Diamond Offshore Drilling (DODRW) 10-K 2008 FY 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, 2008

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from                    to                    

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.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 filerþ  Accelerated filero  Non-accelerated filer  o
(Do not check if a smaller reporting company) Smaller reporting companyo 

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

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

As of June 30, 2008 $9,584,683,667

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, 2009 Common Stock, $0.01 par value per share 139,001,050 shares

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the definitive proxy statement relating to the 2009 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2008, are incorporated by reference in Part III of this report.

DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2008

TABLE OF CONTENTS

	Page No.
Cover Page		1
Document Table of Contents		2
Part I
Item 1.Business		3
Item 1A.Risk Factors		8
Item 1B.Unresolved Staff Comments		15
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		50
Item 8.Financial Statements and Supplementary Data		53
Consolidated Financial Statements		55
Notes to Consolidated Financial Statements		60
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		85
Item 9A.Controls and Procedures		85
Item 9B.Other Information		86
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		86
Signatures		88
Exhibit Index		89
EX-12.1
EX-21.1
EX-23.1
EX-24.1
EX-31.1
EX-31.2
EX-32.1

2

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 45 offshore rigs consisting of 30 semisubmersibles, 14 jack-ups and one drillship. 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 11 high-specification and 19 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 26, 2009, nine of our 11 high-specification semisubmersibles, including the recently upgradedOcean Monarch, were located in the U.S. Gulf of Mexico, or GOM, while the remaining two rigs were located offshore Brazil and Malaysia. See “ —Fleet Enhancements and Additions.”

     Our intermediate semisubmersibles generally work in maximum water depths up to 4,000 feet. As of January 26, 2009, we had 19 intermediate semisubmersible rigs drilling offshore or undergoing contract preparation activities in various locations around the world. Six of these semisubmersibles were located offshore Brazil; four were located in the North Sea; three were located offshore Australia; two each were located in the GOM and offshore Mexico; and one was located each of offshore Libya and Vietnam.

     Drillship. We have one high-specification drillship, theOcean Clipper,which was located offshore Brazil as of January 26, 2009. 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 have 14 jack-up drilling rigs, excluding theOcean Tower, which is currently presented in “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2008 included in Item 8 of this report. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview —Casualty Loss” in Item 7 of this report. 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.

3

     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, which do not have this capability.

     As of January 26, 2009, six of our 14 jack-up rigs were located in the GOM. Three of those rigs are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Of our eight remaining jack-up rigs, all of which are independent-leg cantilevered units, two each were located offshore Egypt and Mexico, and one was located offshore each of Singapore, Croatia, Australia and Argentina.

     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 14 (11 of which are high-specification units), primarily by upgrading our existing fleet. Seven of these upgrades were to our Victory-class semisubmersible rigs, the design of which is well-suited for significant upgrade projects. 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.

     By the end of 2008, we had completed our most recent fleet enhancement and additions program, which included the upgrade of two of our Victory-class semisubmersibles, theOcean Endeavor (completed in March 2007) and theOcean Monarch(completed in December 2008), to 10,000 foot water depth capability and the construction of two high-performance, premium jack-up rigs, theOcean Shield(completed in May 2008) and theOcean Scepter(completed in August 2008).

     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.

4

     More detailed information concerning our fleet of mobile offshore drilling rigs, as of January 26, 2009, 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 (11):
Ocean Confidence		10,000	DP; 15K; 4M	2001/2008	GOM	Murphy Exploration
Ocean Monarch		10,000	VC; 15K; 4M	1974/2008	GOM	Commissioning and contract preparation: Plains Exploration
Ocean Endeavor		10,000	VC; 15K; 4M	1975/2007	GOM	Devon
Ocean Rover		8,000	VC; 15K; 4M	1973/2008	Malaysia	Murphy Exploration
Ocean Baroness		7,000	VC; 15K; 4M	1973/2002	GOM	Devon
Ocean Victory		6,000	VC; 15K; 3M	1972/2006	GOM	Noble Energy
Ocean America		5,500	SP; 15K; 3M	1988/1999	GOM	Mariner Energy
Ocean Valiant		5,500	SP; 15K; 3M	1988/1999	GOM	Anadarko
Ocean Star		5,500	VC; 15K; 3M	1974/1999	GOM	Newfield Exploration
Ocean Alliance		5,000	DP; 15K; 3M	1988/1999	Brazil	Petrobras
Ocean Quest		4,000	VC; 15K; 3M	1973/1996	GOM	ATP Oil & Gas
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		4,000	3M	1982/2008	Brazil	Shipyard: acceptance testing - Petrobras
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	Shell Australia
Ocean Epoch		3,000	3M	1977/2000	Australia	Shell Australia
Ocean General		3,000	3M	1976/2000	Vietnam	Vietsovpetro
Ocean Yorktown		2,200	3M	1976/1996	Brazil	Petrobras
Ocean Concord		2,200	3M	1975/1999	Brazil	Shipyard: Survey
Ocean Lexington		2,200	3M	1976/1995	Libya	Total
Ocean Saratoga		2,200	3M	1976/1995	GOM	Walter Oil & Gas
Ocean Bounty		1,500	VC; 3M	1977/1992	Australia	Woodside Energy
Ocean Guardian		1,500	15K; 3M	1985	North Sea	Oilexco(e)
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	Shipyard: contract modifications-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	GOM	Taylor Energy
Jack-ups (14):
Ocean Scepter		350	IC; 15K; 3M	2008	Argentina	Enap Sipetrol /YPF
Ocean Shield		350	IC; 15K; 3M	2008	Australia	Eni
Ocean Titan		350	IC; 15K; 3M	1974/2004	GOM	Apache
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	Actively Marketing
Ocean Heritage		300	IC	1981/2002	Egypt	IPR
Ocean Spartan		300	IC	1980/2003	GOM	Samson Offshore
Ocean Spur		300	IC	1981/2003	Egypt	WEPCO
Ocean Sovereign		300	IC	1981/2003	Singapore	Shipyard: Survey
Ocean Champion		250	MS	1975/2004	GOM	Stone Energy
Ocean Columbia		250	IC	1978/1990	Mexico	PEMEX
Ocean Crusader		200	MC	1982/1992	GOM	Ready stacked; waiting on customer
Ocean Drake		200	MC	1983/1986	GOM	Tarpon

Attributes

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

See the footnotes to this table on the following page.

5

(a)	Nominal water depth (in feet), as described above for semisubmersibles and drillships, reflects the current operating water depth capability for each drilling unit. In many cases, individual rigs are capable of drilling, or have drilled in, 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 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.
(e)	The Ocean Guardian is contracted to Oilexco, a U.K. customer that has entered into administration under U.K. law, through September 2011. As of January 26, 2009, the rig was stacked in Invergordon, Scotland and was not earning revenue.

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 and Argentina;

• 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 18 “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 other international areas in which we operate, 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 most 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 or to preserve dayrates and utilization during periods of decreasing dayrates”and “Risk Factors —Our business involves

6

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 2008, we performed services for 49 different customers with Petróleo Brasileiro S.A., or Petrobras, accounting for 13.1% of our annual total consolidated revenues. 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 Petrobras accounting for 10.6% and 10.4% 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, Australia. We provide technical and administrative support functions from our Houston office.

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. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. Some of our competitors may have greater financial or other resources than we do. We compete with offshore drilling contractors that together have more than 600 mobile rigs available worldwide.

     The offshore contract drilling industry 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. Mergers among oil and natural gas exploration and production companies have reduced the number of available customers.

     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. Customers may also consider rig availability and location, a drilling contractor’s operational and safety performance record, and condition and suitability of equipment. We believe we compete favorably with respect to these factors.

     We compete on a worldwide basis, but competition may vary significantly by region at any particular time. See “—Markets.” Competition for offshore rigs generally takes place on a global basis, as these rigs are highly mobile and may be moved, at a cost that may be substantial, from one region to another. 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. Significant new rig construction and upgrades of existing drilling units could also intensify price competition. 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.

7

Operations Outside the United States

     Our operations outside the United States accounted for approximately 59%, 50% and 43% of our total consolidated revenues for the years ended December 31, 2008, 2007 and 2006, 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, 2008, we had approximately 5,700 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 or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since our customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to 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;

8

• 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.

The current global financial and credit crisis may have a negative impact on our business and financial condition.

     The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The continued shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. Such deterioration of the worldwide economy has resulted in reduced demand for crude oil and natural gas, exploration and production activity and offshore drilling services that could lead to declining dayrates earned by our drilling rigs and a decrease in new contract activity.

     In addition, the current credit crisis and recession has had and could continue to have an impact on our customers and/or our suppliers including, among other things, causing them to fail to meet their obligations to us. Similarly, the current credit crisis could affect lenders participating in our credit facility, making them unable to fulfill their commitments and obligations to us. The current credit crisis could also limit our ability to secure additional financing, if needed, due to difficulties accessing the capital markets, which could limit our ability to react to changing business and economic conditions. Any such reductions in drilling activity or failure by our customers, suppliers or lenders to meet their contractual obligations to us, or our inability to secure additional financing, could adversely affect our financial position, results of operations and cash flows.

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. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. 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, as well as the contraction of the global economy, have reduced the number of available customers, increasing competition.

     Our industry has historically been cyclical. There have been periods of high demand, short rig supply and high dayrates, followed by periods of lower demand, excess rig supply and low dayrates. We cannot predict the timing or duration of such business cycles. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. In response to a contraction in demand for our drilling services, we may be required to idle rigs or to enter into lower rate contracts. 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.

     Significant new rig construction and upgrades of existing drilling units could also intensify price competition. As of the date of this report, based on an analyst report, we believe that there are approximately 170 jack-up rigs and floaters (semisubmersible rigs and drillships) on order and scheduled for delivery between 2009 and 2012. Periods of improving dayrates and expectations of sustained improvements in rig utilization rates and dayrates may also lead drilling contractors to contract for the construction of additional new rigs. 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.

9

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 $10.3 billion for contracted future work extending, in some cases, until 2016. Generally, contract backlog only includes future earnings under firm commitments; however, from time to time, we may report 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 in cases where one does not currently exist. In addition, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability to fulfill their contractual commitments to us 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.

We rely heavily on a relatively small number of customers and the loss of a significant customer and/or a dispute that leads to the loss of a 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 2008, our five largest customers in the aggregate accounted for approximately 40% of our consolidated revenues. We expect Petrobras, who accounted for approximately 13% of our consolidated revenues in 2008, to continue to be a significant customer in 2009. 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 or to preserve dayrates and utilization during periods of decreasing dayrates.

     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, but often at flat or slightly lower dayrates, 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.

     To the extent possible within the scope of our customers’ requirements, we seek to have a foundation of 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 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.

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

10

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.

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 May 1, 2009 is limited to $125.0 million. If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment, 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;

• fluctuations in currency exchange rates;

• regulatory or financial requirements to comply with foreign bureaucratic actions;

11

• 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.

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

     We currently operate, and expect to continue to operate, our drilling rigs 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 30 days notice, contractually or by statute, subject to certain conditions. While we believe that the financial terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have a negative impact on our future operations or financial results.

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

     Due to our international operations, we have experienced currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not effectively 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, or DOIL, 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, DOIL 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. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest the future earnings of DOIL to finance foreign activities, except for the earnings of Diamond East Asia Limited, a wholly-owned subsidiary of DOIL formed in December 2008. It is our intention to repatriate the earnings of Diamond East Asia Limited, and U.S. income taxes will be provided on such earnings. We do not expect to provide for U.S. taxes on any future earnings generated by DOIL, except to the extent that these earnings are immediately subjected to U.S. federal income tax or as they relate to Diamond East Asia Limited. 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.

12

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.

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.

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.

13

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

     In the United States and in many of the international locations in which we operate, 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.

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 upward pressure on salaries and wages and increased competition for skilled workers during periods of strengthening offshore drilling markets and have also sustained the loss of experienced personnel to our competitors and our customers. In response to these market conditions we may implement 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.

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. 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

14

terminated under these circumstances, we may not be able to secure a replacement contract with equally favorable terms. See “Business — The Fleet — Fleet Enhancements and Additions” in Item 1 of this report.

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 50.4% of our outstanding shares of common stock as of February 20, 2009 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 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 who 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, Singapore, Egypt, Argentina, Vietnam, Libya 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.

15

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, 2009		Position
Lawrence R. Dickerson		56	President, Chief Executive Officer and Director
Gary T. Krenek		50	Senior Vice President and Chief Financial Officer
William C. Long		42	Senior Vice President, General Counsel & Secretary
Beth G. Gordon		53	Controller — Chief Accounting Officer
Mark F. Baudoin		56	Senior Vice President — Administration
Lyndol L. Dew		54	Senior Vice President — Worldwide Operations
John L. Gabriel, Jr.		55	Senior Vice President — Contracts & Marketing
John M. Vecchio		58	Senior Vice President — Technical Services

     Lawrence R. Dickersonhas served as our President and a Director since March 1998 and as our Chief Executive Officer since June 2008. Mr. Dickerson served as our Chief Operating Officer from March 1998 to June 2008. 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 from February 2002 to January 2003.

     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.

16

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
2008
First Quarter	$	140.07	$	106.91
Second Quarter		145.68		117.70
Third Quarter		139.70		98.63
Fourth Quarter		100.35		55.45
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

     As of February 20, 2009 there were approximately 220 holders of record of our common stock. This number represents registered shareholders and does not include shareholders who hold their shares institutionally.

Dividend Policy

     In 2008, we paid regular cash dividends of $0.125 per share of our common stock on March 3, June 2, September 1 and December 1. We also paid special cash dividends of $1.25 per share of our common stock on March 3, June 2 and September 1 and $1.875 per share of our common stock on December 1. In 2007, we paid regular 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.

     On February 5, 2009, we declared a regular cash dividend and a special cash dividend of $0.125 and $1.875, respectively, per share of our common stock. Both the regular and special cash dividends are payable on March 2, 2009 to stockholders of record on February 13, 2009.

     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. Any future determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other relevant factors at that time.

17

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, 2008.

Comparison of 2004 — 2008 Cumulative Total Return (1)

	Dec. 31,		Dec. 31,		Dec. 31,		Dec. 31,		Dec. 31,		Dec. 31,
	2003		2004		2005		2006		2007		2008
Diamond Offshore		100		197		345		407		772		339
S&P 500		100		111		116		135		142		90
Peer Group (2)		100		129		191		206		318		125

(1)	Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2003 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.
	Dividend History for the periods reported above:

	Q1				Q2				Q3				Q4
Year	Regular		Special		Regular		Special		Regular		Special		Regular		Special
2008	$	0.125	$	1.25	$	0.125	$	1.25	$	0.125	$	1.25	$	0.125	$	1.88
2007	$	0.125	$	4.00	$	0.125		—	$	0.125		—	$	0.125	$	1.25
2006	$	0.125	$	1.50	$	0.125		—	$	0.125		—	$	0.125		—
2005	$	0.063		—	$	0.063		—	$	0.125		—	$	0.125		—
2004	$	0.063		—	$	0.063		—	$	0.063		—	$	0.063		—

(2) The peer group is comprised of the following companies: ENSCO International Incorporated, 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.

18

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. 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,
	2008		2007		2006		2005		2004
	(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues	$	3,544,057	$	2,567,723	$	2,052,572	$	1,221,002	$	814,662
Operating income		1,910,761		1,223,522		940,432		374,399		3,928
Net income (loss)		1,311,020		846,541		706,847		260,337		(7,243	)
Net income (loss) per share:
Basic		9.43		6.14		5.47		2.02		(0.06	)
Diluted		9.43		6.12		5.12		1.91		(0.06	)
Balance Sheet Data:
Drilling and other property and equipment, net	$	3,398,704	$	3,040,063	$	2,628,453	$	2,302,020	$	2,154,593
Total assets		4,938,762		4,341,465		4,132,839		3,606,922		3,379,386
Long-term debt (excluding current maturities) (1)		503,280		503,071		964,310		977,654		709,413
Other Financial Data:
Capital expenditures	$	666,857	$	647,101	$	551,237	$	293,829	$	89,229
Cash dividends declared per share		6.13		5.75		2.00		0.375		0.25
Ratio of earnings to fixed charges (2)		64.54x		32.31x		28.26x		9.19x		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 10 “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 year ended December 31, 2004 was approximately $2.3 million. 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.

19

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 45 offshore drilling rigs. Our fleet currently consists of 30 semisubmersibles, 14 jack-ups and one drillship.

Overview

Industry Conditions

     The global economic recession significantly reduced energy demand in the fourth quarter of 2008 and into the first quarter of 2009. As a result, crude oil prices have fallen from a 2008 mid-summer high of $146 per barrel to as low as $34 per barrel in mid-February 2009, and remain volatile. With the falling energy prices, project economics for our customers have deteriorated, 2009 exploration budgets have been trimmed, and demand and pricing for available drilling rigs is declining. Our contract backlog should help mitigate the impact of the current market on us; however, a prolonged decline in commodity prices and the global economy could have a negative impact on us. Possible negative impacts, among others, could include customer credit problems, customers seeking bankruptcy protection, customers attempting to renegotiate or terminate contracts, a further slowing in the pace of new contracting activity, additional declines in dayrates for new contracts, declines in utilization and the stacking of idle equipment.

     Floaters

     The majority of our intermediate and high-specification floater rigs are largely contracted for the remainder of 2009. Additionally, contracts for 71% of our floating rigs extend at least through 2010, with 9% of our floating units having contracts extending into the 2014-2015 timeframe. However, during the first quarter of 2009 a customer employing our semisubmersibleOcean Guardianin the United Kingdom, or U.K., sector of the North Sea entered into administration under U.K. law (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy reorganization but with an external manager, typically an accountant, running the company). The rig, which was operating under a contract that extends until September 2011, is currently on standby and is not earning revenue. In the U.S. Gulf of Mexico, or GOM, during the fourth quarter of 2008, a customer breached its contract with us and canceled the second well of a two-well project for the semisubmersibleOcean Victory. We were able to re-contract the rig, albeit at a lower dayrate, to fill the resulting short gap until a previously committed job is scheduled to begin. We are continuing to pursue appropriate contractual remedies with both customers.

     International Jack-ups

     The industry’s jack-up market is divided between an international sector and a U.S. sector, with the international sector generally characterized by contracts of longer duration and higher prices, compared to the generally shorter term and lower priced domestic sector. However, in 2009 to the date of this report, demand and dayrates have continued to soften internationally. Based on analyst reports to the effect that less than 20% of the industry’s new-build jack-up order book is under contract, it is possible that an oversupply of jack-up rigs will have an increasingly negative impact on the international sector during 2009 and beyond.

     U.S. Gulf of Mexico Jack-ups

     In the domestic jack-up sector, rapidly declining product prices have negatively impacted both demand and dayrates. In response, where possible we are continuing to seek to move units out of the GOM and into markets with generally longer contract duration and higher prices. In that regard, we were low bidder for a 476-day job for the 300-ft.Ocean Summitand for an 849-day extension for the 300-ft.Ocean Nugget. Both bids are for work offshore Mexico and remain subject to final approvals. Absent improving product prices, weakness in the GOM is likely to continue in 2009, with an increasing number of rigs being cold-stacked by the industry in an effort to help bring equipment supply and demand into equilibrium.

20

Contract Drilling Backlog

     The following table reflects our contract drilling backlog as of February 5, 2009, October 23, 2008 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2008) and February 7, 2008 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2007) and for the 2008 periods includes both firm commitments (typically represented by signed contracts), as well as previously-disclosed letters of intent, or LOIs, where indicated. An LOI is subject to customary conditions, including the execution of a definitive agreement, and as such may not result in a binding contract. 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. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.

	February 5,		October 23,		February 7,
	2009		2008(2)		2008(2)
			(In thousands)
Contract Drilling Backlog
High-Specification Floaters	$	4,346,000	$	4,720,000	$	4,448,000
Intermediate Semisubmersibles(1)		5,567,000		6,302,000		5,985,000
Jack-ups		346,000		428,000		421,000
Total	$	10,259,000	$	11,450,000	$	10,854,000

(1)	Although still legally under contract through 2011, contract drilling backlog as of February 5, 2009 excludes future revenues associated with one of our intermediate semisubmersibles located in the U.K. sector of the North Sea, which rig’s customer is currently in administration under U.K. law.
(2)	Contract drilling backlog as of October 23, 2008 and February 7, 2008 included $189.8 million and $238.0 million, respectively, in contract drilling revenue relating to anticipated future work under LOIs.

     The following table reflects the amount of our contract drilling backlog by year as of February 5, 2009.

	For the Years Ending December 31,
	Total		2009		2010		2011		2012 - 2016
	(In thousands)
Contract Drilling Backlog
High-Specification Floaters	$	4,346,000	$	1,507,000	$	1,185,000	$	822,000	$	832,000
Intermediate Semisubmersibles(1)		5,567,000		1,747,000		1,340,000		953,000		1,527,000
Jack-ups		346,000		329,000		17,000		—		—
Total	$	10,259,000	$	3,583,000	$	2,542,000	$	1,775,000	$	2,359,000

(1) Although still legally under contract through 2011, contract drilling backlog as of February 5, 2009 excludes future revenues associated with one of our intermediate semisubmersibles located in the U.K. sector of the North Sea, which rig’s customer is currently in administration under U.K. law.

     The following table reflects the percentage of rig days committed by year as of February 5, 2009. 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).

	For the Years Ending December 31,
	2009			2010			2011			2012 - 2016
Rig Days Committed(1)
High-Specification Floaters		96	%		69	%		42	%		10	%
Intermediate Semisubmersibles		97	%		72	%		48	%		16	%
Jack-ups		51	%		4	%		—			—

21

(1) Includes approximately 1,500 and 600 scheduled shipyard, survey and mobilization days for 2009 and 2010, respectively.

Casualty Loss

     In September 2008, the jack-up rigOcean Towersustained significant damage during Hurricane Ike, which impacted the Gulf of Mexico and the upper Texas and Louisiana Gulf coasts. TheOcean Towerlost its derrick, drill floor and drill floor equipment during the hurricane. During the third quarter of 2008, we wrote off the net book value of the derrick, drill floor and drill floor equipment for theOcean Towerof approximately $2.6 million and accrued $3.7 million in estimated salvage costs for the recovery of equipment from the ocean floor. The aggregate of these items is reflected in “Casualty Loss” in our Consolidated Statements of Operations for the year ended December 31, 2008 included in Item 8 of this report.

     In December 2008, we entered into an agreement to sell theOcean Towerat a price in excess of its $32.2 million carrying value and transferred the $32.2 million net book value of the rig to “Assets held for sale” in our Consolidated Balance Sheets included in Item 8 of this report. The agreement prohibits competitive use of the rig, which is expected to be deployed by the purchaser as an accommodation unit. We do not expect the sale of theOcean Towerto have a material impact on our financial position, results of operations, or our ability to compete in the jack-up market. In connection with the execution of the sales agreement, we received a $3.5 million deposit from the purchaser which we have recorded in “Accrued liabilities” in our Consolidated Balance Sheet at December 31, 2008 included in Item 8 of this report. We expect to complete the sale in the first quarter of 2009.

General

     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. 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.

     Demand affects the number of days our fleet is utilized and the dayrates earned. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs. Conversely, as utilization rates decrease, dayrates tend to decrease as well, reflecting the excess supply of rigs. 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.

     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 (either lump-sum or dayrate). 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.

22

     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. In recent years, we have experienced upward pressure on salaries and wages as a result of the strong offshore drilling market during this period 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, as well as from quarter to quarter.

     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 2009, five of our rigs will require 5-year surveys, and we expect that they will be out of service for approximately 300 days in the aggregate. We also expect to spend an additional approximately 950 days during 2009 for intermediate surveys, the mobilization of rigs, contract modifications for international contracts and extended maintenance projects. In addition, we expect theOcean Bountyto be taken out of service at some time after the first quarter of 2009 for a repowering project and minor water depth upgrade. We expect these projects to take approximately one year to complete and to extend to 2010. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ — Overview — Contract Drilling Backlog.”

     Under our current insurance policy that expires on May 1, 2009, our deductible for physical damage is $75.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss) in the U.S. Gulf of Mexico due to named windstorms 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 May 1, 2009 is limited to $125.0 million. If named windstorms in the U.S. Gulf of

23

Mexico cause significant damage to our rigs, it could have a material adverse effect on our financial position, results of operations and cash flows.

     Insurance premiums are amortized as expense over the applicable policy periods which generally expire at the end of April 2009.

     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. 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. For the three years ended December 31, 2008, we capitalized interest on qualifying expenditures related to the upgrades of theOcean EndeavorandOcean Monarchfor ultra-deepwater service and the construction of two jack-up rigs, theOcean ShieldandOcean Scepterthrough the date of each project’s completion. The upgrades of theOcean EndeavorandOcean Monarchwere completed in March 2007 and December 2008, respectively. Construction of theOcean ShieldandOcean Scepterwas completed in May 2008 and August 2008, respectively.

     As a result of the delivery of these rigs in 2008, we anticipate that depreciation and interest expense in 2009 will increase by approximately $17 million and $16 million, respectively, compared to 2008.

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, 2008, all, except for two, of our drilling rigs were either under contract, in shipyards for surveys or contract modifications or, in the case of the recently upgradedOcean Monarch, mobilizing to the U.S. One of these idle units, theOcean Tower, which was damaged during Hurricane Ike in September 2008, has been transferred to “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2008 included in Item 8 of this report. We have entered into an agreement to sell the rig for a price in excess of its carrying value. At December 31, 2008, the second of our idle rigs was ready-stacked while waiting to begin drilling operations in early January 2009. We did not have any cold-stacked rigs at December 31, 2008. We do not believe that current circumstances indicate that the carrying amount of our property and equipment may not be recoverable.

24

     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 result from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence, with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We estimate 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, respectively, 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 $19.3 million for uncertain tax positions (excluding interest and penalties), the net of which was accounted for as a reduction to the January 1, 2007 balance of retained earnings.

25

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, 2008 and 2007

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

	Year Ended
	December 31,						Favorable/
	2008			2007			(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters	$	1,322,125		$	1,030,892		$	291,233
Intermediate Semisubmersibles		1,629,358			1,028,667			600,691
Jack-ups		524,934			446,104			78,830
Total Contract Drilling Revenue	$	3,476,417		$	2,505,663		$	970,754
Revenues Related to Reimbursable Expenses	$	67,640		$	62,060		$	5,580
CONTRACT DRILLING EXPENSE
High-Specification Floaters	$	367,531		$	318,555		$	(48,976	)
Intermediate Semisubmersibles		581,161			482,464			(98,697	)
Jack-ups		224,365			183,024			(41,341	)
Other		11,950			19,746			7,796
Total Contract Drilling Expense	$	1,185,007		$	1,003,789		$	(181,218	)
Reimbursable Expenses	$	65,895		$	60,261		$	(5,634	)
OPERATING INCOME
High-Specification Floaters	$	954,594		$	712,337		$	242,257
Intermediate Semisubmersibles		1,048,197			546,203			501,994
Jack-ups		300,569			263,080			37,489
Other		(11,950	)		(19,746	)		7,796
Reimbursable expenses, net		1,745			1,799			(54	)
Depreciation		(286,850	)		(235,251	)		(51,599	)
General and administrative expense		(60,142	)		(53,483	)		(6,659	)
Bad debt expense		(31,952	)		—			(31,952	)
Casualty loss		(6,281	)		—			(6,281	)
Gain on disposition of assets		2,831			8,583			(5,752	)
Total Operating Income	$	1,910,761		$	1,223,522		$	687,239
Other income (expense):
Interest income		11,744			33,566			(21,822	)
Interest expense		(10,096	)		(19,191	)		9,095
Foreign currency transaction gain (loss)		(65,566	)		2,906			(68,472	)
Other, net		770			5,734			(4,964	)
Income before income tax expense		1,847,613			1,246,537			601,076
Income tax expense		(536,593	)		(399,996	)		(136,597	)
NET INCOME	$	1,311,020		$	846,541		$	464,479

26

     Demand remained strong for our high-specification floaters and intermediate semisubmersible rigs in all markets and geographic regions during the first nine months of 2008. During the fourth quarter of 2008, the growing global economic recession became apparent in our industry, resulting in reduced demand for energy and a significant decline in crude oil prices. However, because of our contracted revenue backlog, our results were not greatly impacted by these market conditions during the fourth quarter of 2008. The high overall utilization and historically high dayrates for our floater fleet contributed to an overall increase in our revenues of $891.9 million, or 43%, to $3.0 billion in 2008 compared to $2.1 billion in 2007.

     Total contract drilling revenues in 2008 increased $970.8 million, or 39% compared to 2007, to $3.5 billion. Average realized dayrates in many of our floater markets increased as our rigs began operating under contracts at higher dayrates than those earned during 2007, resulting in the generation of additional contract drilling revenues. However, overall revenue increases for our floater fleet were negatively impacted by the effect of downtime associated with scheduled shipyard projects and mandatory inspections or surveys. In addition, the GOM jack-up market, which was improving in early 2008, began experiencing reduced demand and dayrates by the end of 2008. The international jack-up market, which had been strong throughout the majority of 2008, also began to reflect softening demand and reduced dayrates by the end of 2008. Our GOM and international jack-up fleets earned lower dayrates during 2008 compared to 2007 despite a fleet-wide increase in utilization during 2008.

     Total contract drilling expenses increased $181.2 million, or 18%, in 2008 compared to 2007. Overall cost increases for maintenance and repairs between the 2008 and 2007 periods 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 theOcean Endeavor, Ocean ShieldandOcean Scepter. The increase in overall operating and overhead costs also reflects the impact of higher prices throughout the offshore drilling industry and its support businesses, including higher costs associated with hiring and retaining skilled personnel for our worldwide offshore fleet.

     Depreciation expense increased $51.6 million to $286.9 million during 2008, or 22% compared to 2007, due to a higher depreciable asset base.

     Our results during 2008 were negatively impacted by $54.0 million in losses on foreign currency forward exchange contracts included in “Foreign currency transaction gain (loss)”, a $31.9 million provision for bad debt expense related to one of our North Sea semisubmersible rigs contracted to a U.K. customer that has entered into administration under U.K. law (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy) and the recognition of a casualty loss aggregating $6.3 million in connection with damages sustained from Hurricane Ike (see “ — Overview — Casualty Loss”).

27

High-Specification Floaters.

	Year Ended
	December 31,				Favorable/
	2008		2007		(Unfavorable)
	(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM	$	1,051,178	$	833,751	$	217,427
Australia/Asia/Middle East		69,419		73,004		(3,585	)
South America		201,528		124,137		77,391
Total Contract Drilling Revenue	$	1,322,125	$	1,030,892	$	291,233
CONTRACT DRILLING EXPENSE
GOM	$	223,954	$	206,393	$	(17,561	)
Australia/Asia/Middle East		35,079		26,407		(8,672	)
South America		108,498		85,755		(22,743	)
Total Contract Drilling Expense	$	367,531	$	318,555	$	(48,976	)
OPERATING INCOME	$	954,594	$	712,337	$	242,257

     GOM.Revenues generated by our high-specification floaters operating in the GOM increased $217.4 million in 2008 compared to 2007, primarily due to higher average dayrates earned during 2008 ($131.7 million). Average operating revenue per day for our rigs in this market, excluding theOcean Endeavor, increased to $413,300 during 2008 compared to $354,400 in 2007. Excluding theOcean Endeavor, six of our seven other high-specification semisubmersible rigs in the GOM are currently operating at dayrates higher than those earned during 2007. TheOcean Endeavorbegan operating in the GOM during the third quarter of 2007 and generated additional revenues of $49.7 million during 2008 compared to 2007.

     Average utilization for our high-specification rigs operating in the GOM, excluding theOcean Endeavor, increased slightly from 87% in 2007 to 91% in 2008, generating $36.0 million in additional revenues in 2008. The increase in utilization in 2008 is attributable to 88 fewer downtime days during 2008 compared to 2007 when rigs were down, primarily for regulatory inspections and repairs.

     Operating costs during 2008 for our high-specification floaters in the GOM increased $17.6 million to $224.0 million (including $11.3 million in incremental operating expenses for theOcean Endeavor) compared to 2007. Operating costs for 2008 reflect higher labor, benefits and other personnel-related costs, higher maintenance and other project costs and higher property insurance costs, partially offset by lower mobilization and other inspection related costs for these rigs compared to 2007.

     Australia/Asia/Middle East.Revenues generated by theOcean Rover,our high-specification rig operating offshore Malaysia, decreased $3.6 million in 2008 compared to 2007. The revenue decrease was primarily due to scheduled downtime (67 days) for a survey and maintenance, partially offset by the effect of a higher average dayrate earned during 2008 compared to 2007.

     Contract drilling expenses for theOcean Roverincreased $8.7 million in 2008 compared to 2007 primarily due to costs associated with the rig’s 2008 survey and other maintenance and repair costs and, to a lesser extent, higher labor, benefits and other personnel-related costs.

     South America.Revenues earned by our high-specification floaters operating offshore Brazil during 2008 increased $77.4 million compared to 2007. Average operating revenue per day increased from $185,300 during 2007 to $339,700 during 2008, generating additional revenues of $92.3 million. Utilization in 2008 decreased to 81% from 92% in 2007 primarily as the result of 99 days of incremental unpaid downtime for theOcean Clipperfor a special survey and repairs to its propulsion system. The decline in utilization reduced revenues by $14.9 million in 2008.

28

     Contract drilling expense for our operations in Brazil increased $22.7 million in 2008 compared to 2007. The increase in costs is primarily due to inspection and repair costs for theOcean Clipperand higher revenue-based agency fees and personnel and related costs during 2008, as compared to 2007.

Intermediate Semisubmersibles.

	Year Ended
	December 31,				Favorable/
	2008		2007		(Unfavorable)
	(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM	$	134,880	$	170,449	$	(35,569	)
Mexico		220,754		86,135		134,619
Australia/Asia/Middle East		395,124		239,200		155,924
Europe/Africa/Mediterranean		518,382		400,785		117,597
South America		360,218		132,098		228,120
Total Contract Drilling Revenue	$	1,629,358	$	1,028,667	$	600,691
CONTRACT DRILLING EXPENSE
GOM	$	44,902	$	79,288	$	34,386
Mexico		54,187		63,711		9,524
Australia/Asia/Middle East		141,170		112,641		(28,529	)
Europe/Africa/Mediterranean		167,786		143,555		(24,231	)
South America		173,116		83,269		(89,847	)
Total Contract Drilling Expense	$	581,161	$	482,464	$	(98,697	)
OPERATING INCOME	$	1,048,197	$	546,203	$	501,994

     GOM.Revenues generated during 2008 by our intermediate semisubmersible fleet operating in the GOM decreased $35.6 million compared to 2007, primarily as a result of the relocation of three of our rigs from the GOM (Ocean VoyagerandOcean New Erato Mexico andOcean Concordto Brazil) in the fourth quarter of 2007. During 2007, these three rigs generated revenues of $128.9 million while operating in the GOM.

     The negative impact on revenues of the departure of these rigs was partially offset by $65.6 million and $27.8 million in additional revenues generated by theOcean Saratogaand theOcean Ambassador, respectively, during 2008 compared to 2007. The additional contribution by theOcean Saratogawas primarily due to the rig operating at a higher dayrate beginning in the fourth quarter of 2007 and increased utilization during 2008 compared to 2007 when the rig was out of service for 116 days completing a service life extension project. We relocated theOcean Ambassadorto the GOM from Mexico during the second quarter of 2008.

     Contract drilling expenses in the GOM decreased by $34.4 million during 2008 compared to 2007, primarily due to the absence of operating costs for theOcean Voyager,Ocean New EraandOcean Concord($47.9 million) which relocated to other markets during 2007 and costs associated with shipyard projects for theOcean WhittingtonandOcean Worker($16.8 million) that were completed in 2007 prior to relocating these rigs to the South America region. The overall decrease in contract drilling expenses in 2008 was partially offset by the inclusion of normal operating expenses and special survey costs for theOcean Ambassador($21.8 million). Also included in operating expenses for 2008 are $3.2 million in maintenance and other costs associated with contract preparation activities for theOcean Yorktownprior to its mobilization to Brazil in May 2008.

     Mexico.Offshore Mexico, three of our intermediate semisubmersible rigs completed their contracts with PEMEX after the second quarter of 2007 and relocated out of the region. During the fourth quarter of 2007, we relocated two semisubmersible units, theOcean New EraandOcean Voyager, from the GOM to Mexico. Average operating revenue per day for our rigs working offshore Mexico increased to $277,900 for 2008 compared to $98,900 per day for 2007 primarily because these two new rigs in the region are currently working for PEMEX at dayrates substantially higher than average rates earned during 2007. Higher dayrates, partially offset by the net reduction in the number of rigs between periods, generated $134.6 million of additional revenues during 2008 compared to 2007.

29

     Contract drilling expenses for the Mexico region decreased $9.5 million during 2008 compared to 2007 primarily due to the effect on operating costs of the net reduction of one rig in the region, partially offset by higher maintenance costs and revenue-based agency fees.

     Australia/Asia/Middle East. Our intermediate semisubmersibles working in the Australia/Asia/Middle East region generated revenues of $395.1 million during 2008 compared to revenues of $239.2 million in 2007. The $155.9 million increase in operating revenue was primarily due to an increase in average operating revenue per day from $171,500 during 2007 to $306,600 during 2008, which generated additional revenues of $171.0 million during 2008.

     Average utilization in this region decreased to 87% during 2008 from 94% during 2007, resulting in a $15.1 million reduction in revenues during 2008. The decrease in utilization was primarily the result of 170 days of scheduled downtime for special surveys and repairs for three of our rigs in this region during 2008.

     Contract drilling expense for the Australia/Asia/Middle East region increased $28.5 million in 2008 compared to 2007, primarily due to inspection and related repair costs associated with special surveys during 2008. In addition, normal operating costs for theOcean Patriotwere higher during 2008 while operating offshore Australia compared to operating offshore New Zealand during 2007. Operating costs in this region also reflected higher labor and personnel-related costs during 2008 compared to the prior year.

     Europe/Africa/Mediterranean.Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region increased $117.6 million in 2008 compared to 2007 primarily due to higher dayrates earned by our four rigs operating in the North Sea (both U.K. and Norwegian sectors). Average operating revenue per day for our North Sea semisubmersibles increased from $211,500 during 2007 to $321,200 during 2008, contributing $144.7 million in additional revenue in 2008 compared to the prior year. The increase in revenue was partially offset by the impact of 126 days of incremental downtime during 2008 primarily associated with surveys of our U.K. rigs. The decrease in utilization reduced revenues by $27.4 million during 2008 compared to 2007.

     Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets increased $24.2 million in 2008 compared to 2007, primarily due to the inclusion of costs associated with surveys of our rigs operating in the U.K. sector of the North Sea. In addition, during 2008, all of our rigs in this market incurred higher overall costs, primarily for labor and benefits and repairs. Operating costs for 2008 included additional costs for theOcean Vanguardoperating offshore Ireland for a portion of 2008.

     South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $228.1 million during 2008 compared to 2007. During 2008, we had six rigs operating in the region compared to four rigs operating in the region during 2007. Following the first quarter of 2007, we relocated theOcean WhittingtonandOcean Concordto Brazil and theOcean Workerto Trinidad and Tobago where they generated additional aggregate revenues of $196.2 million in 2008. TheOcean Yorktownbegan operating in Brazil during the third quarter of 2008 and generated $30.4 million in revenues.

     Operating expenses for our operations in the South American region increased $89.8 million in 2008, compared to 2007, primarily due to the inclusion of normal operating costs for two of the rigs transferred to this region ($48.1 million) and incremental operating costs for theOcean WorkerandOcean Whittington($38.6 million) which only operated in the South American region for a portion of 2007. Operating expenses for 2008 also reflected higher labor and other personnel-related expenses, freight and repair and maintenance costs for our other two semisubmersible rigs in this market.

30

Jack-Ups.

	Year Ended
	December 31,				Favorable/
	2008		2007		(Unfavorable)
	(In thousands)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM	$	189,500	$	222,276	$	(32,776	)
Mexico		105,055		62,451		42,604
Australia/Asia/Middle East		92,596		88,497		4,099
Europe/Africa/Mediterranean		115,652		72,880		42,772
South America		22,131		—		22,131
Total Contract Drilling Revenue	$	524,934	$	446,104	$	78,830
CONTRACT DRILLING EXPENSE
GOM	$	99,533	$	119,216	$	19,683
Mexico		33,303		16,108		(17,195	)
Australia/Asia/Middle East		42,184		28,214		(13,970	)
Europe/Africa/Mediterranean		35,058		19,486		(15,572	)
South America		14,287		—		(14,287	)
Total Contract Drilling Expense	$	224,365	$	183,024	$	(41,341	)
OPERATING INCOME	$	300,569	$	263,080	$	37,489

     GOM.Revenue generated by our jack-up rigs operating in the GOM decreased $32.8 million during 2008 compared to 2007, primarily due to the relocation of theOcean King(Croatia) and theOcean Columbia(Mexico) after the second quarter of 2007. These two rigs generated $42.1 million in revenues while operating in the GOM during 2007. In addition, average operating revenue per day, excluding theOcean KingandOcean Columbia, decreased to $80,800 in 2008 from $90,500 during 2007, resulting in an additional $18.3 million decrease in revenue from the prior year.

     Average utilization (excluding theOcean KingandOcean Columbia) increased from 78% during 2007 to 92% during 2008, resulting in an increase in revenues of $32.5 million. The increase in utilization was primarily due to an improvement in market conditions in the GOM during 2008 compared to 2007 that resulted in fewer ready-stack days for our jack-up fleet between wells during 2008 (22 days) compared to 2007 (306 days). However, revenues decreased $4.8 million as a result of theOcean Towerbeing taken out of service due to damages sustained during Hurricane Ike in the third quarter of 2008, partially offsetting the favorable effect of increased utilization in 2008.

     Contract drilling expense in the GOM decreased $19.7 million during 2008 compared to 2007. The overall decrease in operating costs during 2008 was due to the absence of operating costs in the GOM for theOcean KingandOcean Columbia($21.8 million). The reduction in overall operating costs was partially offset by costs associated with a regulatory survey for one of our GOM jack-ups, higher labor and benefits costs and higher overhead costs for our remaining rigs in the GOM during 2008 compared to 2007.

     Mexico.Revenue and contract drilling expense from our rigs operating in Mexico increased $42.6 million and $17.2 million, respectively, in 2008 compared to 2007 primarily due to the operation of theOcean Columbiaoffshore Mexico, beginning in the first quarter of 2008. TheOcean Columbiagenerated $42.0 million in revenues and incurred $17.1 million in operating expenses during 2008.

     Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the Australia/Asia/Middle East region increased $4.1 million during 2008 compared to 2007. Our newly constructed jack-up rig, theOcean Shield, began operating offshore Malaysia during the second quarter of 2008 and generated $39.0 million in revenues during 2008. In addition, theOcean Sovereign,operating offshore Indonesia in 2008, generated additional revenues of $8.4 million due to an increase in the operating dayrate earned by the rig beginning late in the second quarter of 2008. These favorable contributions to revenue in the region were partially offset by a decrease in revenue generated by theOcean Heritage, which was ready-stacked in a shipyard in Qatar from March 2008 through late June 2008 until it was subsequently relocated out of the region to Egypt.

31

     Contract drilling expense in the Australia/Asia/Middle East region increased by $14.0 million in 2008 compared to 2007 primarily due to the inclusion of normal operating costs for theOcean Shieldand higher labor, benefits, repair and other operating costs for theOcean Sovereign. These cost increases were partially offset by the absence of operating costs for theOcean Heritagedue to its relocation to Egypt.

     Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region increased $42.8 million in 2008 compared to 2007. TheOcean King, operating under a two-year bareboat charter offshore Croatia that began in the third quarter of 2007, generated revenues of $37.8 million during 2008. In addition, theOcean Heritage, which relocated to Egypt during the third quarter of 2008, generated $17.0 million of revenues in the region.

     Revenues were negatively impacted by theOcean Spur, which operated offshore Egypt all of 2008 and in both Tunisia and Egypt in 2007. TheOcean Spurgenerated $12.0 million less in revenues during 2008 compared to 2007, primarily due to the recognition of other operating revenues associated with its contract offshore Tunisia during 2007.

     Contract drilling expense in the Europe/Africa/Mediterranean region increased by $15.6 million in 2008 compared to 2007 primarily due to the inclusion of normal operating costs for theOcean Heritagebeginning in the third quarter of 2008 and, to a lesser extent, operating expenses associated with theOcean King‘s bareboat charter for the entire 2008 period.

     South America. Our newly constructed jack-up rig, theOcean Scepter, began operating offshore Argentina during the third quarter of 2008 and generated $22.1 million in revenues and incurred $14.3 million in contract drilling expenses.

Other Contract Drilling.

     Other contract drilling expenses decreased $7.8 million during 2008 compared to 2007 primarily due to insurance proceeds received in 2008 related to claims filed in connection with the 2005 Hurricane Katrina. These costs had previously been expensed due to uncertainty of recovery from insurance.

Depreciation.

     Depreciation expense increased $51.6 million to $286.9 million in 2008 compared to $235.3 million in 2007 primarily due to depreciation associated with capital additions in 2007 and 2008, including a partial year’s depreciation of our two newly constructed jack-ups, theOcean ShieldandOcean Scepter.

General and Administrative Expense.

     We incurred general and administrative expense of $60.1 million in 2008 compared to $53.5 million in 2007. The $6.7 million increase in overhead costs between the periods was primarily due to an increase in payroll costs resulting from higher compensation and staffing increases, travel and related costs and engineering and tax consulting fees. These cost increases were partially offset by lower legal fees resulting from an insurance reimbursement related to certain litigation in 2008.

Bad Debt Expense.

     We recorded a provision for bad debt expense of $31.9 million related to one of our North Sea semisubmersible rigs contracted to a U.K. customer that has entered into administration under U.K. law.

Casualty Loss.

     During September 2008, one of our jack-up rigs, theOcean Tower, sustained significant damage during Hurricane Ike. As a result of this damage, we wrote off the net book value of theOcean Tower‘s derrick, drill floor and related equipment lost in the storm of approximately $2.6 million and accrued $3.7 million in estimated salvage costs for recovery of equipment from the ocean floor.

32

Gain on Disposition of Assets.

     We recognized a net gain of $2.8 million on the sale and disposition of assets in 2008 compared to a net gain of $8.6 million in 2007 primarily for the recognition of gains on insurance settlements and from sales of used equipment.

Interest Income.

     Our interest income decreased $21.8 million to $11.7 million in 2008 from $33.6 million in 2007. The decrease was primarily due to lower interest rates earned on our invested cash balances in 2008 compared to 2007.

Interest Expense.

     We recorded interest expense of $10.1 million in 2008 compared to $19.2 million in 2007. Interest expense in 2007 included $9.2 million in debt issuance costs that we wrote off in connection with conversions during the period of our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, and our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, into shares of our common stock. We wrote off $84,000 in debt issuance costs during 2008 related to conversions during the year.

Foreign Currency Transaction Gain (Loss).

     Foreign currency transaction gains (losses) include gains and losses from the settlement of foreign currency forward exchange contracts and fluctuate based on the level of transactions in foreign currencies, as well as fluctuations in such currencies. During 2008, we recognized net foreign currency exchange losses of $65.6 million, including $54.0 million in net losses on foreign currency forward exchange contracts ($37.2 million in net unrealized losses resulting from mark-to-market accounting on our open positions at December 31, 2008 and $16.8 million in net realized losses on settlement of forward contracts). During 2007, we recognized net foreign currency exchange gains of $2.9 million.

Income Tax Expense.

     Our income tax expense 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. We recognized $536.6 million of tax expense on pre-tax income of $1.8 billion for the year ended December 31, 2008 compared to tax expense of $400.0 million on a pre-tax income of $1.2 billion in 2007.

     Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, or DOIL, 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, DOIL 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 in 2007 as a result of the distribution. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest future earnings of DOIL to finance foreign activities except for the earnings of Diamond East Asia Limited, a wholly-owned subsidiary of DOIL formed in December 2008. It is our intention to repatriate the earnings of Diamond East Asia Limited and, accordingly, U.S. income taxes are provided on its earnings.

     We adopted the provisions of FIN 48 on January 1, 2007. During the years ended December 31, 2008 and 2007, we recognized $0.8 million and $1.7 million of interest expense related to uncertain tax positions, respectively. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2008 and 2007 was $1.1 million and $0.8 million, respectively.

33

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	$	318,555		$	234,030		$	(84,525	)
Intermediate Semisubmersibles		482,464			388,239			(94,225	)
Jack-ups		183,024			157,846			(25,178	)
Other		19,746			25,265			5,519
Total Contract Drilling Expense	$	1,003,789		$	805,380		$	(198,409	)
Reimbursable Expenses	$	60,261		$	64,142		$	3,881
OPERATING INCOME
High-Specification Floaters	$	712,337		$	532,843		$	179,494
Intermediate Semisubmersibles		546,203			396,808			149,395
Jack-ups		263,080			277,348			(14,268	)
Other		(19,746	)		(25,265	)		5,519
Reimbursable expenses, net		1,799			1,316			483
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		—			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
Foreign currency transaction gain		2,906			10,343			(7,437	)
Other, net		5,734			1,773			3,961
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

34

     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 $198.4 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	$	206,393	$	142,163	$	(64,230	)
Australia/Asia/Middle East		26,407		23,895		(2,512	)
South America		85,755		67,972		(17,783	)
Total Contract Drilling Expense	$	318,555	$	234,030	$	(84,525	)
OPERATING INCOME	$	712,337	$	532,843	$	179,494

     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. 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

35

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 $64.2 million compared to 2006 to $206.4 million (including $16.8 million in normal operating expenses for theOcean Endeavor). 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 $2.5 million compared to 2006 to $26.4 million, 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 $17.8 million during 2007 compared to 2006. The increase in costs was 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.

36

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	$	79,288	$	80,017	$	729
Mexico		63,711		60,467		(3,244	)
Australia/Asia/Middle East		112,641		85,590		(27,051	)
Europe/Africa/Mediterranean		143,555		109,455		(34,100	)
South America		83,269		52,710		(30,559	)
Total Contract Drilling Expense	$	482,464	$	388,239	$	(94,225	)
OPERATING INCOME	$	546,203	$	396,808	$	149,395

     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.

     Contract drilling expenses decreased by $0.7 million in 2007 compared to 2006. Increased costs in the GOM during 2007 associated with surveys and contract preparation activities, as well as higher labor and related costs,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.

37

Revenues generated in 2007 were reduced by $28.5 million due to the return of theOcean Whittington in 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 was 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 $27.1 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, included 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 $34.1 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.

38

     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	$	119,216	$	111,473	$	(7,743	)
Mexico		16,108		4,373		(11,735	)
Australia/Asia/Middle East		28,214		27,374		(840	)
Europe/Africa/Mediterranean		19,486		14,626		(4,860	)
Total Contract Drilling Expense	$	183,024	$	157,846	$	(25,178	)
OPERATING INCOME	$	263,080	$	277,348	$	(14,268	)

     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 was 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.

39

     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 $1.8 million and $1.3 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.

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.

40

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% 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 Debentures into shares of our common stock. See “— Liquidity and Capital Requirements — 1.5% Debentures” and “ — Liquidity and Capital Requirements — Zero Coupon Debentures.”

Foreign Currency Transaction Gain.

     Foreign currency transaction gains (losses) include gains and losses from the settlement of foreign currency forward exchange contracts and fluctuate based on the level of transactions in foreign currencies, as well as fluctuations in such currencies. During 2007 and 2006, we recognized net foreign currency exchange gains of $8.1 million and $7.3 million, respectively, on settlement of foreign currency forward exchange contracts.

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 were 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.

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

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

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

41

   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, 2008, we had $336.1 million in “Cash and cash equivalents” and $400.6 million in “Investments and marketable securities,” representing our investment of cash available for current operations.

     Cash Flows from Operations.Our cash flows from operations are impacted by the ability of our customers to weather the current global financial and credit crisis. In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. Tightening of the credit markets may preclude us from doing business with potential customers and could have an impact on our existing customers, causing them to fail to meet their obligations to us.

     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, senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit, that will mature on November 2, 2011.

     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, 2008, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2008, there were no loans outstanding under the Credit Facility; however $58.1 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 access the capital markets by issuing debt or equity securities 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.

42

     Contractual Cash Obligations.The following table sets forth our contractual cash obligations at December 31, 2008.

	Payments Due By Period
			Less than 1						After 5
	Total		year		1 – 3 years		4 – 5 years		years
Contractual Obligations	(In thousands)
Long-term debt (principal and interest)	$	655,012	$	25,063	$	54,294	$	50,125	$	525,530
Purchase obligations related to rig upgrade/modifications		22,878		22,878		—		—		—
Operating leases		2,400		1,146		1,152		102		—
Total obligations	$	680,290	$	49,087	$	55,446	$	50,227	$	525,530

     The above table excludes foreign currency forward exchange contracts in the aggregate notional amount of $214.6 million outstanding at December 31, 2008. See further information regarding these contracts in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk —Foreign Exchange Risk” and Note 5 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 8 of this report.

     As of December 31, 2008, the total unrecognized tax benefit related to uncertain tax positions was $23.7 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.

     As of December 31, 2008, we had purchase obligations aggregating approximately $23 million related to the major upgrade of theOcean Monarch. We expect to complete funding of this project in 2009.

     We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2008, 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, 2008 in the amount of $149.1 million under certain performance, bid, supersedeas and custom bonds and letters of credit, including $58.1 million in letters of credit issued under our Credit Facility. Six of these bonds totaling $88.5 million were purchased from a related party after obtaining competitive quotes. Agreements relating to approximately $80.3 million of performance bonds can require collateral at any time. As of December 31, 2008 we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except

43

in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds. See Note 14 “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		2009		2010
	(In thousands)
Other Commercial Commitments
Customs bonds	$	42,062	$	42,062	$	—
Performance bonds		94,434		25,750		68,684
Other		12,630		12,630		—
Total obligations	$	149,126	$	80,442	$	68,684

4.875% Senior Notes.

     On June 14, 2005, we issued $250.0 million aggregate principal amount of 4.875% Senior Notes Due July 1, 2015, or 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 were due April 15, 2031. The 1.5% Debentures were 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. During the period from January 1, 2008 to April 14, 2008 and the year ended December 31, 2007, the holders of $3.5 million and $456.4 million, respectively, in aggregate principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 71,144 shares and 9,309,616 shares of our common stock in 2008 and 2007, respectively, pursuant to these conversions.

     In addition, we had 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. On April 15, 2008, we completed the redemption of all of our outstanding 1.5% Debentures, and, as a result, redeemed for cash the remaining $73,000 aggregate principal amount outstanding of our 1.5% Debentures See “1.5% Debentures” in Note 10 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.

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, 2008, the aggregate accreted value of our outstanding Zero Coupon Debentures was $4.0 million. We will not pay interest prior to maturity unless we elect to convert the Zero Coupon Debentures to

44

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 10 “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 2008 and 2007, holders of $33,000 and $1.5 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 430 and 20,658 shares of our common stock upon conversion of these debentures during 2008 and 2007, respectively. The aggregate principal amount at maturity of our Zero Coupon Debentures converted during 2008 and 2007 was $50,000 and $2.4 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.

     During 2008, construction of our two high-performance, premium jack-up rigs, theOcean Shield andOcean Scepter, was completed at an aggregate construction cost of approximately $324 million. Both rigs began operating under contract during 2008. The upgrade of theOcean Monarchwas completed late in the fourth quarter of 2008 for an aggregate expected cost of approximately $310 million. TheOcean Monarcharrived in the GOM in late January 2009, and we are making final preparations for a four-year term contract, which we expect to commence late in the first quarter of 2009. During 2008, we spent $181.9 million on construction and upgrade projects.

     During 2008, we spent approximately $485.0 million on our continuing rig capital maintenance program (other than rig upgrades and new construction) and to meet other corporate capital expenditure requirements, including $125.1 million towards modification of certain of our rigs to meet contractual requirements. We have budgeted approximately $400 million on capital expenditures for 2009 associated with our ongoing rig equipment replacement and enhancement programs, equipment required for our long-term international contracts and other corporate requirements. In addition, we expect to spend an additional $70.0 million in 2009 in connection with a repowering project and water depth upgrade for theOcean Bounty.We expect to finance our 2009 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, 2008 and 2007, we had no off-balance sheet debt or other arrangements.

45

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, 2008 compared to 2007.

Net Cash Provided by Operating Activities.

	Year Ended December 31,
	2008			2007			Change
	(In thousands)
Net income	$	1,311,020		$	846,541		$	464,479
Net changes in operating assets and liabilities		(87,321	)		129,383			(216,704	)
(Gain) loss on sale and disposition of assets, including casualty loss onOcean Tower		3,450			(8,583	)		12,033
(Gain) loss on sale of marketable securities		(1,282	)		(1,796	)		514
(Gain) loss on foreign currency forward exchange contracts		54,010			(5,423	)		59,433
Deferred tax provision		61,498			1,770			59,728
Depreciation and other non-cash items, net		278,313			246,424			31,889
	$	1,619,688		$	1,208,316		$	411,372

     Our cash flows from operations in 2008 increased $411.4 million or 34% compared to 2007. The increase in cash flows from operations in 2008 is primarily the result of higher average dayrates earned by our rigs as a result of high worldwide demand for offshore contract drilling services through 2008 compared to 2007. 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. However, the increase in cash flows from operations during 2008 was partially offset by an increase in cash required to satisfy our working capital requirements. Trade and other receivables used cash of $42.5 million during 2008 primarily due to a $31.9 million provision for bad debts recorded as a result of one of our customers in the U.K. entering into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy) and our expectation that the receivable would not be collectible. During 2008, we received insurance proceeds of $9.4 million related to the settlement of certain hurricane-related insurance claims resulting from damages sustained in 2005. During 2007, we received insurance proceeds of $51.2 million related to the settlement of certain claims also 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 2008, we made U.S. federal income tax payments of $393.2 million compared to $299.6 million in 2007 for estimated U.S. federal and state income tax payments. We paid foreign income taxes, net of refunds, of $120.7 million and $31.7 million during 2008 and 2007, respectively.

Net Cash Used in Investing Activities.

	Year Ended December 31,
	2008			2007			Change
	(In thousands)
Purchase of marketable securities	$	(1,888,792	)	$	(2,850,135	)	$	961,343
Proceeds from sale of marketable securities		1,493,803			3,163,475			(1,669,672	)
Capital expenditures		(666,857	)		(647,101	)		(19,756	)
Proceeds from disposition of assets		5,881			10,861			(4,980	)
Proceeds from settlement of forward contracts		(16,800	)		8,109			(24,909	)
	$	(1,072,765	)	$	(314,791	)	$	(757,974	)

     Our investing activities used $1.1 billion in 2008 compared to $314.8 million in 2007. During 2008, we purchased marketable securities, net of sales, of $395.0 million compared to net sales of $313.3 million during 2007. 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 2008, we spent approximately $181.9 million related to the major upgrade of theOcean Monarchand construction of theOcean ScepterandOcean Shield. During 2007, we spent approximately $258.7 million related

46

to major upgrades and construction projects, including $38.8 million towards the major upgrade of theOcean Endeavor.Expenditures for our ongoing capital maintenance programs, including rig modifications to meet contractual requirements, were $485.0 million in 2008 compared to $388.4 million in 2007. The increase in expenditures related to our ongoing capital maintenance program in 2008 compared to 2007 is related to an increase in discretionary funds available for capital spending in 2008, as well as a response to customer requirements. See “— Liquidity and Capital Requirements —Capital Expenditures.”

     Primarily during the latter part of 2008, the strengthening U.S. dollar (or, conversely, the weakening foreign currency) negatively impacted our expiring foreign currency forward exchange contracts entered into as economic hedges of our foreign currency requirements and resulted in an aggregate realized loss of $16.8 million for 2008. During 2007, we recognized $8.1 million in realized gains on the settlement of foreign currency forward exchange contracts. As of December 31, 2008, we had foreign currency exchange contracts outstanding, in the aggregate notional amount of $214.6 million, consisting of $50.1 million in Australian dollars, $69.4 million in Brazilian reais, $62.1 million in British pounds sterling, $16.9 million in Mexican pesos and $16.1 million in Norwegian kroner. These contracts settle at various times through June 2009.

Net Cash Used in Financing Activities.

	Year Ended December 31,
	2008			2007			Change
	(In thousands)
Payment of dividends	$	(852,153	)	$	(796,292	)	$	(55,861	)
Proceeds from stock options exercised		2,002			10,836			(8,834	)
Other		1,319			5,194			(3,875	)
	$	(848,832	)	$	(780,262	)	$	(68,570	)

     During 2008, we paid cash dividends totaling $852.2 million, consisting of aggregate regular cash dividends of $69.5 million, or $0.125 per share of our common stock per quarter, and aggregate special cash dividends of $782.7 million ($1.25 per share of our common stock for each of the first three quarters of 2008 and $1.875 per share of our common stock during the final quarter of 2008). During 2007, we paid cash dividends totaling $796.3 million, consisting of regular 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, for the first and fourth quarters, respectively, totaling $553.4 million and $173.6 million, respectively.

     On February 4, 2009, we declared a regular quarterly cash dividend and a special cash dividend of $0.125 and $1.875, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on March 2, 2009 to stockholders of record on February 13, 2009.

     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.

     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, 2008 and 2007.

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.

     To the extent that we are not able to cover our local currency operating costs with customer payments in the

47

local currency, we also utilize foreign exchange forward contracts to reduce our currency exchange risk. Our forward currency exchange contracts may obligate us to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specific dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for certain contracts is the average spot rate for the contract period.

     We record currency transaction gains and losses, including gains and losses on settlement of our foreign currency forward exchange contracts, as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.

Recent Accounting Pronouncements

     In May 2008, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position, or FSP, Accounting Principles Board, or APB, 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),” or FSP APB 14-1. FSP APB 14-1 applies to convertible debt instruments that, by their stated terms, may be settled in cash upon conversion (including partial cash settlement). The FSP requires bifurcation of the instrument into a debt component that is initially valued at fair value and an equity component. The debt component is accreted to par value using the effective yield method, and accretion is reported as a component of interest expense. The equity component is not subsequently revalued as long as it continues to qualify for equity treatment. FSP APB 14-1 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years on a retrospective basis for all periods presented. We will adopt FSP APB 14-1 effective January 1, 2009. We do not expect the adoption of this staff position to have a material effect on our results of operations or financial position in the current year or prospectively.

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 (see “— Sources of Liquidity and Capital Resources” and “— Liquidity and Capital Requirements”);

48

• tax planning (See “— Overview — Critical Accounting Estimates — Income Taxes,” “— Years Ended December 31, 2008 and 2007 — Income Tax Expense” and “— Years Ended December 31, 2007 and 2006 — 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, including the extent and duration of the current credit crisis and recession;

• 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.

49

     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, 2008 and December 31, 2007, 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, 2008 and December 31, 2007, 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, 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 December 31, 2008 and 2007, there were no loans outstanding under the Credit Facility (however, as of December 31, 2008, $58.1 million in letters of credit were issued and outstanding under the Credit Facility).

50

     Our long-term debt, as of December 31, 2008 and December 31, 2007, 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 $20.9 million and $35.8 million as of December 31, 2008 and 2007, respectively. A 100-basis point decrease would result in an increase in market value of $21.6 million and $11.6 million as of December 31, 2008 and 2007, 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. It is customary for us to enter into foreign currency forward exchange contracts in the normal course of business. These contracts may require us to exchange predetermined amounts of foreign currencies on specified dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for certain of our outstanding contracts is the average spot rate for the contract period. As of December 31, 2008, we had foreign currency exchange contracts outstanding, in the aggregate notional amount of $214.6 million, consisting of $50.1 million in Australian dollars, $69.4 million in Brazilian reais, $62.1 million in British pounds sterling, $16.9 million in Mexican pesos and $16.1 million in Norwegian kroner. These contracts settle at various times through June 2009. At December 31, 2008, we have presented the fair value of our outstanding foreign currency forward exchange contracts as a current liability of $(37.3) million in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of this report in accordance with SFAS No. 133, “Accounting for Derivatives and Hedging Activities”. We have presented the fair value of our outstanding foreign currency forward exchange contracts at December 31, 2007 as a current asset of $2,000 in “Prepaid expenses and other current assets” and a current liability of $(93,000) in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of 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, 2008 and 2007.

     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,
	2008			2007			2008			2007
				(In thousands)
Interest rate:
Marketable securities	$	400,592	(a)	$	1,301	(a)	$	(2,000	) (c)	$	(100	) (c)
Long-term debt		470,040	(b)		(500,303	) (b)		—			—
Foreign Exchange:
Forward exchange contracts – receivable positions		—	(d)		2	(d)		—	(e)		(100	) (e)
Forward exchange contracts – liability positions		(37,300	) (d)		(93	) (d)		(32,600	) (e)		(3,400	) (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, 2008 and 2007.
(b)	The fair values of our 4.875% Senior Notes and 5.15% Senior Notes are based on the quoted closing market prices on December 31, 2008 and December 31, 2007. The fair value of our Zero Coupon Debentures is based on the closing market price of our common stock on December 31, 2008 and quoted closing market prices on December 31, 2007. There were no 1.5% Debentures outstanding at December 31, 2008.
(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, 2008 and 2007.
(d)	The fair value of our foreign currency forward exchange contracts is based on both quoted market prices and valuations derived from pricing models on December 31, 2008 and 2007.

51

(e) The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their values at December 31, 2008 and 2007, with all other variables held constant.

52

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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, 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 24, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.

Deloitte & Touche LLP
Houston, Texas
February 24, 2009

53

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, 2008, 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, 2008, 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, 2008 of the Company and our report dated February 24, 2009 expressed an unqualified opinion on those financial statements.

Deloitte & Touche LLP
Houston, Texas
February 24, 2009

54

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

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

	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	336,052		$	637,961
Marketable securities		400,592			1,301
Accounts receivable		574,842			522,808
Prepaid expenses and other current assets		123,046			103,120
Assets held for sale		32,201			—
Total current assets		1,466,733			1,265,190
Drilling and other property and equipment, net of accumulated depreciation		3,398,704			3,040,063
Other assets		73,325			36,212
Total assets	$	4,938,762		$	4,341,465
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	3,563
Accounts payable		93,982			132,243
Accrued liabilities		329,526			235,521
Taxes payable		85,579			81,684
Total current liabilities		509,087			453,011
Long-term debt		503,280			503,071
Deferred tax liability		459,205			397,629
Other liabilities		118,553			110,687
Total liabilities		1,590,125			1,464,398
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; 143,917,850 shares issued and 139,001,050 shares outstanding at December 31, 2008; 143,787,206 shares issued and 138,870,406 shares outstanding at December 31, 2007)		1,439			1,438
Additional paid-in capital		1,845,343			1,831,492
Retained earnings		1,615,758			1,158,535
Accumulated other comprehensive gains		510			15
Treasury stock, at cost (4,916,800 shares at December 31, 2008 and 2007)		(114,413	)		(114,413	)
Total stockholders’ equity		3,348,637			2,877,067
Total liabilities and stockholders’ equity	$	4,938,762		$	4,341,465

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

55

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

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

	Year Ended December 31,
	2008			2007			2006
Revenues:
Contract drilling	$	3,476,417		$	2,505,663		$	1,987,114
Revenues related to reimbursable expenses		67,640			62,060			65,458
Total revenues		3,544,057			2,567,723			2,052,572
Operating expenses:
Contract drilling		1,185,007			1,003,789			805,380
Reimbursable expenses		65,895			60,261			64,142
Depreciation		286,850			235,251			200,503
General and administrative		60,142			53,483			41,551
Bad debt expense		31,952			—			—
Casualty (gain) loss		6,281			—			(500	)
(Gain) loss on disposition of assets		(2,831	)		(8,583	)		1,064
Total operating expenses		1,633,296			1,344,201			1,112,140
Operating income		1,910,761			1,223,522			940,432
Other income (expense):
Interest income		11,744			33,566			37,880
Interest expense		(10,096	)		(19,191	)		(24,096	)
Foreign currency transaction gain (loss)		(65,566	)		2,906			10,343
Other, net		770			5,734			1,773
Income before income tax expense		1,847,613			1,246,537			966,332
Income tax expense		(536,593	)		(399,996	)		(259,485	)
Net income	$	1,311,020		$	846,541		$	706,847
Earnings per share:
Basic	$	9.43		$	6.14		$	5.47
Diluted	$	9.43		$	6.12		$	5.12
Weighted-average shares outstanding:
Shares of common stock		138,959			137,816			129,129
Dilutive potential shares of common stock		114			1,129			9,652
Total weighted-average shares outstanding assuming dilution		139,073			138,945			138,781

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

56

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, 2006		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
Net income		—		—		—		1,311,020				—			—		—			1,311,020
Dividends to stockholders ($6.125 per share)		—		—		—		(851,128	)			—			—		—			(851,128	)
Anti-dilution adjustment paid to stock plan participants ($5.625 per share)		—		—		—		(2,669	)			—			—		—			(2,669	)
Conversion of long-term debt		71,574		1		3,532		—				—			—		—			3,533
Reversal of deferred tax liability related to imputed interest on converted debentures		—		—		532		—				—			—		—			532
Stock options exercised		59,070		—		2,002		—				—			—		—			2,002
Stock-based compensation, net		—		—		7,785		—				—			—		—			7,785
Gain on investments, net		—		—		—		—				495			—		—			495
December 31, 2008		143,917,850	$	1,439	$	1,845,343	$	1,615,758			$	510			4,916,800	$	(114,413	)	$	3,348,637

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

57

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)

	Year Ended December 31,
	2008			2007			2006
Net income	$	1,311,020		$	846,541		$	706,847
Other comprehensive gains (losses), net of tax:
Pension plan termination		—			4,526			—
Unrealized holding gain on investments		507			188			162
Reclassification adjustment for gain included in net income		(12	)		(282	)		(62	)
Total other comprehensive gain		495			4,432			100
Comprehensive income before adoption of SFAS 158, net of tax		1,311,515			850,973			706,947
Adjustment to initially apply SFAS 158, net of tax		—			—			(4,526	)
Comprehensive income	$	1,311,515		$	850,973		$	702,421

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

58

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

	Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income	$	1,311,020		$	846,541		$	706,847
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		286,850			235,251			200,503
(Gain) loss on disposition of assets		(2,831	)		(8,583	)		1,064
Casualty (gain) loss		6,281			—			(500	)
(Gain) loss on sale of marketable securities, net		(1,282	)		(1,796	)		31
(Gain) loss on foreign currency forward exchange contracts		54,010			(5,423	)		(9,510	)
Deferred tax provision		61,498			1,770			610
Accretion of discounts on marketable securities		(2,258	)		(11,830	)		(14,090	)
Amortization of debt issuance costs		529			9,649			848
Amortization of debt discounts		242			238			392
Stock-based compensation expense		6,293			4,454			3,106
Excess tax benefits from stock-based payment arrangements		(1,392	)		(5,194	)		(1,313	)
Deferred income, net		4,610			35,645			7,924
Deferred expenses, net		(20,556	)		(37,429	)		6,317
Other items, net		3,995			15,640			20,878
Changes in operating assets and liabilities:
Accounts receivable		(42,451	)		43,467			(190,054	)
Prepaid expenses and other current assets		1,318			(3,933	)		(9,857	)
Accounts payable and accrued liabilities		(27,150	)		25,896			47,591
Taxes payable		(19,038	)		63,953			(10,698	)
Net cash provided by operating activities		1,619,688			1,208,316			760,089
Investing activities:
Capital expenditures (including rig acquisitions)		(666,857	)		(647,101	)		(551,237	)
Proceeds from sale/involuntary conversion of assets		5,881			10,861			4,731
Proceeds from sale and maturities of marketable securities		1,493,803			3,163,475			2,187,766
Purchase of marketable securities		(1,888,792	)		(2,850,135	)		(2,472,431	)
(Payments for) proceeds from settlement of forward contracts		(16,800	)		8,109			7,289
Net cash used in investing activities		(1,072,765	)		(314,791	)		(823,882	)
Financing activities:
Debt issuance costs and arrangement fees		—			—			(520	)
Payment of dividends		(852,153	)		(796,292	)		(258,155	)
Proceeds from stock options exercised		2,002			10,836			3,263
Excess tax benefits from share-based payment arrangements		1,392			5,194			1,313
Redemption of remaining 1.5% debentures		(73	)		—			—
Net cash used in financing activities		(848,832	)		(780,262	)		(254,099	)
Net change in cash and cash equivalents		(301,909	)		113,263			(317,892	)
Cash and cash equivalents, beginning of year		637,961			524,698			842,590
Cash and cash equivalents, end of year	$	336,052		$	637,961		$	524,698

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

59

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 45 offshore rigs consisting of 30 semisubmersibles, 14 jack-ups and one drillship. 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, 2009, Loews Corporation, or Loews, owned 50.4% 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, at December 31, 2007, a contingent interest provision that was embedded in our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, issued on April 11, 2001. See Notes 5 and 6.

Supplementary Cash Flow Information

     We paid interest totaling $25.1 million, $25.3 million and $32.5 million on long-term debt for the years ended December 31, 2008, 2007 and 2006, respectively.

     We paid $120.7 million, $31.7 million and $10.8 million in foreign income taxes, net of foreign tax refunds, during the years ended December 31, 2008, 2007 and 2006, respectively. We paid $393.2 million, $299.0 million and $262.4 million in U.S. federal income taxes during the years ended December 31, 2008, 2007 and 2006, respectively. We received refunds of $25,000 and $13.7 million in U.S. income taxes during the years ended December 31, 2007 and 2006, respectively. We paid state income taxes of $0.6 million during the year ended December 31, 2007 and received a $0.1 million refund of state income tax during the year ended December 31, 2008.

     Cash payments for capital expenditures for the year ended December 31, 2008 included $43.0 million of capital expenditures that were accrued but unpaid at 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. Capital expenditures that were accrued but not paid as of December 31, 2008, totaled $59.4 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2008.

60

     We recorded income tax benefits of $1.5 million, $2.7 million and $1.7 million related to the exercise of employee stock options in 2008, 2007 and 2006, respectively.

     During 2008 and 2007, holders of $33,000 and $1.5 million, respectively, in accreted, or carrying, value through the date of conversion of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, elected to convert their outstanding debentures into shares of our common stock. Also during 2008 and 2007, the holders of $3.5 million and $456.4 million, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. See Note 10.

Assets Held For Sale

     At December 31, 2008, we had transferred the $32.2 million net book value of theOcean Tower to “Assets held for sale” in our Consolidated Balance Sheets. In December 2008, we entered into an agreement to sell the rig, which was damaged during Hurricane Ike (see Note 17), at a price in excess of its $32.2 million carrying value. In connection with the execution of the sales agreement, we received a $3.5 million deposit from the purchaser which we have recorded in “Accrued liabilities” in our Consolidated Balance Sheet at December 31, 2008. We expect to complete the sale in the first quarter of 2009.

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. For the three years ended December 31, 2008, 2007 and 2006, we capitalized interest on qualifying expenditures related to the upgrades of theOcean EndeavorandOcean Monarchfor ultra-deepwater service and the construction of two jack-up rigs, theOcean ShieldandOcean Scepter, through the date of each project’s completion. The upgrades of theOcean EndeavorandOcean Monarchwere completed in March 2007 and December 2008, respectively. Construction of theOcean ShieldandOcean Scepterwere completed in May 2008 and August 2008, 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,
	2008			2007			2006
	(In thousands)
Total interest cost including amortization of debt issuance costs	$	26,966		$	37,735		$	33,892
Capitalized interest		(16,870	)		(18,544	)		(9,796	)
Total interest expense as reported	$	10,096		$	19,191		$	24,096

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, 2008 and 2007, we had no asset retirement obligations.

61

Impairment of Long-Lived Assets

     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.

     2008. As of December 31, 2008, all, except for two, of our drilling rigs were either under contract, in shipyards for surveys or contract modifications or, as in the case of the recently upgradedOcean Monarch,mobilizing to the U.S. One of these idle units, theOcean Tower, which was damaged during Hurricane Ike in September 2008 (See Note 17), has been transferred to “Assets held for sale” in our Consolidated Balance Sheets. We have entered into an agreement to sell the rig for a price in excess of its carrying value. (See “ –Assets Held For Sale.”) At December 31, 2008, the second of our idle rigs was ready-stacked while waiting to begin drilling operations in early January 2009. Consequently, we determined that an impairment test of our drilling equipment was not needed as we are currently marketing all of our drilling units and did not have any cold-stacked rigs at December 31, 2008. We do not believe that current circumstances indicate that the carrying amount of our property and equipment may not be recoverable.

     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 were currently marketing all of our drilling units at the time. We did not have any cold-stacked rigs at December 31, 2007. We did not believe that current circumstances at that time indicated that the carrying amount of our property and equipment might 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.

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 Notes 6 and 13.

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 2008 included $84,000 in debt issuance costs that we wrote off in connection with the conversions and final redemption of our 1.5% Debentures during 2008. Interest expense for the years ended December 31, 2007 and 2006 included $9.2 million and $0.2 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 10.

Income Taxes

     We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” which requires

62

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.

     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 or 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 activity. In December 2007, this subsidiary made a non-recurring distribution to its U.S. parent. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign activities, except for the earnings of Diamond East Asia Limited, a wholly-owned subsidiary of Diamond Offshore International Limited formed in December 2008. It is our intention to repatriate the earnings of Diamond East Asia Limited and, accordingly, U.S. income taxes are recorded on its earnings.

     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 $19.3 million for uncertain tax positions (excluding interest and penalties), 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. See Note 15.

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 2008, 2007 or 2006.

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, 2008, 2007 and 2006 includes net income (loss), 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 11.

Foreign Currency

     Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses, including gains and losses from the settlement of foreign currency forward exchange contracts, are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. During the year ended December 31, 2008, we recognized net foreign currency exchange losses of $65.6 million. 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. 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

63

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 (either lump-sum or dayrate). 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.

     Previously reported amounts for “Reimbursable expenses” in our Consolidated Statements of Operations for the years ended December 31, 2007 and 2006 have been adjusted to include $7.4 million and $6.7 million, respectively, in reimbursable catering expense to conform to the current year presentation. These amounts were previously reported as “Contract drilling” expense in our Consolidated Statements of Operations. This reclassification had no effect on total operating expenses, operating income or net income for the years ended December 31, 2007 and 2006.

Recent Accounting Pronouncements

     In May 2008, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position, or FSP, Accounting Principles Board, or APB, 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),” or FSP APB 14-1. FSP APB 14-1 applies to convertible debt instruments that, by their stated terms, may be settled in cash upon conversion (including partial cash settlement). The FSP requires bifurcation of the instrument into a debt component that is initially valued at fair value and an equity component. The debt component is accreted to par value using the effective yield method, and accretion is reported as a component of interest expense. The equity component is not subsequently revalued as long as it continues to qualify for equity treatment. FSP APB 14-1 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years on a retrospective basis for all periods presented. We will adopt FSP APB 14-1 effective January 1, 2009. We do not expect the adoption of this staff position to have a material effect on our results of operations or financial position in 2009 or prospectively.

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

64

common stock on the date of grant. Generally, stock options and SARs vest ratably over a four year period and expire in ten years.

     Total compensation cost recognized for Stock Plan transactions for the years ended December 31, 2008, 2007 and 2006 was $6.3 million, $4.5 million and $3.1 million, respectively. Tax benefits recognized for the years ended December 31, 2008, 2007 and 2006 related thereto were $2.1 million, $1.5 million and $1.1 million, respectively.

     For the year ended December 31, 2006 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,
	2008			2007			2006
Expected life of stock options/SARs (in years)		5			5			6
Expected volatility		31.96	%		27.53	%		30.72	%
Dividend yield		.51	%		.48	%		.62	%
Risk free interest rate		2.66	%		4.28	%		4.85	%

     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, 2008 and changes during the year then ended is as follows:

						Weighted-
						Average		Aggregate
				Weighted-		Remaining		Intrinsic
	Number of			Average		Contractual		Value
	Awards			Exercise Price		Term		(In Thousands)
Awards outstanding at January 1, 2008		432,777		$	85.44
Granted		195,600		$	108.18
Exercised		(80,845	)	$	62.35
Forfeited		—		$	—
Expired		(500	)	$	21.66
Awards outstanding at December 31, 2008		547,032		$	97.04		8.5	$	637
Awards exercisable at December 31, 2008		124,759		$	88.31		7.9	$	476

     The weighted-average grant date fair values of options granted during the years ended December 31, 2008, 2007 and 2006 were $33.73, $36.80 and $39.24, respectively. The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006 was $6.3 million, $20.6 million and $5.0 million, respectively. The total fair value of stock options vested during the years ended December 31, 2008, 2007 and 2006 was $5.3 million, $3.6 million and $2.7 million, respectively. As of December 31, 2008 there was $11.3 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 2.48 years.

65

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,
	2008		2007		2006
	(In thousands, except per share data)
Net income – basic (numerator):	$	1,311,020	$	846,541	$	706,847
Effect of dilutive potential shares
Zero Coupon Debentures		32		51		236
1.5% Debentures		22		3,087		3,293
Net income including conversions – diluted (numerator):	$	1,311,074	$	849,679	$	710,376
Weighted-average shares – basic (denominator):		138,959		137,816		129,129
Effect of dilutive potential shares
Zero Coupon Debentures		51		54		119
1.5% Debentures		19		1,015		9,383
Stock options and SARs		44		60		150
Weighted-average shares including conversions – diluted (denominator):		139,073		138,945		138,781
Earnings per share:
Basic	$	9.43	$	6.14	$	5.47
Diluted	$	9.43	$	6.12	$	5.12

     Our computation of diluted EPS for the year ended December 31, 2008 excludes stock options representing 3,362 shares of common stock and 254,821 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.

     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.

66

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, 2008
	Amortized		Unrealized		Market
	Cost		Gain		Value
	(In thousands)
Due within one year	$	398,791	$	758	$	399,549
Mortgage-backed securities		1,016		27		1,043
Total	$	399,807	$	785	$	400,592

	December 31, 2007
	Amortized		Unrealized		Market
	Cost		Gain		Value
			(In thousands)
Mortgage-backed securities	$	1,277	$	24	$	1,301

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

	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Proceeds from maturities	$	550,000		$	1,325,000		$	950,000
Proceeds from sales		943,803			1,838,475			1,237,766
Gross realized gains		1,291			1,856			188
Gross realized losses		(9	)		(60	)		(219	)

5. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

     Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. We may utilize foreign exchange forward contracts to reduce our forward exchange risk. Our foreign currency forward exchange contracts may obligate us to exchange predetermined amounts of foreign currencies on specified dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for certain of our contracts, is the average spot rate for the contract period.

     We enter into foreign currency forward exchange contracts when we believe market conditions are favorable to purchase contracts for future settlement with the expectation that such contracts, when settled, will minimize our exposure to foreign currency gains/losses on foreign currency expenditures in the future. The amount and duration of such contracts is based on our annual forecast of expenditures in the significant currencies in which we do business and for which there is a financial market (i.e., Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner). 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. We did not seek hedge accounting treatment for these contracts under SFAS 133. Accordingly, adjustments to record the carrying value of our derivative financial instruments at fair value are reported as “Foreign

67

currency transaction gain (loss)” in our Consolidated Statements of Operations. Realized gains or losses upon settlement of the derivative contracts are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.

     As of December 31, 2008, we had foreign currency exchange contracts outstanding, in the aggregate notional amount of $214.6 million, consisting of $50.1 million in Australian dollars, $69.4 million in Brazilian reais, $62.1 million in British pounds sterling, $16.9 million in Mexican pesos and $16.1 million in Norwegian kroner. These contracts settle at various times through June 2009. See Note 6.

     The following table presents the fair values of our derivative financial instruments at December 31, 2008 and 2007 not designated as hedging instruments under SFAS 133:

	December 31,
	2008				2007
	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
	(In thousands)
Asset Derivatives:
Foreign currency forward exchange contracts	Prepaid expenses and other current assets	$	—		Prepaid expenses and other current assets	$	2
Liability Derivatives:
Foreign currency forward exchange contracts	Accrued liabilities	$	(37,301	)	Accrued liabilities	$	(93	)

     The following table presents the amounts recognized in our Consolidated Statements of Operations for the three years ended December 31, 2008, 2007 and 2006 related to our derivative financial instruments not designated as hedging instruments under SFAS 133. During the three-year period ended December 31, 2008, we did not have any derivative instruments designated as hedging instruments under SFAS 133.

		Amount of Gain (Loss) Recognized in Income
		Year Ended December 31
	Location of Gain (Loss)
Type of Instrument	Recognized in Income	2008			2007		2006
		(In thousands)
Foreign currency forward exchange contracts	Foreign currency transaction gain (loss)	$	(54,010	)	$	5,423	$	9,510

     The amounts presented in the table above include unrealized gains (losses) of $(37.2) million, $(91,000) and $2.2 million for the years ended December 31, 2008, 2007 and 2006, respectively, to record the carrying value of our derivative financial instruments to their fair value.

Contingent Interest

     Our 1.5% Debentures, which were redeemed in full in April 2008, contained a contingent interest provision. The contingent interest component was an embedded derivative as defined by SFAS 133 and was required to 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.

68

6. Fair Value Disclosures

     Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” or SFAS 157, which requires additional disclosures about our assets and liabilities that are measured at fair value. SFAS 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. SFAS 157 also establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:

Level 1	Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds and U.S. Treasury Bills. Our Level 1 assets at December 31, 2008 included cash held in money market funds of $300.5 million and investments in U.S. Treasury Bills of $399.5 million.
Level  2	Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 assets and liabilities include mortgage-backed securities and over-the-counter foreign currency forward exchange contracts that are valued using a model-derived valuation technique.
Level 3	Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

     Assets measured at fair value on a recurring basis are summarized below:

	December 31, 2008
	Fair Value Measurements Using							Assets at Fair
	Level 1		Level 2			Level 3		value
	(In thousands)
Assets:
Short-term investments	$	700,038	$	—		$	—	$	700,038
Mortgage-backed securities		—		1,043			—		1,043
Total assets	$	700,038	$	1,043		$	—	$	701,081
Liabilities:
Forward exchange contracts	$	—	$	(37,301	)	$	—	$	(37,301	)

7. Prepaid Expenses and Other Current Assets

     Prepaid expenses and other current assets consist of the following:

	December 31,
	2008		2007
	(In thousands)
Rig spare parts and supplies	$	52,481	$	50,699
Deferred mobilization costs		28,924		17,295
Prepaid insurance		11,845		11,444
Deferred tax assets		9,350		9,006
Vendor prepayments		889		7,296
Deposits		3,846		2,292
Prepaid taxes		11,589		1,681
Forward exchange contracts		—		2
Other		4,122		3,405
Total	$	123,046	$	103,120

69

8. Drilling and Other Property and Equipment

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

	December 31,
	2008			2007
	(In thousands)
Drilling rigs and equipment	$	5,581,712		$	4,540,797
Construction work-in-progress		—			453,093
Land and buildings		35,069			24,123
Office equipment and other		34,021			29,742
Cost		5,650,802			5,047,755
Less accumulated depreciation		(2,252,098	)		(2,007,692	)
Drilling and other property and equipment, net	$	3,398,704		$	3,040,063

     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. As of December 31, 2008, these projects had been completed and the related assets placed in service. At December 31, 2008, there were no ongoing construction projects.

9. Accrued Liabilities

     Accrued liabilities consist of the following:

	December 31,
	2008		2007
	(In thousands)
Accrued project/upgrade expenses	$	107,502	$	96,211
Payroll and benefits		69,326		52,975
Deferred revenue		39,307		36,134
Foreign currency forward exchange contracts		37,301		93
Rig operating expenses		29,749		19,868
Personal injury and other claims		10,489		8,692
Interest payable		10,385		10,413
Hurricane related expenses		5,080		1,380
Other		20,387		9,755
Total	$	329,526	$	235,521

10. Long-Term Debt

     Long-term debt consists of the following:

	December 31,
	2008		2007
	(In thousands)
Zero Coupon Debentures (due 2020)	$	4,036	$	3,931
1.5% Debentures (due 2031)		—		3,563
5.15% Senior Notes (due 2014)		249,623		249,566
4.875% Senior Notes (due 2015)		249,621		249,574
		503,280		506,634
Less: Current maturities		—		3,563
Total	$	503,280	$	503,071

70

     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 Zero Coupon Debentures have the right to require us to purchase all or a portion of their outstanding debentures on June 6, 2010. See “Zero Coupon 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, 2008, are as follows:

(Dollars in thousands)
2009	$	—
2010		4,036
2011		—
2012		—
2013		—
Thereafter		499,244
Total	$	503,280

$285 Million Revolving Credit Facility.

     In November 2006, we entered into a $285 million syndicated, senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit, that will mature on November 2, 2011.

     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, 2008, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2008, there were no loans outstanding under the Credit Facility. See Note 12 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

71

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.

     During 2008 and 2007, holders of $33,000 and $1.5 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 430 and 20,658 shares of our common stock upon conversion of these debentures during 2008 and 2007, respectively. The aggregate principal amount at maturity of our Zero Coupon Debentures converted during 2008 and 2007 was $50,000 and $2.4 million, respectively.

     As of December 31, 2008, the aggregate accreted value of our outstanding Zero Coupon Debentures was $4.0 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

     On April 11, 2001, we issued $460.0 million principal amount of 1.5% Debentures, which were due April 15, 2031. The 1.5% Debentures were 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. During the period from January 1, 2008 to April 14, 2008 and the year ended December 31, 2007, the holders of $3.5 million and $456.4 million, respectively, in aggregate principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 71,144 shares and 9,309,616 shares of our common stock in 2008 and 2007, respectively, pursuant to these conversions.

     In addition, we had 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. On April 15, 2008, we completed the redemption of all of our outstanding 1.5% Debentures, and, as a result, redeemed for cash the remaining $73,000 aggregate principal amount outstanding of our 1.5% Debentures.

     As a result of the conversions of our 1.5% Debentures, we reversed $0.5 million and $54.2 million in non-current deferred tax liabilities during 2008 and 2007, respectively, related to interest expense imputed on these debentures for U.S. federal income tax return purposes. See Note 15.

72

11. 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, 2008
	Before Tax			Tax Effect			Net-of-Tax
				(In thousands)
Unrealized gain (loss) on investments:
Gain arising during 2008	$	780		$	(273	)	$	507
Reclassification adjustment		(18	)		6			(12	)
Net unrealized gain		762			(267	)		495
Other comprehensive income	$	762		$	(267	)	$	495

	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	)

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

	Adjustment to
	Initially Apply			Unrealized Gain			Total Other
	SFAS 158, Net			(Loss) on			Comprehensive
	of Tax			Investments			Income (Loss)
	(In thousands)
Balance at January 1, 2006	$	—		$	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
Other comprehensive gain		—			495			495
Balance at December 31, 2008	$	—		$	510		$	510

73

12. 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,” or SFAS 5, 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, 2008, our loss reserves related to our Brazilian operations aggregated $5.5 million, of which $2.0 million and $3.5 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. Loss reserves related to our Brazilian operations totaled $8.5 million at December 31, 2007, of which $1.9 million was recorded in “Accrued liabilities” and $6.6 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 result from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence, with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. 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, 2008, our estimated liability for personal injury claims was $30.1 million, of which $9.5 million and $20.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2007, we had recorded loss reserves for personal injury claims aggregating $32.0 million, of which $8.5 million and $23.5 million were recorded in “Accrued liabilities” and “Other liabilities,”

74

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, 2008, we had purchase obligations aggregating approximately $23 million related to the major upgrade of theOcean Monarch. We expect to complete funding of this project in 2009.

     We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2008, 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 2013. Total rent expense amounted to $5.7 million, $4.6 million and $3.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. Future minimum rental payments under leases are approximately $2.7 million, $0.8 million, $0.4 million, $0.1 million and nil for the years ending December 31, 2009, 2010, 2011, 2012 and 2013, respectively. There are no minimum future rental payments under leases after 2013.

     Letters of Credit and Other.We were contingently liable as of December 31, 2008 in the amount of $149.1 million under certain performance, bid, supersedeas and custom bonds and letters of credit, including $58.1 million in letters of credit issued under our Credit Facility. At December 31, 2008, we had purchased six of our outstanding bonds totaling $88.5 million from a related party after obtaining competitive quotes. Agreements relating to approximately $80.3 million of performance bonds can require collateral at any time. As of December 31, 2008, 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.

13. 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. In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements.

     In December 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected balance of one of our customers in the United Kingdom, or U.K., that has entered into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy). We also provide allowances for potential credit losses when necessary. No additional allowances were deemed necessary for the years presented. Prior to December 2008, we have not experienced significant losses on our trade receivables.

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

75

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,
	2008				2007
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
Zero Coupon Debentures	$	3.0	$	4.0	$	7.4	$	3.9
1.5% Debentures		—		—		10.3		3.6
4.875% Senior Notes		230.0		249.6		238.6		249.6
5.15% Senior Notes		237.0		249.6		244.0		249.6

     We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of December 31, 2008 and 2007, 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, 2008 and 2007, 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 both quoted market prices and valuations derived from pricing models on December 31, 2008 and 2007, 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, 2008 and 2007, respectively, from brokers of these instruments. The fair value of our Zero Coupon Debentures was based on the closing market price of our common stock on December 31, 2008 and 2007, respectively, and the stated conversion rate for these debentures. The fair value of our 1.5% Debentures at December 31, 2007 was based on the closing market price of our stock on December 31, 2007 and the stated conversion rate for the debenture. There were no 1.5% Debentures outstanding at December 31, 2008.

14. 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, internal auditing, accounting, 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 $0.5 million, $0.4 million and $0.4 million by Loews for these support functions during the years ended December 31, 2008, 2007 and 2006, respectively.

     In addition, since 2006 we purchased five performance bonds in support of our drilling operations offshore Mexico (four of which remain outstanding at December 31, 2008) and two appeal bonds totaling $88.5 million from affiliates of a majority-owned subsidiary of Loews after obtaining competitive quotes. Premiums and fees associated with these bonds totaled $74,000, $45,000 and $1.0 million in 2008, 2007 and 2006, respectively.

76

     Transactions with Other Related Parties.We hire 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, 2008, 2007 and 2006, we paid $0.5 million, $4.6 million and $0.7 million, respectively, for the hire of such vessels and such services.

     During the years ended December 31, 2008, 2007 and 2006 we made payments of $2.0 million, $1.1 million and $0.6 million, respectively, to Ernst & Young LLP for tax and other consulting services. The wife of our President and Chief Executive Officer is an audit partner at this firm.

15. Income Taxes

     Our income tax expense 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, or DOIL, 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, DOIL 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 in 2007 as a result of the distribution. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest future earnings of DOIL to finance foreign activities except for the earnings of Diamond East Asia Limited, a wholly-owned subsidiary of DOIL formed in December 2008. It is our intention to repatriate the earnings of Diamond East Asia Limited and, accordingly, U.S. income taxes are provided on its earnings.

     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, 2008, we provided $0.3 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,
	2008			2007			2006
				(In thousands)
Federal – current	$	346,796		$	338,638		$	230,907
State – current		(282	)		950			—
Foreign – current		128,581			58,638			27,968
Total current		475,095			398,226			258,875
Federal – deferred		52,718			7,594			5,006
Foreign – deferred		8,780			(5,824	)		(4,396	)
Total deferred		61,498			1,770			610
Total	$	536,593		$	399,996		$	259,485

77

     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,
	2008			2007			2006
	(In thousands)
Income before income tax expense:
U.S	$	1,376,125		$	947,476		$	765,583
Foreign		471,488			299,061			200,749
Worldwide	$	1,847,613		$	1,246,537		$	966,332
Expected income tax expense at federal statutory rate	$	646,665		$	436,288		$	338,216
Foreign earnings of foreign subsidiaries (not taxed at the statutory federal income tax rate) net of related foreign taxes		(87,383	)		(70,800	)		(60,624	)
Foreign taxes – domestic companies		66,435			22,111			15,200
Foreign tax credits		(72,205	)		(27,238	)		(15,087	)
$850.0 million distribution from foreign subsidiary		—			58,562			—
Valuation allowance – foreign tax credits		—			—			(831	)
Reduction of deferred tax liability related to Arethusa goodwill deduction		(8,850	)		(8,850	)		(8,850	)
Domestic production activities deduction		(14,351	)		(12,740	)		(8,339	)
Uncertain tax positions		4,446			4,466			—
Nondeductible deferred arrangement fee		3,212			—			—
Revision of estimated tax balance		(2,022	)		(130	)		1,039
Amortization of deferred tax liability related to transfer of drilling rigs to different taxing jurisdictions		(1,480	)		(1,580	)		(1,580	)
Other		2,126			(93	)		341
Income tax expense	$	536,593		$	399,996		$	259,485

78

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

	December 31,
	2008			2007
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	900		$	1,831
Goodwill		7,346			10,494
Worker’s compensation and other current accruals (1)		13,248			12,905
Disputed receivables reserved		4,599			4,831
Deferred compensation		6,233			3,730
Foreign deferred taxes		—			2,696
Nonqualified stock options		2,526			1,480
Other		1,942			2,450
Total deferred tax assets		36,794			40,417
Valuation allowance for foreign tax credits		—			—
Net deferred tax assets		36,794			40,417
Deferred tax liabilities:
Depreciation		(475,017	)		(425,488	)
Foreign deferred taxes		(6,084	)		—
Mobilization		(4,488	)		(2,630	)
Other		(1,060	)		(922	)
Total deferred tax liabilities		(486,649	)		(429,040	)
Net deferred tax liability	$	(449,855	)	$	(388,623	)

(1) $9.4 million and $9.0 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance Sheets at December 31, 2008 and 2007, respectively. See Note 7.

     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 $19.3 million for uncertain tax positions (excluding interest and penalties), 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, excluding interest and penalties is as follows:

	Long term						Net Liability
	Tax			Long term Tax			for Uncertain Tax
	Receivable			Payable			Positions
				(In thousands)
Balance at January 1, 2007	$	2,642		$	(19,277	)	$	(16,635	)
Additions based on tax positions related to the current year		785			(4,479	)		(3,694	)
Balance at December 31, 2007	$	3,427		$	(23,756	)	$	(20,329	)
Reduction based on tax position related to a prior year		—			307			307
Additions based on tax positions related to the current year		2,418			(7,941	)		(5,523	)
Reductions as a result of a lapse of the applicable statute of limitations		(311	)		2,159			1,848
Balance at December 31, 2008	$	5,534		$	(29,231	)	$	(23,697	)

     At December 31, 2008 all $23.7 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 years ended December 31, 2008 and 2007, we recognized $0.8 million and $1.7 million of interest expense related to uncertain tax positions, respectively. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2008 and 2007 was $1.1 million

79

and $0.8 million, respectively. At December 31, 2008, we had $16.1 million accrued for the payment of interest and penalties in our Consolidated Balance Sheets. At December 31, 2007, we had $14.2 million accrued for the payment of interest and penalties in our Consolidated Balance Sheets.

     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 $12.1 million through December 31, 2009.

     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 2007. We are currently under audit in several of these jurisdictions including an audit by the Internal Revenue Service of years 2004, 2005 and 2006. We do not anticipate that any adjustments resulting from the tax audits will have a material impact on our consolidated results of operations, financial position and cash flows.

     The Brazilian tax authorities are auditing our income tax returns for the periods 2000, 2004 and 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 years ended December 31, 2008 and 2007, the holders of certain of our debentures elected to convert them into shares of our common stock. See Note 10. As a result of the conversions of our 1.5% Debentures, we reversed a non-current deferred tax liability of $0.5 million and $54.2 million in 2008 and 2007, respectively, 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, 2008, we had net operating loss, or NOL, carryforwards of approximately $2.6 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 2009 and 2010. During 2008, we were able to utilize approximately $2.7 million of the NOL carryforwards.

16. 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 years ended December 31, 2008 and 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 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, 2008, 2007 and 2006, our provision for contributions was $23.8 million, $20.9 million and $9.0 million, respectively.

     The defined contribution retirement plan for our U.K. employees, or U.K. Plan, provides that we make annual

80

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 $1.7 million, $1.5 million and $1.2 million for the years ended December 31, 2008, 2007 and 2006, respectively.

     The defined contribution retirement plan for our TCN employees, or TCN Plan, is similar to the 401k Plan. During 2008 and 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. During 2006 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 $2.3 million, $2.1 million and $0.9 million for the years ended December 31, 2008, 2007 and 2006, 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, 2008, 2007 and 2006 was approximately $222,000, $192,000 and $65,000, respectively.

17. Hurricane Damage and Casualty Loss

Casualty (Gain) Loss

     In September 2008, theOcean Towersustained significant damage during Hurricane Ike, which impacted the Gulf of Mexico and the upper Texas and Louisiana Gulf coasts. TheOcean Towerlost its derrick, drill floor and drill floor equipment during the hurricane. During the third quarter of 2008, we wrote off the net book value of the derrick, drill floor and drill floor equipment for theOcean Towerof approximately $2.6 million and accrued $3.7 million in estimated salvage costs for the recovery of equipment from the ocean floor. The aggregate of these items is reflected in “Casualty (Gain) Loss” in our Consolidated Statements of Operations for the year ended December 31, 2008.

     In December 2008, we transferred the $32.2 million net book value of theOcean Towerto “Assets held for sale” in our Consolidated Balance Sheets pursuant to entering into an agreement to sell the rig for use in a non-drilling capacity at a price in excess of its carrying value. We expect to complete the sale in the first quarter of 2009.

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. During 2005, we recorded estimated deductibles of $2.5 million for salvage and wreck removal of theOcean Warwickand $2.6 million associated with our remaining rigs damaged by Hurricane Katrina and our rigs and facility damaged by Hurricane Rita. The physical damage to our rigs, as well as related removal and recovery costs, has been primarily covered by insurance, after applicable deductibles. As of December 31, 2008, we had filed all expected insurance claims related to the 2005 storms and had received insurance proceeds pursuant to these claims.

     During 2006, we reduced 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) Loss” in our Consolidated Statements of Operations for the year ended December 31, 2006. In addition, we reduced our estimate of the applicable insurance deductibles related to damages to our other rigs and facilities and recorded a $0.4 million gain on disposition of assets in our Consolidated Statements of Operations for the year ended December 31, 2006.

81

     During 2008 and 2007, we received insurance proceeds, net of deductibles, aggregating $9.4 million and $56.1 million, respectively, related to property damage and salvage/wreck removal claims filed as a result of these hurricanes. For the year ended December 31, 2007, we recognized insurance gains of $4.9 million resulting from the involuntary conversion of assets lost during the hurricanes, which we recorded as “Gain on disposition of assets” in our Consolidated Statements of Operations. 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.

18. 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,
	2008		2007		2006
	(In thousands)
High-Specification Floaters	$	1,322,125	$	1,030,892	$	766,873
Intermediate Semisubmersibles		1,629,358		1,028,667		785,047
Jack-ups		524,934		446,104		435,194
Total contract drilling revenues		3,476,417		2,505,663		1,987,114
Revenues related to reimbursable expenses		67,640		62,060		65,458
Total revenues	$	3,544,057	$	2,567,723	$	2,052,572

Geographic Areas

     At December 31, 2008, 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 international operations and our results of operations and the value of our international 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,
	2008		2007		2006
	(In thousands)
United States	$	1,443,200	$	1,288,535	$	1,179,676
International:
Europe/Africa/Mediterranean		634,033		473,665		250,103
South America		583,876		256,236		203,338
Australia/Asia/Middle East		557,138		400,701		323,003
Mexico		325,810		148,586		96,452
		2,100,857		1,279,188		872,896
Total revenues	$	3,544,057	$	2,567,723	$	2,052,572

82

     An individual international 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, 2008, 2007 and 2006, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.

	Year Ended December 31,
	2008			2007			2006
Brazil		13.0	%		9.1	%		9.9	%
Australia		9.6	%		4.8	%		4.2	%
Mexico		9.2	%		5.8	%		4.7	%
United Kingdom		8.3	%		9.6	%		7.5	%
Egypt		4.2	%		5.4	%		0.8	%

     The following table presents our long-lived tangible assets by geographic location as of December 31, 2008 and 2007. 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,
	2008		2007
	(In thousands)
Drilling and other property and equipment, net:
United States	$	1,750,289	$	1,605,961
International:
South America		801,989		440,208
Australia/Asia/Middle East		504,904		683,307
Europe/Africa/Mediterranean		243,535		206,834
Mexico		97,987		103,753
		1,648,415		1,434,102
Total	$	3,398,704	$	3,040,063

     The following table presents countries where we had a material concentration of operating assets as of December 31, 2008 and 2007:

	December 31,
	2008			2007
United States		51.5	%		53.0	%
Brazil		18.5	%		12.6	%
Malaysia		9.7	%		5.5	%
Argentina		5.0	%		—
Singapore		—			11.4	%

As of December 31, 2008 and 2007, no other countries had more than a 5% concentration of our operating assets.

83

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, 2008 and 2006 that contributed more than 10% of our total revenues are as follows:

	Year Ended December 31,
Customer	2008			2007			2006
Petróleo Brasileiro S.A.		13.1	%		9.2	%		10.4	%
Anadarko Petroleum		3.5	%		9.4	%		10.6	%

19. Unaudited Quarterly Financial Data

     Unaudited summarized financial data by quarter for the years ended December 31, 2008 and 2007 is shown below.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(In thousands, except per share data)
2008
Revenues	$	786,102	$	954,372	$	900,376	$	903,207
Operating income		401,186		577,387		475,966		456,222
Income before income tax expense		405,922		590,921		447,566		403,204
Net income		290,625		416,283		310,650		293,462
Net income per share:
Basic	$	2.09	$	3.00	$	2.23	$	2.11
Diluted	$	2.09	$	2.99	$	2.23	$	2.11
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

84

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, 2008. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2008.

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, 2008. 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, 2008, 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 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

85

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 2009 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

	Page
(1) Financial Statements
Report of Independent Registered Public Accounting Firm		53
Consolidated Balance Sheets		55
Consolidated Statements of Operations		56
Consolidated Statements of Stockholders’ Equity		57
Consolidated Statements of Comprehensive Income		58
Consolidated Statements of Cash Flows		59
Notes to Consolidated Financial Statements		60
(2) Financial Statement Schedules
Schedule II – Valuation and Qualifying Accounts for the Years Ended
December 31, 2008, 2007 and 2006		87
(3) Exhibit Index		89

     See the Exhibit Index for a list of those exhibits filed herewith, which Exhibit 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.

86

SCHEDULE II

DIAMOND OFFSHORE DRILLING, INC.

Valuation and Qualifying Accounts

Column A	Column B		Column C				Column D		Column E
			Additions
	Balance at		Charged to Costs		Charged to Other				Balance at End of
Description	Beginning of Period		and Expenses		Accounts		Deductions		Period
					(In thousands)
Deducted in balance sheet from Accounts receivable:
Allowance for doubtful accounts:
2008	$	—	$	31,952	$	—	$	—	$	31,952
2007		—		—		—		—		—
2006		—		—		—		—		—

87

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 24, 2009.

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/ LAWRENCE R. DICKERSON*Lawrence R. Dickerson	President, Chief Executive Officer and Director (Principal Executive Officer)	February 24, 2009
/s/ GARY T. KRENEK*Gary T. Krenek	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 24, 2009
/s/ BETH G. GORDON*Beth G. Gordon	Controller (Principal Accounting Officer)	February 24, 2009
/s/ JAMES S. TISCH*James S. Tisch	Chairman of the Board	February 24, 2009
/s/ JOHN R. BOLTON*John R. Bolton	Director	February 24, 2009
/s/ CHARLES L. FABRIKANT*Charles L. Fabrikant	Director	February 24, 2009
/s/ PAUL G. GAFFNEY II*Paul G. Gaffney II	Director	February 24, 2009
/s/ EDWARD GREBOW *Edward Grebow	Director	February 24, 2009
/s/ HERBERT C. HOFMANN*Herbert C. Hofmann	Director	February 24, 2009
/s/ ARTHUR L. REBELL*Arthur L. Rebell	Director	February 24, 2009
/s/ RAYMOND S. TROUBH*Raymond S. Troubh	Director	February 24, 2009

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

88

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). (SEC File No. 1-13926).
	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	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).
	4.4	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 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2007).
	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 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).

89

Exhibit No.		Description
	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+	Amendment to Employment Agreement, dated June 16, 2008, between Diamond Offshore Management Company and Lawrence R. Dickerson (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008).
	12.1*	Statement re Computation of Ratios.
	21.1*	List of Subsidiaries of Diamond Offshore Drilling, Inc.

90

Exhibit No.		Description
	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.

91