Diamond Offshore Drilling 10K 2007 Annual report

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

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)


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

15415 Katy Freeway
Houston, Texas 77094
(Address and zip code of principal executive offices)

(281) 492-5300
(Registrant’s telephone number, including area code)

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


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

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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

DOCUMENTS INCORPORATED BY REFERENCE

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, theOcean Scepterand theOcean 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, theOcean 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, theOcean 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 theOcean 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. TheOcean Monarchis 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 theOcean Endeavorto 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, theOcean Scepterand theOcean 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. TheOcean Shieldis 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

Attributes

DP
IC
MC

=
=
=

Dynamically-Positioned/Self-Propelled
Independent-Leg Cantilevered Rig
Mat-Supported Cantilevered Rig

MS
VC
SP

=
=
=

Mat-Supported Slot Rig
Victory-Class
Self-Propelled

3M
4M
15K

=
=
=

Three Mud Pumps
Four Mud Pumps
15,000 psi well control system

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, theOcean Monarch, to ultra-deepwater capability at an estimated aggregate cost of approximately $305 million. We expect delivery of the upgradedOcean Monarchduring 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. Tischhas served as our Chief Executive Officer since March 1998. Mr. Tisch has also served as Chairman of the Board since 1995 and as a director since June 1989. Mr. Tisch has served as Chief Executive Officer of Loews, a diversified holding company and our controlling stockholder, since January 1999. Mr. Tisch, a director of Loews since 1986, also serves as a director of CNA Financial Corporation, an 89% owned subsidiary of Loews.

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

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

William C. Longhas 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. Gordonhas served as our Controller and Chief Accounting Officer since April 2000.

Mark F. Baudoinhas 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. Dewhas 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. Vecchiohas 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


(1)		Total return assuming reinvestment of dividends. Dividends for the periods reported include regular quarterly dividends of $0.125 per share of our common stock that we paid during the first three quarters of 2003, the last two quarters of 2005 and all four quarters of 2006 and 2007. Beginning in the fourth quarter of 2003 through the first two quarters of 2005, we paid a regular quarterly dividend of $0.0625 per share. We paid special dividends of $4.00 and $1.25 per share of our common stock in the first quarter and fourth quarter of 2007, respectively. We paid a special dividend of $1.50 per share of our common stock in the first quarter of 2006. Assumes $100 invested on December 31, 2002 in our common stock, the S&P 500 Index and a peer group index comprised of a group of other companies in the contract drilling industry.

(2)		The peer group is comprised of the following companies: ENSCO International Incorporated, GlobalSantaFe (included until November 27, 2007 merger with Transocean Inc.), Noble Drilling Corporation, Pride International, Inc., Rowan Companies, Inc. and Transocean Inc. Total return calculations were weighted according to the respective company’s market capitalization.

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


(1)		See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Requirements” in Item 7 and Note 9 “Long-Term Debt” to our Consolidated Financial Statements included in Item 8 of this report for a discussion of changes in our long-term debt.

(2)		The deficiency in our earnings available for fixed charges for the years ended December 31, 2004 and 2003 was approximately $2.3 million and $55.3 million, respectively. For all periods presented, the ratio of earnings to fixed charges has been computed on a total enterprise basis. Earnings represent pre-tax income from continuing operations plus fixed charges. Fixed charges include (i) interest, whether expensed or capitalized, (ii) amortization of debt issuance costs, whether expensed or capitalized, and (iii) a portion of rent expense, which we believe represents the interest factor attributable to rent.

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 theOcean Sovereignin Indonesia at a dayrate in the mid $140,000s that is expected to commence in the second quarter of 2008. The mobilization of theOcean Columbiafrom 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, theOcean YorktownandOcean 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 semisubmersibleOcean Generalreceived 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


(1)		Contract drilling backlog as of February 7, 2008 includes an aggregate $238 million in contract drilling revenue relating to expected future work under an LOI.

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


(1)		Includes an aggregate $238 million in contract drilling revenue of which approximately $37.5 million, $102.2 million and $98.3 million is expected to be earned during 2008, 2009 and 2010, respectively, relating to expected future work under an LOI.

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 theOcean Monarch, and our two new-build jack-up rigs, theOcean ScepterandOcean 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	%		—


(1)		Includes approximately 1,166 and 349 scheduled shipyard, survey and mobilization days for 2008 and 2009, respectively.

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 theOcean Monarchand 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 theOcean Endeavorin 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 theOcean Monarchand to accept delivery of the newly constructedOcean ScepterandOcean Shield.We will continue to capitalize interest costs related to this upgrade until sea trials and commissioning of theOcean Monarchare 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 onOcean 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 upgradedOcean 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 theOcean 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 theOcean 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. TheOcean Endeavorbegan 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 theOcean 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 theOcean Star(47 days) andOcean Quest(66 days) and for a special survey and repairs to theOcean Baroness(149 days), Combined utilization for these three rigs was 95% during 2006.

During 2006, we recognized $4.3 million in mobilization revenue for theOcean 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 theOcean 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 theOcean Baroness,Ocean StarandOcean Quest, including mobilization, inspection and related repair costs.

Australia/Asia/Middle East.Revenues generated by theOcean 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 theOcean Roverin 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 theOcean 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 theOcean 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 theOcean Lexingtonto 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 theOcean Voyager, a service life extension project for theOcean Saratogaand contract modifications for theOcean ConcordandOcean New Era. Excluding theOcean Lexington, average utilization for our intermediate semisubmersible rigs operating in the GOM (Ocean Voyager,Ocean Concord,Ocean New EraandOcean Saratoga)declined from 84% in 2006 to 75% during 2007 and reduced revenues by $58.3 million. During 2006, theOcean Lexingtongenerated revenues of $33.4 million in the GOM. Of these rigs, only theOcean Saratogaremained 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 theOcean 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. TheOcean Whittingtonreturned to the GOM in July 2006 for a survey, contract preparation work and a service life extension. TheOcean YorktownandOcean Workerreturned 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 theOcean 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, theOcean Whittingtonand theOcean Workerdeparted the GOM for Brazil and Trinidad and Tobago, respectively, where they are working under contract. TheOcean Yorktownis 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 theOcean New EraandOcean Voyagerfrom 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 theOcean Whittingtonin July 2006 and theOcean WorkerandOcean Yorktownin 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 theOcean New EraandOcean Voyagerand costs to mobilize theOcean WorkerandOcean Yorktownfrom Mexico to the GOM. The overall increase in costs was partially offset by the absence of operating costs for theOcean Whittingtonin 2007 and reduced normal operating costs for theOcean WorkerandOcean Yorktownbeginning 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 theOcean Patriotthat occurred in the third quarter of 2007, and theOcean EpochandOcean Generalthat 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 theOcean Generaland an environmental survey of theOcean 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 theOcean Epochand theOcean Generalto other areas within the Australia/Asia region. During 2006, we recognized $2.3 million in mobilization revenue for the relocation of theOcean Patriotto 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 theOcean 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 theOcean Patriot. These increased costs were partially offset by lower agency fee costs incurred by theOcean Epochin 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 theOcean Lexington ($97.1 million) from the GOM to offshore Egypt in the fourth quarter of 2006. Additionally, theOcean Princessgenerated 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 theOcean Vanguardthat 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 theOcean GuardianandOcean 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 theOcean Nomad, Ocean GuardianandOcean Vanguardduring 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 theOcean 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 theOcean Vanguard‘s intermediate survey in December 2007 were well below aggregate expenses related to surveys for theOcean GuardianandOcean Princessin 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 theOcean Whittington(Brazil) and theOcean 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 theOcean Whittingtonand theOcean Worker, as well as start-up costs for theOcean Concord which relocated to Brazil from the GOM in the fourth quarter of 2007 to begin a five-year contract. TheOcean Concorddid 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: theOcean Kingto Croatia in the third quarter of 2007; theOcean Nuggetto Mexico in the fourth quarter of 2006; and theOcean Spurto 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 theOcean Kingin the GOM during 2007. In addition, theOcean 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 theOcean Columbia,Ocean King, Ocean NuggetandOcean 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 theOcean CrusaderandOcean Towerand contract preparation activities for theOcean Columbia.TheOcean Columbiadeparted 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 theOcean Columbia,Ocean King, Ocean NuggetandOcean 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 theOcean 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 theOcean NuggetandOcean Spurand lower operating costs for theOcean King during 2007, which reduced operating expenses by $19.5 million.

Mexico.TheOcean 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 theOcean HeritageandOcean Sovereignthat 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 theOcean HeritageandOcean Sovereignin 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, theOcean 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 theOcean Kingfrom 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 theOcean Spurin 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 theOcean Endeavordue 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 theOcean 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 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 onOcean 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 theOcean Warwickas a result of Hurricane Katrina in August 2005 and an $8.0 million gain related to the June 2005 sale of theOcean 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 theOcean Baroness, which relocated to the GOM from the Australia/Asia market in the latter half of 2005 ($58.1 million). Excluding theOcean 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 theOcean 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 theOcean Baronessduring 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 theOcean Baronessfrom this market to the GOM in the latter half of 2005. Prior to its relocation to the GOM, theOcean Baronessgenerated $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 theOcean Rovercompared 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 theOcean Roverduring 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 theOcean Baronessto the GOM ($15.5 million). This decrease was partially offset by an increase in operating costs for theOcean 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 theOcean Allianceand theOcean Clipperincreased 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 theOcean 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 theOcean 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 theOcean Saratogain 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 theOcean VoyagerandOcean Concordfor mooring upgrades. Partially offsetting the decline in average utilization in 2006 was an improvement in utilization for theOcean Lexington,which worked nearly all of 2006 prior to its move to Egypt at the beginning of the fourth quarter. During 2005, theOcean Lexingtonincurred 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 theOcean New Erain 2006 ($7.6 million) and repair and other normal operating costs for theOcean 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 theOcean ConcordandOcean Voyager,survey and related repair costs for theOcean Saratogaand 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 theOcean 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 theOcean Whittingtonin July 2006, partially offset by increased revenues for theOcean Workeras 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 theOcean Whittingtonpursuant to its third quarter relocation to the GOM after termination of its drilling contract by PEMEX. In addition, we incurred $1.9 million in costs associated with the demobilization of theOcean Whittingtonfrom offshore Mexico to the GOM.

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 theOcean Epoch andOcean Patriotduring 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 theOcean Epochhad 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 theOcean Patriotincurred 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 theOcean 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 theOcean Patriot. However, during 2005, we recognized $5.7 million and $0.9 million in connection with theOcean 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 theOcean 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 theOcean 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 theOcean Vanguardbegan 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 theOcean Lexington, generating $20.7 million in additional revenues. The increase in average utilization was primarily due to higher utilization in 2006 for theOcean 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 theOcean Nomadduring 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 theOcean Princesswhich was in a shipyard for an intermediate survey during 2006. In comparison, theOcean Princessoperated 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 theOcean GuardianandOcean 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 theOcean Lexingtonin Egypt and costs associated with scheduled surveys for theOcean

GuardianandOcean 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 theOcean Vanguardin 2006 compared to 2005 and the absence of mobilization costs in 2006 related to theOcean 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 theOcean 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 theOcean 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 theOcean YatzyandOcean Winnerincreased $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 theOcean 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 theOcean Warwick). During 2006, utilization in the GOM was negatively impacted primarily by the relocation of theOcean Spurto Tunisia in the first quarter of 2006 and over five months of downtime for theOcean Nuggetfor a special survey, related repairs and contract preparation work prior to its relocation to Mexico in the fourth

quarter of 2006. Also during 2006, theOcean Spartanunderwent leg repairs and was ready-stacked from mid-September 2006 until mid-December 2006 for total downtime of approximately four months, and theOcean Summitincurred over three months of downtime for a special survey and related repairs. During 2005, theOcean Warwickgenerated 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 theOcean SummitandOcean Nugget, leg repairs for theOcean Nugget, leg/spud can repairs for theOcean Spartanand 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 theOcean Warwickduring 2006 and reduced operating costs in the GOM for theOcean Spur(which only operated in the GOM for 45 days in 2006 before relocating to Tunisia) and theOcean Nugget(which was relocated to Mexico at the beginning of the fourth quarter of 2006). Both theOcean SpurandOcean Nuggetoperated 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 theOcean Spartan‘s survey in late 2005. We also recognized a $1.0 million insurance deductible for a leg punchthrough incident on theOcean Spartanin 2005.

Mexico.Our jack-up rig theOcean 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 theOcean Heritageand the recognition of mobilization costs related to relocation of theOcean Sovereignto locations offshore Bangladesh and Indonesia during 2005.

Europe/Africa/Mediterranean.TheOcean Spurbegan 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 theOcean Warwickin 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 theOcean 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 theOcean 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 theOcean 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 onOcean 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 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 theOcean Monarchand construction of two new jack-up rigs, theOcean ScepterandOcean 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

4.875% Senior Notes.

On June 14, 2005, we issued $250.0 million aggregate principal amount of 4.875% Senior Notes at an offering price of 99.785% of the principal amount, which resulted in net proceeds to us of $247.6 million. These notes bear interest at 4.875% per year, payable semiannually in arrears on January 1 and July 1 of each year and mature on July 1, 2015. The 4.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. We have the right to redeem all or a portion of the 4.875% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.

5.15% Senior Notes.

On August 27, 2004, we issued $250.0 million aggregate principal amount of 5.15% Senior Notes Due September 1, 2014, or 5.15% Senior Notes, at an offering price of 99.759% of the principal amount, which resulted in net proceeds to us of $247.6 million. These notes bear interest at 5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year and mature on September 1, 2014. The 5.15% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. We have the right to redeem all or a portion of the 5.15% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.

1.5% Debentures.

On April 11, 2001, we issued $460.0 million principal amount of 1.5% Debentures, which are due April 15, 2031. The 1.5% Debentures are convertible into shares of our common stock at an initial conversion rate of 20.3978 shares per $1,000 principal amount of the 1.5% Debentures, or $49.02 per share, subject to adjustment in certain circumstances. Upon conversion, we have the right to deliver cash in lieu of shares of our common stock. Holders may require us to purchase all or a portion of their outstanding 1.5% Debentures on April 15, 2008, at a price equal to 100% of the principal amount of the 1.5% Debentures to be purchased plus accrued and unpaid interest. We may choose to pay the purchase price in cash or shares of our common stock or a combination of cash and common stock. In addition, we have the option to redeem all or a portion of the 1.5% Debentures at any time on or after April 15, 2008 at a price equal to 100% of the principal amount plus accrued and unpaid interest. See “1.5% Debentures” in Note 9 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The 1.5% Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

During 2007 and 2006, the holders of $456.4 million and $20,000, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock, resulting in the issuance of 9,309,616 shares and 404 shares of our common stock in 2007 and 2006, respectively.

Zero Coupon Debentures.

We issued our Zero Coupon Debentures on June 6, 2000 at a price of $499.60 per $1,000 principal amount at maturity, which represents a yield to maturity of 3.50% per year. The Zero Coupon Debentures mature on June 6, 2020, and, as of December 31, 2007, the aggregate accreted value of our outstanding Zero Coupon Debentures was $3.9 million. We will not pay interest prior to maturity unless we elect to convert the Zero Coupon Debentures to interest-bearing debentures upon the occurrence of certain tax events. The Zero Coupon Debentures are convertible at the option of the holder at any time prior to maturity, unless previously redeemed, into our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. See “Zero Coupon Debentures” in Note 9 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

During 2007 and 2006, holders of $1.5 million and $13.7 million, respectively, in accreted, or carrying, value through the date of conversion of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 20,658 and 193,147 shares of our common stock upon conversion of these debentures during 2007 and 2006, respectively. The aggregate principal amount at maturity of our Zero Coupon Debentures converted during 2007 and 2006 was $2.4 million and $22.4 million, respectively.

Credit Ratings.

Our current credit rating is Baa1 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings would result in higher rates for borrowings under our Credit Facility and could also result in higher interest rates on future debt issuances.

Capital Expenditures.

The newly upgradedOcean Endeavorcommenced drilling operations in the GOM in early July 2007. The aggregate cost of the upgrade was approximately $248 million of which $38.8 million was spent in 2007. In addition, the upgrade of theOcean Monarchcontinues in Singapore with expected delivery of the upgraded rig late in the fourth quarter of 2008. We expect to spend approximately $305 million to modernize this rig of which $181.4 million had been spent through December 31, 2007.

Construction of our two high-performance, premium jack-up rigs, theOcean ScepterandOcean Shieldis nearing completion, and delivery of both units is expected in the second quarter of 2008. The aggregate expected cost for both rigs is approximately $320 million, including drill pipe and capitalized interest, of which $248.5 million had been spent through December 31, 2007.

During 2007, we spent approximately $388.4 million on our continuing rig capital maintenance program (other than rig upgrades and new construction) and to meet other corporate capital expenditure requirements, including $62.9 million towards modification of certain of our rigs to meet contractual requirements. We have budgeted approximately $500 million in additional capital expenditures in 2008 associated with our ongoing rig equipment replacement and enhancement programs, equipment required for our long-term international contracts and other corporate requirements. We expect to finance our 2008 capital expenditures through the use of our existing cash balances or internally generated funds. From time to time, however, we may also make use of our Credit Facility to finance capital expenditures.

Off-Balance Sheet Arrangements.

At December 31, 2007 and 2006, we had no off-balance sheet debt or other arrangements.

Current Credit Environment.

Recent developments in the financial markets, including a series of rating agency downgrades of sub-prime U.S. mortgage-related assets and significant provisions for loan losses recorded by several major financial institutions, have caused the fair value of sub-prime-related investments to decline. This decline in fair value has become especially problematic for certain large financial institutions and has had an effect through the U.S. economy, including limiting access to capital markets to certain borrowers at reasonable rates and also affecting the market value of certain investments whether or not linked to sub-prime mortgages.

The fair value of our investments in debt securities, comprised of U.S. government securities or U.S. government-backed mortgage securities, have not to date been materially negatively impacted by events in the current credit market. However, we cannot predict with any certainty whether or not any such investments will be impacted in the future or how our customers and/or suppliers will be affected by the current credit conditions. We believe that our cash flows from operations and cash reserves will be sufficient to fund our ongoing operations and capital projects for the next twelve months; however, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes. Our Credit Facility matures in 2011. We do not anticipate that these current credit market conditions will have a material adverse effect on our financial condition, results of operations and cash flows.

Historical Cash Flows

The following is a discussion of our historical cash flows from operating, investing and financing activities for the year ended December 31, 2007 compared to 2006.

Net Cash Provided by Operating Activities.


	Year Ended December 31,
	2007			2006			Change

	(In thousands)
Net income	$	846,541		$	706,847		$	139,694
Net changes in operating assets and liabilities		139,253			(154,068	)		293,321
(Gain) loss on sale of marketable securities		(1,796	)		31			(1,827	)
Depreciation and other non-cash items, net		224,318			207,279			17,039

	$	1,208,316		$	760,089		$	448,227

Our cash flows from operations in 2007 increased $448.2 million or 59% over net cash generated by our operating activities in 2006. The increase in cash flow from operations in 2007 is primarily the result of higher average dayrates by our rigs as a result of continued high worldwide demand for offshore contract drilling services in 2007 compared to 2006. The favorable contribution to cash flows was partially offset by lower utilization of our offshore drilling units due to planned downtime for modifications to our rigs to meet customer requirements and regulatory surveys, as well as the ready-stacking of rigs within our GOM jack-up fleet between wells. In addition, the increase in cash flows from operations was augmented by a decrease in cash required to satisfy our working capital requirements. Trade and other receivables generated cash of $43.5 million during 2007 as the billing cycle for our trade receivables was completed compared to a $190.1 million usage of cash during 2006. During 2007, we also received insurance proceeds of $51.2 million related to the settlement of certain claims arising from the 2005 hurricanes (total insurance proceeds of $56.1 million were received of which $4.9 million is included as a reduction in net cash used in investing activities.) During 2007, we made estimated U.S. federal and state income tax payments and paid foreign income taxes, net of refunds, of $299.6 million and $31.7 million, respectively.

Net Cash Used in Investing Activities.


	Year Ended December 31,
	2007			2006			Change

	(In thousands)
Purchase of marketable securities	$	(2,850,135	)	$	(2,472,431	)	$	(377,704	)
Proceeds from sale of marketable securities		3,163,475			2,187,766			975,709
Capital expenditures		(647,101	)		(551,237	)		(95,864	)
Proceeds from disposition of assets		10,861			4,731			6,130
Proceeds from settlement of forward contracts		8,109			7,289			820

	$	(314,791	)	$	(823,882	)	$	509,091

Our investing activities used $314.8 million in 2007, as compared to $823.9 million in 2006. During 2007, we sold marketable securities, net of purchases, of $313.3 million compared to net purchases of $284.7 million during 2006. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets.

During 2007, we spent approximately $258.7 million related to the major upgrades of theOcean EndeavorandOcean Monarchand construction of theOcean ScepterandOcean Shieldcompared to $278.0 million during 2006. Expenditures for our ongoing capital maintenance programs, including rig modifications to meet contractual requirements, were $388.4 million in 2007 compared to $273.2 million in 2006. The increase in expenditures related to our ongoing capital maintenance program in 2007 compared to 2006 is related to an increase in discretionary funds available for capital spending in 2007, as well as a response to customer requirements. See “— Liquidity and Capital Requirements —Capital Expenditures.”

As of December 31, 2007, we had foreign currency exchange contracts outstanding, which aggregated $18.1 million, that require us to purchase the equivalent of $17.9 million in British pounds sterling and $0.2 million in Mexican pesos at various times through April 2008.

Net Cash Used in Financing Activities.


	Year Ended December 31,
	2007			2006			Change

	(In thousands)
Payment of dividends	$	(796,292	)	$	(258,155	)	$	(538,137	)
Proceeds from stock options exercised		10,836			3,263			7,573
Other		5,194			793			4,401

	$	(780,262	)	$	(254,099	)	$	(526,163	)

During 2007, we paid cash dividends totaling $796.3 million (consisting of quarterly cash dividends aggregating $69.3 million, or $0.125 per share of our common stock per quarter, and special cash dividends of $4.00 and $1.25 per share of our common stock, totaling $553.4 million and $173.6 million, respectively). During 2006, we paid cash dividends totaling $258.2 million (consisting of quarterly dividends of $64.6 million in the aggregate, or $0.125 per share of our common stock per quarter, and a special cash dividend of $1.50 per share of our common stock, totaling $193.6 million).

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not repurchase any shares of our outstanding common stock during the years ended December 31, 2007 and 2006.

Other

Currency Risk.Some of our subsidiaries conduct a portion of their operations in the local currency of the country where they conduct operations. Currency environments in which we have significant business operations include Mexico, Brazil, the U.K., Australia and Malaysia. When possible, we attempt to minimize our currency exchange risk by seeking international contracts payable in local currency in amounts equal to our estimated operating costs payable in local currency with the balance of the contract payable in U.S. dollars. At present, however, only a limited number of our contracts are payable both in U.S. dollars and the local currency.

We also utilize foreign exchange forward contracts to reduce our forward exchange risk. A forward currency exchange contract obligates a contract holder to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specific dates.

We record currency translation adjustments and transaction gains and losses as “Other income (expense)” in our Consolidated Statements of Operations. The effect on our results of operations from these translation adjustments and transaction gains and losses has not been material and are not expected to have a significant effect in the future.

Recent Accounting Pronouncements

choose different measurement attributes for similar types of assets and liabilities. Accounting principles generally accepted in the U.S., or GAAP, have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 159 on our financial statements and have determined that the adoption of SFAS 159 will not have a material impact on our consolidated results of operations, financial position and cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” or SFAS 157, which establishes a separate framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 was issued to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS 157 does not require any new fair value measurements; however, its adoption may result in changes to current practice. Changes resulting from the application of SFAS 157 relate to the definition of fair value, the methods used to measure fair value and the expanded disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, rather than an entity-specific measurement. It also establishes a fair value hierarchy that distinguishes between (i) market participant assumptions developed based on market data obtained from independent sources and (ii) the reporting entity’s own assumptions about market participant assumptions developed based on the best information available under the circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 157 on our financial statements and have determined that the adoption of SFAS 157 will not have a material impact on our consolidated results of operations, financial position and cash flows.

Forward-Looking Statements

We or our representatives may, from time to time, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. Statements made by us in this report that contain forward-looking statements include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

	•		future market conditions and the effect of such conditions on our future results of operations (see “— Overview — Industry Conditions”);

	•		future uses of and requirements for financial resources (see “— Liquidity and Capital Requirements” and “— Sources of Liquidity and Capital Resources”);

	•		interest rate and foreign exchange risk (see “— Liquidity and Capital Requirements — Credit Ratings” and “Quantitative and Qualitative Disclosures About Market Risk”);

	•		future contractual obligations (see “— Overview — Industry Conditions,” “Business — Operations Outside the United States” and “— Liquidity and Capital Requirements”);

	•		future operations outside the United States including, without limitation, our operations in Mexico (see “— Overview — Industry Conditions” and “Risk Factors”);

	•		business strategy;

	•		growth opportunities;

	•		competitive position;

	•		expected financial position;

	•		future cash flows (see “ — Overview — Contract Drilling Backlog”);

	•		future regular or special dividends (see “ — Historical Cash Flows” and “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Dividend Policy”);

	•		financing plans;

	•		tax planning (See “— Overview — Critical Accounting Estimates — Income Taxes,” “— Years Ended December 31, 2007 and 2006 — Income Tax Expense” and “— Years Ended December 31, 2006 and 2005 — Income Tax Expense”);

	•		budgets for capital and other expenditures (see “— Liquidity and Capital Requirements”);

	•		timing and cost of completion of rig upgrades and other capital projects (see “— Liquidity and Capital Requirements”);

	•		delivery dates and drilling contracts related to rig conversion and upgrade projects (see “— Overview — Industry Conditions” and “— Liquidity and Capital Requirements”);

	•		plans and objectives of management;

	•		performance of contracts (see “— Overview — Industry Conditions” and “Risk Factors”);

	•		outcomes of legal proceedings;

	•		compliance with applicable laws; and

	•		adequacy of insurance or indemnification (see “Risk Factors”).

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

	•		general economic and business conditions;

	•		worldwide demand for oil and natural gas;

	•		changes in foreign and domestic oil and gas exploration, development and production activity;

	•		oil and natural gas price fluctuations and related market expectations;

	•		the ability of OPEC to set and maintain production levels and pricing, and the level of production in non-OPEC countries;

	•		policies of various governments regarding exploration and development of oil and gas reserves;

	•		advances in exploration and development technology;

	•		the worldwide political and military environment, including in oil-producing regions;

	•		casualty losses;

	•		operating hazards inherent in drilling for oil and gas offshore;

	•		industry fleet capacity;

	•		market conditions in the offshore contract drilling industry, including dayrates and utilization levels;

	•		competition;

	•		changes in foreign, political, social and economic conditions;

	•		risks of international operations, compliance with foreign laws and taxation policies and expropriation or nationalization of equipment and assets;

	•		risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;

	•		the risk that an LOI may not result in a definitive agreement;

	•		foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;

	•		risks of war, military operations, other armed hostilities, terrorist acts and embargoes;

	•		changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness;

	•		regulatory initiatives and compliance with governmental regulations;

	•		compliance with environmental laws and regulations;

	•		development and exploitation of alternative fuels;

	•		customer preferences;

	•		effects of litigation;

	•		cost, availability and adequacy of insurance;

	•		the risk that future regular or special dividends may not be declared;

	•		adequacy of our sources of liquidity;

	•		the availability of qualified personnel to operate and service our drilling rigs; and

	•		various other matters, many of which are beyond our control.

The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings

with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The information included in this Item 7A is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Forward-Looking Statements” in Item 7 of this report.

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2007 and December 31, 2006, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

Exposure to market risk is managed and monitored by our senior management. Senior management approves the overall investment strategy that we employ and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling instruments or entering into offsetting positions.

Interest Rate Risk

We have exposure to interest rate risk arising from changes in the level or volatility of interest rates. Our investments in marketable securities are primarily in fixed maturity securities. We monitor our sensitivity to interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on stockholders’ equity. The analysis presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over a one-year period.

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on December 31, 2007 and December 31, 2006, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.

The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.

Loans under our $285 million syndicated, five-year senior unsecured revolving Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. As of and December 31, 2007 and 2006, there were no loans outstanding under the Credit Facility (however, as of December 31, 2007, $54.2 million in letters of credit were issued and outstanding under the Credit Facility).

Our long-term debt, as of December 31, 2007 and December 31, 2006, is denominated in U.S. dollars. Our debt has been primarily issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $35.8 million and $270.8 million as of December 31, 2007 and 2006, respectively. A 100-basis point decrease would result in an increase in market value of $11.6 million and $33.0 million as of December 31, 2007 and 2006, respectively.

Foreign Exchange Risk

Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. During 2007 and 2006, we entered into various foreign currency forward exchange contracts that required us to purchase predetermined amounts of foreign currencies at predetermined dates. As of December 31, 2007, we had foreign currency exchange contracts outstanding, which aggregated $18.1 million, that require us to purchase the equivalent of $17.9 million in British pounds sterling and $0.2 million in Mexican pesos at various times through April 2008. As of December 31, 2006, we had foreign currency exchange contracts outstanding, which aggregated $22.5 million, that required us to purchase the equivalent of $5.7 million in Brazilian reais, $2.7 million in British pounds sterling, $10.3 million in Mexican pesos and $3.8 million in Norwegian kroner at various times through June 2007. At December 31, 2007, we have presented the $2,000 and $(93,000) fair value of our outstanding foreign currency forward exchange contracts in accordance with SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” as “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, in our Consolidated Balance Sheets included in Item 8 of this report. We have presented the $2.6 million fair value of our foreign currency forward exchange contracts at December 31, 2006 as “Prepaid expenses and other current assets” in our Consolidated Balance Sheets included in Item 8 or this report.

The sensitivity analysis assumes an instantaneous 20% change in foreign currency exchange rates versus the U.S. dollar from their levels at December 31, 2007 and 2006.

The following table presents our exposure to market risk by category (interest rates and foreign currency exchange rates):


	Fair Value Asset (Liability)						Market Risk
	December 31,						December 31,
	2007			2006			2007			2006

				(In thousands)
Interest rate:
Marketable securities	$	1,301	(a)	$	301,159	(a)	$	100	(c)	$	400	(c)
Long-term debt		(500,303	) (b)		(1,231,689	) (b)		—			—

Foreign Exchange:
Forward exchange contracts		2	(d)		2,600	(d)		100	(e)		7,400	(e)
Forward exchange contracts		(93	) (d)		—	(d)		3,300	(e)		—	(e)


(a)		The fair market value of our investment in marketable securities, excluding repurchase agreements, is based on the quoted closing market prices on December 31, 2007 and 2006.

(b)		The fair values of our 4.875% Senior Notes, 5.15% Senior Notes, 1.5% Debentures and Zero Coupon Debentures are based on the quoted closing market prices on December 31, 2007 and 2006.

(c)		The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at December 31, 2007 and 2006.

(d)		The fair value of our foreign currency forward exchange contracts is based on the quoted market prices on December 31, 2007 and 2006.

(e)		The calculation of estimated foreign exchange risk is based on assumed adverse changes in the underlying reference price or index of an increase in foreign exchange rates of 20% at December 31, 2007 and 2006.

Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Diamond Offshore Drilling, Inc. and Subsidiaries
Houston, Texas

We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 14 to the consolidated financial statements, the Company changed its method of accounting for uncertainty in income taxes in 2007.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

Deloitte & Touche LLP
Houston, Texas
February 25, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Diamond Offshore Drilling, Inc. and Subsidiaries
Houston, Texas

We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A of this Form 10-K under the heading “Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007 of the Company and our report dated February 25, 2008 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s change in its method of accounting for uncertainty in income taxes in 2007.

Deloitte & Touche LLP
Houston, Texas
February 25, 2008

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)


	December 31,
	2007			2006

ASSETS
Current assets:
Cash and cash equivalents	$	637,961		$	524,698
Marketable securities		1,301			301,159
Accounts receivable		522,808			567,474
Prepaid expenses and other current assets		103,120			88,216

Total current assets		1,265,190			1,481,547
Drilling and other property and equipment, net of accumulated depreciation		3,040,063			2,628,453
Other assets		36,212			22,839

Total assets	$	4,341,465		$	4,132,839


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	3,563		$	—
Accounts payable		132,243			122,000
Accrued liabilities		235,521			184,978
Taxes payable		81,684			26,531

Total current liabilities		453,011			333,509
Long-term debt		503,071			964,310
Deferred tax liability		397,629			448,227
Other liabilities		110,687			67,285

Total liabilities		1,464,398			1,813,331


Commitments and contingencies		—			—

Stockholders’ equity:
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding)		—			—
Common stock (par value $0.01, 500,000,000 shares authorized; 143,787,206 shares issued and 138,870,406 shares outstanding at December 31, 2007; 134,133,776 shares issued and 129,216,976 shares outstanding at December 31, 2006)		1,438			1,341
Additional paid-in capital		1,831,492			1,299,846
Retained earnings		1,158,535			1,137,151
Accumulated other comprehensive (losses) gains		15			(4,417	)
Treasury stock, at cost (4,916,800 shares at December 31, 2007 and 2006)		(114,413	)		(114,413	)

Total stockholders’ equity		2,877,067			2,319,508

Total liabilities and stockholders’ equity	$	4,341,465		$	4,132,839

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)


	Year Ended December 31,
	2007			2006			2005
Revenues:
Contract drilling	$	2,505,663		$	1,987,114		$	1,179,015
Revenues related to reimbursable expenses		62,060			65,458			41,987

Total revenues		2,567,723			2,052,572			1,221,002


Operating expenses:
Contract drilling		1,011,193			812,057			638,540
Reimbursable expenses		52,857			57,465			35,549
Depreciation		235,251			200,503			183,724
General and administrative		53,483			41,551			37,162
Casualty gain onOcean Warwick		—			(500	)		(33,605	)
(Gain) loss on disposition of assets		(8,583	)		1,064			(14,767	)

Total operating expenses		1,344,201			1,112,140			846,603


Operating income		1,223,522			940,432			374,399

Other income (expense):
Interest income		33,566			37,880			26,028
Interest expense		(19,191	)		(24,096	)		(41,799	)
Gain (loss) on sale of marketable securities		1,796			(31	)		(1,180	)
Other, net		6,844			12,147			(1,053	)

Income before income tax expense		1,246,537			966,332			356,395

Income tax expense		(399,996	)		(259,485	)		(96,058	)


Net income	$	846,541		$	706,847		$	260,337


Earnings per share:
Basic	$	6.14		$	5.47		$	2.02

Diluted	$	6.12		$	5.12		$	1.91


Weighted-average shares outstanding:
Shares of common stock		137,816			129,129			128,690
Dilutive potential shares of common stock		1,129			9,652			12,661

Total weighted-average shares outstanding assuming dilution		138,945			138,781			141,351

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except number of shares)


										Accumulated
					Additional					Other								Total
	Common Stock				Paid-in		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity

January 1, 2005		133,483,820	$	1,335	$	1,264,512	$	476,382		$	(1,988	)		4,916,800	$	(114,413	)	$	1,625,828

Net income		—		—		—		260,337			—			—		—			260,337
Dividends to stockholders ($0.375 per share)		—		—		—		(48,260	)		—			—		—			(48,260	)
Conversion of long-term debt.		264		—		13		—			—			—		—			13
Stock options exercised		358,345		3		13,409		—			—			—		—			13,412
Reversal of cumulative foreign currency translation loss		—		—		—		—			2,077			—		—			2,077
Loss on investments, net		—		—		—		—			(80	)		—		—			(80	)

December 31, 2005		133,842,429		1,338		1,277,934		688,459			9			4,916,800		(114,413	)		1,853,327

Net income		—		—		—		706,847			—			—		—			706,847
Dividends to stockholders ($2.00 per share)		—		—		—		(258,155	)		—			—		—			(258,155	)
Conversion of long-term debt.		193,551		2		13,734		—			—			—		—			13,736
Stock options exercised		97,796		1		3,295		—			—			—		—			3,296
Stock-based compensation, net		—		—		4,883		—			—			—		—			4,883
Gain on investments, net		—		—		—		—			100			—		—			100

December 31, 2006, before adoption of SFAS 158		134,133,776		1,341		1,299,846		1,137,151			109			4,916,800		(114,413	)		2,324,034

Adjustment to initially apply SFAS 158, net of tax		—		—		—		—			(4,526	)		—		—			(4,526	)

December 31, 2006		134,133,776		1,341		1,299,846		1,137,151			(4,417	)		4,916,800		(114,413	)		2,319,508

Cumulative effect of adopting FIN 48		—		—		—		(28,422	)		—			—		—			(28,422	)

January 1, 2007		134,133,776		1,341		1,299,846		1,108,729			(4,417	)		4,916,800		(114,413	)		2,291,086

Net income		—		—		—		846,541			—			—		—			846,541
Dividends to stockholders ($5.75 per share)		—		—		—		(796,735	)		—			—		—			(796,735	)
Conversion of long-term debt.		9,330,274		94		459,654		—			—			—		—			459,748
Reversal of deferred tax liability related to imputed interest on converted debentures		—		—		54,154		—			—			—		—			54,154
Stock options exercised		323,156		3		10,707		—			—			—		—			10,710
Stock-based compensation, net		—		—		7,131		—			—			—		—	��		7,131
Loss on investments, net		—		—		—		—			(94	)		—		—			(94	)
Pension plan termination		—		—		—		—			4,526			—		—			4,526

December 31, 2007		143,787,206	$	1,438	$	1,831,492	$	1,158,535		$	15			4,916,800	$	(114,413	)	$	2,877,067

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)


	Year Ended December 31,
	2007			2006			2005

Net income	$	846,541		$	706,847		$	260,337

Other comprehensive gains (losses), net of tax:
Foreign currency translation gain		—			—			2,077
Pension plan termination		4,526			—			—
Unrealized holding gain on investments		188			162			10
Reclassification adjustment for gain included in net income		(282	)		(62	)		(90	)

Total other comprehensive gain		4,432			100			1,997
Comprehensive income before adoption of SFAS 158, net of tax		850,973			706,947			262,334

Adjustment to initially apply SFAS 158, net of tax		—			(4,526	)		—

Comprehensive income	$	850,973		$	702,421		$	262,334

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


	Year Ended December 31,
	2007			2006			2005


Operating activities:
Net income	$	846,541		$	706,847		$	260,337
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		235,251			200,503			183,724
Casualty gain onOcean Warwick		—			(500	)		(33,605	)
(Gain) loss on disposition of assets		(8,583	)		1,064			(14,767	)
(Gain) loss on sale of marketable securities, net		(1,796	)		31			1,180
Deferred tax provision		1,770			610			65,159
Accretion of discounts on marketable securities		(11,830	)		(14,090	)		(7,683	)
Amortization of debt issuance costs		9,649			848			7,742
Amortization of debt discounts		238			392			7,523
Stock-based compensation expense		4,454			3,106			—
Excess tax benefits from stock-based payment arrangements		(5,194	)		(1,313	)		—
Deferred income, net		28,461			13,373			935
Deferred expenses, net		(37,429	)		6,317			(1,010	)
Other items, net		7,531			(3,031	)		3,942
Changes in operating assets and liabilities:
Accounts receivable		43,467			(190,054	)		(174,659	)
Prepaid expenses and other current assets		(1,341	)		(12,078	)		(4,752	)
Accounts payable and accrued liabilities		33,174			58,762			66,011
Taxes payable		63,953			(10,698	)		28,494

Net cash provided by operating activities		1,208,316			760,089			388,571

Investing activities:
Capital expenditures (including rig acquisitions)		(647,101	)		(551,237	)		(293,829	)
Proceeds from casualty loss ofOcean Warwick		—			—			50,500
Proceeds from sale/involuntary conversion of assets		10,861			4,731			26,047
Proceeds from sale and maturities of marketable securities		3,163,475			2,187,766			5,610,907
Purchase of marketable securities		(2,850,135	)		(2,472,431	)		(4,956,560	)
Proceeds from maturities of Australian dollar time deposits		—			—			11,761
Proceeds from settlement of forward contracts		8,109			7,289			1,136

Net cash (used in) provided by investing activities		(314,791	)		(823,882	)		449,962

Financing activities:
Issuance of 4.875% senior unsecured notes		—			—			249,462
Debt issuance costs and arrangement fees		—			(520	)		(1,866	)
Redemption of zero coupon debentures		—			—			(460,015	)
Payment of dividends		(796,292	)		(258,155	)		(48,260	)
Payments under lease-leaseback agreement		—			—			(12,818	)
Proceeds from stock options exercised		10,836			3,263			11,547
Excess tax benefits from share-based payment arrangements		5,194			1,313			—

Net cash used in financing activities		(780,262	)		(254,099	)		(261,950	)

Net change in cash and cash equivalents		113,263			(317,892	)		576,583
Cash and cash equivalents, beginning of year		524,698			842,590			266,007

Cash and cash equivalents, end of year	$	637,961		$	524,698		$	842,590

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. General Information

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

As of February 20, 2008, Loews Corporation, or Loews, owned 50.5% of the outstanding shares of our common stock.

Principles of Consolidation

Our consolidated financial statements include the accounts of Diamond Offshore Drilling, Inc. and our subsidiaries after elimination of intercompany transactions and balances.

Cash and Cash Equivalents, Marketable Securities

We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.

We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in “Accumulated other comprehensive gains (losses)” until realized. The cost of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments are included in our Consolidated Statements of Operations in “Interest income.” The sale and purchase of securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific identification method. Realized gains or losses, as well as any declines in value that are judged to be other than temporary, are reported in our Consolidated Statements of Operations in “Other income (expense).”

Derivative Financial Instruments

Our derivative financial instruments include foreign currency forward exchange contracts and a contingent interest provision that is embedded in our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, issued on April 11, 2001. See Note 5.

Supplementary Cash Flow Information

We paid interest totaling $25.3 million, $32.5 million and $94.1 million on long-term debt for the years ended December 31, 2007, 2006 and 2005, respectively. The amount of interest paid in 2005 included $73.3 million in accreted interest paid in connection with the June 2005 partial redemption of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures. See Note 9.

We paid $31.7 million, $10.8 million and $5.3 million in foreign income taxes, net of foreign tax refunds, during the years ended December 31, 2007, 2006 and 2005, respectively. We paid $299.0 million and $262.4 million in U.S. federal income taxes during the years ended December 31, 2007 and 2006, respectively. We received refunds of $25,000, $13.7 million and $7.7 million in U.S. income taxes during the years ended December 31, 2007, 2006 and 2005, respectively. We paid state income taxes of $0.6 million during the year ended December 31, 2007.

Cash payments for capital expenditures for the year ended December 31, 2007, included $41.4 million of capital expenditures that were accrued but unpaid at December 31, 2006. Cash payments for capital expenditures for the year ended December 31, 2006, included $53.7 million of capital expenditures that were accrued but unpaid at December 31, 2005. Capital expenditures that were accrued but not paid as of December 31, 2007, totaled $43.0 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2007.

We recorded income tax benefits of $2.7 million, $1.7 million and $2.4 million related to the exercise of employee stock options in 2007, 2006 and 2005, respectively.

During 2007 and 2006, holders of $1.5 million and $13.7 million, respectively, in accreted, or carrying, value through the date of conversion of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. Also during 2007 and 2006, the holders of $456.4 million and $20,000, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. See Note 9.

Drilling and Other Property and Equipment

Our drilling and other property and equipment is carried at cost. We charge maintenance and routine repairs to income currently while replacements and betterments, which meet certain criteria, are capitalized. Costs incurred for major rig upgrades are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations. Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from three to 30 years.

Capitalized Interest

We capitalize interest cost for the construction and upgrade of qualifying assets. In April 2005 and July 2006 we began capitalizing interest on expenditures related to the upgrades of theOcean Endeavorand theOcean Monarch, respectively, for ultra-deepwater service. In December 2005 and January 2006 we began capitalizing interest on expenditures related to the construction of two jack-up rigs, theOcean ScepterandOcean Shield, respectively.

A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:


	For the Year Ended December 31,
	2007			2006			2005
	(In thousands)

Total interest cost including amortization of debt issuance costs	$	37,735		$	33,892		$	42,541
Capitalized interest		(18,544	)		(9,796	)		(742	)

Total interest expense as reported	$	19,191		$	24,096		$	41,799

Asset Retirement Obligations

Statement of Financial Accounting Standards, or SFAS, No. 143, “Accounting for Asset Retirement Obligations” requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred. At December 31, 2007 and 2006, we had no asset retirement obligations.

Impairment of Long-Lived Assets

	•		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.

2007. 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 U.S. Gulf of Mexico. 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. Based on this knowledge, we determined that an impairment test of our drilling equipment was not needed as we are currently marketing all of our drilling units. We did not have any cold-stacked rigs at December 31, 2007. We do not believe that current circumstances indicate that the carrying amount of our property and equipment may not be recoverable.

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

2005. In December 2005, we reviewed our single cold-stacked rig, theOcean Monarch, for impairment. Based on our decision to upgrade this drilling unit to high-specification capabilities at an estimated cost of approximately $305 million and the low net book value of this rig, we did not consider this asset to be impaired.

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

Fair Value of Financial Instruments

We believe that the carrying amount of our current financial instruments approximates fair value because of the short maturity of these instruments. For non-current financial instruments we use quoted market prices, when available, and discounted cash flows to estimate fair value. See Note 12.

Debt Issuance Costs

Debt issuance costs are included in our Consolidated Balance Sheets in “Other assets” and are amortized over the respective terms of the related debt. Interest expense for the years ended December 31, 2007, 2006 and 2005 includes $9.2 million, $0.2 million and $6.9 million, respectively, in debt issuance costs that we wrote off in connection with conversions of our 1.5% Debentures and Zero Coupon Debentures into shares of our common stock. See Note 9.

Income Taxes

We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” which requires the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in 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. We make judgments regarding future events and related estimates especially as they pertain to the 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.

Treasury Stock

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We account for the purchase of treasury stock using the cost method, which reports the cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated Balance Sheets. We did not repurchase any shares of our outstanding common stock during 2007, 2006 or 2005.

Comprehensive Income (Loss)

Comprehensive income (loss) is the change in equity of a business enterprise during a period from transactions and other events and circumstances except those transactions resulting from investments by owners and distributions to owners. Comprehensive income (loss) for the three years ended December 31, 2007 includes net income (loss), foreign currency translation gains and losses, unrealized holding gains and losses on marketable securities and an adjustment to initially adopt SFAS No. 158, “Accounting for Defined Benefit Pension or Other Postretirement Plans,” or SFAS 158, in 2006. See Note 10.

Currency Translation

Our functional currency is the U.S. dollar. 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 our subsidiaries operate. Prior to this date, these subsidiaries utilized the local currency of the country in which they conduct business as their functional currency. As a result of this change, currency translation adjustments and transaction gains and losses, including gains and losses from the settlement of foreign currency forward exchange contracts, are reported as “Other income (expense)” in our Consolidated Statements of Operations. For the years ended December 31, 2007 and 2006, we recognized net foreign currency exchange gains of $2.9 million and $10.3 million, respectively. During the year ended December 31, 2005, we recognized net foreign currency exchange losses of $0.8 million. See Note 5.

Revenue Recognition

Revenue from our dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. These fees are earned 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 initial 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 as incurred.

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

We record reimbursements received 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, for the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S., or GAAP, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.

Reclassifications

Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings.

Recent Accounting Pronouncements

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” or SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. GAAP has required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 159 on our financial statements and have determined that the adoption of SFAS 159 will not have a material impact on our consolidated results of operations, financial position and cash flows.

circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 157 on our financial statements and have determined that the adoption of SFAS 157 will not have a material impact on our consolidated results of operations, financial position and cash flows.

2. Stock-Based Compensation

Our Second Amended and Restated 2000 Stock Option Plan, as amended, or Stock Plan, provides for the issuance of either incentive stock options or non-qualified stock options to our employees, consultants and non-employee directors. Our Stock Plan also authorizes the award of stock appreciation rights, or SARs, in tandem with stock options or separately. The aggregate number of shares of our common stock for which stock options or SARs may be granted is 1,500,000 shares. The exercise price per share may not be less than the fair market value of the common stock on the date of grant. Generally, stock options and SARs vest ratably over a four year period and expire in ten years.

Effective January 1, 2006, we adopted the FASB’s revised SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123(R), using the modified prospective application transition method. Prior to the adoption of SFAS 123(R) on January 1, 2006, we accounted for our Stock Plan in accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, no compensation expense was recognized for the options granted to our employees in periods prior to January 1, 2006. If compensation expense had been recognized for stock options granted to our employees based on the fair value of the options at the grant dates our net income and earnings per share, or EPS, would have been as follows:


	Year Ended December 31,
	2005
	(In thousands, except
	per share data)

Net income as reported	$	260,337
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(1,411	)


Pro forma net income	$	258,926


Earnings per share of common stock:
As reported	$	2.02

Pro forma	$	2.01


Earnings per share of common stock-assuming dilution:
As reported	$	1.91

Pro forma	$	1.90

Total compensation cost recognized for Stock Plan transactions for the years ended December 31, 2007 and 2006 was $4.5 million and $3.1 million, respectively. Tax benefits recognized for the years ended December 31, 2007 and 2006 related thereto were $1.5 million and $1.1 million, respectively.

For the years ended December 31, 2006 and 2005 the fair value of options and SARs granted under the Stock Plan was estimated using the Binomial Option pricing model. During the third quarter of 2007, we began using the Black Scholes model to value SARs that were granted during the period. The change in valuation technique was necessitated by our decision to change our stock option administrator. There was no material impact to our consolidated results of operations, financial position and cash flows as a result of the change in valuation techniques.

The following are the weighted average assumptions used in estimating the fair value of our options and SARS:


	Year Ended December 31,
	2007			2006			2005
Expected life of stock options/SARs (in years)		5			6			7
Expected volatility		27.53	%		30.72	%		29.53	%
Dividend yield		.48	%		.62	%		.56	%
Risk free interest rate		4.28	%		4.85	%		4.16	%

Expected life of stock options and SARs is based on historical data as is the expected volatility. The dividend yield is based on the current approved regular dividend rate in effect and the current market price at the time of grant. Risk free interest rates are determined using the U.S. Treasury yield curve at time of grant with a term equal to the expected life of the options and SARs.

A summary of activity under the Stock Plan as of December 31, 2007 and changes during the year then ended is as follows:


						Weighted-Average		Aggregate Intrinsic
				Weighted-Average		Remaining		Value
	Number of Awards			Exercise Price		Contractual Term		(In Thousands)

Awards outstanding at January 1, 2007		595,290		$	49.81
Granted		194,450		$	109.80
Exercised		(346,809	)	$	38.74
Forfeited		(8,904	)	$	61.79
Expired		(1,250	)	$	30.37

Awards outstanding at December 31, 2007		432,777		$	85.44		8.7	$	24,590

Awards exercisable at December 31, 2007		31,665		$	74.52		7.8	$	2,168

The weighted-average grant date fair values of options granted during the years ended December 31, 2007, 2006 and 2005 were $36.80, $39.24 and $25.80, respectively. The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005 was $20.6 million, $5.0 million and $10.5 million, respectively. The total fair value of stock options vested during the years ended December 31, 2007, 2006 and 2005 was $3.6 million, $2.7 million and $2.0 million, respectively. As of December 31, 2007 there was $10.9 million of total unrecognized compensation cost related to nonvested stock options and SARs granted under the Stock Plan which we expect to recognize over a weighted average period of 2.68 years.

3. Earnings Per Share

A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:


	Year Ended December 31,
	2007		2006		2005

	(In thousands, except per share data)

Net income — basic (numerator):	$	846,541	$	706,847	$	260,337
Effect of dilutive potential shares
Zero Coupon Debentures		51		236		4,880
1.5% Debentures		3,087		3,293		4,583

Net income including conversions — diluted (numerator):	$	849,679	$	710,376	$	269,800


Weighted-average shares — basic (denominator):		137,816		129,129		128,690
Effect of dilutive potential shares
Zero Coupon Debentures		54		119		3,114
1.5% Debentures		1,015		9,383		9,383
Stock options and SARs		60		150		164

Weighted-average shares including conversions — diluted (denominator):		138,945		138,781		141,351

Earnings per share:
Basic	$	6.14	$	5.47	$	2.02

Diluted	$	6.12	$	5.12	$	1.91

Our computation of diluted EPS for the year ended December 31, 2007 excludes stock options representing 22,937 shares of common stock and 154,119 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.

The computation of diluted EPS for the year ended December 31, 2006 excludes stock options representing 82,257 shares of common stock and 56,916 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.

The computation of diluted EPS for the year ended December 31, 2005 excludes stock options representing 22,088 shares of common stock because the options’ exercise prices were higher than the average market price per share of our common stock for the period.

4. Investments and Marketable Securities

We report our investments as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations.

Our other investments in marketable securities are classified as available for sale and are summarized as follows:


	December 31, 2007
	Amortized		Unrealized		Market
	Cost		Gain		Value

	(In thousands)
U.S. government-backed mortgage securities	$	1,277	$	24	$	1,301


	December 31, 2006
	Amortized		Unrealized			Market
	Cost		Gain (Loss)			Value

	(In thousands)
Debt securities issued by the U.S. Treasury and other U.S. government agencies:
Due within one year	$	299,252	$	170		$	299,422
Mortgage-backed securities		1,740		(3	)		1,737

Total	$	300,992	$	167		$	301,159

Proceeds from maturities and sales of marketable securities and gross realized gains and losses are summarized as follows:


	Year Ended December 31,
	2007			2006			2005

	(In thousands)
Proceeds from maturities	$	1,325,000		$	950,000		$	2,550,000
Proceeds from sales		1,838,475			1,237,766			3,060,907
Gross realized gains		1,856			188			220
Gross realized losses		(60	)		(219	)		(1,400	)

5. Derivative Financial Instruments

Forward Exchange Contracts

Our international operations expose us to foreign exchange risk, primarily associated with our costs payable in foreign currencies for employee compensation and for purchases from foreign suppliers. We utilize foreign exchange forward contracts to reduce our forward exchange risk. A forward currency exchange contract obligates a contract holder to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specified dates.

During 2007 and 2006, we entered into various foreign currency forward exchange contracts which resulted in net realized gains totaling $8.1 million and $7.3 million, respectively. As of December 31, 2007, we had foreign currency exchange contracts outstanding, which aggregated $18.1 million, that require us to purchase the equivalent of $17.9 million in British pounds sterling and $0.2 million in Mexican pesos at various times through April 2008.

These forward contracts are derivatives as defined by SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” or SFAS 133. SFAS 133 requires that each derivative be stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for hedge accounting, the gains and losses are reflected in income in the same period as offsetting losses and gains on the qualifying hedged positions. The forward contracts we entered into in 2007 and 2006 did not qualify for hedge accounting. In accordance with SFAS 133, we recorded a net unrealized loss of $91,000 and a net unrealized gain of $2.6 million in our Consolidated Statements of Operations for the years ended December 31, 2007 and 2006, respectively, as “Other income (expense)” to adjust the carrying value of these derivative financial instruments to

their fair value. At December 31, 2007, we have presented the $2,000 and $(93,000) fair value of our outstanding foreign currency forward exchange contracts as “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, in our Consolidated Balance Sheets. We have presented the $2.6 million fair value of our foreign currency forward exchange contracts at December 31, 2006 as “Prepaid expenses and other current assets” in our Consolidated Balance Sheets.

Contingent Interest

Our 1.5% Debentures, of which an aggregate principal amount of $3.6 million were outstanding at December 31, 2007, contain a contingent interest provision. The contingent interest component is an embedded derivative as defined by SFAS 133 and accordingly must be split from the host instrument and recorded at fair value on the balance sheet. The contingent interest component had no fair value at issuance or at December 31, 2007 or at December 31, 2006.

6. Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of the following:


	December 31,
	2007		2006

	(In thousands)

Rig spare parts and supplies	$	50,699	$	48,801
Deferred mobilization costs		17,295		3,433
Prepaid insurance		11,444		5,891
Deferred tax assets		9,006		9,606
Vendor prepayments		7,296		12,251
Deposits		2,292		1,434
Prepaid taxes		1,681		1,958
Forward exchange contracts		2		2,594
Other		3,405		2,248

Total	$	103,120	$	88,216

7. Drilling and Other Property and Equipment

Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:


	December 31,
	2007			2006

	(In thousands)

Drilling rigs and equipment	$	4,540,797		$	3,896,585
Construction work-in-progress		453,093			459,824
Land and buildings		24,123			17,353
Office equipment and other		29,742			27,132

Cost		5,047,755			4,400,894
Less accumulated depreciation		(2,007,692	)		(1,772,441	)

Drilling and other property and equipment, net	$	3,040,063		$	2,628,453

Construction work-in-progress at December 31, 2007 consisted of $186.8 million related to the major upgrade of theOcean Monarchto ultra-deepwater service and $266.3 million related to the construction of two new jack-up drilling units, theOcean Scepterand theOcean Shield, including accrued capital expenditures aggregating $23.2 million related to these projects. We anticipate that both theOcean ScepterandOcean Shieldwill be delivered in the second quarter of 2008. We expect the upgrade of theOcean Monarchto be completed in late 2008. Construction work-in-progress related to these projects was $210.0 million at December 31, 2006 and $249.8 million for theOcean Endeavorat December 31, 2006.

8. Accrued Liabilities

Accrued liabilities consist of the following:


	December 31,
	2007		2006

	(In thousands)

Accrued project/upgrade expenses	$	95,778	$	67,308
Payroll and benefits		52,975		42,496
Deferred revenue		36,134		13,887
Interest payable		10,413		11,823
Personal injury and other claims		8,692		9,934
Hurricane-related expenses and deferred gains		1,380		8,328
Other		30,149		31,202

Total	$	235,521	$	184,978

9. Long-Term Debt

Long-term debt consists of the following:


	December 31,
	2007		2006

	(In thousands)

Zero Coupon Debentures (due 2020)	$	3,931	$	5,302
1.5% Debentures (due 2031)		3,563		459,967
5.15% Senior Notes (due 2014)		249,566		249,513
4.875% Senior Notes (due 2015)		249,574		249,528

		506,634		964,310
Less: Current maturities		3,563		—

Total	$	503,071	$	964,310

Certain of our long-term debt payments may be accelerated due to rights that the holders of our debt securities have to put the securities to us. The holders of our outstanding 1.5% Debentures and Zero Coupon Debentures have the right to require us to purchase all or a portion of their outstanding debentures on April 15, 2008 and June 6, 2010, respectively. See “Zero Coupon Debentures” and“1.5% Debentures” for further discussion of the rights that the holders of these debentures have to put the securities to us.

The aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2007, are as follows:


(Dollars in thousands)

2008	$	3,563
2009		—
2010		3,931
2011		—
2012		—
Thereafter		499,140

		506,634
Less: Current maturities		3,563

Total	$	503,071

$285 Million Revolving Credit Facility.

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

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. See Note 11 for a discussion of letters of credit issued under the Credit Facility.

4.875% Senior Notes

Our 4.875% Senior Notes Due July 1, 2015, or 4.875% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at 4.875% per year, payable semiannually in arrears on January 1 and July 1 of each year and mature on July 1, 2015. The 4.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc., and they rank equal in right of payment to our existing and future unsecured and unsubordinated indebtedness, although the 4.875% Senior Notes will be effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of the 4.875% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.

5.15% Senior Notes

Our 5.15% Senior Notes Due September 1, 2014, or 5.15% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at 5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year and mature on September 1, 2014. The 5.15% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc., and they rank equal in right of payment to our existing and future unsecured and unsubordinated indebtedness, although the 5.15% Senior Notes will be effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of the 5.15% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.

Zero Coupon Debentures

We issued our Zero Coupon Debentures on June 6, 2000 at a price of $499.60 per $1,000 principal amount at maturity, which represents a yield to maturity of 3.50% per year. The Zero Coupon Debentures mature on June 6, 2020. We will not pay interest prior to maturity unless we elect to convert the Zero Coupon Debentures to interest-bearing debentures upon the occurrence of certain tax events. The Zero Coupon Debentures are convertible at the option of the holder at any time prior to maturity, unless previously redeemed, into our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. In addition, holders may require us to purchase, for cash, all or a portion of their Zero Coupon Debentures upon a change in control (as defined in the governing indenture) for a purchase price equal to the accreted value through the date of repurchase. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

We also have the right to redeem the Zero Coupon Debentures, in whole or in part, for a price equal to the issuance price plus accrued original issue discount through the date of redemption. Holders have the right to require us to repurchase the Zero Coupon Debentures on June 6, 2010 and June 6, 2015, at the accreted value through the date of repurchase. We may pay any such repurchase price with either cash or shares of our common stock or a combination of cash and shares of common stock.

As of December 31, 2007, the aggregate accreted value of our outstanding Zero Coupon Debentures was $3.9 million, which is classified as long-term debt in our Consolidated Balance Sheets. The aggregate principal amount at maturity of those Zero Coupon Debentures would be $6.0 million assuming no additional conversions or redemptions occur prior to the maturity date.

1.5% Debentures

We pay interest of 1.5% per year on the outstanding principal amount of the 1.5% Debentures, semiannually in arrears on April 15 and October 15 of each year. In addition we will pay contingent interest to holders of our 1.5% Debentures during any six-month period commencing after April 15, 2008, if the average market price of a 1.5% Debenture for a measurement period preceding such six-month period equals 120% or more of the principal amount of such 1.5% Debenture and we pay a regular cash dividend during such six-month period. The contingent interest payable per $1,000 principal amount of 1.5% Debentures, in respect of any quarterly period, will equal 50% of regular cash dividends we pay per share on our common stock during that quarterly period multiplied by the conversion rate. This contingent interest component is an embedded derivative, which had no fair value at issuance or at December 31, 2007 or December 31, 2006.

Holders may require us to purchase all or a portion of their outstanding 1.5% Debentures on April 15, 2008, at a price equal to 100% of the principal amount of the 1.5% Debentures to be purchased plus accrued and unpaid interest. We may choose to pay the purchase price in cash or shares of our common stock or a combination of cash and common stock. In addition, holders may require us to purchase, for cash, all or a portion of their 1.5% Debentures upon a change in control (as defined in the governing indenture) for a purchase price equal to 100% of the principal amount plus accrued and unpaid interest. Additionally, we have the option to redeem all or a portion of the 1.5% Debentures at any time on or after April 15, 2008, at a price equal to 100% of the principal amount plus accrued and unpaid interest. Because the holders of the 1.5% Debentures have the right to require us to repurchase the outstanding debentures on April 15, 2008, the aggregate outstanding principal amount of $3.6 million is presented as “Current portion of long-term debt” in our Consolidated Balance Sheets at December 31, 2007.

As a result of the conversions of our 1.5% Debentures, we reversed a $54.2 million non-current deferred tax liability during 2007 related to interest expense imputed on these debentures for U.S. federal income tax return purposes. See Note 14.

10. Other Comprehensive Income (Loss)

The income tax effects allocated to the components of our other comprehensive income (loss) are as follows:


	Year Ended December 31, 2007
	Before Tax			Tax Effect			Net-of-Tax

				(In thousands)

Unrealized gain (loss) on investments:
Gain arising during 2007	$	289		$	(101	)	$	188
Reclassification adjustment		(434	)		152			(282	)

Net unrealized loss		(145	)		51			(94	)
Pension plan termination		6,963			(2,437	)		4,526

Other comprehensive income	$	6,818		$	(2,386	)	$	4,432


	Year Ended December 31, 2006
	Before Tax			Tax Effect			Net-of-Tax

				(In thousands)

Unrealized gain (loss) on investments:
Gain arising during 2006	$	249		$	(87	)	$	162
Reclassification adjustment		(95	)		33			(62	)

Net unrealized gain		154			(54	)		100

Other comprehensive income before adoption of SFAS 158		154			(54	)		100
Adjustment to initially apply SFAS 158		(6,963	)		2,437			(4,526	)

Other comprehensive (loss)	$	(6,809	)	$	2,383		$	(4,426	)


	Year Ended December 31, 2005
	Before Tax			Tax Effect			Net-of-Tax

				(In thousands)

Reversal of cumulative foreign currency translation loss	$	3,600		$	(1,523	)	$	2,077
Unrealized gain (loss) on investments:
Gain arising during 2005		15			(5	)		10
Reclassification adjustment		(138	)		48			(90	)

Net unrealized loss		(123	)		43			(80	)

Other comprehensive income	$	3,477		$	(1,480	)	$	1,997

The components of our accumulated other comprehensive income (loss) are as follows:


	Foreign Currency			Adjustment to			Unrealized Gain			Total Other
	Translation			Initially Apply			(Loss) on			Comprehensive
	Adjustments			SFAS 158, Net of Tax			Investments			Income (Loss)

Balance at January 1, 2005	$	(2,077	)	$	—		$	89		$	(1,988	)
Other comprehensive gain		2,077			—			(80	)		1,997

Balance at December 31, 2005		—			—			9			9
Other comprehensive loss		—			(4,526	)		100			(4,426	)

Balance at December 31, 2006		—			(4,526	)		109			(4,417	)
Other comprehensive gain		—			4,526			(94	)		4,432

Balance at December 31, 2007	$	—		$	—		$	15		$	15

11. Commitments and Contingencies

Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. In accordance with SFAS No. 5, “Accounting for Contingencies,” we have assessed each claim or exposure to determine the likelihood that the resolution of the matter might ultimately result in an adverse effect on our financial condition, results of operations and cash flows. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a reserve for the estimated loss at the time that both of these criteria are met. Our management believes that we have established adequate reserves for any liabilities that may reasonably be expected to result from these claims.

Litigation.We are a defendant in a lawsuit filed in January 2005 in the U.S. District Court for the Eastern District of Louisiana on behalf of Total E&P USA, Inc. and several oil companies alleging that our semisubmersible rig, theOcean America, damaged a natural gas pipeline in the Gulf of Mexico during Hurricane Ivan. The plaintiffs seek damages from us including, but not limited to, loss of revenue, that are currently estimated to be in excess of $100 million, together with interest, attorneys’ fees and costs. We deny any liability for plaintiffs’ alleged loss and do not believe that ultimate liability, if any, resulting from this litigation will have a material adverse effect on our financial condition, results of operations and cash flows.

We are one of several unrelated defendants in lawsuits filed in the Circuit Courts of the State of Mississippi alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our offshore drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. We expect to receive complete defense and indemnity from Murphy Exploration & Production Company pursuant to the terms of our 1992 asset purchase agreement with them. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that ultimate liability, if any, resulting from this litigation will have a material adverse effect on our financial condition, results of operations and cash flows.

Various other claims have been filed against us in the ordinary course of business. In the opinion of our management, no pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Other.Our operations in Brazil have exposed us to various claims and assessments related to our personnel, customs duties and municipal taxes, among other things, that have arisen in the ordinary course of business. During 2007, we reviewed our estimated reserve for personnel taxes in Brazil based on current facts and circumstances and adjusted our estimated reserve in accordance with SFAS 5. Accordingly, we recorded a $6.5 million reduction in “Contract drilling” expense in our Consolidated Statements of Operations in 2007 as a result of our change in estimate. At December 31, 2007, our loss reserves related to our Brazilian operations aggregated $8.5 million, of which $1.9 million and $6.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. Loss reserves related to our Brazilian operations totaled $14.2 million at December 31, 2006, of which $0.5 million was recorded in “Accrued liabilities” and $13.7 million was recorded in “Other liabilities” in our Consolidated Balance Sheets.

We intend to defend these matters vigorously; however, we cannot predict with certainty the outcome or effect of any litigation matters specifically described above or any other pending litigation or claims. There can be no assurance as to the ultimate outcome of these lawsuits.

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 per occurrence (or $10.0 million if hurricane-related), 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. At December 31, 2007, our estimated liability for personal injury claims was $32.0 million, of which $8.5 million and $23.5 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2006, we had recorded loss reserves for personal injury claims aggregating $35.0 million, of which $9.9 million and $25.1 million were recorded in “Accrued liabilities” and “Other liabilities,”

respectively, in our Consolidated Balance Sheets. 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.

Purchase Obligations.As of December 31, 2007, we had purchase obligations aggregating approximately $200 million related to the major upgrade of theOcean Monarchand construction of two new jack-up rigs, theOcean ScepterandOcean 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 beyond our control.

We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2007 and 2006, except for those related to our direct rig operations, which arise during the normal course of business.

Operating Leases.We lease office facilities and equipment under operating leases, which expire at various times through the year 2010. Total rent expense amounted to $4.6 million, $3.8 million and $3.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. Future minimum rental payments under leases are approximately $4.3 million, $0.9 million, $0.2 million, $0.1 million and $0.1 million for the years ending December 31, 2008, 2009, 2010, 2011 and 2012, respectively. There are no minimum future rental payments under leases after 2012.

Letters of Credit and Other.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.

12. Financial Instruments

Concentrations of Credit and Market Risk

Financial instruments which potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including mortgage-backed securities. We place our excess cash investments in high quality short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.

Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies and government-owned oil companies. We provide allowances for potential credit losses when necessary. No such allowances were deemed necessary for the years presented and, historically, we have not experienced significant losses on our trade receivables.

All of our investments in debt securities are U.S. government securities or U.S. government-backed with minimal credit risk. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.

Fair Values

The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents, marketable securities, accounts receivable, forward exchange contracts and accounts payable approximate fair value. Fair values and related carrying values of our debt instruments are shown below:


	Year Ended December 31,
	2007				2006
	Fair Value		Carrying Value		Fair Value		Carrying Value
			(In millions)

Zero Coupon Debentures	$	7.4	$	3.9	$	5.0	$	5.3
1.5% Debentures		10.3		3.6		749.7		460.0
4.875% Senior Notes		238.6		249.6		234.9		249.5
5.15% Senior Notes		244.0		249.6		242.0		249.5

We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of December 31, 2007 and 2006, respectively. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange. The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it was practicable to estimate that value:

	•		Cash and cash equivalents— The carrying amounts approximate fair value because of the short maturity of these instruments.

	•		Marketable securities— The fair values of the debt securities, including mortgage-backed securities, available for sale were based on the quoted closing market prices on December 31, 2007 and 2006, respectively.

	•		Accounts receivable and accounts payable— The carrying amounts approximate fair value based on the nature of the instruments.

	•		Forward exchange contracts —The fair value of our foreign currency forward exchange contracts is based on the quoted market prices on December 31, 2007 and 2006, respectively.

	•		Long-term debt— The fair value of our 4.875% Senior Notes and 5.15% Senior Notes was based on the quoted closing market price on December 31, 2007 and 2006, respectively, from brokers of these instruments. The fair value of our Zero Coupon Debentures and 1.5% Debentures was based on the closing market price of our common stock on December 31, 2007 and 2006, respectively, and the stated conversion rates for these debentures.

13. Related-Party Transactions

Transactions with Loews.We are party to a services agreement with Loews, or the Services Agreement, pursuant to which Loews performs certain administrative and technical services on our behalf. Such services include personnel, telecommunications, purchasing, internal auditing, accounting, data processing and cash management services, in addition to advice and assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the provision of such services. The Services Agreement may be terminated at our option upon 30 days’ notice to Loews and at the option of Loews upon six months’ notice to us. In addition, we have agreed to indemnify Loews for all claims and damages arising from the provision of services by Loews under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. We were charged $0.4 million, $0.4 million and $0.4 million by Loews for these support functions during the years ended December 31, 2007, 2006 and 2005, respectively.

In addition, during 2007 and 2006 we purchased four performance bonds in support of our drilling operations offshore Mexico and an appeals bond totaling $81.2 million from affiliates of a majority-owned subsidiary of Loews after obtaining competitive quotes. Premiums and fees associated with these bonds totaled $45,000 and $1.0 million in 2007 and 2006, respectively.

Transactions with Other Related Parties.During 2006, we hired marine vessels and helicopter transportation services at the prevailing market rate from subsidiaries of SEACOR Holdings Inc. The Chairman of the Board of Directors, President and Chief Executive Officer of SEACOR Holdings Inc. is also a member of our Board of Directors. For the years ended December 31, 2007 and 2006, we paid $4.6 million and $0.7 million for the hire of such vessels and such services.

During the years ended December 31, 2007, 2006 and 2005 we made payments of $1.1 million, $0.6 million and $1.2 million, respectively, to Ernst & Young LLP for tax and other consulting services. The wife of our President and Chief Operating Officer is an audit partner at this firm.

14. Income Taxes

Our net income tax expense or benefit is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. 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 the 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 taxes. 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 have certain other foreign subsidiaries for which U.S. taxes have been provided to the extent a U.S. tax liability could arise upon remittance of earnings from the foreign subsidiaries. As of December 31, 2007, we provided $0.4 million of U.S. taxes attributable to undistributed earnings of the foreign subsidiaries. On actual remittance, certain countries may impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.

The components of income tax expense (benefit) are as follows:


	Year Ended December 31,
	2007			2006			2005
	(In thousands)

Federal — current	$	338,638		$	230,907		$	28,106
State — current		950			—			—
Foreign — current		58,638			27,968			2,793

Total current		398,226			258,875			30,899


Federal — deferred		7,594			5,006			63,408
Foreign — deferred		(5,824	)		(4,396	)		1,751

Total deferred		1,770			610			65,159


Total	$	399,996		$	259,485		$	96,058

The difference between actual income tax expense and the tax provision computed by applying the statutory federal income tax rate to income before taxes is attributable to the following:


	Year Ended December 31,
	2007			2006			2005
	(In thousands)

Income before income tax expense:
U.S.	$	947,476		$	765,583		$	324,390
Foreign		299,061			200,749			32,005

Worldwide	$	1,246,537		$	966,332		$	356,395


Expected income tax expense at federal statutory rate	$	436,288		$	338,216		$	124,738
Foreign earnings of foreign subsidiaries (not taxed at the statutory federal income tax rate) net of related foreign taxes		(70,800	)		(60,624	)		529
Foreign taxes — domestic companies		22,111			15,200			1,806
Foreign tax credits		(27,238	)		(15,087	)		(1,811	)
$850.0 million distribution from foreign subsidiary		58,562			—			—
Valuation allowance — foreign tax credits		—			(831	)		(9,574	)
Reduction of deferred tax liability related to Arethusa goodwill deduction		(8,850	)		(8,850	)		(8,850	)
Reduction of contingent tax liability related to Arethusa goodwill deduction		—			—			(8,850	)
Domestic production activities deduction		(12,740	)		(8,339	)		—
Uncertain tax positions		4,466			—			—
East Timor — Indonesia tax settlement		—			—			(4,365	)
Revision of estimated tax balance		(130	)		1,039			843
IRS audit adjustments		—			—			1,931
Amortization of deferred tax liability related to transfer of drilling rigs to different taxing jurisdictions		(1,580	)		(1,580	)		(1,763	)
Other		(93	)		341			1,424

Income tax expense	$	399,996		$	259,485		$	96,058

Significant components of our deferred income tax assets and liabilities are as follows:


	December 31,
	2007			2006
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	1,831		$	2,761
Capital loss carryback/carryforward		—			412
Goodwill		10,494			13,643
Worker’s compensation and other current accruals (1)		12,905			14,733
Disputed receivables reserved		4,831			3,603
Deferred compensation		3,730			2,152
Foreign deferred taxes		2,696			—
Nonqualified stock options		1,480			1,044
Other		2,450			1,186

Total deferred tax assets		40,417			39,534
Valuation allowance for foreign tax credits		—			—

Net deferred tax assets		40,417			39,534

Deferred tax liabilities:
Depreciation		(425,488	)		(418,703	)
Contingent interest		(507	)		(53,399	)
Foreign deferred taxes		—			(3,128	)
Other		(3,045	)		(2,925	)

Total deferred tax liabilities		(429,040	)		(478,155	)

Net deferred tax liability	$	(388,623	)	$	(438,621	)


(1)		$9.0 million and $9.6 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance Sheets at December 31, 2007 and 2006, respectively. See Note 6.

We adopted the provisions of 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. A reconciliation of the beginning and ending amount of unrecognized tax benefits including interest and penalties is as follows:


						Net Liability
	Long term Tax		Long term Tax			for Uncertain Tax
	Receivable		Payable			Positions
	(In thousands)
Balance at January 1, 2007	$	2,642	$	(31,064	)	$	(28,422	)
Additions based on tax positions related to the current year		785		(6,908	)		(6,123	)

Balance at December 31, 2007	$	3,427	$	(37,972	)	$	(34,545	)

At December 31, 2007 all $34.5 million of the net unrecognized tax benefits would affect the effective tax rate if recognized.

We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense. During the year ended December 31, 2007, we recognized $1.7 million of interest expense related to uncertain tax positions. Penalty related tax expense for uncertain tax positions during the year ended December 31, 2007 was $0.8 million. At December 31, 2007, we had $14.2 million accrued for the payment of interest and penalties in our Consolidated Balance Sheets.

A reconciliation of the beginning and ending amount of unrecognized tax benefits excluding interest and penalties is as follows:


	Net Liability
	for Uncertain Tax
	Positions
	(In thousands)
Balance at January 1, 2007	$	(16,635	)
Additions based on tax positions related to the current year		(3,694	)

Balance at December 31, 2007	$	(20,329	)

In several of the international locations in which we operate, certain of our wholly owned subsidiaries enter into agreements with other of our wholly owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be charged for providing the services and equipment. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts. Taxing authorities in the various foreign locations in which we operate could apply one of the alternative transfer pricing methodologies that could result in an increase to our income tax liabilities with respect to tax returns that remain subject to examination. During the next twelve months certain income tax returns will no longer be subject to examination due to a lapse in the applicable statute of limitations. As a result, we anticipate that the amount of unrecognized tax benefits attributable to transfer pricing methodology will decrease by approximately $1.4 million through December 31, 2008.

We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions include years 2000 to 2006. We are currently under audit in several of these jurisdictions including an audit by the Internal Revenue Service of years 2004 and 2005.

The Brazilian tax authorities are auditing our income tax returns for the periods 2000 to 2005. We have received an initial audit report for tax year 2000 disallowing various deductions claimed in the tax return. The tax auditors have issued an assessment for tax year 2000 of approximately $1.5 million, including interest and penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal. We do not anticipate that any adjustments resulting from the tax audit will have a material impact on our consolidated results of operations, financial position and cash flows.

During the year ended December 31, 2007, the holders of certain of our debentures elected to convert them into shares of our common stock. (See Note 9.) As a result of the conversions of our 1.5% Debentures, we reversed a non-current deferred tax liability of $54.2 million which was accounted for as an increase to “Additional paid-in capital.” The reversal related to interest expense imputed on these debentures for U.S. federal income tax return purposes.

As of December 31, 2007, we had net operating loss, or NOL, carryforwards of approximately $5.2 million available to offset future taxable income. The NOL carryforwards consist entirely of losses that were acquired in our merger with Arethusa (Off-Shore) Limited, or Arethusa, in 1996. The utilization of the NOL carryforwards acquired in the Arethusa merger is limited pursuant to Section 382 of the Internal Revenue Code of 1986, as amended, or the Code. We expect to fully utilize all of the NOL carryforwards in future tax years. During 2007, we were able to utilize approximately $2.7 million of the NOL carryforwards.

We have recorded a deferred tax asset of $1.8 million for the benefit of the NOL carryforwards. The NOL carryforwards will expire as follows:


			Tax
	Net		Benefit of Net
	Operating		Operating
Year	Losses		Losses
	(In millions)

2009	$	2.8	$	1.0
2010		2.4		0.8

Total	$	5.2	$	1.8

15. Employee Benefit Plans

Defined Contribution Plans

We maintain defined contribution retirement plans for our U.S., U.K. and third-country national, or TCN, employees. The plan for our U.S. employees, or the 401k Plan, is designed to qualify under Section 401(k) of the Code. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. During the year ended December 31, 2007 we contributed 5.00% of a participant’s defined compensation and matched 100% of the first 6% of each employee’s compensation contributed to the 401k Plan. During 2006 and 2005 we contributed 3.75% of a participant’s defined compensation and matched 25% of the first 6% of each employee’s compensation contributed to the 401k Plan. Participants are fully vested immediately upon enrollment in the 401k Plan. For the years ended December 31, 2007, 2006 and 2005, our provision for contributions was $11.2 million, $9.0 million and $7.3 million, respectively.

The defined contribution retirement plan for our U.K. employees, or U.K. Plan, provides that we make annual contributions in an amount equal to the employee’s contributions, generally up to a maximum of 5.25% of the employee’s defined compensation per year for employees working in the U.K. sector of the North Sea and up to a maximum of 9% of the employee’s defined compensation per year for U.K. nationals working in the Norwegian sector of the North Sea. Our provision for contributions was $1.5 million, $1.2 million and $0.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.

The defined contribution retirement plan for our TCN employees, or TCN Plan, is similar to the 401k Plan. During 2007 we contributed 5.00% of a participant’s defined compensation and matched 100% of the first 6% of each employee’s compensation contributed to the TCN Plan. For the years ended December 31, 2006 and 2005 we contributed 3.75% of a participant’s defined compensation and matched 25% of the first 6% of each employee’s compensation contributed to the TCN Plan. Our provision for contributions was $1.2 million, $0.9 million and $0.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Deferred Compensation and Supplemental Executive Retirement Plan

Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly compensated employees to compensate such employees for any portion of our base salary contribution and/or matching contribution under the 401k Plan that could not be contributed to that plan because of limitations within the Code. Prior to January 1, 2007, the Supplemental Plan also allowed participants to defer up to 10% of their base compensation and/or up to 100% of any performance bonus. Participants are fully vested in all amounts paid into the Supplemental Plan. Our provision for contributions to the Supplemental Plan for the years ended December 31, 2007, 2006 and 2005 was approximately $192,000, $65,000 and $77,000, respectively.

Pension Plan

The defined benefit pension plan established by Arethusa effective October 1, 1992 was frozen on April 30, 1996. At that date all participants were deemed fully vested in the plan, which covered substantially all U.S. citizens and U.S. permanent residents who were employed by Arethusa. During the fourth quarter of 2006 we began the process of terminating the plan and transferred all of the assets of the plan to an insurance company along with our additional payment of approximately $0.3 million. In the second quarter of 2007 we obtained Pension Benefit Guarantee Corporation, or PBGC, approval to terminate the plan and we have entered into an irrevocable contract with the insurance company to transfer the responsibility for making payments of plan benefits to the insurance company. Thus, we no longer have any liability for benefits to participants under the plan. As a result of terminating the plan, we recorded a one-time settlement expense of $4.0 million during the year ended December 31, 2007 in “Contract drilling” expense in our Consolidated Statements of Operations.

We have recently been advised by the PBGC that our termination of the Arethusa plan is under audit.

The following provides a reconciliation of benefit obligations, fair value of plan assets and funded status of the plan:


	September 30,
	2007			2006
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	20,115		$	19,467
Interest cost		692			1,054
Settlement		(21,806	)		—
Actuarial loss		1,173			275
Benefits paid		(174	)		(681	)

Benefit obligation at end of year	$	—		$	20,115


Change in plan assets:
Fair value of plan assets at beginning of year	$	20,886		$	19,770
Actual return on plan assets		799			1,797
Settlement		(21,806	)		—
Contributions		295			—
Benefits paid		(174	)		(681	)

Fair value of plan assets at end of year	$	—		$	20,886

Funded status of plan	$	—		$	771

Components of net periodic benefit costs were as follows:


	September 30,
	2007			2006			2005
	(In thousands)
Interest cost	$	692		$	1,054		$	1,040
Expected return on plan assets		(625	)		(1,362	)		(1,222	)
Amortization of unrecognized loss		171			303			306
Settlement		3,997			—			—

Net periodic pension benefit (income) loss	$	4,235		$	(5	)	$	124

As a result of freezing the plan in 1996, no service cost has been accrued for the years presented.

Other changes in plan assets and benefit obligation recognized in other comprehensive income were as follows:


	September 30,
	2007			2006		2005
	(In thousands)
Net actuarial loss	$	999		$	—	$	—
Amortization of loss		(7,962	)		—		—

Total recognized in other comprehensive income	$	(6,963	)	$	—	$	—

Total recognized in net benefit cost and other comprehensive income	$	(2,728	)	$	—	$	—

16. Hurricane Damage

2005 Storms

In the third quarter of 2005, two major hurricanes, Katrina and Rita, struck the U.S. Gulf Coast and Gulf of Mexico. One of our jack-up drilling rigs, theOcean Warwick, was seriously damaged during Hurricane Katrina and other rigs in our fleet, as well as our warehouse in New Iberia, Louisiana, sustained lesser damage in Hurricane Katrina or Rita, or both storms. The physical damage to our rigs, as well as related removal and recovery costs, has been primarily covered by insurance, after applicable deductibles. At December 31, 2007, we had filed most of our expected insurance claims related to the 2005 storms and had received insurance proceeds pursuant to these claims, although certain claims are still under review by our underwriters or yet to be filed pending completion of permanent repairs.

Ocean Warwick —TheOcean Warwick, with a net book value of $14.0 million, was declared a constructive total loss effective August 29, 2005. We issued a proof of loss in the amount of $50.5 million to our insurers, representing the insured value of the rig less a $4.5 million deductible. The recovery and removal of theOcean Warwickwas subject to a separate deductible, which we estimated to be $2.5 million at the time of loss.

Our insurance claim relating to the loss of theOcean Warwickwas settled in the third quarter of 2005. As a result, we recorded a net $33.6 million casualty gain, representing net insurance proceeds received of $50.5 million, less the write-off of the $14.0 million net carrying value of the drilling rig and $0.4 million in rig-based spare parts and supplies, and an estimated insurance deductible of $2.5 million for salvage and wreck removal. We have presented this as “Casualty Gain onOcean Warwick” in our Consolidated Statements of Operations for the year ended December 31, 2005.

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

Other Rigs and Facilities— Damages to our other affected rigs and warehouse were less severe. At the time of loss, we estimated insurance deductibles related to the remaining rigs damaged during Hurricane Katrina and our rigs and facility damaged by Hurricane Rita to total $2.6 million in the aggregate, of which $1.2 million and $1.4 million were recorded as additional contract drilling expense and loss on disposition of assets, respectively, for the year ended December 31, 2005 in our Consolidated Statements of Operations. Subsequently, we revised our estimate of the applicable insurance deductibles related to these damages and recorded a $0.4 million gain on disposition of assets in our Consolidated Statements of Operations for the year ended December 31, 2006.

During 2007, we received insurance proceeds, net of deductibles, aggregating $56.1 million related to property damage and salvage/wreck removal claims filed as a result of these hurricanes and recognized insurance gains of $4.9 million resulting from the involuntary conversion of assets lost during the hurricanes. We have recorded these insurance gains as “Gain on disposition of assets” in our Consolidated Statements of Operations for the year ended December 31, 2007. We accounted for the remaining portion of the insurance proceeds as a reduction in an insurance receivable for hurricane-related repair costs.

In addition, during 2007 and 2006, we collected $4.2 million and $3.1 million, respectively, from certain of our customers primarily related to the replacement or repair of equipment damage during the 2005 hurricanes. For the

year ended December 31, 2007, we recorded the $4.2 million recovery as other income in our Consolidated Statements of Operations. We recorded $0.3 million of the 2006 recovery as a credit to contract drilling expense, $1.1 million as a gain on disposition of assets and the remaining $1.7 million as other income in our Consolidated Statements of Operations for the year ended December 31, 2006.

2004 Storm

During the fourth quarter of 2005 we recovered $14.5 million, net of deductibles previously recorded, from our insurers relating to damages to several of our rigs as a result of Hurricane Ivan in 2004. We recognized an insurance gain of $5.6 million as “Gain on disposition of assets” in our Consolidated Statements of Operations for the year ended December 31, 2005, resulting from the involuntary conversion of assets lost during the hurricane in 2004. We accounted for the remaining portion of the insurance proceeds as a reduction in an insurance receivable for hurricane-related repair costs.

In addition, in the fourth quarter of 2005 we received $2.4 million from a customer related to equipment damaged on one of our high-specification rigs during Hurricane Ivan. We recorded $2.0 million of this recovery as a credit to contract drilling expense and $0.4 million as a gain on disposition of assets.

17. Segments and Geographic Area Analysis

Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics among all divisions and locations, including the nature of services provided and the type of customers of such services, in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

Revenues from contract drilling services by equipment-type are listed below:


	Year Ended December 31,
	2007		2006		2005
	(In thousands)

High-Specification Floaters	$	1,030,892	$	766,873	$	448,937
Intermediate Semisubmersibles		1,028,667		785,047		456,734
Jack-ups		446,104		435,194		271,809
Other		—		—		1,535

Total contract drilling revenues		2,505,663		1,987,114		1,179,015
Revenues related to reimbursable expenses		62,060		65,458		41,987

Total revenues	$	2,567,723	$	2,052,572	$	1,221,002

Geographic Areas

At December 31, 2007, our drilling rigs were located offshore twelve countries in addition to the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in foreign operations and our results of operations and the value of our foreign assets are affected by fluctuations in foreign currency exchange rates. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.


	Year Ended December 31,
	2007		2006		2005
	(In thousands)
United States	$	1,288,535	$	1,179,676	$	668,423

Foreign:
Europe/Africa		473,665		250,103		106,188
Australia/Asia/Middle East		400,701		323,003		231,273
South America		256,236		203,338		129,524
Mexico		148,586		96,452		85,594

		1,279,188		872,896		552,579


Total revenues	$	2,567,723	$	2,052,572	$	1,221,002

An individual foreign country may, from time to time, comprise a material percentage of our total contract drilling revenues from unaffiliated customers. For the years ended December 31, 2007, 2006 and 2005, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.


	Year Ended December 31,
	2007			2006			2005

United Kingdom		9.6	%		7.5	%		6.3	%
Brazil		9.1	%		9.9	%		10.6	%
Mexico		5.8	%		4.7	%		7.0	%
Egypt		5.4	%		0.8	%		—

The following table presents our long-lived tangible assets by geographic location as of December 31, 2007 and 2006. A substantial portion of our assets are mobile, therefore asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods.


	December 31,
	2007		2006
	(In thousands)
Drilling and other property and equipment, net:
United States	$	1,605,961	$	1,335,329

Foreign:
Australia/Asia/Middle East		683,307		728,383
South America		440,208		269,821
Europe/Africa		206,834		183,242
Mexico		103,753		111,678

		1,434,102		1,293,124


Total	$	3,040,063	$	2,628,453

Besides the United States, Brazil and Singapore are currently the only countries with a material concentration of our assets. Approximately 12.6% and 11.4% of our drilling and other property and equipment were located offshore

Brazil and Singapore, respectively, as of December 31, 2007. Approximately 10.3% and 14.8% of our drilling and other property and equipment were located offshore Brazil and Singapore, respectively, as of December 31, 2006.

Major Customers

Our customer base includes major and independent oil and gas companies and government-owned oil companies. No one customer accounted for 10% or more of our total revenues for the year ended December 31, 2007. Revenues from our major customers for the years ended December 31, 2006 and 2005 that contributed more than 10% of our total revenues are as follows:


	Year Ended December 31,
Customer	2007			2006			2005

Anadarko Petroleum		9.4	%		10.6	%		—
Petróleo Brasileiro S.A.		9.2	%		10.4	%		10.7	%
Kerr-McGee Oil & Gas Corporation (acquired by Anadarko Petroleum in 2006)		—			—			10.3	%

18. Unaudited Quarterly Financial Data

Unaudited summarized financial data by quarter for the years ended December 31, 2007 and 2006 is shown below.


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(In thousands, except per share data)

2007
Revenues	$	608,184	$	648,875	$	643,962	$	666,702
Operating income		311,942		347,617		277,971		285,992
Income before income tax expense		310,270		352,453		288,247		295,567
Net income		224,150		251,927		205,523		164,941
Net income per share:
Basic	$	1.66	$	1.82	$	1.48	$	1.19
Diluted	$	1.64	$	1.81	$	1.48	$	1.19

2006
Revenues	$	447,730	$	512,188	$	514,456	$	578,198
Operating income		202,943		238,095		216,147		283,247
Income before income tax expense		206,691		242,167		223,047		294,427
Net income		145,321		175,721		164,450		221,355
Net income per share:
Basic	$	1.13	$	1.36	$	1.27	$	1.71
Diluted	$	1.06	$	1.27	$	1.19	$	1.60

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Not applicable.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures which are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.

Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2007. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2007.

Internal Control Over Financial Reporting

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Diamond Offshore Drilling, Inc. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.

There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework. Based on management’s assessment our management believes that, as of December 31, 2007, our internal control over financial reporting was effective based on those criteria.

Deloitte & Touche LLP, the registered public accounting firm that audited our financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of our internal control over financial reporting. The attestation report of Deloitte & Touche LLP is included at the beginning of Item 8 of this Form 10-K.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our fourth fiscal quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

Not applicable.

PART III

Reference is made to the information responsive to Items 10, 11, 12, 13 and 14 of this Part III contained in our definitive proxy statement for our 2008 Annual Meeting of Stockholders, which is incorporated herein by reference.

Item 10. Directors, Executive Officers and Corporate Governance.

Item 11. Executive Compensation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Item 14. Principal Accountant Fees and Services.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) Index to Financial Statements, Financial Statement Schedules and Exhibits

(1) Financial Statements


	Page

Report of Independent Registered Public Accounting Firm		54
Consolidated Balance Sheets		56
Consolidated Statements of Operations		57
Consolidated Statements of Stockholders’ Equity		58
Consolidated Statements of Comprehensive Income		59
Consolidated Statements of Cash Flows		60
Notes to Consolidated Financial Statements		61

(2) Financial Statement Schedules

No schedules have been included herein because the information required to be submitted has been included in our Consolidated Financial Statements or the notes thereto or the required information is not applicable.


(3) Index of Exhibits			90

See the Index of Exhibits for a list of those exhibits filed herewith, which index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 of Regulation S-K.


Exhibit No.		Description

3.1		Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003).

3.2		Amended and Restated By-laws (as amended through October 22, 2007) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 26, 2007).

4.1		Indenture, dated as of February 4, 1997, between Diamond Offshore Drilling, Inc. and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

4.2		Second Supplemental Indenture, dated as of June 6, 2000, between Diamond Offshore Drilling, Inc. and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.2 to our Quarterly Report on Form 10-Q/A for the quarterly period ended June 30, 2000) (SEC File No. 1-13926).

4.3		Third Supplemental Indenture, dated as of April 11, 2001, between Diamond Offshore Drilling, Inc. and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.2 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2001) (SEC File No. 1-13926).

4.4		Fourth Supplemental Indenture, dated as of August 27, 2004, between Diamond Offshore Drilling, Inc. and JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed September 1, 2004).

4.5		Fifth Supplemental Indenture, dated as of June 14, 2005, between Diamond Offshore Drilling, Inc. and JPMorgan Chase Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed June 16, 2005).

10.1		Registration Rights Agreement (the “Registration Rights Agreement”) dated October 16, 1995 between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

10.2		Amendment to the Registration Rights Agreement, dated September 16, 1997, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).

10.3		Services Agreement, dated October 16, 1995, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.3 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

10.4+		Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan effective as of January 1, 2007 (incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.5+		Diamond Offshore Management Bonus Program, as amended and restated, and dated as of December 31, 1997 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).

10.6*+		Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan, as amended.

10.7+		Form of Stock Option Certificate for grants to executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed October 1, 2004).

10.8+		Form of Stock Option Certificate for grants to non-employee directors pursuant to the Second Amended


Exhibit No.		Description

		and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 1, 2004).

10.9+		Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (as amended and restated effective January 1, 2007) (incorporated by reference to Exhibit A attached to our definitive proxy statement on Schedule 14A filed on April 3, 2007).

10.10+		Form of Award Certificate for stock appreciation right grants to the Company’s executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed April 28, 2006).

10.11+		Form of Award Certificate for stock appreciation right grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007).

10.12		5-Year Revolving Credit Agreement, dated as of November 2, 2006, among Diamond Offshore Drilling, Inc., JPMorgan Chase Bank, N.A., as administrative agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd. Houston Agency, Fortis Capital Corp., HSBC Bank USA, National Association, Wells Fargo Bank, N.A. and Bayerische Hypo-Und Vereinsbank AG, Munich Branch, as co-syndication agents, and the lenders named therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 3, 2006).

10.13+		Employment Agreement between Diamond Offshore Management Company and Lawrence R. Dickerson dated as of December 15, 2006 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed December 21, 2006).

10.14+		Employment Agreement between Diamond Offshore Management Company and Gary T. Krenek dated as of December 15, 2006 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed December 21, 2006).

10.15+		Employment Agreement between Diamond Offshore Management Company and John L. Gabriel dated as of December 15, 2006 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed December 21, 2006).

10.16+		Employment Agreement between Diamond Offshore Management Company and John M. Vecchio dated as of December 15, 2006 (incorporated by reference to Exhibit 10.15 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.17+		Employment Agreement between Diamond Offshore Management Company and William C. Long dated as of December 15, 2006 (incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.18+		Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew dated as of December 15, 2006 (incorporated by reference to Exhibit 10.17 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.19+		Employment Agreement between Diamond Offshore Management Company and Mark F. Baudoin dated as of December 15, 2006 (incorporated by reference to Exhibit 10.18 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.20+		Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon dated as of January 3, 2007 (incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.21*+		Summary Sheet of Base Salary Increases Effective October 1, 2007 for Certain Named Executive Officers.


Exhibit No.		Description

12.1*		Statement re Computation of Ratios.

21.1*		List of Subsidiaries of Diamond Offshore Drilling, Inc.

23.1*		Consent of Deloitte & Touche LLP.

24.1*		Powers of Attorney.

31.1*		Rule 13a-14(a) Certification of the Chief Executive Officer.

31.2*		Rule 13a-14(a) Certification of the Chief Financial Officer.

32.1*		Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.


*		Filed or furnished herewith.

+		Management contracts or compensatory plans or arrangements.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 25, 2008.


	DIAMOND OFFSHORE DRILLING, INC.
	By:	/s/ GARY T. KRENEK
		Gary T. Krenek
		Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ JAMES S. TISCH* James S. Tisch	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	February 25, 2008

/s/ LAWRENCE R. DICKERSON* Lawrence R. Dickerson	President, Chief Operating Officer and Director	February 25, 2008

/s/ GARY T. KRENEK* Gary T. Krenek	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 25, 2008

/s/ BETH G. GORDON* Beth G. Gordon	Controller (Principal Accounting Officer)	February 25, 2008

/s/ ALAN R. BATKIN* Alan R. Batkin	Director	February 25, 2008

/s/ JOHN R. BOLTON* John R. Bolton	Director	February 25, 2008

/s/ CHARLES L. FABRIKANT* Charles L. Fabrikant	Director	February 25, 2008

/s/ PAUL G. GAFFNEY II* Paul G. Gaffney II	Director	February 25, 2008

/s/ HERBERT C. HOFMANN* Herbert C. Hofmann	Director	February 25, 2008

/s/ ARTHUR L. REBELL* Arthur L. Rebell	Director	February 25, 2008

/s/ RAYMOND S. TROUBH* Raymond S. Troubh	Director	February 25, 2008



*By:	/s/ WILLIAM C. LONG
	William C. Long
	Attorney-in-fact

EXHIBIT INDEX


Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003).

3.2		Amended and Restated By-laws (as amended through October 22, 2007) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 26, 2007).

4.1		Indenture, dated as of February 4, 1997, between Diamond Offshore Drilling, Inc. and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

4.2		Second Supplemental Indenture, dated as of June 6, 2000, between Diamond Offshore Drilling, Inc. and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.2 to our Quarterly Report on Form 10-Q/A for the quarterly period ended June 30, 2000) (SEC File No. 1-13926).

4.3		Third Supplemental Indenture, dated as of April 11, 2001, between Diamond Offshore Drilling, Inc. and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4.2 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2001) (SEC File No. 1-13926).

4.4		Fourth Supplemental Indenture, dated as of August 27, 2004, between Diamond Offshore Drilling, Inc. and JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed September 1, 2004).

4.5		Fifth Supplemental Indenture, dated as of June 14, 2005, between Diamond Offshore Drilling, Inc. and JPMorgan Chase Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed June 16, 2005).

10.1		Registration Rights Agreement (the “Registration Rights Agreement”) dated October 16, 1995 between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

10.2		Amendment to the Registration Rights Agreement, dated September 16, 1997, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).

10.3		Services Agreement, dated October 16, 1995, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.3 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

10.4+		Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan effective as of January 1, 2007 (incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.5+		Diamond Offshore Management Bonus Program, as amended and restated, and dated as of December 31, 1997 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).

10.6*+		Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan, as amended.

10.7+		Form of Stock Option Certificate for grants to executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed October 1, 2004).

10.8+		Form of Stock Option Certificate for grants to non-employee directors pursuant to the Second Amended


Exhibit No.		Description
		and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 1, 2004).

10.9+		Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (as amended and restated effective January 1, 2007) (incorporated by reference to Exhibit A attached to our definitive proxy statement on Schedule 14A filed on April 3, 2007).

10.10+		Form of Award Certificate for stock appreciation right grants to the Company’s executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed April 28, 2006).

10.11+		Form of Award Certificate for stock appreciation right grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007).

10.12		5-Year Revolving Credit Agreement, dated as of November 2, 2006, among Diamond Offshore Drilling, Inc., JPMorgan Chase Bank, N.A., as administrative agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd. Houston Agency, Fortis Capital Corp., HSBC Bank USA, National Association, Wells Fargo Bank, N.A. and Bayerische Hypo-Und Vereinsbank AG, Munich Branch, as co-syndication agents, and the lenders named therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 3, 2006).

10.13+		Employment Agreement between Diamond Offshore Management Company and Lawrence R. Dickerson dated as of December 15, 2006 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed December 21, 2006).

10.14+		Employment Agreement between Diamond Offshore Management Company and Gary T. Krenek dated as of December 15, 2006 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed December 21, 2006).

10.15+		Employment Agreement between Diamond Offshore Management Company and John L. Gabriel dated as of December 15, 2006 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed December 21, 2006).

10.16+		Employment Agreement between Diamond Offshore Management Company and John M. Vecchio dated as of December 15, 2006 (incorporated by reference to Exhibit 10.15 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.17+		Employment Agreement between Diamond Offshore Management Company and William C. Long dated as of December 15, 2006 (incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.18+		Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew dated as of December 15, 2006 (incorporated by reference to Exhibit 10.17 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.19+		Employment Agreement between Diamond Offshore Management Company and Mark F. Baudoin dated as of December 15, 2006 (incorporated by reference to Exhibit 10.18 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).

10.20+		Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon dated as of January 3, 2007 (incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).


Exhibit No.		Description
10.21*+		Summary Sheet of Base Salary Increases Effective October 1, 2007 for Certain Named Executive Officers.

12.1*		Statement re Computation of Ratios.

21.1*		List of Subsidiaries of Diamond Offshore Drilling, Inc.

23.1*		Consent of Deloitte & Touche LLP.

24.1*		Powers of Attorney.

31.1*		Rule 13a-14(a) Certification of the Chief Executive Officer.

31.2*		Rule 13a-14(a) Certification of the Chief Financial Officer.

32.1*		Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.


*		Filed or furnished herewith.

+		Management contracts or compensatory plans or arrangements.

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Diamond Offshore Drilling (DODRW) 10-K2007 FY Annual report

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