally determined by the length of the rig’s legs. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues until the hull

is elevated above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the water and then the legs are retracted for relocation to another drillsite.

     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 28, 2008, seven of our 13 jack-up rigs were located in the GOM. Four of those rigs are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Of our six remaining jack-up rigs, all of which are independent-leg cantilevered units, two were located offshore Mexico, one was located offshore Indonesia, one was located offshore Egypt, one was located offshore Croatia and the other rig was located offshore Qatar.

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

     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 of, 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 13 (10 of which are high-specification units), primarily by upgrading our existing fleet. Six of these upgrades were to our Victory-class semisubmersible rigs, the design of which is well-suited for significant upgrade projects. We are in the process of upgrading one of our remaining Victory-class rigs in Singapore, and we have two additional Victory-class rigs that are currently operating as intermediate semisubmersibles that could potentially be upgraded at some time in the future.

     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 $305 million. Through December 31, 2007, we had spent $181.4 million related to this project. The Ocean Monarch is expected to be ready for deepwater service in the fourth quarter of 2008. The rig will then return to the GOM where it is expected to begin operating under contract in early 2009.

     The upgrade of the Ocean Endeavor to 10,000 foot water depth capability was completed in 2007 for a total cost of approximately $248 million, substantially all of which had been spent through December 31, 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 $248.5 million had been spent through December 31, 2007. Each new-build 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 second quarter of 2008. The Ocean Shield is expected to begin working under a one-year contract offshore Australia beginning in the second 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 28, 2008, is set forth in the table below.

		Nominal Water Depth				Year Built/Latest		Current
Type and Name		Rating (a)		Attributes		Enhancement (b)		Location (c)		Customer (d)
High-Specification Floaters Semisubmersibles (10):
Ocean Endeavor		10,000		VC; 15K; 4M		1975/2007		GOM		Devon
Ocean Confidence		7,500		DP; 15K; 4M		2001		GOM		BP America
Ocean Baroness		7,000		VC; 15K; 4M		1973/2002		GOM		Hess Corporation
Ocean Rover		7,000		VC; 15K; 4M		1973/2003		Malaysia		Murphy Exploration
Ocean America		5,500		SP; 15K; 3M		1988/1999		GOM		LLOG
Ocean Valiant		5,500		SP; 15K; 3M		1988/1999		GOM		LLOG
Ocean Victory		5,500		VC; 15K; 3M		1972/1997		GOM		Shipyard: Survey
Ocean Star		5,500		VC; 15K; 3M		1974/1999		GOM		Anadarko
Ocean Alliance		5,000		DP; 15K; 3M		1988/1999		Brazil		Petrobras
Ocean Quest		3,500		VC; 15K; 3M		1973/1996		GOM		Marathon Oil
Drillship (1):
Ocean Clipper		7,500		DP; 15K; 3M		1976/1999		Brazil		Petrobras
Intermediate Semisubmersibles (19):
Ocean Winner		4,000		3M		1977/2004		Brazil		Petrobras
Ocean Worker		3,500		3M		1982/1992		Trinidad & Tobago		Petro-Canada
Ocean Yatzy		3,300		DP		1989/1998		Brazil		Petrobras
Ocean Voyager		3,200		VC; 3M		1973/1995		Mexico		PEMEX
Ocean Patriot		3,000		15K; 3M		1982/2003		Australia		Shipyard: Survey
Ocean Yorktown		2,200		3M		1976/1996		GOM		Shipyard:
										Contract Preparation
Ocean Concord		2,200		3M		1975/1999		Brazil		Petrobras
Ocean Lexington		2,200		3M		1976/1995		Egypt		BP Egypt
Ocean Saratoga		2,200		3M		1976/1995		GOM		Nexen Petroleum
Ocean Epoch		1,640		3M		1977/2000		Australia		Shell Australia
Ocean General		1,640		3M		1976/1999		Indonesia		Inpex
Ocean Bounty		1,500		VC; 3M		1977/1992		Australia		Woodside Energy
Ocean Guardian		1,500		15K; 3M		1985		North Sea		Oilexco
Ocean New Era		1,500		3M		1974/1990		Mexico		PEMEX
Ocean Princess		1,500		15K; 3M		1977/1998		North Sea		Talisman
Ocean Whittington		1,500		3M		1974/1995		Brazil		Petrobras
Ocean Vanguard		1,500		15K; 3M		1982		Norway		Statoil
Ocean Nomad		1,200		3M		1975/2001		North Sea		Talisman
Ocean Ambassador		1,100		3M		1975/1995		Mexico		PEMEX
Jack-ups (13):
Ocean Titan		350		IC; 15K; 3M		1974/2004		GOM		Apache
Ocean Tower		350		IC; 3M		1972/2003		GOM		Chevron
Ocean King		300		IC; 3M		1973/1999		Croatia		Bareboat charter to
										CROSCO
Ocean Nugget		300		IC		1976/1995		Mexico		PEMEX
Ocean Summit		300		IC		1972/2003		GOM		Energy Partners
Ocean Heritage		300		IC		1981/2002		Qatar		Qatar Petroleum
Ocean Spartan		300		IC		1980/2003		GOM		Apache
Ocean Spur		300		IC		1981/2003		Egypt		NOSPCO
Ocean Sovereign		300		IC		1981/2003		Indonesia		KODECO
Ocean Champion		250		MS		1975/2004		GOM		Bois d'Arc
Ocean Columbia		250		IC		1978/1990		Mexico		PEMEX
Ocean Crusader		200		MC		1982/1992		GOM		Breton Energy
Ocean Drake		200		MC		1983/1986		GOM		Fairways Offshore
Under Construction (3):
Ocean Monarch		1,500		VC		1974/2008		Singapore		Shipyard; Upgrade to
										10,000’
Ocean Scepter		350		IC; 15K; 3M		2008		GOM		New; Under Construction
Ocean Shield		350		IC; 15K; 3M		2008		Singapore		New; Under Construction

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 drilling depth capability 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.
(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 Tunisia 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 17 “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 the majority 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 an extended 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. During 2007, we performed services for 49 different customers, none of which accounted for 10% or more of our annual total consolidated revenues. 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.

     We principally market our services in North America through our Houston, Texas office. 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 global demand for oil and natural gas, 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 50%, 43% and 45% of our total consolidated revenues for the years ended December 31, 2007, 2006 and 2005, 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 offshore Mexico 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, 2007, we had approximately 5,400 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. Worldwide demand for oil and gas, 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 demand and prices do not necessarily translate into increased drilling activity since our customers’ expectations of future commodity demand and prices typically drive demand for our rigs. Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including:

	•		worldwide demand for oil and gas;
	•		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 worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East, other oil-producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;
	•		the worldwide economic environment or economic trends, such as recessions;
	•		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 policies of various governments regarding exploration and development of their oil and gas reserves;
	•		development and exploitation of alternative fuels;
	•		domestic and foreign tax policy; 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. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors.

     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 virtually all 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.

     Growing worldwide demand for crude oil and natural gas has caused current oil and natural gas prices to rise

significantly above historical averages, which has generally resulted in higher utilization and dayrates earned by our drilling units, generally since 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 as of the date of this report there are approximately 150 jack-up rigs and floaters (semisubmersible rigs and drillships) on order and scheduled for delivery between 2008 and 2011. Improvements in dayrates and expectations of sustained improvements in rig utilization rates and dayrates by drilling contractors may result in the construction of additional new rigs. At the same time, anticipated shortages of sufficient rig capacity to meet future requirements on the part of operators may cause the operators to contract for additional new-build equipment. The resulting increases in rig supply could be sufficient to 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 and our customers. 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.

We rely heavily on a relatively small number of customers and the loss of a significant customer could have a material adverse impact on our financial results.

     We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. However, the number of potential customers has decreased in recent years as a result of mergers among the major international oil companies and large independent oil companies. In 2007, our five largest customers in the aggregate accounted for approximately 39% of our consolidated revenues. While it is normal for our customer base to change over time as work programs are completed, the loss of any major customer may have a material adverse effect on our financial position, results of operations and cash flows.

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 customer requirements and, to a lesser extent, the respective management strategies of the offshore drilling contractors. In periods of rising demand for offshore rigs, contractors typically prefer shorter contracts that allow them to more quickly 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 shorter contracts that allow them to more quickly obtain the benefit of lower dayrates.

     Typically, as a period of high dayrates and utilization lengthens, customers who perceive a continuing long-term need for equipment begin to seek increasingly long-term contracts, but often at flat or slightly lower dayrates in exchange for the term length. To the extent possible within the scope of our customers’ requirements, we seek to have a foundation of these long-term contracts with a reasonable balance of shorter-term exposure to the spot market in an attempt to maintain upside potential while endeavoring to limit the downside impact of a potential decline in the 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 approximately $11 billion for expected future work extending, in some cases, until 2015, which includes future earnings under both firm commitments and. in a few instances, 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 new-builds 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 are currently upgrading one of our semisubmersible drilling units, the Ocean Monarch, to ultra-deepwater capability at an estimated aggregate cost of approximately $305 million. We expect delivery of the upgraded Ocean Monarch 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 second 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;
	•		customer acceptance delays
	•		shipyard failures or unavailability; 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, resulting in a loss of revenue to us. If a drilling contract is terminated under these circumstances, we may not be able to secure a replacement contract on as favorable terms.

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, and could have a material adverse effect on our results of operations and financial condition. 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, 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 and 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 are self-insured for a portion of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico.

     For physical damage due to named windstorms in the U.S. Gulf of Mexico, as of the date of this report our deductible is $75.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss) with an annual aggregate limit of $125.0 million. Accordingly, our insurance coverage for all physical damage to our rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico for the policy period ending April 30, 2008 is limited to $125.0 million. 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 and 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 or assaults on property or personnel;
	•		kidnapping of personnel;
	•		expropriation of property or equipment;
	•		renegotiation or nullification of existing contracts;
	•		changing political conditions;
	•		foreign and domestic monetary policies;
	•		the inability to repatriate income or capital;
	•		regulatory or financial requirements to comply with foreign bureaucratic actions;
	•		travel limitations or operational problems caused by public health threats; 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.

     Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict 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.

Future acts of terrorism and other political and military events could adversely affect the markets for our drilling services.

     Terrorist acts and political events around the world have resulted in military actions in Afghanistan and Iraq, as well as related political and economic unrest in various parts of the world. Future terrorist attacks and the continued threat of terrorism in this country or abroad, the continuation or escalation of existing armed hostilities or the outbreak of additional hostilities could lead to increased political, economic and financial market instability and a downturn in the economies of the U.S. and other countries. A lower level of economic activity could result in a decline in energy consumption or an increase in the volatility of energy prices, either of which could adversely affect the market for our offshore drilling services, our dayrates or utilization and, accordingly, our financial position, results of operations and cash flows. In addition, it has been reported that terrorists might target domestic energy facilities. While we take steps that we believe are appropriate to increase the security of our energy assets, there is no assurance that we can completely secure these assets, completely protect them against a terrorist attack or obtain adequate insurance coverage for terrorist acts at reasonable rates. Moreover, U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.

Our drilling contracts offshore Mexico expose us to greater risks than we normally assume.

     As of the date of this report, we have three intermediate semisubmersible rigs and two jack-up rigs drilling offshore Mexico for PEMEX — Exploración Y Producción, or PEMEX, the national oil company of Mexico. 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.

Public health threats could have a material adverse effect on our operations and financial results.

     Public health threats such as outbreaks of highly communicable diseases, which periodically occur in various parts of the world in which we operate, could adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may have a material adverse effect on our financial position, results of operations and cash flows.

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. Since forming this subsidiary it has been our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign operations. During 2007, this subsidiary made a non-recurring distribution to its U.S. parent company, and we recognized U.S. federal income tax expense on the portion of the distribution that consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. As of December 31, 2007, the amount of previously untaxed earnings of this subsidiary was zero. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest the future earnings of this subsidiary to finance foreign activities. We do not expect to provide for U.S. taxes on any future earnings generated by this subsidiary, except to the extent that these earnings are immediately subjected to U.S. federal income tax. Should a future distribution be made from any unremitted earnings of this 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.

     Governments in some foreign countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industries. The modification of

existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.

     The Minerals Management Service of the U.S. Department of the Interior, or MMS, has established guidelines for drilling operations in the GOM We believe that we are currently in compliance with the existing regulations set forth by the MMS with respect to our operations in the GOM; however, these regulations are continually under review by the MMS and may change from time to time. Implementation of additional MMS regulations may subject us to increased costs of operating, or a reduction in the area and/or periods 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 and 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 50.5% of our outstanding shares of common stock as of February 20, 2008 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.

Item 2. Properties.

     We own an eight-story office building containing approximately 182,000-net rentable square feet on approximately 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located, two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, and a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, The Netherlands, Malaysia, Qatar, Singapore, Egypt, Trinidad and Tobago and Mexico to support our offshore drilling operations.

Item 3. Legal Proceedings.

     Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders.

     Not applicable.

Executive Officers of the Registrant

     We have included information on our executive officers in Part I of this report in reliance on General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors to serve until the next annual meeting of our Board of Directors, or until their successors are duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office. Information with respect to our executive officers is set forth below.

		Age as of
Name		January 31, 2008				Position
James S. Tisch			55			Chairman of the Board of Directors and Chief Executive Officer
Lawrence R. Dickerson			55			President, Chief Operating Officer and Director
Gary T. Krenek			49			Senior Vice President and Chief Financial Officer
William C. Long			41			Senior Vice President, General Counsel & Secretary
Beth G. Gordon			52			Controller — Chief Accounting Officer
Mark F. Baudoin			55			Senior Vice President — Administration
Lyndol L. Dew			53			Senior Vice President — Worldwide Operations
John L. Gabriel, Jr.			54			Senior Vice President — Contracts & Marketing
John M. Vecchio			57			Senior Vice President — Technical Services

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

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

     Gary T. Krenek has served as a Senior Vice President and our Chief Financial Officer since October 2006. Mr. Krenek previously served as our Vice President and Chief Financial Officer since March 1998.

     William C. Long has served as a Senior Vice President and our General Counsel and Secretary since October 2006. Mr. Long previously served as our Vice President, General Counsel and Secretary since March 2001 and as our General Counsel and Secretary from March 1999 through February 2001.

     Beth G. Gordon has served as our Controller and Chief Accounting Officer since April 2000.

     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 Senior Vice President — Technical Services since April 2002.

PART II

Item 5.		Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Price Range of Common Stock

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

		Common Stock
		High				Low
2007
First Quarter		$	87.23			$	73.65
Second Quarter			107.13				81.47
Third Quarter			115.05				91.23
Fourth Quarter			148.51				105.19
2006
First Quarter		$	90.70			$	72.75
Second Quarter			96.15				72.49
Third Quarter			85.44				67.46
Fourth Quarter			84.43				63.90

     As of February 20, 2008 there were approximately 232 holders of record of our common stock.

Dividend Policy

     In 2007, we paid quarterly cash dividends of $0.125 per share of our common stock on March 1, June 1, September 4 and December 3. We paid special cash dividends of $4.00 and $1.25 per share of our common stock on March 1, 2007 and December 3, 2007, respectively. In 2006, we paid regular quarterly cash dividends of $0.125 per share of our common stock on March 1, June 1, September 1 and December 1 and a special cash dividend of $1.50 per share of our common stock on March 1.

     On February 6, 2008, we declared a regular quarterly cash dividend and a special cash dividend of $0.125 and $1.25, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on March 3, 2008 to stockholders of record on February 18, 2008.

     In the fourth quarter of 2007, our Board of Directors adopted a policy of considering paying special cash dividends, in amounts to be determined, on a quarterly basis, rather than annually. Our Board of Directors may, in subsequent quarters, consider paying additional special cash dividends, in amounts to be determined, if it believes that our financial position, earnings, earnings outlook, capital spending plans and other relevant factors warrant such action at that time.

CUMULATIVE TOTAL STOCKHOLDER RETURN

     The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Index and a Peer Group Index over the five year period ended December 31, 2007.

Comparison of 2003 — 2007 Cumulative Total Return (1)

		Dec. 31, 2002				Dec. 31, 2003				Dec. 31, 2004				Dec. 31, 2005				Dec. 31, 2006				Dec. 31, 2007
Diamond Offshore			100				96				189				331				391				741
S&P 500			100				129				143				150				173				183
Peer Group (2)			100				103				136				203				225				319

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.

		As of and for the Year Ended December 31,
		2007				2006				2005				2004				2003
		(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues		$	2,567,723			$	2,052,572			$	1,221,002			$	814,662			$	680,941
Operating income (loss)			1,223,522				940,432				374,399				3,928				(38,323	)
Net income (loss)			846,541				706,847				260,337				(7,243	)			(48,414	)
Net income (loss) per share:
Basic			6.14				5.47				2.02				(0.06	)			(0.37	)
Diluted			6.12				5.12				1.91				(0.06	)			(0.37	)
Balance Sheet Data:
Drilling and other property and equipment, net		$	3,040,063			$	2,628,453			$	2,302,020			$	2,154,593			$	2,257,876
Total assets			4,341,465				4,132,839				3,606,922				3,379,386				3,135,019
Long-term debt (excluding current maturities) (1)			503,071				964,310				977,654				709,413				928,030
Other Financial Data:
Capital expenditures		$	647,101			$	551,237			$	293,829			$	89,229			$	272,026
Cash dividends declared per share			5.75				2.00				0.375				0.25				0.438
Ratio of earnings to fixed charges (2)			32.31x				28.26x				9.19x				N/A				N/A

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 offshore 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 under construction at shipyards in Brownsville, Texas and Singapore. We expect both of these units to be delivered during the second quarter of 2008.

Overview

Industry Conditions

     Worldwide demand for our mid-water (intermediate) and deepwater (high-specification) semisubmersible rigs remained strong throughout the year 2007 and into 2008. The jack-up market in the U.S. Gulf of Mexico, however, continues to experience reduced demand, resulting in downward pricing pressure and some of our jack-up rigs being ready-stacked for periods of time between wells. Exclusive of the GOM jack-up market, which accounted for nine percent of our total revenue for the year ended December 31, 2007, solid fundamental market conditions remain in place for all classes of our offshore drilling rigs worldwide.

     Gulf of Mexico. In the GOM, the market for our high-specification semisubmersible equipment remains firm. One of our high-specification rigs is contracted for work in the GOM until late in the fourth quarter of 2008, while the remaining seven high-specification rigs currently located in the GOM have contracts that extend well into 2009 and beyond, including two at dayrates as high as $500,000 for future work. In many cases, these contracts also include un-priced option periods that have neither been exercised nor have expired.

     As of the date of this report, dayrates for intermediate semisubmersibles in the GOM, where we currently have one such unit operating, are ranging between $250,000 and $300,000. During 2007, strong international demand offering lengthy terms encouraged us to obtain international contracts for four of our intermediate rigs that were previously located in the GOM. All but one of these rigs has left the GOM. The fourth unit is in a shipyard in Brownsville for a survey and life extension project. We expect this rig to depart the GOM in the second quarter of 2008 for Brazil. 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 2008.

     Our jack-up fleet in the GOM continued to experience lower utilization and dayrates during the fourth quarter of 2007, compared to the third quarter of 2007, as four of our seven available rigs were ready-stacked for periods of time and average dayrates declined slightly from those earned during the third quarter of 2007. As of January 28, 2008, all seven of our available jack-ups in the GOM were on contract, although the well-to-well nature of the market persists. The international market for jack-ups remains generally strong. As a result, we signed a two-year term extension with KODECO Energy Co. LTD. for the Ocean Sovereign in Indonesia at a dayrate in the mid $140,000s that is expected to commence in the second quarter of 2008. The mobilization of the Ocean Columbia from the GOM to Mexico also was completed during the fourth quarter of 2007, and that unit began operating in the first quarter of 2008. We believe that the current market environment for jack-up rigs, both in the GOM and internationally, will continue at least through the first quarter of 2008.

     Brazil. During 2007, we added two semisubmersible rigs to our fleet in Brazil, where we currently have five semisubmersibles and one drillship operating. Two additional semisubmersible units, the Ocean Yorktown and Ocean Worker, are expected to commence operations there in the second and third quarters of 2008, respectively. Our drillship is contracted until the end of 2010. Of our other seven rigs that are or are expected to be working offshore Brazil in 2008, one is contracted until 2012 and two each are contracted until 2013, 2014 and 2015. In late 2007, Petrobras announced the discovery of an ultra-deep Atlantic Ocean field with as much as 8 billion barrels of crude oil. In early 2008, Petrobras also announced the discovery of a large natural gas reserve off the coast of Rio de Janeiro that may more than equal the size of the crude oil discovery. We expect the Brazilian floater market to remain strong during 2008.

     North Sea. Effective semisubmersible utilization remains at 100 percent in the North Sea where we have three semisubmersible rigs in the U.K. and one semisubmersible unit in Norway. The current contract for one of our four rigs in the North Sea extends until the second quarter of 2009, and 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 three jack-up rigs and one semisubmersible rig located in the Middle East/Mediterranean sector. During the fourth quarter of 2007, the semisubmersible Ocean General received a Letter of Intent, or LOI, for two years of work in Vietnam at a dayrate in the low $280,000s. We believe that the Australia/Asia/Middle East and Mediterranean floater markets will remain strong during 2008.

Contract Drilling Backlog

     The following table reflects our contract drilling backlog as of February 7, 2008, October 25, 2007 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) and February 19, 2007 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2006) and reflects both firm commitments (typically represented by signed contracts), as well as previously-disclosed LOIs. An LOI is subject to customary conditions, including the execution of a definitive agreement. Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, 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% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes 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.

						October 25,
		February 7, 2008				2007				February 19, 2007
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters		$	4,448,000			$	3,657,000			$	4,115,000
Intermediate Semisubmersibles (1)			5,985,000				4,450,000				2,895,000
Jack-ups			421,000				432,000				432,000
Total		$	10,854,000			$	8,539,000			$	7,442,000

     The following table reflects the amount of our contract drilling backlog by year as of February 7, 2008.

		For the Years Ending December 31,
		Total				2008				2009				2010				2011 - 2015
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters		$	4,448,000			$	1,287,000			$	1,115,000			$	810,000			$	1,236,000
Intermediate Semisubmersibles (1)			5,985,000				1,612,000				1,588,000				1,060,000				1,725,000
Jack-ups			421,000				281,000				121,000				19,000				—
Total		$	10,854,000			$	3,180,000			$	2,824,000			$	1,889,000			$	2,961,000

     The following table reflects the percentage of rig days committed by year as of February 7, 2008. The percentage of rig days committed is calculated as the ratio of total days committed under contracts and LOIs, as well as scheduled shipyard, survey and mobilization 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 Monarch, and our two new-build jack-up rigs, the Ocean Scepter and Ocean Shield.

		For the Years Ending December 31,
		2008				2009				2010				2011 - 2015
Rig Days Committed (1)
High-Specification Floaters			99	%			73	%			51	%			14	%
Intermediate Semisubmersibles			94	%			83	%			53	%			19	%
Jack-ups			48	%			17	%			2	%			—

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 fees (either lump-sum or dayrate) 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 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 strong 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 and the regions in which our rigs are working.

     Operating expenses generally are not affected by changes in dayrates, and short-term reductions in utilization do not necessarily result in lower operating expenses. 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, except for rigs located in the U.K. and Norwegian sectors of the North Sea.

     During 2008, we expect 12 rigs in our fleet to undergo 5-year or intermediate surveys at an estimated aggregate cost of approximately $45 million, 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 2007, 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 2008.

     For physical damage due to named windstorms in the U.S. Gulf of Mexico, as of the date of this report our deductible is $75.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss) with an annual aggregate limit of $125.0 million. Accordingly, our insurance coverage for all physical damage to our rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico for the policy period ending April 30, 2008 is limited to $125.0 million. 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 and cash flows.

     Insurance premiums will be amortized as expense over the applicable policy periods which generally expire at the end of April 2008.

     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 2005 and 2006, we began capitalizing interest with respect to expenditures related to our upgrade of the Ocean Monarch 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. Prior to the completion of our upgrade of the Ocean Endeavor in March 2007, we capitalized interest on qualifying expenditures on that project beginning in April 2005. See Note 1 “General Information — Capitalized Interest” to our Consolidated Financial Statements included in Item 8 of this report.

     During 2008, we expect to complete the upgrade of the Ocean Monarch and to accept delivery of the newly constructed Ocean Scepter and Ocean Shield. We will continue to capitalize interest costs related to this upgrade until sea trials and commissioning of the Ocean Monarch are completed and the rig is loaded on a heavy lift vessel for its return to the GOM, which we anticipate will occur late in the fourth quarter of 2008. We expect to continue capitalizing interest costs in connection with the construction of our two jack-up rigs until sea trials and commissioning of the rigs are complete, which we expect to occur in the second quarter of 2008. Accordingly, we will then cease capitalizing interest costs related to these projects and will begin depreciating the newly upgraded/constructed rigs. As a result of the scheduled delivery of these rigs, we anticipate that depreciation and interest expense in 2008 will increase by approximately $7 million and $2 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, 2007, all of our drilling rigs were either under contract or were in shipyards for surveys, contract modifications or major upgrade, except for two of our jack-up drilling rigs located in the GOM. At December 31, 2007, one of these idle units was under contract but waiting to begin drilling operations while the other unit was being actively marketed. We did not have any cold-stacked rigs at December 31, 2007. 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. Our deductible for liability coverage for personal injury claims, which primarily results from Jones Act liability in the Gulf of Mexico, is $5.0 million (or $10.0 million if hurricane-related) 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. We engage experts to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models.

     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.

     We adopted the provisions of Financial Accounting Standards Board, or FASB, Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48, on January 1, 2007. As a result of the implementation of FIN 48, we recognized a long-term tax receivable of $2.6 million and a long-term tax liability of $31.1 million for uncertain tax positions, the net of which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense.

Results of Operations

     Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of economic characteristics among all our divisions and locations, including the nature of services provided and the type of customers for our services. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in our fleet and the geographic regions in which they operate to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.

Years Ended December 31, 2007 and 2006

     Comparative data relating to our revenue and operating expenses by equipment type are listed below.

		Year Ended
		December 31,								Favorable/
		2007				2006				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	1,030,892			$	766,873			$	264,019
Intermediate Semisubmersibles			1,028,667				785,047				243,620
Jack-ups			446,104				435,194				10,910
Total Contract Drilling Revenue		$	2,505,663			$	1,987,114			$	518,549
Revenues Related to Reimbursable Expenses		$	62,060			$	65,458			$	(3,398	)
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	321,266			$	236,276			$	(84,990	)
Intermediate Semisubmersibles			485,681				391,092				(94,589	)
Jack-ups			184,500				159,424				(25,076	)
Other			19,746				25,265				5,519
Total Contract Drilling Expense		$	1,011,193			$	812,057			$	(199,136	)
Reimbursable Expenses		$	52,857			$	57,465			$	4,608
OPERATING INCOME
High-Specification Floaters		$	709,626			$	530,597			$	179,029
Intermediate Semisubmersibles			542,986				393,955				149,031
Jack-ups			261,604				275,770				(14,166	)
Other			(19,746	)			(25,265	)			5,519
Reimbursable expenses, net			9,203				7,993				1,210
Depreciation			(235,251	)			(200,503	)			(34,748	)
General and administrative expense			(53,483	)			(41,551	)			(11,932	)
Gain (loss) on disposition of assets			8,583				(1,064	)			9,647
Casualty gain on Ocean Warwick			—				500				(500	)
Total Operating Income		$	1,223,522			$	940,432			$	283,090
Other income (expense):
Interest income			33,566				37,880				(4,314	)
Interest expense			(19,191	)			(24,096	)			4,905
Gain (loss) on sale of marketable securities			1,796				(31	)			1,827
Other, net			6,844				12,147				(5,303	)
Income before income tax expense			1,246,537				966,332				280,205
Income tax expense			(399,996	)			(259,485	)			(140,511	)
NET INCOME		$	846,541			$	706,847			$	139,694

     Demand remained strong for our rigs in all markets and geographic regions during 2007, except for the jack-up market in the GOM. Continued high overall utilization and historically high dayrates contributed to an overall increase in our net income of $139.7 million, or 20%, to $846.5 million in 2007 compared to $706.8 million in 2006. In many of the markets in which we operate, dayrates continued to increase compared to 2006 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 scheduled shipyard projects and mandatory inspections or surveys, as well as the temporary ready-stacking of drilling rigs between wells in the GOM jack-up market. Total contract drilling revenues in 2007 increased $518.5 million, or 26%, to $2.5 billion compared to $2.0 billion in 2006.

     Total contract drilling expenses increased $199.1 million, or 25%, in 2007, compared to 2006, to $1.0 billion. Overall cost increases for maintenance and repairs between 2007 and 2006 reflect the impact of high, sustained utilization of our drilling units across our fleet, additional survey and related maintenance costs, contract preparation and mobilization costs, as well as the inclusion of normal operating costs for the newly upgraded Ocean Endeavor. The increase in overall operating and overhead costs also reflects the impact of higher prices throughout the offshore drilling industry and its support businesses. Our results were also impacted by higher expenses related to our mooring enhancement and other hurricane preparedness activities in 2006 and compensation increases during 2006 and 2007.

     Depreciation and general and administrative expenses increased $46.7 million in the aggregate, or 19% in 2007, compared to 2006, reducing our net income by $288.7 million in 2007.

     Net income for 2007 includes $58.6 million of non-recurring U.S. federal income tax expense related to the distribution of previously untaxed earnings from one of our foreign subsidiaries.

High-Specification Floaters.

		Year Ended
		December 31,								Favorable/
		2007				2006				(Unfavorable)
		(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM		$	833,751			$	574,594			$	259,157
Australia/Asia/Middle East			73,004				65,682				7,322
South America			124,137				126,597				(2,460	)
Total Contract Drilling Revenue		$	1,030,892			$	766,873			$	264,019
CONTRACT DRILLING EXPENSE
GOM		$	208,140			$	143,447			$	(64,693	)
Australia/Asia/Middle East			27,070				24,465				(2,605	)
South America			86,056				68,364				(17,692	)
Total Contract Drilling Expense		$	321,266			$	236,276			$	(84,990	)
OPERATING INCOME		$	709,626			$	530,597			$	179,029

     GOM. Revenues generated by our high-specification floaters operating in the GOM increased $259.2 million during 2007 compared to 2006, primarily due to higher average dayrates earned during 2007 ($259.1 million). Average operating revenue per day for our rigs in this market, excluding the Ocean Endeavor, increased to $354,400 during 2007 compared to $236,600 in 2006, reflecting the continued high demand for this class of rig in the GOM. Excluding the Ocean Endeavor, six of our seven other high-specification semisubmersible rigs in the GOM are currently operating at dayrates higher than those they earned during 2006. The Ocean Endeavor began operating during the third quarter of 2007 and generated revenues of $42.7 million in the GOM in 2007.

     Average utilization for our high-specification rigs operating in the GOM, excluding the Ocean Endeavor, decreased from 94% in 2006 to 87% in 2007 and resulted in a $38.4 million decline in revenues comparing the

years. The decline in utilization during the 2007 period was primarily the result of scheduled downtime for special surveys for the Ocean Star (47 days) and Ocean Quest (66 days) and for a special survey and repairs to the Ocean Baroness (149 days), Combined utilization for these three rigs was 95% during 2006.

     During 2006, we recognized $4.3 million in mobilization revenue for the Ocean Baroness associated with its 2005 relocation to the GOM.

     Operating costs during 2007 for our high-specification floaters in the GOM increased $64.7 million to $208.1 million (including $16.8 million in normal operating expenses for the Ocean Endeavor) compared to 2006. The increase in operating costs in 2007 compared to 2006 reflects higher labor, benefits and other personnel-related costs resulting from compensation increases, higher maintenance and project costs and incremental costs associated with regulatory surveys for the Ocean Baroness, Ocean Star and Ocean Quest, including mobilization, inspection and related repair costs.

     Australia/Asia/Middle East. Revenues generated by the Ocean Rover, our high-specification rig operating offshore Malaysia, increased $7.3 million during 2007, as compared to 2006, primarily due to a higher operating dayrate earned by the rig in the first quarter and last two months of 2007.

     Operating expenses for the Ocean Rover in 2007 increased $2.6 million to $27.1 million compared to 2006, primarily due to higher labor, benefits and maintenance and project costs, partially offset by lower insurance and other costs.

     South America. Revenues earned by our high-specification floaters operating offshore Brazil decreased $2.5 million to $124.1 million in 2007 compared to 2006. The decrease in revenue was primarily due to a decline in utilization ($5.8 million) resulting from 33 days of additional unpaid downtime in 2007 for a special survey for the Ocean Alliance. The decline in revenues in 2007 was partially offset by an increase in the average operating revenue per day from $180,100 during 2006 to $185,300 during 2007, which contributed additional revenues of $3.3 million.

     Contract drilling expense for our operations in Brazil increased $17.7 million during 2007 compared to 2006. The increase in costs is primarily due to survey costs for the Ocean Alliance, higher labor and benefits costs as a result of compensation increases, as well as higher catering, freight and maintenance and project costs during 2007 compared to 2006.

Intermediate Semisubmersibles.

		Year Ended
		December 31,								Favorable/
		2007				2006				(Unfavorable)
		(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM		$	170,449			$	224,344			$	(53,895	)
Mexico			86,135				80,487				5,648
Australia/Asia/Middle East			239,200				196,180				43,020
Europe/Africa/Mediterranean			400,785				207,295				193,490
South America			132,098				76,741				55,357
Total Contract Drilling Revenue		$	1,028,667			$	785,047			$	243,620
CONTRACT DRILLING EXPENSE
GOM		$	79,606			$	80,498			$	892
Mexico			63,711				60,467				(3,244	)
Australia/Asia/Middle East			114,567				87,535				(27,032	)
Europe/Africa/Mediterranean			144,302				109,741				(34,561	)
South America			83,495				52,851				(30,644	)
Total Contract Drilling Expense		$	485,681			$	391,092			$	(94,589	)
OPERATING INCOME		$	542,986			$	393,955			$	149,031

     GOM. Revenues generated during 2007 by our intermediate semisubmersible fleet decreased $53.9 million compared to 2006, primarily as a result of the fourth quarter 2006 relocation of the Ocean Lexington to Egypt, as well as shipyard time during 2007 for four of our other rigs in this market. During 2007, we completed a survey and contract preparation work for the Ocean Voyager, a service life extension project for the Ocean Saratoga and contract modifications for the Ocean Concord and Ocean New Era. Excluding the Ocean Lexington, average utilization for our intermediate semisubmersible rigs operating in the GOM (Ocean Voyager, Ocean Concord, Ocean New Era and Ocean Saratoga) declined from 84% in 2006 to 75% during 2007 and reduced revenues by $58.3 million. During 2006, the Ocean Lexington generated revenues of $33.4 million in the GOM. Of these rigs, only the Ocean Saratoga remained in the GOM as of December 31, 2007.

     The overall decline in revenues in 2007 was partially offset by an increase in average dayrates earned by our intermediate semisubmersible rigs operating in the GOM during both 2007 and 2006. Average operating revenue per day, excluding the Ocean Lexington, increased from $155,200 during 2006 to $189,400 in 2007 and contributed additional revenues of $37.8 million.

     During 2006 and 2007, three of our rigs completed their contracts with PEMEX and temporarily returned to the GOM. The Ocean Whittington returned to the GOM in July 2006 for a survey, contract preparation work and a service life extension. The Ocean Yorktown and Ocean Worker returned to the GOM in July 2007 and August 2007, respectively for surveys and contract preparation work, as well as a service life extension project for the Ocean Yorktown. All three rigs were located in shipyards in the GOM for extended periods during 2007, and we incurred additional costs in the GOM associated with these activities. During the third and fourth quarters of 2007, the Ocean Whittington and the Ocean Worker departed the GOM for Brazil and Trinidad and Tobago, respectively, where they are working under contract. The Ocean Yorktown is expected to leave for Brazil in the second quarter of 2008.

     Contract drilling expenses decreased by $0.9 million in 2007 compared to 2006. Increased costs in the GOM associated with surveys and contract preparation activities, as well as higher labor and related costs during 2007 were offset by lower normal operating costs in the GOM as a result of the numerous rigs that were relocated from the region at the end of 2006 and during 2007.

     Mexico. Revenues generated by our intermediate semisubmersible rigs operating offshore Mexico increased $5.6 million in 2007 compared to 2006. The relocation of the Ocean New Era and Ocean Voyager from the GOM to Mexico in the fourth quarter of 2007 generated an additional $33.3 million in revenues for this region in 2007. Revenues generated in 2007 were reduced by $28.5 million due to the return of the Ocean Whittington in July 2006 and the Ocean Worker and Ocean Yorktown in the third quarter of 2007 to the GOM.

     Our operating costs in Mexico increased by $3.2 million in 2007 compared to 2006, primarily due to the inclusion of operating costs for the Ocean New Era and Ocean Voyager and costs to mobilize the Ocean Worker and Ocean Yorktown from Mexico to the GOM. The overall increase in costs was partially offset by the absence of operating costs for the Ocean Whittington in 2007 and reduced normal operating costs for the Ocean Worker and Ocean Yorktown beginning in the third quarter of 2007.

     Australia/Asia/Middle East. Our intermediate semisubmersibles working in the Australia/Asia/Middle East regions generated revenues of $239.2 million in 2007 compared to revenues of $196.2 million in 2006. The $43.0 million increase in operating revenue was primarily due to an increase in average operating revenue per day from $135,600 in 2006 to $169,900 in 2007, which generated additional revenues of $45.4 million during 2007. The increase in average operating revenue per day is primarily attributable to an increase in the contractual dayrates earned by the Ocean Patriot that occurred in the third quarter of 2007, and the Ocean Epoch and Ocean General that occurred during the second and third quarters of 2006, respectively.

     Average utilization in this region decreased to 94% during 2007 from 97% utilization during 2006, primarily due to 46 days of incremental unpaid downtime in 2007, as compared to 2006, for repairs as well as a survey of the Ocean General and an environmental survey of the Ocean Patriot and related removal of an invasive species of green, lipped mussels that had attached itself to the rig while working offshore New Zealand. The decline in utilization during 2007 reduced revenues by $4.4 million. Additionally, during 2007 we recognized $4.6 million in mobilization revenue in connection with the relocations of the Ocean Epoch and the Ocean General to other areas within the Australia/Asia region. During 2006, we recognized $2.3 million in mobilization revenue for the relocation of the Ocean Patriot to New Zealand.

     Contract drilling expense for the Australia/Asia/Middle East region increased $27.0 million in 2007 compared to 2006. The increase in operating costs was primarily due to higher labor and personnel-related costs, including higher local labor costs for the Ocean Epoch, which relocated to Australia in the fourth quarter of 2006 from Malaysia. Other cost increases for our rigs operating in this region during 2007, as compared to 2006, include higher repair and maintenance costs, higher freight costs and additional costs associated with the environmental survey of the Ocean Patriot. These increased costs were partially offset by lower agency fee costs incurred by the Ocean Epoch in 2007 compared to 2006 when the rig was operating offshore Malaysia.

     Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean regions increased $193.5 million in 2007 compared to 2006. Overall utilization during 2007 increased primarily due to the relocation of the Ocean Lexington ($97.1 million) from the GOM to offshore Egypt in the fourth quarter of 2006. Additionally, the Ocean Princess generated additional revenues of $8.4 million during 2007 compared to 2006 when the rig had 48 days of downtime for an intermediate survey and related repairs. These favorable variances resulting from the increased utilization of two of our rigs in this region were partially offset by 18 days of unpaid downtime for an intermediate survey of the Ocean Vanguard that reduced revenues by $1.9 million in 2007. Also during 2006, we 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.

     Average operating revenue per day for our North Sea semisubmersibles increased from $144,500 in 2006 to $211,500 in 2007, contributing $93.9 million in additional revenue in 2007 as compared to 2006. The overall increase in average operating revenue per day in this market was primarily due to higher dayrates earned by the Ocean Nomad, Ocean Guardian and Ocean Vanguard during 2007.

     Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets increased $34.6 million in 2007 compared to 2006, primarily due to the inclusion of normal operating costs for the Ocean Lexington ($21.8 million). Increased operating expenses in 2007 are also reflective of higher labor and benefits costs incurred in 2007 for our rigs operating in the North Sea, including the effect of compensation increases and implementation of a retention plan, and higher shorebase support

costs. However, overall operating expense increases in this region during 2007 were partially offset by lower mobilization and inspection costs associated with surveys, as costs incurred for the Ocean Vanguard‘s intermediate survey in December 2007 were well below aggregate expenses related to surveys for the Ocean Guardian and Ocean Princess in 2006.

     South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $55.4 million to $132.1 million in 2007 from $76.7 million in 2006. During 2007, we relocated the Ocean Whittington (Brazil) and the Ocean Worker (Trinidad and Tobago) to this region where they generated revenues of $25.7 million and $21.5 million, respectively. For our other two semisubmersible rigs operating offshore Brazil in both 2007 and 2006, average operating revenue per day in 2007 increased to $123,900 from $113,700 in 2006, resulting in a $7.0 million increase in revenue from 2006.

     Operating expenses for our operations in the South American region increased $30.6 million in 2007, as compared to 2006, partially due to the inclusion of normal operating and start-up costs for the Ocean Whittington and the Ocean Worker, as well as start-up costs for the Ocean Concord which relocated to Brazil from the GOM in the fourth quarter of 2007 to begin a five-year contract. The Ocean Concord did not begin operating under contract until 2008. Other cost increases during 2007 compared to 2006 include increased labor and other personnel-related costs, shorebase support and freight costs, as well as higher repair and maintenance costs.

Jack-Ups.

		Year Ended
		December 31,								Favorable/
		2007				2006				(Unfavorable)
		(In thousands)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM		$	222,276			$	315,279			$	(93,003	)
Mexico			62,451				15,966				46,485
Australia/Asia/Middle East			88,497				61,141				27,356
Europe/Africa/Mediterranean			72,880				42,808				30,072
Total Contract Drilling Revenue		$	446,104			$	435,194			$	10,910
CONTRACT DRILLING EXPENSE
GOM		$	120,210			$	112,524			$	(7,686	)
Mexico			16,108				4,373				(11,735	)
Australia/Asia/Middle East			28,438				27,721				(717	)
Europe/Africa/Mediterranean			19,744				14,806				(4,938	)
Total Contract Drilling Expense		$	184,500			$	159,424			$	(25,076	)
OPERATING INCOME		$	261,604			$	275,770			$	(14,166	)

     GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $93.0 million during 2007 compared to 2006. The decline in revenues is primarily due to the relocation of three of our jack-up rigs from the GOM to other markets: the Ocean King to Croatia in the third quarter of 2007; the Ocean Nugget to Mexico in the fourth quarter of 2006; and the Ocean Spur to Tunisia in the first quarter of 2006. These rigs generated $56.0 million in revenues while operating in the GOM in 2006 compared to only $13.3 million earned by the Ocean King in the GOM during 2007. In addition, the Ocean Columbia, which was in a shipyard for a majority of the fourth quarter of 2007 for preparation work in connection with an 18-month contract offshore Mexico, generated revenues of $28.8 million in the GOM during 2007 compared to $37.5 million in 2006.

     Average utilization (excluding the Ocean Columbia, Ocean King, Ocean Nugget and Ocean Spur) declined from 90% during 2006 to 78% during 2007 resulting in a reduction in revenues of $29.6 million. The decline in utilization was primarily in response to market conditions in the GOM that caused us to ready-stack certain of our jack-up rigs for a portion of time between wells, scheduled downtime for surveys of the Ocean Crusader and Ocean Tower and contract preparation activities for the Ocean Columbia. The Ocean Columbia departed the GOM for Mexico at the end of the fourth quarter of 2007.

     Revenues also declined due to a decrease in average operating dayrates. Average operating revenue per day in 2007, excluding the Ocean Columbia, Ocean King, Ocean Nugget and Ocean Spur, decreased to $90,500 from $96,500 in 2006, resulting in a $11.9 million decrease in revenue from 2006.

     Contract drilling expense in the GOM increased $7.7 million in 2007 compared to 2006. The overall increase in costs was primarily due to higher survey and related repair costs in 2007, contract preparation activities for the Ocean Columbia, as well as increased repair and ready-stacking costs for several of our rigs marketed in the GOM. In addition, operating costs for our rigs in this market were negatively impacted by regular salary increases and higher overhead costs. The overall increase in operating costs was partially offset by the absence of operating costs in the GOM for the Ocean Nugget and Ocean Spur and lower operating costs for the Ocean King during 2007, which reduced operating expenses by $19.5 million.

     Mexico. The Ocean Nugget, which began operating offshore Mexico in the fourth quarter of 2006, generated $62.5 million in revenues during 2007 and incurred contract drilling expenses of $16.1 million. We had no jack-up rigs operating in this market prior to the fourth quarter of 2006.

     Australia/Asia/Middle East. Our two jack-up rigs operating in the Australia/Asia/Middle East regions generated revenues of $88.5 million during 2007 compared to $61.1 million in 2006. The $27.4 million increase in revenues was primarily due to an increase in average operating revenue per day earned by our rigs in this region from $95,600 during 2006 to $123,600 for 2007, primarily due to new contracts at higher dayrates for both the Ocean Heritage and Ocean Sovereign that began late in the second and third quarters of 2006, respectively, as well as additional dayrate increases for both rigs during 2007 which generated additional revenues of $19.5 million. Average utilization for our rigs in this region increased from 87% during 2006 to 98% in 2007 primarily due to increased utilization for both the Ocean Heritage and Ocean Sovereign in 2007, as compared to 2006 when these rigs were out of service for scheduled surveys and related repairs. The increase in utilization in 2007 resulted in the generation of additional revenues of $8.3 million.

     Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean regions increased $30.1 million during 2007 compared to 2006. Our jack-up rig, the Ocean Spur, began operating offshore Tunisia in March 2006 and generated revenues of $42.8 million and $32.9 million during 2006 and 2007, respectively. The rig subsequently mobilized to the Mediterranean Basin and began operating offshore Egypt in late May 2007, generating revenues of $36.6 million.

     During the third quarter of 2007, we relocated the Ocean King from the GOM to Croatia where it began operating under a two-year bareboat charter, generating revenues of $3.3 million in 2007.

     Operating expenses in this region increased $4.9 million during 2007 compared to 2006, primarily due to the inclusion of a full year of operating costs for the Ocean Spur in 2007 compared to only nine and one-half months of expenses during 2006.

Reimbursable expenses, net.

     Revenues related to reimbursable items, offset by the related expenditures for these items, were $9.2 million and $8.0 million for 2007 and 2006, 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 $34.7 million to $235.2 million in 2007 compared to $200.5 million in 2006 primarily due to depreciation associated with capital additions in 2006 and 2007, as well as higher depreciation expense for the Ocean Endeavor due to the completion of its major upgrade in March 2007.

General and Administrative Expense.

     We incurred general and administrative expense of $53.5 million in 2007 compared to $41.6 million in 2006. The $11.9 million increase in overhead costs between the periods was primarily due to an increase in payroll costs resulting from higher compensation and staffing increases, legal fees, engineering and tax consulting fees and miscellaneous office expenses.

Gain (Loss) on Disposition of Assets.

     We recognized a net gain of $8.6 million on the sale and disposition of assets, net of disposal costs, in 2007 compared to a net loss of $1.1 million in 2006. The gain recognized in 2007 primarily consists of the recognition of gains on insurance settlements and from sales of used equipment. 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.

Interest Expense.

     We recorded interest expense during 2007 of $19.2 million, representing a $4.9 million decrease in interest cost compared to 2006. This decrease was primarily attributable to a greater amount of interest capitalized during 2007 related to our qualifying rig upgrades and construction projects and lower interest cost associated with our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures. This decrease was partially offset by $9.2 million in debt issuance costs that we wrote off during 2007 in connection with conversions of our 1.5% Debentures and our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, into shares of our common stock. See “— Liquidity and Capital Requirements — 1.5% Debentures” and “ — Liquidity and Capital Requirements — Zero Coupon Debentures.”

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 $6.8 million during 2007 and other income, net, of $12.1 million in 2006.

     During 2007 and 2006, we recognized net foreign currency exchange gains of $2.9 million and $10.3 million, respectively.

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 $400.0 million of tax expense on pre-tax income of $1.2 billion for the year ended December 31, 2007 compared to tax expense of $259.5 million on a pre-tax income of $966.3 million in 2006.

     Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary which we wholly own. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes were provided on these earnings in years subsequent to 2002 except to the extent that such earnings were immediately subject to U.S. federal income tax. In December 2007, this subsidiary made a non-recurring distribution of $850.0 million to its U.S. parent, a portion of which consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. We recognized $58.6 million of U.S. federal income tax expense as a result of the distribution. As of December 31, 2007, the amount of previously untaxed earnings of this subsidiary was zero. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest future earnings of this subsidiary to finance foreign activities.

     We adopted the provisions of FIN 48 on January 1, 2007. During the year ended December 31, 2007 we recognized $4.4 million of tax expense for uncertain tax positions related to the current year, $0.8 million of which was penalty related tax expense.

     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 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.

Years Ended December 31, 2006 and 2005

     Comparative data relating to our revenues and operating expenses by equipment type are presented below.

		Year Ended
		December 31,								Favorable/
		2006				2005				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	766,873			$	448,937			$	317,936
Intermediate Semisubmersibles			785,047				456,734				328,313
Jack-ups			435,194				271,809				163,385
Other			—				1,535				(1,535	)
Total Contract Drilling Revenue		$	1,987,114			$	1,179,015			$	808,099
Revenues Related to Reimbursable Expenses		$	65,458			$	41,987			$	23,471
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	236,276			$	179,248			$	(57,028	)
Intermediate Semisubmersibles			391,092				325,579				(65,513	)
Jack-ups			159,424				123,833				(35,591	)
Other			25,265				9,880				(15,385	)
Total Contract Drilling Expense		$	812,057			$	638,540			$	(173,517	)
Reimbursable Expenses		$	57,465			$	35,549			$	(21,916	)
OPERATING INCOME
High-Specification Floaters		$	530,597			$	269,689			$	260,908
Intermediate Semisubmersibles			393,955				131,155				262,800
Jack-ups			275,770				147,976				127,794
Other			(25,265	)			(8,345	)			(16,920	)
Reimbursables, net			7,993				6,438				1,555
Depreciation			(200,503	)			(183,724	)			(16,779	)
General and Administrative Expense			(41,551	)			(37,162	)			(4,389	)
(Loss) gain on Sale and Disposition of Assets			(1,064	)			14,767				(15,831	)
Casualty gain on Ocean Warwick			500				33,605				(33,105	)
Total Operating Income		$	940,432			$	374,399			$	566,033
Other income (expense):
Interest income			37,880				26,028				11,852
Interest expense			(24,096	)			(41,799	)			17,703
Gain (loss) on sale of marketable securities			(31	)			(1,180	)			1,149
Other, net			12,147				(1,053	)			13,200
Income before income tax expense			966,332				356,395				609,937
Income tax expense			(259,485	)			(96,058	)			(163,427	)
NET INCOME		$	706,847			$	260,337			$	446,510

     Net income in 2006 increased $446.5 million, or 172%, to $706.8 million, compared to $260.3 million in 2005 due to strong demand for our rigs in all markets and geographic regions in which we operate. Dayrates generally increased during 2006, compared to 2005, and resulted in the generation of additional contract drilling revenues by our fleet. The effect of higher dayrates earned by our rigs was negatively impacted by the effect of downtime associated with mandatory surveys and related repair time, as well as 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 to $1,987.1 million, or 69% compared to 2005.

     Total contract drilling expenses in 2006 increased $173.5 million to $812.1 million, or 27% compared to 2005. Our results in 2006 were negatively impacted by higher expenses related to our mooring enhancement and other hurricane preparedness activities, compensation increases and mandatory 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 reflected the impact of higher prices throughout the offshore drilling industry and its support businesses. 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.

     Net income for 2006 compared to 2005 reflected higher interest income on invested cash balances combined with lower interest expense on our outstanding debentures due to debt conversions in 2006 and foreign currency exchange gains recognized in 2006. These favorable contributions to net income were partially offset by higher depreciation and general and administrative expenses of $21.2 million in 2006 compared to 2005. Additionally, during 2005, we recognized 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.

     Our net income in 2006 was reduced by $259.5 million of income tax expense on pre-tax earnings of $966.3 million compared to income tax expense of $96.1 million on pre-tax earnings of $356.4 million in 2005.

High-Specification Floaters.

		Year Ended
		December 31,								Favorable/
		2006				2005				(Unfavorable)
		(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM		$	574,594			$	304,642			$	269,952
Australia/Asia/Middle East			65,682				68,349				(2,667	)
South America			126,597				75,946				50,651
Total Contract Drilling Revenue		$	766,873			$	448,937			$	317,936
CONTRACT DRILLING EXPENSE
GOM		$	143,447			$	88,107			$	(55,340	)
Australia/Asia/Middle East			24,465				35,891				11,426
South America			68,364				55,250				(13,114	)
Total Contract Drilling Expense		$	236,276			$	179,248			$	(57,028	)
OPERATING INCOME		$	530,597			$	269,689			$	260,908

     GOM. Revenues generated by our high-specification floaters operating in the GOM increased $270.0 million in 2006 compared to 2005, primarily due to higher average dayrates earned during the period and revenues generated by the Ocean Baroness, which relocated to the GOM from the Australia/Asia market in the latter half of 2005 ($58.1 million). Excluding the Ocean Baroness, average operating revenue per day for our rigs in this market increased to $242,000 during 2006, compared to $142,600 during 2005, generating additional revenues of $211.6 million. The higher overall dayrates achieved for our high-specification floaters reflected the continuing high demand for this class of rig in the GOM.

     Average utilization for our high-specification rigs operating in the GOM, excluding the contribution from the Ocean Baroness, increased slightly to 96% in 2006 compared to 2005, and resulted in $0.2 million in revenue.

     Operating costs during 2006 for our high-specification floaters in the GOM increased $55.3 million over operating costs incurred during 2005. The increase in operating costs was primarily due to the inclusion of normal operating costs and amortization of mobilization expenses for the Ocean Baroness during 2006 ($30.6 million) compared to the prior year when this drilling rig operated offshore Indonesia. In addition, our operating expenses

for 2006, compared to 2005, reflected higher labor and benefits costs related to late 2005 and first quarter of 2006 wage increases, higher repair and maintenance costs, and higher miscellaneous operating expenses, including catering costs. Our operating expenses in 2005 reflected a $2.0 million reduction in costs due to a recovery from a 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 compensation 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 was primarily due to higher labor, benefits and other personnel-related costs as a result of 2005 and March 2006 compensation 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.

Intermediate Semisubmersibles.

		Year Ended
		December 31,								Favorable/
		2006				2005				(Unfavorable)
		(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM		$	224,344			$	99,500			$	124,844
Mexico			80,487				85,594				(5,107	)
Australia/Asia/Middle East			196,180				111,811				84,369
Europe/Africa/Mediterranean			207,295				106,251				101,044
South America			76,741				53,578				23,163
Total Contract Drilling Revenue		$	785,047			$	456,734			$	328,313
CONTRACT DRILLING EXPENSE
GOM		$	80,498			$	49,947			$	(30,551	)
Mexico			60,467				57,246				(3,221	)
Australia/Asia/Middle East			87,535				83,768				(3,767	)
Europe/Africa/Mediterranean			109,741				93,253				(16,488	)
South America			52,851				41,365				(11,486	)
Total Contract Drilling Expense		$	391,092			$	325,579			$	(65,513	)
OPERATING INCOME		$	393,955			$	131,155			$	262,800

     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 Mexico. Higher operating costs in 2006, as compared to 2005, reflected 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.

     Mexico. Revenues generated by our intermediate semisubmersibles operating offshore Mexico 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. Operating costs in Mexico 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 was 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/Mediterranean. 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 was 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 in 2006 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, was 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)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM		$	315,279			$	222,365			$	92,914
Mexico			15,966				—				15,966
Australia/Asia/Middle East			61,141				49,444				11,697
Europe/Africa/Mediterranean			42,808				—				42,808
Total Contract Drilling Revenue		$	435,194			$	271,809			$	163,385
CONTRACT DRILLING EXPENSE
GOM		$	112,524			$	98,866			$	(13,658	)
Mexico			4,373				—				(4,373	)
Australia/Asia/Middle East			27,721				24,967				(2,754	)
Europe/Africa/Mediterranean			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 Mexico 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 was 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 Mexico 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.

     Mexico. Our jack-up rig the Ocean Nugget, which relocated to Mexico 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 was 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/Mediterranean. 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 was 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 was 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 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.

     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.

Sources of Liquidity and Capital Resources

     Our principal sources of liquidity and capital resources are cash flows from our operations 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, 2007, we had $638.0 million in “Cash and cash equivalents” and $1.3 million in “Investments and marketable securities,” representing our investment of cash available for current operations.

     Cash Flows from Operations. Our internally generated cash flow is directly related to our business and the geographic regions in which we operate. Deterioration in the offshore drilling market or poor operating results may result in reduced cash flows from operations. 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 external factors which affect our cash flows from operations 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. We maintain 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 a rate per annum equal to, at our election, either (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, 2007, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2007, there were no loans outstanding under the Credit Facility; however $54.2 million in letters of credit were issued and outstanding under the Credit Facility.

     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 both our working capital requirements and our capital commitments over the next twelve months; however, we will continue to make periodic assessments based on industry conditions and will adjust capital spending programs if required.

     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.

     Contractual Cash Obligations. The following table sets forth our contractual cash obligations at December 31, 2007.

		Payments Due By Period
Contractual Obligations		Total				Less than 1 year				1—3 years				4—5 years				After 5 years
		(In thousands)
Long-term debt (principal and interest)		$	683,657			$	28,642			$	54,401			$	50,125			$	550,489
Forward exchange contracts			18,142				18,142				—				—				—
Purchase obligations related to rig upgrade/modifications			198,752				198,752				—				—				—
Operating leases			5,584				4,353				1,085				146				—
Total obligations		$	906,135			$	249,889			$	55,486			$	50,271			$	550,489

     As of December 31, 2007, the total unrecognized tax benefit related to uncertain tax positions was $34.5 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

     Certain of our long-term debt payments may be accelerated due to certain rights that holders of our debt securities have to put the securities to us. See the discussion below related to our 1.5% Debentures and Zero Coupon Debentures.

     As of December 31, 2007, we had purchase obligations aggregating approximately $200 million related to the major upgrade of the Ocean Monarch and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We expect to complete funding of these projects in 2008. However, the actual timing of these expenditures will vary based on the completion of various construction milestones, which are generally beyond our control.

     We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2007, except for those related to our direct rig operations, which arise during the normal course of business.

     Other Commercial Commitments — Letters of Credit.

     We were contingently liable as of December 31, 2007 in the amount of $168.0 million under certain performance, bid, supersedeas and custom bonds and letters of credit, including $54.2 million in letters of credit issued under our Credit Facility. During 2007 and 2006, we purchased five of these bonds totaling $81.2 million from a related party after obtaining competitive quotes. Agreements relating to approximately $103.5 million of performance bonds can require collateral at any time. As of December 31, 2007 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 13 “Related-Party Transactions” to our Consolidated Financial Statements included in Item 8 of this report. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.

		For the years ending December 31,
		Total				2008				2009—2010
		(In thousands)
Other Commercial Commitments
Customs bonds		$	42,056			$	42,056			$	—
Performance bonds			114,794				36,148				78,646
Other			11,127				3,850				7,277
Total obligations		$	167,977			$	82,054			$	85,923