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Diamond Offshore Drilling 10-K 2008
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Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number 1-13926
DIAMOND OFFSHORE DRILLING, INC.
(Exact name of registrant as specified in its charter)
     
Delaware   76-0321760
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
15415 Katy Freeway
Houston, Texas 77094

(Address and zip code of principal executive offices)
(281) 492-5300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
     
Title of each class   Name of each exchange on which registered
Common Stock, $0.01 par value per share
  New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ     No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o     No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ     No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o     No þ
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter.
     
          As of June 30, 2007   $6,963,153,673
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
As of February 20, 2008                    Common Stock, $0.01 par value per share                     138,873,545 shares
DOCUMENTS INCORPORATED BY REFERENCE
     Portions of the definitive proxy statement relating to the 2008 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2007, are incorporated by reference in Part III of this report.
 
 

 


 

DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2007
TABLE OF CONTENTS
             
        Page No.
Cover Page        
 
           
Document Table of Contents     2  
 
           
Part I        
  Business     3  
 
           
  Risk Factors     8  
 
           
  Unresolved Staff Comments     14  
 
           
  Properties     15  
 
           
  Legal Proceedings     15  
 
           
  Submission of Matters to a Vote of Security Holders     15  
 
           
Part II        
  Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     17  
 
           
  Selected Financial Data     19  
 
           
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     20  
 
           
  Quantitative and Qualitative Disclosures About Market Risk     52  
 
           
  Financial Statements and Supplementary Data     54  
 
           
 
  Consolidated Financial Statements     56  
 
  Notes to Consolidated Financial Statements     61  
 
           
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     88  
 
           
  Controls and Procedures     88  
 
           
  Other Information     89  
 
           
Part III        
 
  Information called for by Part III Items 10, 11, 12, 13 and 14 has been omitted as the Registrant intends to file with the Securities and Exchange Commission not later than 120 days after the end of its fiscal year a definitive Proxy Statement pursuant to Regulation 14A.        
Part IV        
  Exhibits and Financial Statement Schedules     89  
 
           
Signatures     93  
 
           
Exhibit Index     94  
 Second Amended and Restated 2000 Stock Option Plan
 Summary Sheet of Base Salary Increases
 Statement re Computation of Ratios
 List of Subsidiaries
 Consent of Deloitte & Touche LLP
 Powers of Attorney
 Rule 13a-14(a) Certification of CEO
 Rule 13a-14(a) Certification of CFO
 Section 1350 Certification of CEO and CFO

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PART I
Item 1. Business.
General
     Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a current fleet of 44 offshore rigs consisting of 30 semisubmersibles, 13 jack-ups and one drillship. In addition, we have two jack-up drilling rigs, the Ocean Scepter and the Ocean Shield, under construction at shipyards in Brownsville, Texas and Singapore, respectively. We expect delivery of both of these rigs during the second quarter of 2008. Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.
The Fleet
     Our fleet includes some of the most technologically advanced rigs in the world, enabling us to offer a broad range of services worldwide in various markets, including the deep water, harsh environment, conventional semisubmersible and jack-up markets.
     Semisubmersibles. We own and operate 30 semisubmersibles, consisting of 10 high-specification and 20 intermediate rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles are typically anchored in position and remain stable for drilling in the semi-submerged floating position due in part to their wave transparency characteristics at the water line. Semisubmersibles can also be held in position through the use of a computer controlled thruster (dynamic-positioning) system to maintain the rig’s position over a drillsite. We have three semisubmersible rigs in our fleet with this capability.
     Our high specification semisubmersibles are generally capable of working in water depths of 4,000 feet or greater or in harsh environments and have other advanced features, as compared to intermediate semisubmersibles. As of January 28, 2008, eight of our 10 high-specification semisubmersibles were located in the U.S. Gulf of Mexico, or GOM, while the remaining two rigs were located offshore Brazil and Malaysia.
     Our intermediate semisubmersibles generally work in maximum water depths up to 4,000 feet. As of January 28, 2008, we had 19 intermediate semisubmersible rigs drilling offshore or undergoing contract preparation activities in various locations around the world. Two of these semisubmersibles were located in the GOM; three were located offshore Mexico, four were located in the North Sea, three were located offshore Australia, four were located offshore Brazil and one each was located offshore Egypt, Indonesia and Trinidad and Tobago.
     Our remaining intermediate semisubmersible, the Ocean Monarch, is currently in Singapore where construction activities are underway to upgrade this rig to a high-specification unit which will be able to operate in up to 10,000 feet of water in a moored configuration. See “ — Fleet Enhancements and Additions.”
     Drillship. We have one high-specification drillship, the Ocean Clipper, which was located offshore Brazil as of January 28, 2008. Drillships, which are typically self-propelled, are positioned over a drillsite through the use of either an anchoring system or a dynamic-positioning system similar to those used on certain semisubmersible rigs. Deepwater drillships compete in many of the same markets as do high-specification semisubmersible rigs.
     Both semisubmersible rigs and drillships are commonly referred to as floaters in the offshore drilling industry.
     Jack-ups. We currently own 13 jack-up drilling rigs. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is principally determined by the length of the rig’s legs. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues until the hull

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is elevated above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the water and then the legs are retracted for relocation to another drillsite.
     Most of our jack-up rigs are equipped with a cantilever system that enables the rig to cantilever or extend its drilling package over the aft end of the rig. This is particularly important when attempting to drill over existing platforms. Cantilever rigs have historically earned higher dayrates and achieved greater utilization compared to slot rigs.
     As of January 28, 2008, seven of our 13 jack-up rigs were located in the GOM. Four of those rigs are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Of our six remaining jack-up rigs, all of which are independent-leg cantilevered units, two were located offshore Mexico, one was located offshore Indonesia, one was located offshore Egypt, one was located offshore Croatia and the other rig was located offshore Qatar.
     In addition, we have two premium jack-up rigs currently under construction. We expect delivery of both of these units during the second quarter of 2008. See “ — Fleet Enhancements and Additions.
     Fleet Enhancements and Additions. Our strategy is to economically upgrade our fleet to meet customer demand for advanced, efficient, high-tech rigs, particularly deepwater semisubmersibles, in order to maximize the utilization of, and dayrates earned by, the rigs in our fleet. Since 1995, we have increased the number of our rigs capable of operating in 3,500 feet or more of water from three rigs to 13 (10 of which are high-specification units), primarily by upgrading our existing fleet. Six of these upgrades were to our Victory-class semisubmersible rigs, the design of which is well-suited for significant upgrade projects. We are in the process of upgrading one of our remaining Victory-class rigs in Singapore, and we have two additional Victory-class rigs that are currently operating as intermediate semisubmersibles that could potentially be upgraded at some time in the future.
     In 2006, we began a major upgrade of the Ocean Monarch, a Victory-class semisubmersible that we acquired in August 2005 for $20.0 million. The modernized rig is being designed to operate in up to 10,000 feet of water in a moored configuration for an estimated cost of approximately $305 million. Through December 31, 2007, we had spent $181.4 million related to this project. The Ocean Monarch is expected to be ready for deepwater service in the fourth quarter of 2008. The rig will then return to the GOM where it is expected to begin operating under contract in early 2009.
     The upgrade of the Ocean Endeavor to 10,000 foot water depth capability was completed in 2007 for a total cost of approximately $248 million, substantially all of which had been spent through December 31, 2007.
     In the second quarter of 2005, we entered into agreements to construct two high-performance, premium jack-up rigs. The two new drilling units, the Ocean Scepter and the Ocean Shield, are being constructed in Brownsville, Texas and Singapore, respectively, at an aggregate expected cost of approximately $320 million, including drill pipe and capitalized interest, of which $248.5 million had been spent through December 31, 2007. Each new-build jack-up rig will be equipped with a 70-foot cantilever package, be capable of drilling depths of up to 35,000 feet and have a hook load capacity of two million pounds. We expect delivery of both of these units during the second quarter of 2008. The Ocean Shield is expected to begin working under a one-year contract offshore Australia beginning in the second quarter of 2008. See “Risk Factors” in Item 1A of this report.
     We will evaluate further rig acquisition and upgrade opportunities as they arise. However, we can provide no assurance whether or to what extent we will continue to make rig acquisitions or upgrades to our fleet. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Requirements” in Item 7 of this report.

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     More detailed information concerning our fleet of mobile offshore drilling rigs, as of January 28, 2008, is set forth in the table below.
                     
    Nominal Water Depth       Year Built/Latest   Current    
Type and Name   Rating (a)   Attributes   Enhancement (b)   Location (c)   Customer (d)
High-Specification Floaters Semisubmersibles (10):
                   
Ocean Endeavor
  10,000   VC; 15K; 4M   1975/2007   GOM   Devon
Ocean Confidence
  7,500   DP; 15K; 4M   2001   GOM   BP America
Ocean Baroness
  7,000   VC; 15K; 4M   1973/2002   GOM   Hess Corporation
Ocean Rover
  7,000   VC; 15K; 4M   1973/2003   Malaysia   Murphy Exploration
Ocean America
  5,500   SP; 15K; 3M   1988/1999   GOM   LLOG
Ocean Valiant
  5,500   SP; 15K; 3M   1988/1999   GOM   LLOG
Ocean Victory
  5,500   VC; 15K; 3M   1972/1997   GOM   Shipyard: Survey
Ocean Star
  5,500   VC; 15K; 3M   1974/1999   GOM   Anadarko
Ocean Alliance
  5,000   DP; 15K; 3M   1988/1999   Brazil   Petrobras
Ocean Quest
  3,500   VC; 15K; 3M   1973/1996   GOM   Marathon Oil
Drillship (1):
                   
Ocean Clipper
  7,500   DP; 15K; 3M   1976/1999   Brazil   Petrobras
Intermediate Semisubmersibles (19):
                   
Ocean Winner
  4,000   3M   1977/2004   Brazil   Petrobras
Ocean Worker
  3,500   3M   1982/1992   Trinidad & Tobago   Petro-Canada
Ocean Yatzy
  3,300   DP   1989/1998   Brazil   Petrobras
Ocean Voyager
  3,200   VC; 3M   1973/1995   Mexico   PEMEX
Ocean Patriot
  3,000   15K; 3M   1982/2003   Australia   Shipyard: Survey
Ocean Yorktown
  2,200   3M   1976/1996   GOM   Shipyard:
 
                  Contract Preparation
Ocean Concord
  2,200   3M   1975/1999   Brazil   Petrobras
Ocean Lexington
  2,200   3M   1976/1995   Egypt   BP Egypt
Ocean Saratoga
  2,200   3M   1976/1995   GOM   Nexen Petroleum
Ocean Epoch
  1,640   3M   1977/2000   Australia   Shell Australia
Ocean General
  1,640   3M   1976/1999   Indonesia   Inpex
Ocean Bounty
  1,500   VC; 3M   1977/1992   Australia   Woodside Energy
Ocean Guardian
  1,500   15K; 3M   1985   North Sea   Oilexco
Ocean New Era
  1,500   3M   1974/1990   Mexico   PEMEX
Ocean Princess
  1,500   15K; 3M   1977/1998   North Sea   Talisman
Ocean Whittington
  1,500   3M   1974/1995   Brazil   Petrobras
Ocean Vanguard
  1,500   15K; 3M   1982   Norway   Statoil
Ocean Nomad
  1,200   3M   1975/2001   North Sea   Talisman
Ocean Ambassador
  1,100   3M   1975/1995   Mexico   PEMEX
Jack-ups (13):
                   
Ocean Titan
  350   IC; 15K; 3M   1974/2004   GOM   Apache
Ocean Tower
  350   IC; 3M   1972/2003   GOM   Chevron
Ocean King
  300   IC; 3M   1973/1999   Croatia   Bareboat charter to
 
                  CROSCO
Ocean Nugget
  300   IC   1976/1995   Mexico   PEMEX
Ocean Summit
  300   IC   1972/2003   GOM   Energy Partners
Ocean Heritage
  300   IC   1981/2002   Qatar   Qatar Petroleum
Ocean Spartan
  300   IC   1980/2003   GOM   Apache
Ocean Spur
  300   IC   1981/2003   Egypt   NOSPCO
Ocean Sovereign
  300   IC   1981/2003   Indonesia   KODECO
Ocean Champion
  250   MS   1975/2004   GOM   Bois d'Arc
Ocean Columbia
  250   IC   1978/1990   Mexico   PEMEX
Ocean Crusader
  200   MC   1982/1992   GOM   Breton Energy
Ocean Drake
  200   MC   1983/1986   GOM   Fairways Offshore
Under Construction (3):
                   
Ocean Monarch
  1,500   VC   1974/2008   Singapore   Shipyard; Upgrade to
 
                  10,000’
Ocean Scepter
  350   IC; 15K; 3M   2008   GOM   New; Under Construction
Ocean Shield
  350   IC; 15K; 3M   2008   Singapore   New; Under Construction

                                 
Attributes
DP
IC
MC
  =
=
=
  Dynamically-Positioned/Self-Propelled
Independent-Leg Cantilevered Rig
Mat-Supported Cantilevered Rig
  MS
VC
SP
  =
=
=
  Mat-Supported Slot Rig
Victory-Class
Self-Propelled
  3M
4M
15K
  =
=
=
  Three Mud Pumps
Four Mud Pumps
15,000 psi well control system
See the footnotes to this table on the following page.

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(a)   Nominal water depth (in feet), as described above for semisubmersibles and drillships, reflects the current drilling depth capability for each drilling unit. In many cases, individual rigs are capable of achieving, or have achieved, greater water depths. In all cases, floating rigs are capable of working successfully at greater depths than their nominal water depth. On a case by case basis, we may achieve a greater depth capacity by providing additional equipment.
 
(b)   Such enhancements may include the installation of top-drive drilling systems, water depth upgrades, mud pump additions and increases in deck load capacity. Top-drive drilling systems are included on all rigs included in the table above.
 
(c)   GOM means U.S. Gulf of Mexico.
 
(d)   For ease of presentation in this table, customer names have been shortened or abbreviated.
Markets
     The principal markets for our offshore contract drilling services are the following:
    the Gulf of Mexico, including the United States and Mexico;
 
    Europe, principally in the United Kingdom, or U.K., and Norway;
 
    the Mediterranean Basin, including Egypt, Libya and Tunisia and other parts of Africa;
 
    South America, principally in Brazil;
 
    Australia and Asia, including Malaysia, Indonesia and Vietnam; and
 
    the Middle East, including Kuwait, Qatar and Saudi Arabia.
     We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the world as the market demands. See Note 17 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.
     We believe our presence in multiple markets is valuable in many respects. For example, we believe that our experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and in the Gulf of Mexico, while production experience we have gained through our Brazilian and North Sea operations has potential application worldwide. Additionally, we believe our performance for a customer in one market segment or area enables us to better understand that customer’s needs and better serve that customer in different market segments or other geographic locations.
Offshore Contract Drilling Services
     Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through competitive bidding, although it is not unusual for us to be awarded drilling contracts without competitive bidding. Our drilling contracts generally provide for a basic drilling rate on a fixed dayrate basis regardless of whether or not such drilling results in a productive well. Drilling contracts may also provide for lower rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of our revenues. In addition, from time to time, our dayrate contracts may also provide for the ability to earn an incentive bonus from our customer based upon performance.
     A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or a group of wells, which we refer to as a well-to-well contract, or a fixed term, which we refer to as a term contract, and may be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to other events beyond the control of either party to the contract. In addition, certain of our contracts permit the customer to terminate the contract early by giving notice, and in some circumstances may require the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension. See “Risk Factors — The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market” and “Risk Factors — Our business involves numerous operating hazards, and we are not fully insured against all of them” in Item 1A of this report, which are incorporated herein by reference.

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Customers
     We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2007, we performed services for 49 different customers, none of which accounted for 10% or more of our annual total consolidated revenues. During 2006, we performed services for 51 different customers with Anadarko Petroleum Corporation (which acquired Kerr-McGee Oil & Gas Corporation, or Kerr-McGee, in mid-2006) and Petróleo Brasileiro S.A., or Petrobras, accounting for 10.6% and 10.4% of our annual total consolidated revenues, respectively. During 2005, we performed services for 53 different customers with Petrobras and Kerr-McGee accounting for 10.7% and 10.3% of our annual total consolidated revenues, respectively.
     We principally market our services in North America through our Houston, Texas office. We market our services in other geographic locations principally from our office in The Hague, The Netherlands with support from our regional offices in Aberdeen, Scotland and Perth, Western Australia. We provide technical and administrative support functions from our Houston office.
Competition
     The offshore contract drilling industry is highly competitive and is influenced by a number of factors, including global demand for oil and natural gas, current and anticipated prices of oil and natural gas, expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling rigs. See “Risk Factors — Our industry is highly competitive and cyclical, with intense price competition” in Item 1A of this report, which is incorporated herein by reference.
Governmental Regulation
     Our operations are subject to numerous international, U.S., state and local laws and regulations that relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment. See “Risk Factors — Compliance with or breach of environmental laws can be costly and could limit our operations” in Item 1A of this report, which is incorporated herein by reference.
Operations Outside the United States
     Our operations outside the United States accounted for approximately 50%, 43% and 45% of our total consolidated revenues for the years ended December 31, 2007, 2006 and 2005, respectively. See “Risk Factors — A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations,” “Risk Factors — Our drilling contracts offshore Mexico expose us to greater risks than we normally assume” and “Risk Factors — Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us” in Item 1A of this report, which are incorporated herein by reference.
Employees
     As of December 31, 2007, we had approximately 5,400 workers, including international crew personnel furnished through independent labor contractors. We have experienced satisfactory labor relations and provide comprehensive benefit plans for our employees.
Access to Company Filings
     We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy statements and other information with the United States Securities and Exchange Commission, or SEC. You may read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Our SEC filings are also available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably

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practicable after we have electronically filed such material with, or furnished it to, the SEC. The information contained on our website, or on other websites linked to our website, is not part of this report.
Item 1A. Risk Factors.
     Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that we currently believe are not as significant as the risks described below. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected.
Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.
     Our business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher commodity demand and prices do not necessarily translate into increased drilling activity since our customers’ expectations of future commodity demand and prices typically drive demand for our rigs. Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including:
    worldwide demand for oil and gas;
 
    the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing;
 
    the level of production in non-OPEC countries;
 
    the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East, other oil-producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;
 
    the worldwide economic environment or economic trends, such as recessions;
 
    the cost of exploring for, producing and delivering oil and gas;
 
    the discovery rate of new oil and gas reserves;
 
    the rate of decline of existing and new oil and gas reserves;
 
    available pipeline and other oil and gas transportation capacity;
 
    the ability of oil and gas companies to raise capital;
 
    weather conditions in the United States and elsewhere;
 
    the policies of various governments regarding exploration and development of their oil and gas reserves;
 
    development and exploitation of alternative fuels;
 
    domestic and foreign tax policy; and
 
    advances in exploration and development technology.
Our industry is highly competitive and cyclical, with intense price competition.
     The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered. Mergers among oil and natural gas exploration and production companies have reduced the number of available customers. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors.
     Our industry has historically been cyclical. There have been periods of high demand, short rig supply and high dayrates (such as we are currently experiencing in virtually all of the markets in which we operate), followed by periods of lower demand, excess rig supply and low dayrates. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time.
     Growing worldwide demand for crude oil and natural gas has caused current oil and natural gas prices to rise

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significantly above historical averages, which has generally resulted in higher utilization and dayrates earned by our drilling units, generally since the third quarter of 2004. However, we can provide no assurance that the current industry cycle of high demand, short rig supply and higher dayrates will continue. We may be required to idle rigs or to enter into lower rate contracts in response to market conditions in the future.
     Significant new rig construction and upgrades of existing drilling units could also intensify price competition. We believe that as of the date of this report there are approximately 150 jack-up rigs and floaters (semisubmersible rigs and drillships) on order and scheduled for delivery between 2008 and 2011. Improvements in dayrates and expectations of sustained improvements in rig utilization rates and dayrates by drilling contractors may result in the construction of additional new rigs. At the same time, anticipated shortages of sufficient rig capacity to meet future requirements on the part of operators may cause the operators to contract for additional new-build equipment. The resulting increases in rig supply could be sufficient to result in depressed rig utilization and greater price competition from both existing competitors, as well as new entrants into the offshore drilling market. As of the date of this report, not all of the rigs currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. In addition, competing contractors are able to adjust localized supply and demand imbalances by moving rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates.
     Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.
Failure to obtain and retain highly skilled personnel could hurt our operations.
     We require highly skilled personnel to operate and provide technical services and support for our business. To the extent that demand for drilling services and the size of the worldwide industry fleet increase (including the impact of newly constructed rigs), shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs, which could adversely affect our results of operations. In addition, the entrance of new participants into the offshore drilling market would cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry.
     We have experienced and continue to experience upward pressure on salaries and wages and increased competition for skilled workers as a result of the strengthening offshore drilling market. We have also sustained the loss of experienced personnel to our competitors and our customers. In response to these market conditions we have implemented retention programs, including increases in compensation. The heightened competition for skilled personnel could adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.
We rely heavily on a relatively small number of customers and the loss of a significant customer could have a material adverse impact on our financial results.
     We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. However, the number of potential customers has decreased in recent years as a result of mergers among the major international oil companies and large independent oil companies. In 2007, our five largest customers in the aggregate accounted for approximately 39% of our consolidated revenues. While it is normal for our customer base to change over time as work programs are completed, the loss of any major customer may have a material adverse effect on our financial position, results of operations and cash flows.
The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market.
     The duration of offshore drilling contracts is generally determined by customer requirements and, to a lesser extent, the respective management strategies of the offshore drilling contractors. In periods of rising demand for offshore rigs, contractors typically prefer shorter contracts that allow them to more quickly profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. Conversely, in periods of decreasing demand for offshore rigs, contractors generally prefer longer term contracts to preserve dayrates at existing levels and ensure

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utilization, while customers prefer shorter contracts that allow them to more quickly obtain the benefit of lower dayrates.
     Typically, as a period of high dayrates and utilization lengthens, customers who perceive a continuing long-term need for equipment begin to seek increasingly long-term contracts, but often at flat or slightly lower dayrates in exchange for the term length. To the extent possible within the scope of our customers’ requirements, we seek to have a foundation of these long-term contracts with a reasonable balance of shorter-term exposure to the spot market in an attempt to maintain upside potential while endeavoring to limit the downside impact of a potential decline in the market. However, we can provide no assurance that we will be able to achieve or maintain such a balance from time to time. Our inability to fully benefit from increasing dayrates in an improving market, due to the long-term nature of some of our contracts, may adversely affect our profitability.
Contracts for our drilling units are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability on those contracts.
     Our contracts for our drilling units provide for the payment of a fixed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs incurred by us. Many of our operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond our control. The gross margin that we realize on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers. Our inability to recover these increased or unforeseen costs from our customers could adversely affect our financial position, results of operations and cash flows.
Our drilling contracts may be terminated due to events beyond our control.
     Our customers may terminate some of our term drilling contracts if the drilling unit is destroyed or lost or if drilling operations are suspended for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial position, results of operations and cash flows.
     During depressed market conditions, our customers may also seek renegotiation of firm drilling contracts to reduce their obligations. The renegotiation of our drilling contracts could adversely affect our financial position, results of operations and cash flows.
We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.
     As of the date of this report, our contract drilling backlog was approximately $11 billion for expected future work extending, in some cases, until 2015, which includes future earnings under both firm commitments and. in a few instances, anticipated commitments for which definitive agreements have not yet been executed. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement where one does not currently exist. Our inability to perform under our contractual obligations or to execute definitive agreements may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Contract Drilling Backlog” included in Item 7 of this report.
Rig conversions, upgrades or new-builds may be subject to delays and cost overruns.
     From time to time we may undertake to add new capacity through conversions or upgrades to our existing rigs or through new construction. We are currently upgrading one of our semisubmersible drilling units, the Ocean Monarch, to ultra-deepwater capability at an estimated aggregate cost of approximately $305 million. We expect delivery of the upgraded Ocean Monarch during the fourth quarter of 2008. We have also entered into agreements to construct two new jack-up drilling units with expected delivery dates in the second quarter of 2008 at an

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aggregate cost of approximately $320 million, including drill pipe and capitalized interest. These projects and other projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:
    shortages of equipment, materials or skilled labor;
 
    work stoppages;
 
    unscheduled delays in the delivery of ordered materials and equipment;
 
    unanticipated cost increases;
 
    weather interferences;
 
    difficulties in obtaining necessary permits or in meeting permit conditions;
 
    design and engineering problems;
 
    customer acceptance delays
 
    shipyard failures or unavailability; and
 
    failure or delay of third party service providers and labor disputes.
     Failure to complete a rig upgrade or new construction on time, or failure to complete a rig conversion or new construction in accordance with its design specifications may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling contract, resulting in a loss of revenue to us. If a drilling contract is terminated under these circumstances, we may not be able to secure a replacement contract on as favorable terms.
Our business involves numerous operating hazards, and we are not fully insured against all of them.
     Our operations are subject to the usual hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings and natural disasters such as hurricanes or fires. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations and environmental damage, and could have a material adverse effect on our results of operations and financial condition. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. In addition, offshore drilling operators are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to damage claims by oil and gas companies or other parties.
     Pollution and environmental risks generally are not fully insurable, and we do not typically retain loss-of-hire insurance policies to cover our rigs. Our insurance policies and contractual rights to indemnity may not adequately cover our losses, or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including, among other things, liability risk for certain amounts of excess coverage and certain physical damage risk. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position, results of operations and cash flows. There can be no assurance that we will continue to carry the insurance we currently maintain or that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks. In addition, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks.
We are self-insured for a portion of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico.
     For physical damage due to named windstorms in the U.S. Gulf of Mexico, as of the date of this report our deductible is $75.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss) with an annual aggregate limit of $125.0 million. Accordingly, our insurance coverage for all physical damage to our rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico for the policy period ending April 30, 2008 is limited to $125.0 million. If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment, or to the property of others for which we may be liable, it could have a material adverse effect on our financial position, results of operations and cash flows.

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A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations.
     We operate in various regions throughout the world which may expose us to political and other uncertainties, including risks of:
    terrorist acts, war and civil disturbances;
 
    piracy or assaults on property or personnel;
 
    kidnapping of personnel;
 
    expropriation of property or equipment;
 
    renegotiation or nullification of existing contracts;
 
    changing political conditions;
 
    foreign and domestic monetary policies;
 
    the inability to repatriate income or capital;
 
    regulatory or financial requirements to comply with foreign bureaucratic actions;
 
    travel limitations or operational problems caused by public health threats; and
 
    changing taxation policies.
     In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
    the equipping and operation of drilling units;
 
    repatriation of foreign earnings;
 
    oil and gas exploration and development;
 
    taxation of offshore earnings and earnings of expatriate personnel; and
 
    use and compensation of local employees and suppliers by foreign contractors.
     Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete.
Future acts of terrorism and other political and military events could adversely affect the markets for our drilling services.
     Terrorist acts and political events around the world have resulted in military actions in Afghanistan and Iraq, as well as related political and economic unrest in various parts of the world. Future terrorist attacks and the continued threat of terrorism in this country or abroad, the continuation or escalation of existing armed hostilities or the outbreak of additional hostilities could lead to increased political, economic and financial market instability and a downturn in the economies of the U.S. and other countries. A lower level of economic activity could result in a decline in energy consumption or an increase in the volatility of energy prices, either of which could adversely affect the market for our offshore drilling services, our dayrates or utilization and, accordingly, our financial position, results of operations and cash flows. In addition, it has been reported that terrorists might target domestic energy facilities. While we take steps that we believe are appropriate to increase the security of our energy assets, there is no assurance that we can completely secure these assets, completely protect them against a terrorist attack or obtain adequate insurance coverage for terrorist acts at reasonable rates. Moreover, U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
Our drilling contracts offshore Mexico expose us to greater risks than we normally assume.
     As of the date of this report, we have three intermediate semisubmersible rigs and two jack-up rigs drilling offshore Mexico for PEMEX — Exploración Y Producción, or PEMEX, the national oil company of Mexico. The terms of these contracts expose us to greater risks than we normally assume, such as exposure to greater environmental liability. In addition, each contract can be terminated by PEMEX on short-term notice, contractually

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or by statute, subject to certain conditions. While we believe that the financial terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have a negative impact on our future operations or financial results.
Public health threats could have a material adverse effect on our operations and financial results.
     Public health threats such as outbreaks of highly communicable diseases, which periodically occur in various parts of the world in which we operate, could adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may have a material adverse effect on our financial position, results of operations and cash flows.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
     Due to our international operations, we may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.
We may be required to accrue additional tax liability on certain of our foreign earnings.
     Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, our wholly-owned Cayman Islands subsidiary. Since forming this subsidiary it has been our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign operations. During 2007, this subsidiary made a non-recurring distribution to its U.S. parent company, and we recognized U.S. federal income tax expense on the portion of the distribution that consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. As of December 31, 2007, the amount of previously untaxed earnings of this subsidiary was zero. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest the future earnings of this subsidiary to finance foreign activities. We do not expect to provide for U.S. taxes on any future earnings generated by this subsidiary, except to the extent that these earnings are immediately subjected to U.S. federal income tax. Should a future distribution be made from any unremitted earnings of this subsidiary, we may be required to record additional U.S. income taxes that, if material, could have an adverse effect on our financial position, results of operations and cash flows.
We may be subject to litigation that could have an adverse effect on us.
     We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment and tax matters and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our management’s resources and other factors.
Governmental laws and regulations may add to our costs or limit our drilling activity.
     Our operations are affected from time to time in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.
     Governments in some foreign countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industries. The modification of

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existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.
     The Minerals Management Service of the U.S. Department of the Interior, or MMS, has established guidelines for drilling operations in the GOM We believe that we are currently in compliance with the existing regulations set forth by the MMS with respect to our operations in the GOM; however, these regulations are continually under review by the MMS and may change from time to time. Implementation of additional MMS regulations may subject us to increased costs of operating, or a reduction in the area and/or periods of operation, in the GOM.
Compliance with or breach of environmental laws can be costly and could limit our operations.
     In the United States, regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment apply to some of our operations. For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those operations. Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed.
     The United States Oil Pollution Act of 1990, or OPA ‘90, and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ‘90 and such similar legislation and related regulations impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting from such spills. OPA ‘90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages.
     The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations and cash flows.
We are controlled by a single stockholder, which could result in potential conflicts of interest.
     Loews Corporation, which we refer to as Loews, beneficially owns approximately 50.5% of our outstanding shares of common stock as of February 20, 2008 and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. One of those, James S. Tisch, the Chief Executive Officer and Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews and we may in the future enter into other agreements with Loews.
     Loews and its subsidiaries and we are generally engaged in businesses sufficiently different from each other as to make conflicts as to possible corporate opportunities unlikely. However, it is possible that Loews may in some circumstances be in direct or indirect competition with us, including competition with respect to certain business strategies and transactions that we may propose to undertake. In addition, potential conflicts of interest exist or could arise in the future for our directors that are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations. We cannot assure you that these conflicts of interest will not materially adversely affect us.
Item 1B. Unresolved Staff Comments.
     Not applicable.

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Item 2. Properties.
     We own an eight-story office building containing approximately 182,000-net rentable square feet on approximately 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located, two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, and a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, The Netherlands, Malaysia, Qatar, Singapore, Egypt, Trinidad and Tobago and Mexico to support our offshore drilling operations.
Item 3. Legal Proceedings.
     Not applicable.
Item 4. Submission of Matters to a Vote of Security Holders.
     Not applicable.
Executive Officers of the Registrant
     We have included information on our executive officers in Part I of this report in reliance on General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors to serve until the next annual meeting of our Board of Directors, or until their successors are duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office. Information with respect to our executive officers is set forth below.
             
    Age as of    
Name   January 31, 2008   Position
James S. Tisch
    55     Chairman of the Board of Directors and Chief Executive Officer
Lawrence R. Dickerson
    55     President, Chief Operating Officer and Director
Gary T. Krenek
    49     Senior Vice President and Chief Financial Officer
William C. Long
    41     Senior Vice President, General Counsel & Secretary
Beth G. Gordon
    52     Controller — Chief Accounting Officer
Mark F. Baudoin
    55     Senior Vice President — Administration
Lyndol L. Dew
    53     Senior Vice President — Worldwide Operations
John L. Gabriel, Jr.
    54     Senior Vice President — Contracts & Marketing
John M. Vecchio
    57     Senior Vice President — Technical Services
     James S. Tisch has served as our Chief Executive Officer since March 1998. Mr. Tisch has also served as Chairman of the Board since 1995 and as a director since June 1989. Mr. Tisch has served as Chief Executive Officer of Loews, a diversified holding company and our controlling stockholder, since January 1999. Mr. Tisch, a director of Loews since 1986, also serves as a director of CNA Financial Corporation, an 89% owned subsidiary of Loews.
     Lawrence R. Dickerson has served as our President, Chief Operating Officer and Director since March 1998. Mr. Dickerson served on the United States Commission on Ocean Policy from 2001 to 2004.
     Gary T. Krenek has served as a Senior Vice President and our Chief Financial Officer since October 2006. Mr. Krenek previously served as our Vice President and Chief Financial Officer since March 1998.
     William C. Long has served as a Senior Vice President and our General Counsel and Secretary since October 2006. Mr. Long previously served as our Vice President, General Counsel and Secretary since March 2001 and as our General Counsel and Secretary from March 1999 through February 2001.
     Beth G. Gordon has served as our Controller and Chief Accounting Officer since April 2000.

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     Mark F. Baudoin has served as a Senior Vice President since October 2006. Mr. Baudoin previously served as our Vice President — Administration and Operations Support since March 1996.
     Lyndol L. Dew has served as a Senior Vice President since September 2006. Previously, Mr. Dew served as our Vice President — International Operations from January 2006 to August 2006 and as our Vice President — North American Operations from January 2003 to December 2005. Mr. Dew previously served as an Area Manager for our domestic operations since February 2002.
     John L. Gabriel, Jr. has served as a Senior Vice President since November 1999.
     John M. Vecchio has served as Senior Vice President — Technical Services since April 2002.

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PART II
Item 5.   Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Price Range of Common Stock
     Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol “DO.” The following table sets forth, for the calendar quarters indicated, the high and low closing prices of our common stock as reported by the NYSE.
                 
    Common Stock
    High   Low
 
               
2007
               
First Quarter
  $ 87.23     $ 73.65  
Second Quarter
    107.13       81.47  
Third Quarter
    115.05       91.23  
Fourth Quarter
    148.51       105.19  
 
               
2006
               
First Quarter
  $ 90.70     $ 72.75  
Second Quarter
    96.15       72.49  
Third Quarter
    85.44       67.46  
Fourth Quarter
    84.43       63.90  
     As of February 20, 2008 there were approximately 232 holders of record of our common stock.
Dividend Policy
     In 2007, we paid quarterly cash dividends of $0.125 per share of our common stock on March 1, June 1, September 4 and December 3. We paid special cash dividends of $4.00 and $1.25 per share of our common stock on March 1, 2007 and December 3, 2007, respectively. In 2006, we paid regular quarterly cash dividends of $0.125 per share of our common stock on March 1, June 1, September 1 and December 1 and a special cash dividend of $1.50 per share of our common stock on March 1.
     On February 6, 2008, we declared a regular quarterly cash dividend and a special cash dividend of $0.125 and $1.25, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on March 3, 2008 to stockholders of record on February 18, 2008.
     In the fourth quarter of 2007, our Board of Directors adopted a policy of considering paying special cash dividends, in amounts to be determined, on a quarterly basis, rather than annually. Our Board of Directors may, in subsequent quarters, consider paying additional special cash dividends, in amounts to be determined, if it believes that our financial position, earnings, earnings outlook, capital spending plans and other relevant factors warrant such action at that time.

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CUMULATIVE TOTAL STOCKHOLDER RETURN
     The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Index and a Peer Group Index over the five year period ended December 31, 2007.
Comparison of 2003 — 2007 Cumulative Total Return (1)
(PERFORMANCE GRAPH)
                                                 
    Dec. 31, 2002   Dec. 31, 2003   Dec. 31, 2004   Dec. 31, 2005   Dec. 31, 2006   Dec. 31, 2007
Diamond Offshore
    100       96       189       331       391       741  
S&P 500
    100       129       143       150       173       183  
Peer Group (2)
    100       103       136       203       225       319  
 
(1)   Total return assuming reinvestment of dividends. Dividends for the periods reported include regular quarterly dividends of $0.125 per share of our common stock that we paid during the first three quarters of 2003, the last two quarters of 2005 and all four quarters of 2006 and 2007. Beginning in the fourth quarter of 2003 through the first two quarters of 2005, we paid a regular quarterly dividend of $0.0625 per share. We paid special dividends of $4.00 and $1.25 per share of our common stock in the first quarter and fourth quarter of 2007, respectively. We paid a special dividend of $1.50 per share of our common stock in the first quarter of 2006. Assumes $100 invested on December 31, 2002 in our common stock, the S&P 500 Index and a peer group index comprised of a group of other companies in the contract drilling industry.
 
(2)   The peer group is comprised of the following companies: ENSCO International Incorporated, GlobalSantaFe (included until November 27, 2007 merger with Transocean Inc.), Noble Drilling Corporation, Pride International, Inc., Rowan Companies, Inc. and Transocean Inc. Total return calculations were weighted according to the respective company’s market capitalization.

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Item 6. Selected Financial Data.
     The following table sets forth certain historical consolidated financial data relating to Diamond Offshore. We prepared the selected consolidated financial data from our consolidated financial statements as of and for the periods presented. Prior periods have been reclassified to conform to the classifications we currently follow. Such reclassifications do not affect earnings. The selected consolidated financial data below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
                                         
    As of and for the Year Ended December 31,
    2007   2006   2005   2004   2003
    (In thousands, except per share and ratio data)
Income Statement Data:
                                       
Total revenues
  $ 2,567,723     $ 2,052,572     $ 1,221,002     $ 814,662     $ 680,941  
Operating income (loss)
    1,223,522       940,432       374,399       3,928       (38,323 )
Net income (loss)
    846,541       706,847       260,337       (7,243 )     (48,414 )
Net income (loss) per share:
                                       
Basic
    6.14       5.47       2.02       (0.06 )     (0.37 )
Diluted
    6.12       5.12       1.91       (0.06 )     (0.37 )
 
                                       
Balance Sheet Data:
                                       
Drilling and other property and equipment, net
  $ 3,040,063     $ 2,628,453     $ 2,302,020     $ 2,154,593     $ 2,257,876  
Total assets
    4,341,465       4,132,839       3,606,922       3,379,386       3,135,019  
Long-term debt (excluding current maturities) (1)
    503,071       964,310       977,654       709,413       928,030  
 
                                       
Other Financial Data:
                                       
Capital expenditures
  $ 647,101     $ 551,237     $ 293,829     $ 89,229     $ 272,026  
Cash dividends declared per share
    5.75       2.00       0.375       0.25       0.438  
Ratio of earnings to fixed charges (2)
    32.31x       28.26x       9.19x       N/A       N/A  
 
(1)   See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Requirements” in Item 7 and Note 9 “Long-Term Debt” to our Consolidated Financial Statements included in Item 8 of this report for a discussion of changes in our long-term debt.
 
(2)   The deficiency in our earnings available for fixed charges for the years ended December 31, 2004 and 2003 was approximately $2.3 million and $55.3 million, respectively. For all periods presented, the ratio of earnings to fixed charges has been computed on a total enterprise basis. Earnings represent pre-tax income from continuing operations plus fixed charges. Fixed charges include (i) interest, whether expensed or capitalized, (ii) amortization of debt issuance costs, whether expensed or capitalized, and (iii) a portion of rent expense, which we believe represents the interest factor attributable to rent.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
     The following discussion should be read in conjunction with our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
     We provide contract drilling services to the energy industry around the globe and are a leader in offshore drilling with a fleet of 44 offshore drilling rigs. Our fleet currently consists of 30 semisubmersibles, 13 jack-ups and one drillship. In addition, we have two jack-up drilling units under construction at shipyards in Brownsville, Texas and Singapore. We expect both of these units to be delivered during the second quarter of 2008.
Overview
Industry Conditions
     Worldwide demand for our mid-water (intermediate) and deepwater (high-specification) semisubmersible rigs remained strong throughout the year 2007 and into 2008. The jack-up market in the U.S. Gulf of Mexico, however, continues to experience reduced demand, resulting in downward pricing pressure and some of our jack-up rigs being ready-stacked for periods of time between wells. Exclusive of the GOM jack-up market, which accounted for nine percent of our total revenue for the year ended December 31, 2007, solid fundamental market conditions remain in place for all classes of our offshore drilling rigs worldwide.
     Gulf of Mexico. In the GOM, the market for our high-specification semisubmersible equipment remains firm. One of our high-specification rigs is contracted for work in the GOM until late in the fourth quarter of 2008, while the remaining seven high-specification rigs currently located in the GOM have contracts that extend well into 2009 and beyond, including two at dayrates as high as $500,000 for future work. In many cases, these contracts also include un-priced option periods that have neither been exercised nor have expired.
     As of the date of this report, dayrates for intermediate semisubmersibles in the GOM, where we currently have one such unit operating, are ranging between $250,000 and $300,000. During 2007, strong international demand offering lengthy terms encouraged us to obtain international contracts for four of our intermediate rigs that were previously located in the GOM. All but one of these rigs has left the GOM. The fourth unit is in a shipyard in Brownsville for a survey and life extension project. We expect this rig to depart the GOM in the second quarter of 2008 for Brazil. We continue to view the deepwater and intermediate markets in the GOM as under-supplied and believe that the GOM semisubmersible market will remain strong in 2008.
     Our jack-up fleet in the GOM continued to experience lower utilization and dayrates during the fourth quarter of 2007, compared to the third quarter of 2007, as four of our seven available rigs were ready-stacked for periods of time and average dayrates declined slightly from those earned during the third quarter of 2007. As of January 28, 2008, all seven of our available jack-ups in the GOM were on contract, although the well-to-well nature of the market persists. The international market for jack-ups remains generally strong. As a result, we signed a two-year term extension with KODECO Energy Co. LTD. for the Ocean Sovereign in Indonesia at a dayrate in the mid $140,000s that is expected to commence in the second quarter of 2008. The mobilization of the Ocean Columbia from the GOM to Mexico also was completed during the fourth quarter of 2007, and that unit began operating in the first quarter of 2008. We believe that the current market environment for jack-up rigs, both in the GOM and internationally, will continue at least through the first quarter of 2008.
     Brazil. During 2007, we added two semisubmersible rigs to our fleet in Brazil, where we currently have five semisubmersibles and one drillship operating. Two additional semisubmersible units, the Ocean Yorktown and Ocean Worker, are expected to commence operations there in the second and third quarters of 2008, respectively. Our drillship is contracted until the end of 2010. Of our other seven rigs that are or are expected to be working offshore Brazil in 2008, one is contracted until 2012 and two each are contracted until 2013, 2014 and 2015. In late 2007, Petrobras announced the discovery of an ultra-deep Atlantic Ocean field with as much as 8 billion barrels of crude oil. In early 2008, Petrobras also announced the discovery of a large natural gas reserve off the coast of Rio de Janeiro that may more than equal the size of the crude oil discovery. We expect the Brazilian floater market to remain strong during 2008.

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     North Sea. Effective semisubmersible utilization remains at 100 percent in the North Sea where we have three semisubmersible rigs in the U.K. and one semisubmersible unit in Norway. The current contract for one of our four rigs in the North Sea extends until the second quarter of 2009, and the other three rigs have term contracts that extend into 2010.
     Australia/Asia/Middle East/Mediterranean. We currently have five semisubmersible rigs and one jack-up unit operating in the Australia/Asia market, and three jack-up rigs and one semisubmersible rig located in the Middle East/Mediterranean sector. During the fourth quarter of 2007, the semisubmersible Ocean General received a Letter of Intent, or LOI, for two years of work in Vietnam at a dayrate in the low $280,000s. We believe that the Australia/Asia/Middle East and Mediterranean floater markets will remain strong during 2008.
Contract Drilling Backlog
     The following table reflects our contract drilling backlog as of February 7, 2008, October 25, 2007 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) and February 19, 2007 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2006) and reflects both firm commitments (typically represented by signed contracts), as well as previously-disclosed LOIs. An LOI is subject to customary conditions, including the execution of a definitive agreement. Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 95-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. Changes in our contract drilling backlog between periods is a function of both the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.
                         
            October 25,        
    February 7, 2008     2007     February 19, 2007  
    (In thousands)  
Contract Drilling Backlog
                       
High-Specification Floaters
  $ 4,448,000     $ 3,657,000     $ 4,115,000  
Intermediate Semisubmersibles (1)
    5,985,000       4,450,000       2,895,000  
Jack-ups
    421,000       432,000       432,000  
 
                 
Total
  $ 10,854,000     $ 8,539,000     $ 7,442,000  
 
                 
 
(1)   Contract drilling backlog as of February 7, 2008 includes an aggregate $238 million in contract drilling revenue relating to expected future work under an LOI.
     The following table reflects the amount of our contract drilling backlog by year as of February 7, 2008.
                                         
    For the Years Ending December 31,
    Total   2008   2009   2010   2011 - 2015
    (In thousands)
Contract Drilling Backlog
                                       
High-Specification Floaters
  $ 4,448,000     $ 1,287,000     $ 1,115,000     $ 810,000     $ 1,236,000  
Intermediate Semisubmersibles (1)
    5,985,000       1,612,000       1,588,000       1,060,000       1,725,000  
Jack-ups
    421,000       281,000       121,000       19,000        
 
                                       
Total
  $ 10,854,000     $ 3,180,000     $ 2,824,000     $ 1,889,000     $ 2,961,000  
 
                                       
 
(1)   Includes an aggregate $238 million in contract drilling revenue of which approximately $37.5 million, $102.2 million and $98.3 million is expected to be earned during 2008, 2009 and 2010, respectively, relating to expected future work under an LOI.

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     The following table reflects the percentage of rig days committed by year as of February 7, 2008. The percentage of rig days committed is calculated as the ratio of total days committed under contracts and LOIs, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected delivery dates for the Ocean Monarch, and our two new-build jack-up rigs, the Ocean Scepter and Ocean Shield.
                                 
    For the Years Ending December 31,
    2008   2009   2010   2011 - 2015
Rig Days Committed (1)
                               
High-Specification Floaters
    99 %     73 %     51 %     14 %
Intermediate Semisubmersibles
    94 %     83 %     53 %     19 %
Jack-ups
    48 %     17 %     2 %      
 
(1)   Includes approximately 1,166 and 349 scheduled shipyard, survey and mobilization days for 2008 and 2009, respectively.
General
     Our revenues vary based upon demand, which affects the number of days our fleet is utilized and the dayrates earned. When a rig is idle, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, we may mobilize our rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, we may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues, respectively.
     The two most significant variables affecting revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs, and vice versa. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political and economic factors. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within our control and are difficult to predict.
     We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.
     From time to time, we may receive fees from our customers for capital improvements to our rigs. We defer such fees and recognize them into income on a straight-line basis over the period of the related drilling contract as a component of contract drilling revenue. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.
     We receive reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement. We record these reimbursements at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations included in Item 8 of this report.
     Operating Income. Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most

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significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate. We have experienced and continue to experience upward pressure on salaries and wages as a result of the strong offshore drilling market and increased competition for skilled workers. In response to these market conditions we have implemented retention programs, including increases in compensation.
     Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and condition of the equipment and the regions in which our rigs are working.
     Operating expenses generally are not affected by changes in dayrates, and short-term reductions in utilization do not necessarily result in lower operating expenses. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “ready-stacked” state with a full crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if the rig is to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. We recognize, as incurred, operating expenses related to activities such as inspections, painting projects and routine overhauls that meet certain criteria and which maintain rather than upgrade our rigs. These expenses vary from period to period. Costs of rig enhancements are capitalized and depreciated over the expected useful lives of the enhancements. Higher depreciation expense decreases operating income in periods subsequent to capital upgrades.
     Periods of high, sustained utilization may result in cost increases for maintenance and repairs in order to maintain our equipment in proper, working order. In addition, during periods of high activity and dayrates, higher prices generally pervade the entire offshore drilling industry and its support businesses, which cause our costs for goods and services to increase.
     Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. Operating revenue decreases because these surveys are performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance costs may be required resulting from the survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year.
     In addition, operating income may be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time, except for rigs located in the U.K. and Norwegian sectors of the North Sea.
     During 2008, we expect 12 rigs in our fleet to undergo 5-year or intermediate surveys at an estimated aggregate cost of approximately $45 million, including estimated mobilization costs, but excluding any resulting repair and maintenance costs, which could be significant. Costs of mobilizing our rigs to shipyards for scheduled surveys, which were a major component of our survey-related costs during 2007, are indicative of higher prices commanded by support businesses to the offshore drilling industry. We expect mobilization costs to be a significant component of our survey-related costs in 2008.
     For physical damage due to named windstorms in the U.S. Gulf of Mexico, as of the date of this report our deductible is $75.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss) with an annual aggregate limit of $125.0 million. Accordingly, our insurance coverage for all physical damage to our rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico for the policy period ending April 30, 2008 is limited to $125.0 million. If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment or to the property of others for which we may be liable, it could have a material adverse effect on our financial position, results of operations and cash flows.
     Insurance premiums will be amortized as expense over the applicable policy periods which generally expire at the end of April 2008.

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     Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with Statement of Financial Accounting Standards, or SFAS, No. 34, “Capitalization of Interest Cost,” or SFAS 34. During 2005 and 2006, we began capitalizing interest with respect to expenditures related to our upgrade of the Ocean Monarch and the construction of our two new jack-up rigs. Pursuant to SFAS 34, the period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. Prior to the completion of our upgrade of the Ocean Endeavor in March 2007, we capitalized interest on qualifying expenditures on that project beginning in April 2005. See Note 1 “General Information — Capitalized Interest” to our Consolidated Financial Statements included in Item 8 of this report.
     During 2008, we expect to complete the upgrade of the Ocean Monarch and to accept delivery of the newly constructed Ocean Scepter and Ocean Shield. We will continue to capitalize interest costs related to this upgrade until sea trials and commissioning of the Ocean Monarch are completed and the rig is loaded on a heavy lift vessel for its return to the GOM, which we anticipate will occur late in the fourth quarter of 2008. We expect to continue capitalizing interest costs in connection with the construction of our two jack-up rigs until sea trials and commissioning of the rigs are complete, which we expect to occur in the second quarter of 2008. Accordingly, we will then cease capitalizing interest costs related to these projects and will begin depreciating the newly upgraded/constructed rigs. As a result of the scheduled delivery of these rigs, we anticipate that depreciation and interest expense in 2008 will increase by approximately $7 million and $2 million, respectively.
      Critical Accounting Estimates
     Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:
     Property, Plant and Equipment. We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which meet certain criteria, are capitalized. Depreciation is amortized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives. Our management makes judgments, assumptions and estimates regarding capitalization, useful lives and salvage values. Changes in these judgments, assumptions and estimates could produce results that differ from those reported.
     We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
    dayrate by rig;
 
    utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);
 
    the per day operating cost for each rig if active, ready-stacked or cold-stacked; and
 
    salvage value for each rig.
     Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various combinations of assumed utilization rates and dayrates. We also consider the impact of a 5% reduction in assumed dayrates for the cold-stacked rigs (holding all other assumptions and estimates in the model constant), or alternatively the impact of a 5% reduction in utilization (again holding all other assumptions and estimates in the model constant) as part of our analysis.
     As of December 31, 2007, all of our drilling rigs were either under contract or were in shipyards for surveys, contract modifications or major upgrade, except for two of our jack-up drilling rigs located in the GOM. At December 31, 2007, one of these idle units was under contract but waiting to begin drilling operations while the other unit was being actively marketed. We did not have any cold-stacked rigs at December 31, 2007. We do not believe that current circumstances indicate that the carrying amount of our property and equipment may not be recoverable.

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     Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from those reported.
     Personal Injury Claims. Our deductible for liability coverage for personal injury claims, which primarily results from Jones Act liability in the Gulf of Mexico, is $5.0 million (or $10.0 million if hurricane-related) per occurrence, with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage experts to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models.
     The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:
    the severity of personal injuries claimed;
 
    significant changes in the volume of personal injury claims;
 
    the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
 
    inconsistent court decisions; and
 
    the risks and lack of predictability inherent in personal injury litigation.
     Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” or SFAS 109, which requires the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. For interim periods, we estimate our annual effective tax rate by forecasting our annual income before income tax, taxable income and tax expense in each of our tax jurisdictions. We make judgments regarding future events and related estimates especially as they pertain to forecasting of our effective tax rate, the potential realization of deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.
     We adopted the provisions of Financial Accounting Standards Board, or FASB, Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48, on January 1, 2007. As a result of the implementation of FIN 48, we recognized a long-term tax receivable of $2.6 million and a long-term tax liability of $31.1 million for uncertain tax positions, the net of which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense.

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Results of Operations
     Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of economic characteristics among all our divisions and locations, including the nature of services provided and the type of customers for our services. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in our fleet and the geographic regions in which they operate to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.
Years Ended December 31, 2007 and 2006
     Comparative data relating to our revenue and operating expenses by equipment type are listed below.
                         
    Year Ended    
    December 31,   Favorable/
    2007   2006   (Unfavorable)
    (In thousands)
CONTRACT DRILLING REVENUE
                       
High-Specification Floaters
  $ 1,030,892     $ 766,873     $ 264,019  
Intermediate Semisubmersibles
    1,028,667       785,047       243,620  
Jack-ups
    446,104       435,194       10,910  
     
Total Contract Drilling Revenue
  $ 2,505,663     $ 1,987,114     $ 518,549  
     
 
                       
Revenues Related to Reimbursable Expenses
  $ 62,060     $ 65,458     $ (3,398 )
 
                       
CONTRACT DRILLING EXPENSE
                       
High-Specification Floaters
  $ 321,266     $ 236,276     $ (84,990 )
Intermediate Semisubmersibles
    485,681       391,092       (94,589 )
Jack-ups
    184,500       159,424       (25,076 )
Other
    19,746       25,265       5,519  
     
Total Contract Drilling Expense
  $ 1,011,193     $ 812,057     $ (199,136 )
     
 
                       
Reimbursable Expenses
  $ 52,857     $ 57,465     $ 4,608  
 
                       
OPERATING INCOME
                       
High-Specification Floaters
  $ 709,626     $ 530,597     $ 179,029  
Intermediate Semisubmersibles
    542,986       393,955       149,031  
Jack-ups
    261,604       275,770       (14,166 )
Other
    (19,746 )     (25,265 )     5,519  
Reimbursable expenses, net
    9,203       7,993       1,210  
Depreciation
    (235,251 )     (200,503 )     (34,748 )
General and administrative expense
    (53,483 )     (41,551 )     (11,932 )
Gain (loss) on disposition of assets
    8,583       (1,064 )     9,647  
Casualty gain on Ocean Warwick
          500       (500 )
     
Total Operating Income
  $ 1,223,522     $ 940,432     $ 283,090  
     
 
                       
Other income (expense):
                       
Interest income
    33,566       37,880       (4,314 )
Interest expense
    (19,191 )     (24,096 )     4,905  
Gain (loss) on sale of marketable securities
    1,796       (31 )     1,827  
Other, net
    6,844       12,147       (5,303 )
     
Income before income tax expense
    1,246,537       966,332       280,205  
Income tax expense
    (399,996 )     (259,485 )     (140,511 )
     
NET INCOME
  $ 846,541     $ 706,847     $ 139,694  
     

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     Demand remained strong for our rigs in all markets and geographic regions during 2007, except for the jack-up market in the GOM. Continued high overall utilization and historically high dayrates contributed to an overall increase in our net income of $139.7 million, or 20%, to $846.5 million in 2007 compared to $706.8 million in 2006. In many of the markets in which we operate, dayrates continued to increase compared to 2006 resulting in the generation of additional contract drilling revenues by our fleet. However, overall revenue increases were negatively impacted by the effect of downtime associated with scheduled shipyard projects and mandatory inspections or surveys, as well as the temporary ready-stacking of drilling rigs between wells in the GOM jack-up market. Total contract drilling revenues in 2007 increased $518.5 million, or 26%, to $2.5 billion compared to $2.0 billion in 2006.
     Total contract drilling expenses increased $199.1 million, or 25%, in 2007, compared to 2006, to $1.0 billion. Overall cost increases for maintenance and repairs between 2007 and 2006 reflect the impact of high, sustained utilization of our drilling units across our fleet, additional survey and related maintenance costs, contract preparation and mobilization costs, as well as the inclusion of normal operating costs for the newly upgraded Ocean Endeavor. The increase in overall operating and overhead costs also reflects the impact of higher prices throughout the offshore drilling industry and its support businesses. Our results were also impacted by higher expenses related to our mooring enhancement and other hurricane preparedness activities in 2006 and compensation increases during 2006 and 2007.
     Depreciation and general and administrative expenses increased $46.7 million in the aggregate, or 19% in 2007, compared to 2006, reducing our net income by $288.7 million in 2007.
     Net income for 2007 includes $58.6 million of non-recurring U.S. federal income tax expense related to the distribution of previously untaxed earnings from one of our foreign subsidiaries.
High-Specification Floaters.
                         
    Year Ended    
    December 31,   Favorable/
    2007   2006   (Unfavorable)
    (In thousands)
HIGH-SPECIFICATION FLOATERS:
                       
CONTRACT DRILLING REVENUE
                       
GOM
  $ 833,751     $ 574,594     $ 259,157  
Australia/Asia/Middle East
    73,004       65,682       7,322  
South America
    124,137       126,597       (2,460 )
     
Total Contract Drilling Revenue
  $ 1,030,892     $ 766,873     $ 264,019  
     
 
                       
CONTRACT DRILLING EXPENSE
                       
GOM
  $ 208,140     $ 143,447     $ (64,693 )
Australia/Asia/Middle East
    27,070       24,465       (2,605 )
South America
    86,056       68,364       (17,692 )
     
Total Contract Drilling Expense
  $ 321,266     $ 236,276     $ (84,990 )
     
 
                       
     
OPERATING INCOME
  $ 709,626     $ 530,597     $ 179,029  
     
     GOM. Revenues generated by our high-specification floaters operating in the GOM increased $259.2 million during 2007 compared to 2006, primarily due to higher average dayrates earned during 2007 ($259.1 million). Average operating revenue per day for our rigs in this market, excluding the Ocean Endeavor, increased to $354,400 during 2007 compared to $236,600 in 2006, reflecting the continued high demand for this class of rig in the GOM. Excluding the Ocean Endeavor, six of our seven other high-specification semisubmersible rigs in the GOM are currently operating at dayrates higher than those they earned during 2006. The Ocean Endeavor began operating during the third quarter of 2007 and generated revenues of $42.7 million in the GOM in 2007.
     Average utilization for our high-specification rigs operating in the GOM, excluding the Ocean Endeavor, decreased from 94% in 2006 to 87% in 2007 and resulted in a $38.4 million decline in revenues comparing the

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years. The decline in utilization during the 2007 period was primarily the result of scheduled downtime for special surveys for the Ocean Star (47 days) and Ocean Quest (66 days) and for a special survey and repairs to the Ocean Baroness (149 days), Combined utilization for these three rigs was 95% during 2006.
     During 2006, we recognized $4.3 million in mobilization revenue for the Ocean Baroness associated with its 2005 relocation to the GOM.
     Operating costs during 2007 for our high-specification floaters in the GOM increased $64.7 million to $208.1 million (including $16.8 million in normal operating expenses for the Ocean Endeavor) compared to 2006. The increase in operating costs in 2007 compared to 2006 reflects higher labor, benefits and other personnel-related costs resulting from compensation increases, higher maintenance and project costs and incremental costs associated with regulatory surveys for the Ocean Baroness, Ocean Star and Ocean Quest, including mobilization, inspection and related repair costs.
     Australia/Asia/Middle East. Revenues generated by the Ocean Rover, our high-specification rig operating offshore Malaysia, increased $7.3 million during 2007, as compared to 2006, primarily due to a higher operating dayrate earned by the rig in the first quarter and last two months of 2007.
     Operating expenses for the Ocean Rover in 2007 increased $2.6 million to $27.1 million compared to 2006, primarily due to higher labor, benefits and maintenance and project costs, partially offset by lower insurance and other costs.
     South America. Revenues earned by our high-specification floaters operating offshore Brazil decreased $2.5 million to $124.1 million in 2007 compared to 2006. The decrease in revenue was primarily due to a decline in utilization ($5.8 million) resulting from 33 days of additional unpaid downtime in 2007 for a special survey for the Ocean Alliance. The decline in revenues in 2007 was partially offset by an increase in the average operating revenue per day from $180,100 during 2006 to $185,300 during 2007, which contributed additional revenues of $3.3 million.
     Contract drilling expense for our operations in Brazil increased $17.7 million during 2007 compared to 2006. The increase in costs is primarily due to survey costs for the Ocean Alliance, higher labor and benefits costs as a result of compensation increases, as well as higher catering, freight and maintenance and project costs during 2007 compared to 2006.

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Intermediate Semisubmersibles.
                         
    Year Ended    
    December 31,   Favorable/
    2007   2006   (Unfavorable)
    (In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
                       
CONTRACT DRILLING REVENUE
                       
GOM
  $ 170,449     $ 224,344     $ (53,895 )
Mexico
    86,135       80,487       5,648  
Australia/Asia/Middle East
    239,200       196,180       43,020  
Europe/Africa/Mediterranean
    400,785       207,295       193,490  
South America
    132,098       76,741       55,357  
     
Total Contract Drilling Revenue
  $ 1,028,667     $ 785,047     $ 243,620  
     
 
                       
CONTRACT DRILLING EXPENSE
                       
GOM
  $ 79,606     $ 80,498     $ 892  
Mexico
    63,711       60,467       (3,244 )
Australia/Asia/Middle East
    114,567       87,535       (27,032 )
Europe/Africa/Mediterranean
    144,302       109,741       (34,561 )
South America
    83,495       52,851       (30,644 )
     
Total Contract Drilling Expense
  $ 485,681     $ 391,092     $ (94,589 )
     
 
                       
     
OPERATING INCOME
  $ 542,986     $ 393,955     $ 149,031  
     
     GOM. Revenues generated during 2007 by our intermediate semisubmersible fleet decreased $53.9 million compared to 2006, primarily as a result of the fourth quarter 2006 relocation of the Ocean Lexington to Egypt, as well as shipyard time during 2007 for four of our other rigs in this market. During 2007, we completed a survey and contract preparation work for the Ocean Voyager, a service life extension project for the Ocean Saratoga and contract modifications for the Ocean Concord and Ocean New Era. Excluding the Ocean Lexington, average utilization for our intermediate semisubmersible rigs operating in the GOM (Ocean Voyager, Ocean Concord, Ocean New Era and Ocean Saratoga) declined from 84% in 2006 to 75% during 2007 and reduced revenues by $58.3 million. During 2006, the Ocean Lexington generated revenues of $33.4 million in the GOM. Of these rigs, only the Ocean Saratoga remained in the GOM as of December 31, 2007.
     The overall decline in revenues in 2007 was partially offset by an increase in average dayrates earned by our intermediate semisubmersible rigs operating in the GOM during both 2007 and 2006. Average operating revenue per day, excluding the Ocean Lexington, increased from $155,200 during 2006 to $189,400 in 2007 and contributed additional revenues of $37.8 million.
     During 2006 and 2007, three of our rigs completed their contracts with PEMEX and temporarily returned to the GOM. The Ocean Whittington returned to the GOM in July 2006 for a survey, contract preparation work and a service life extension. The Ocean Yorktown and Ocean Worker returned to the GOM in July 2007 and August 2007, respectively for surveys and contract preparation work, as well as a service life extension project for the Ocean Yorktown. All three rigs were located in shipyards in the GOM for extended periods during 2007, and we incurred additional costs in the GOM associated with these activities. During the third and fourth quarters of 2007, the Ocean Whittington and the Ocean Worker departed the GOM for Brazil and Trinidad and Tobago, respectively, where they are working under contract. The Ocean Yorktown is expected to leave for Brazil in the second quarter of 2008.
     Contract drilling expenses decreased by $0.9 million in 2007 compared to 2006. Increased costs in the GOM associated with surveys and contract preparation activities, as well as higher labor and related costs during 2007 were offset by lower normal operating costs in the GOM as a result of the numerous rigs that were relocated from the region at the end of 2006 and during 2007.

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     Mexico. Revenues generated by our intermediate semisubmersible rigs operating offshore Mexico increased $5.6 million in 2007 compared to 2006. The relocation of the Ocean New Era and Ocean Voyager from the GOM to Mexico in the fourth quarter of 2007 generated an additional $33.3 million in revenues for this region in 2007. Revenues generated in 2007 were reduced by $28.5 million due to the return of the Ocean Whittington in July 2006 and the Ocean Worker and Ocean Yorktown in the third quarter of 2007 to the GOM.
     Our operating costs in Mexico increased by $3.2 million in 2007 compared to 2006, primarily due to the inclusion of operating costs for the Ocean New Era and Ocean Voyager and costs to mobilize the Ocean Worker and Ocean Yorktown from Mexico to the GOM. The overall increase in costs was partially offset by the absence of operating costs for the Ocean Whittington in 2007 and reduced normal operating costs for the Ocean Worker and Ocean Yorktown beginning in the third quarter of 2007.
     Australia/Asia/Middle East. Our intermediate semisubmersibles working in the Australia/Asia/Middle East regions generated revenues of $239.2 million in 2007 compared to revenues of $196.2 million in 2006. The $43.0 million increase in operating revenue was primarily due to an increase in average operating revenue per day from $135,600 in 2006 to $169,900 in 2007, which generated additional revenues of $45.4 million during 2007. The increase in average operating revenue per day is primarily attributable to an increase in the contractual dayrates earned by the Ocean Patriot that occurred in the third quarter of 2007, and the Ocean Epoch and Ocean General that occurred during the second and third quarters of 2006, respectively.
     Average utilization in this region decreased to 94% during 2007 from 97% utilization during 2006, primarily due to 46 days of incremental unpaid downtime in 2007, as compared to 2006, for repairs as well as a survey of the Ocean General and an environmental survey of the Ocean Patriot and related removal of an invasive species of green, lipped mussels that had attached itself to the rig while working offshore New Zealand. The decline in utilization during 2007 reduced revenues by $4.4 million. Additionally, during 2007 we recognized $4.6 million in mobilization revenue in connection with the relocations of the Ocean Epoch and the Ocean General to other areas within the Australia/Asia region. During 2006, we recognized $2.3 million in mobilization revenue for the relocation of the Ocean Patriot to New Zealand.
     Contract drilling expense for the Australia/Asia/Middle East region increased $27.0 million in 2007 compared to 2006. The increase in operating costs was primarily due to higher labor and personnel-related costs, including higher local labor costs for the Ocean Epoch, which relocated to Australia in the fourth quarter of 2006 from Malaysia. Other cost increases for our rigs operating in this region during 2007, as compared to 2006, include higher repair and maintenance costs, higher freight costs and additional costs associated with the environmental survey of the Ocean Patriot. These increased costs were partially offset by lower agency fee costs incurred by the Ocean Epoch in 2007 compared to 2006 when the rig was operating offshore Malaysia.
     Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean regions increased $193.5 million in 2007 compared to 2006. Overall utilization during 2007 increased primarily due to the relocation of the Ocean Lexington ($97.1 million) from the GOM to offshore Egypt in the fourth quarter of 2006. Additionally, the Ocean Princess generated additional revenues of $8.4 million during 2007 compared to 2006 when the rig had 48 days of downtime for an intermediate survey and related repairs. These favorable variances resulting from the increased utilization of two of our rigs in this region were partially offset by 18 days of unpaid downtime for an intermediate survey of the Ocean Vanguard that reduced revenues by $1.9 million in 2007. Also during 2006, we recognized $4.4 million in revenues related to the amortization of lump-sum fees received from customers for capital improvements to the Ocean Guardian and Ocean Vanguard.
     Average operating revenue per day for our North Sea semisubmersibles increased from $144,500 in 2006 to $211,500 in 2007, contributing $93.9 million in additional revenue in 2007 as compared to 2006. The overall increase in average operating revenue per day in this market was primarily due to higher dayrates earned by the Ocean Nomad, Ocean Guardian and Ocean Vanguard during 2007.
     Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets increased $34.6 million in 2007 compared to 2006, primarily due to the inclusion of normal operating costs for the Ocean Lexington ($21.8 million). Increased operating expenses in 2007 are also reflective of higher labor and benefits costs incurred in 2007 for our rigs operating in the North Sea, including the effect of compensation increases and implementation of a retention plan, and higher shorebase support

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costs. However, overall operating expense increases in this region during 2007 were partially offset by lower mobilization and inspection costs associated with surveys, as costs incurred for the Ocean Vanguard‘s intermediate survey in December 2007 were well below aggregate expenses related to surveys for the Ocean Guardian and Ocean Princess in 2006.
     South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $55.4 million to $132.1 million in 2007 from $76.7 million in 2006. During 2007, we relocated the Ocean Whittington (Brazil) and the Ocean Worker (Trinidad and Tobago) to this region where they generated revenues of $25.7 million and $21.5 million, respectively. For our other two semisubmersible rigs operating offshore Brazil in both 2007 and 2006, average operating revenue per day in 2007 increased to $123,900 from $113,700 in 2006, resulting in a $7.0 million increase in revenue from 2006.
     Operating expenses for our operations in the South American region increased $30.6 million in 2007, as compared to 2006, partially due to the inclusion of normal operating and start-up costs for the Ocean Whittington and the Ocean Worker, as well as start-up costs for the Ocean Concord which relocated to Brazil from the GOM in the fourth quarter of 2007 to begin a five-year contract. The Ocean Concord did not begin operating under contract until 2008. Other cost increases during 2007 compared to 2006 include increased labor and other personnel-related costs, shorebase support and freight costs, as well as higher repair and maintenance costs.
Jack-Ups.
                         
    Year Ended    
    December 31,   Favorable/
    2007   2006   (Unfavorable)
    (In thousands)
 
                       
JACK-UPS:
                       
CONTRACT DRILLING REVENUE
                       
GOM
  $ 222,276     $ 315,279     $ (93,003 )
Mexico
    62,451       15,966       46,485  
Australia/Asia/Middle East
    88,497       61,141       27,356  
Europe/Africa/Mediterranean
    72,880       42,808       30,072  
     
Total Contract Drilling Revenue
  $ 446,104     $ 435,194     $ 10,910  
     
 
                       
CONTRACT DRILLING EXPENSE
                       
GOM
  $ 120,210     $ 112,524     $ (7,686 )
Mexico
    16,108       4,373       (11,735 )
Australia/Asia/Middle East
    28,438       27,721       (717 )
Europe/Africa/Mediterranean
    19,744       14,806       (4,938 )
     
Total Contract Drilling Expense
  $ 184,500     $ 159,424     $ (25,076 )
     
 
                       
     
OPERATING INCOME
  $ 261,604     $ 275,770     $ (14,166 )
     
     GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $93.0 million during 2007 compared to 2006. The decline in revenues is primarily due to the relocation of three of our jack-up rigs from the GOM to other markets: the Ocean King to Croatia in the third quarter of 2007; the Ocean Nugget to Mexico in the fourth quarter of 2006; and the Ocean Spur to Tunisia in the first quarter of 2006. These rigs generated $56.0 million in revenues while operating in the GOM in 2006 compared to only $13.3 million earned by the Ocean King in the GOM during 2007. In addition, the Ocean Columbia, which was in a shipyard for a majority of the fourth quarter of 2007 for preparation work in connection with an 18-month contract offshore Mexico, generated revenues of $28.8 million in the GOM during 2007 compared to $37.5 million in 2006.
     Average utilization (excluding the Ocean Columbia, Ocean King, Ocean Nugget and Ocean Spur) declined from 90% during 2006 to 78% during 2007 resulting in a reduction in revenues of $29.6 million. The decline in utilization was primarily in response to market conditions in the GOM that caused us to ready-stack certain of our jack-up rigs for a portion of time between wells, scheduled downtime for surveys of the Ocean Crusader and Ocean Tower and contract preparation activities for the Ocean Columbia. The Ocean Columbia departed the GOM for Mexico at the end of the fourth quarter of 2007.

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     Revenues also declined due to a decrease in average operating dayrates. Average operating revenue per day in 2007, excluding the Ocean Columbia, Ocean King, Ocean Nugget and Ocean Spur, decreased to $90,500 from $96,500 in 2006, resulting in a $11.9 million decrease in revenue from 2006.
     Contract drilling expense in the GOM increased $7.7 million in 2007 compared to 2006. The overall increase in costs was primarily due to higher survey and related repair costs in 2007, contract preparation activities for the Ocean Columbia, as well as increased repair and ready-stacking costs for several of our rigs marketed in the GOM. In addition, operating costs for our rigs in this market were negatively impacted by regular salary increases and higher overhead costs. The overall increase in operating costs was partially offset by the absence of operating costs in the GOM for the Ocean Nugget and Ocean Spur and lower operating costs for the Ocean King during 2007, which reduced operating expenses by $19.5 million.
     Mexico. The Ocean Nugget, which began operating offshore Mexico in the fourth quarter of 2006, generated $62.5 million in revenues during 2007 and incurred contract drilling expenses of $16.1 million. We had no jack-up rigs operating in this market prior to the fourth quarter of 2006.
     Australia/Asia/Middle East. Our two jack-up rigs operating in the Australia/Asia/Middle East regions generated revenues of $88.5 million during 2007 compared to $61.1 million in 2006. The $27.4 million increase in revenues was primarily due to an increase in average operating revenue per day earned by our rigs in this region from $95,600 during 2006 to $123,600 for 2007, primarily due to new contracts at higher dayrates for both the Ocean Heritage and Ocean Sovereign that began late in the second and third quarters of 2006, respectively, as well as additional dayrate increases for both rigs during 2007 which generated additional revenues of $19.5 million. Average utilization for our rigs in this region increased from 87% during 2006 to 98% in 2007 primarily due to increased utilization for both the Ocean Heritage and Ocean Sovereign in 2007, as compared to 2006 when these rigs were out of service for scheduled surveys and related repairs. The increase in utilization in 2007 resulted in the generation of additional revenues of $8.3 million.
     Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean regions increased $30.1 million during 2007 compared to 2006. Our jack-up rig, the Ocean Spur, began operating offshore Tunisia in March 2006 and generated revenues of $42.8 million and $32.9 million during 2006 and 2007, respectively. The rig subsequently mobilized to the Mediterranean Basin and began operating offshore Egypt in late May 2007, generating revenues of $36.6 million.
     During the third quarter of 2007, we relocated the Ocean King from the GOM to Croatia where it began operating under a two-year bareboat charter, generating revenues of $3.3 million in 2007.
     Operating expenses in this region increased $4.9 million during 2007 compared to 2006, primarily due to the inclusion of a full year of operating costs for the Ocean Spur in 2007 compared to only nine and one-half months of expenses during 2006.
Reimbursable expenses, net.
     Revenues related to reimbursable items, offset by the related expenditures for these items, were $9.2 million and $8.0 million for 2007 and 2006, respectively. Reimbursable expenses include items that we purchase, and/or services we perform, at the request of our customers. We charge our customers for purchases and/or services performed on their behalf at cost, plus a mark-up where applicable. Therefore, net reimbursables fluctuate based on customer requirements, which vary.
Depreciation.
     Depreciation expense increased $34.7 million to $235.2 million in 2007 compared to $200.5 million in 2006 primarily due to depreciation associated with capital additions in 2006 and 2007, as well as higher depreciation expense for the Ocean Endeavor due to the completion of its major upgrade in March 2007.

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General and Administrative Expense.
     We incurred general and administrative expense of $53.5 million in 2007 compared to $41.6 million in 2006. The $11.9 million increase in overhead costs between the periods was primarily due to an increase in payroll costs resulting from higher compensation and staffing increases, legal fees, engineering and tax consulting fees and miscellaneous office expenses.
Gain (Loss) on Disposition of Assets.
     We recognized a net gain of $8.6 million on the sale and disposition of assets, net of disposal costs, in 2007 compared to a net loss of $1.1 million in 2006. The gain recognized in 2007 primarily consists of the recognition of gains on insurance settlements and from sales of used equipment. The loss recognized in 2006 is primarily the result of costs associated with the removal of production equipment from the Ocean Monarch, which was subsequently sold to a third party.
Interest Expense.
     We recorded interest expense during 2007 of $19.2 million, representing a $4.9 million decrease in interest cost compared to 2006. This decrease was primarily attributable to a greater amount of interest capitalized during 2007 related to our qualifying rig upgrades and construction projects and lower interest cost associated with our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures. This decrease was partially offset by $9.2 million in debt issuance costs that we wrote off during 2007 in connection with conversions of our 1.5% Debentures and our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, into shares of our common stock. See “— Liquidity and Capital Requirements — 1.5% Debentures” and “ — Liquidity and Capital Requirements — Zero Coupon Debentures.”
Other Income and Expense (Other, net).
     Included in “Other, net” are foreign currency translation adjustments and transaction gains and losses and other income and expense items, among other things, which are not attributable to our drilling operations. The components of “Other, net” fluctuate based on the level of activity, as well as fluctuations in foreign currencies. We recorded other income, net, of $6.8 million during 2007 and other income, net, of $12.1 million in 2006.
     During 2007 and 2006, we recognized net foreign currency exchange gains of $2.9 million and $10.3 million, respectively.
Income Tax Expense.
     Our net income tax expense is a function of the mix of our domestic and international pre-tax earnings, as well as the mix of earnings from the international tax jurisdictions in which we operate. We recognized $400.0 million of tax expense on pre-tax income of $1.2 billion for the year ended December 31, 2007 compared to tax expense of $259.5 million on a pre-tax income of $966.3 million in 2006.
     Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary which we wholly own. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes were provided on these earnings in years subsequent to 2002 except to the extent that such earnings were immediately subject to U.S. federal income tax. In December 2007, this subsidiary made a non-recurring distribution of $850.0 million to its U.S. parent, a portion of which consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. We recognized $58.6 million of U.S. federal income tax expense as a result of the distribution. As of December 31, 2007, the amount of previously untaxed earnings of this subsidiary was zero. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest future earnings of this subsidiary to finance foreign activities.
     We adopted the provisions of FIN 48 on January 1, 2007. During the year ended December 31, 2007 we recognized $4.4 million of tax expense for uncertain tax positions related to the current year, $0.8 million of which was penalty related tax expense.

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     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.

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Years Ended December 31, 2006 and 2005
     Comparative data relating to our revenues and operating expenses by equipment type are presented below.
                         
    Year Ended    
    December 31,   Favorable/
    2006   2005   (Unfavorable)
    (In thousands)
CONTRACT DRILLING REVENUE
                       
High-Specification Floaters
  $ 766,873     $ 448,937     $ 317,936  
Intermediate Semisubmersibles
    785,047       456,734       328,313  
Jack-ups
    435,194       271,809       163,385  
Other
          1,535       (1,535 )
     
Total Contract Drilling Revenue
  $ 1,987,114     $ 1,179,015     $ 808,099  
     
 
                       
Revenues Related to Reimbursable Expenses
  $ 65,458     $ 41,987     $ 23,471  
 
                       
CONTRACT DRILLING EXPENSE
                       
High-Specification Floaters
  $ 236,276     $ 179,248     $ (57,028 )
Intermediate Semisubmersibles
    391,092       325,579       (65,513 )
Jack-ups
    159,424       123,833       (35,591 )
Other
    25,265       9,880       (15,385 )
     
Total Contract Drilling Expense
  $ 812,057     $ 638,540     $ (173,517 )
     
 
                       
Reimbursable Expenses
  $ 57,465     $ 35,549     $ (21,916 )
 
                       
OPERATING INCOME
                       
High-Specification Floaters
  $ 530,597     $ 269,689     $ 260,908  
Intermediate Semisubmersibles
    393,955       131,155       262,800  
Jack-ups
    275,770       147,976       127,794  
Other
    (25,265 )     (8,345 )     (16,920 )
Reimbursables, net
    7,993       6,438       1,555  
Depreciation
    (200,503 )     (183,724 )     (16,779 )
General and Administrative Expense
    (41,551 )     (37,162 )     (4,389 )
(Loss) gain on Sale and Disposition of Assets
    (1,064 )     14,767       (15,831 )
Casualty gain on Ocean Warwick
    500       33,605       (33,105 )
     
Total Operating Income
  $ 940,432     $ 374,399     $ 566,033  
     
Other income (expense):
                       
Interest income
    37,880       26,028       11,852  
Interest expense
    (24,096 )     (41,799 )     17,703  
Gain (loss) on sale of marketable securities
    (31 )     (1,180 )     1,149  
Other, net
    12,147       (1,053 )     13,200  
     
Income before income tax expense
    966,332       356,395       609,937  
Income tax expense
    (259,485 )     (96,058 )     (163,427 )
     
NET INCOME
  $ 706,847     $ 260,337     $ 446,510  
     
     Net income in 2006 increased $446.5 million, or 172%, to $706.8 million, compared to $260.3 million in 2005 due to strong demand for our rigs in all markets and geographic regions in which we operate. Dayrates generally increased during 2006, compared to 2005, and resulted in the generation of additional contract drilling revenues by our fleet. The effect of higher dayrates earned by our rigs was negatively impacted by the effect of downtime associated with mandatory surveys and related repair time, as well as lower dayrates earned by some of our semisubmersible rigs due to previously established job sequencing that caused the units to temporarily roll to older contracts with lower dayrates. Total contract drilling revenues in 2006 increased $808.1 million to $1,987.1 million, or 69% compared to 2005.

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     Total contract drilling expenses in 2006 increased $173.5 million to $812.1 million, or 27% compared to 2005. Our results in 2006 were negatively impacted by higher expenses related to our mooring enhancement and other hurricane preparedness activities, compensation increases and mandatory surveys performed during 2006. The increase in survey costs included higher expenses for survey-related services and higher boat charges associated with moving rigs to and from shipyards. In addition, overall cost increases for maintenance and repairs between 2005 and 2006 reflect the impact of high, sustained utilization of our drilling units across our fleet and in all geographic locations in which we operate. The increase in overall operating and overhead costs also reflected the impact of higher prices throughout the offshore drilling industry and its support businesses. The increase in our operating expenses in 2006, as compared to 2005, was partially offset by an $8.0 million reduction in our reserve for personal injury claims based on an actuarial review.
     Net income for 2006 compared to 2005 reflected higher interest income on invested cash balances combined with lower interest expense on our outstanding debentures due to debt conversions in 2006 and foreign currency exchange gains recognized in 2006. These favorable contributions to net income were partially offset by higher depreciation and general and administrative expenses of $21.2 million in 2006 compared to 2005. Additionally, during 2005, we recognized a $33.6 million casualty gain due to the constructive total loss of the Ocean Warwick as a result of Hurricane Katrina in August 2005 and an $8.0 million gain related to the June 2005 sale of the Ocean Liberator.
     Our net income in 2006 was reduced by $259.5 million of income tax expense on pre-tax earnings of $966.3 million compared to income tax expense of $96.1 million on pre-tax earnings of $356.4 million in 2005.
High-Specification Floaters.
                         
    Year Ended    
    December 31,   Favorable/
    2006   2005   (Unfavorable)
     
    (In thousands)
HIGH-SPECIFICATION FLOATERS:
                       
CONTRACT DRILLING REVENUE
                       
GOM
  $ 574,594     $ 304,642     $ 269,952  
Australia/Asia/Middle East
    65,682       68,349       (2,667 )
South America
    126,597       75,946       50,651  
     
Total Contract Drilling Revenue
  $ 766,873     $ 448,937     $ 317,936  
     
CONTRACT DRILLING EXPENSE
                       
GOM
  $ 143,447     $ 88,107     $ (55,340 )
Australia/Asia/Middle East
    24,465       35,891       11,426  
South America
    68,364       55,250       (13,114 )
     
Total Contract Drilling Expense
  $ 236,276     $ 179,248     $ (57,028 )
     
 
                       
     
OPERATING INCOME
  $ 530,597     $ 269,689     $ 260,908  
     
     GOM. Revenues generated by our high-specification floaters operating in the GOM increased $270.0 million in 2006 compared to 2005, primarily due to higher average dayrates earned during the period and revenues generated by the Ocean Baroness, which relocated to the GOM from the Australia/Asia market in the latter half of 2005 ($58.1 million). Excluding the Ocean Baroness, average operating revenue per day for our rigs in this market increased to $242,000 during 2006, compared to $142,600 during 2005, generating additional revenues of $211.6 million. The higher overall dayrates achieved for our high-specification floaters reflected the continuing high demand for this class of rig in the GOM.
     Average utilization for our high-specification rigs operating in the GOM, excluding the contribution from the Ocean Baroness, increased slightly to 96% in 2006 compared to 2005, and resulted in $0.2 million in revenue.
     Operating costs during 2006 for our high-specification floaters in the GOM increased $55.3 million over operating costs incurred during 2005. The increase in operating costs was primarily due to the inclusion of normal operating costs and amortization of mobilization expenses for the Ocean Baroness during 2006 ($30.6 million) compared to the prior year when this drilling rig operated offshore Indonesia. In addition, our operating expenses

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for 2006, compared to 2005, reflected higher labor and benefits costs related to late 2005 and first quarter of 2006 wage increases, higher repair and maintenance costs, and higher miscellaneous operating expenses, including catering costs. Our operating expenses in 2005 reflected a $2.0 million reduction in costs due to a recovery from a customer for damages sustained by one of our GOM rigs during Hurricane Ivan in 2004, partially offset by the recognition of $0.5 million in deductibles for damages sustained during Hurricane Katrina in 2005.
     Australia/Asia. Revenues generated by our high-specification rigs in the Australia/Asia/Middle East market decreased $2.7 million in 2006 compared to 2005, primarily due to the relocation of the Ocean Baroness from this market to the GOM in the latter half of 2005. Prior to its relocation to the GOM, the Ocean Baroness generated $18.2 million in revenues during 2005. The decrease in revenues in 2006 was partially offset by additional revenue ($13.7 million) generated by an increase in the dayrate earned by the Ocean Rover compared to the prior year. The average operating revenue per day for this rig increased from $143,500 in 2005 to $181,500 in 2006 as a result of a new drilling program which began in the second quarter of 2006. Utilization improvements for the Ocean Rover during 2006, as compared to 2005 when the unit had 11 days of downtime for repairs, generated an additional $1.8 million in revenues.
     Operating costs for our rigs in the Australia/Asia/Middle East market decreased $11.4 million in 2006 compared to 2005 primarily due to the relocation of the Ocean Baroness to the GOM ($15.5 million). This decrease was partially offset by an increase in operating costs for the Ocean Rover during 2006, compared to the prior year, primarily related to higher personnel-related costs as a result of late 2005 and March 2006 compensation increases, increased agency fee costs (which are based on a percentage of revenues) and higher other miscellaneous operating expenses.
     South America. Revenues for our high-specification rigs operating offshore Brazil increased $50.7 million in 2006 compared to 2005, primarily due to higher average dayrates earned by our rigs in this market ($44.1 million). Average operating revenue per day earned by the Ocean Alliance and the Ocean Clipper increased to $180,100 during 2006 up from $117,300 during the prior year as a result of contract renewals for both rigs in the latter part of 2005. Utilization for our rigs offshore Brazil increased from 89% in 2005 to 96% in 2006, contributing $6.6 million in additional revenues in 2006, primarily due to less downtime during 2006 for repairs.
     Contract drilling expenses for our operations offshore Brazil increased $13.1 million in 2006 compared to 2005. The increase in costs was primarily due to higher labor, benefits and other personnel-related costs as a result of 2005 and March 2006 compensation increases and other compensation enhancement programs, increased agency fee costs (which are based on a percentage of revenues), higher freight costs and higher maintenance and project costs.

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Intermediate Semisubmersibles.
                         
    Year Ended    
    December 31,   Favorable/
    2006   2005   (Unfavorable)
     
    (In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
                       
CONTRACT DRILLING REVENUE
                       
GOM
  $ 224,344     $ 99,500     $ 124,844  
Mexico
    80,487       85,594       (5,107 )
Australia/Asia/Middle East
    196,180       111,811       84,369  
Europe/Africa/Mediterranean
    207,295       106,251       101,044  
South America
    76,741       53,578       23,163  
     
Total Contract Drilling Revenue
  $ 785,047     $ 456,734     $ 328,313  
     
CONTRACT DRILLING EXPENSE
                       
GOM
  $ 80,498     $ 49,947     $ (30,551 )
Mexico
    60,467       57,246       (3,221 )
Australia/Asia/Middle East
    87,535       83,768       (3,767 )
Europe/Africa/Mediterranean
    109,741       93,253       (16,488 )
South America
    52,851       41,365       (11,486 )
     
Total Contract Drilling Expense
  $ 391,092     $ 325,579     $ (65,513 )
     
 
                       
     
OPERATING INCOME
  $ 393,955     $ 131,155     $ 262,800  
     
     GOM. Revenues generated by our intermediate semisubmersible rigs operating in the GOM during 2006 increased $124.8 million over the prior year primarily due to higher average operating dayrates and the operation of the Ocean New Era ($53.9 million) which was reactivated in December 2005. Average operating dayrates for the remainder of our GOM fleet of intermediate rigs increased from $77,300 in 2005 to $149,300 in 2006 and generated additional revenues of $82.2 million during 2006. Excluding the Ocean New Era, utilization fell from 87% in 2005 to 75% in 2006, resulting in an $11.3 million reduction in revenues generated in 2006 compared to 2005. Average utilization in 2006 was negatively impacted by approximately five months of downtime for the Ocean Saratoga in connection with its survey and related repairs, as well as a life enhancement upgrade that commenced in the third quarter of 2006 and approximately one month of downtime for both the Ocean Voyager and Ocean Concord for mooring upgrades. Partially offsetting the decline in average utilization in 2006 was an improvement in utilization for the Ocean Lexington, which worked nearly all of 2006 prior to its move to Egypt at the beginning of the fourth quarter. During 2005, the Ocean Lexington incurred over four months of downtime for a survey and life enhancement upgrade.
     Contract drilling expense for our GOM operations increased $30.6 million in 2006 compared to 2005, primarily due to normal operating costs for the Ocean New Era in 2006 ($7.6 million) and repair and other normal operating costs for the Ocean Whittington ($6.4 million) in the latter half of 2006 after its return from Mexico. Higher operating costs in 2006, as compared to 2005, reflected higher labor and benefits costs as a result of September 2005 and March 2006 wage increases for our rig-based personnel, mobilization costs associated with mooring upgrades for the Ocean Concord and Ocean Voyager, survey and related repair costs for the Ocean Saratoga and higher maintenance and other miscellaneous operating costs for our semisubmersible rigs in this market segment. In addition, during 2006, we incurred $2.4 million in costs associated with the rental of mooring lines and chains as temporary replacements for equipment lost during the 2005 hurricanes in the GOM. Partially offsetting the increased operating costs in 2006 was the absence of reactivation costs for the Ocean New Era, which returned to service in December 2005.
     Mexico. Revenues generated by our intermediate semisubmersibles operating offshore Mexico during 2006 decreased $5.1 million compared to 2005, primarily due to PEMEX’s early cancellation of its contract for the Ocean Whittington in July 2006, partially offset by increased revenues for the Ocean Worker as a result of a small dayrate increase received in December 2005. Operating costs in Mexico increased $3.2 million during 2006 compared to 2005, primarily due to the effect of 2005 and March 2006 wage increases for our rig-based personnel, as well as higher repair and maintenance costs, other miscellaneous operating costs and overheads, partially offset by lower

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operating costs for the Ocean Whittington pursuant to its third quarter relocation to the GOM after termination of its drilling contract by PEMEX. In addition, we incurred $1.9 million in costs associated with the demobilization of the Ocean Whittington from offshore Mexico to the GOM.
     Australia/Asia. Our intermediate semisubmersible rigs operating in the Australia/Asia market during 2006 generated an additional $84.4 million in revenues compared to 2005 primarily due to higher average operating dayrates ($84.3 million). Average operating dayrates increased from $76,300 in 2005 to $135,600 in 2006. In addition, the over 95% utilization of both the Ocean Epoch and Ocean Patriot during 2006, as compared to 2005 when the average utilization for these two rigs was 84%, contributed an additional $6.6 million to 2006 revenues. During 2005 the Ocean Epoch had over two months of downtime associated with a scheduled 5-year survey, other regulatory inspections and contract preparation work prior to its relocation to Malaysia and the Ocean Patriot incurred over one month of downtime associated with an intermediate inspection and repairs.
     These favorable revenue variances in 2006 were partially offset by the lower recognition of deferred mobilization, capital upgrade and other fees in 2006 compared to 2005. During 2006, we recognized $2.3 million in lump-sum mobilization revenue related to the Ocean Patriot‘s move offshore New Zealand at the beginning of the fourth quarter of 2006 and equipment upgrade fees from two customers in connection with customer-requested capital improvements to the Ocean Patriot. However, during 2005, we recognized $5.7 million and $0.9 million in connection with the Ocean Patriot‘s 2004 mobilization from South Africa to New Zealand and the Bass Strait and equipment upgrade fees, respectively. Additionally, we received a fee from another customer in this market for a drilling option for another rig, of which $0.6 million and $3.7 million were recognized in 2006 and 2005, respectively.
     Contract drilling expense for the Australia/Asia/Middle East region increased slightly from $83.8 million in 2005 to $87.5 million in 2006. The $3.8 million net increase in costs for 2006 was primarily the result of higher labor costs (due to wage increases in late 2005 and March 2006), higher repair and maintenance costs, higher revenue-based agency fees and higher other operating costs. These unfavorable cost trends were partially offset by lower survey and inspection costs in 2006 and the recognition of an insurance deductible in 2005 related to an anchor winch failure on the Ocean Patriot. In addition, we recognized $1.1 million and $5.2 million in mobilization expenses for our rigs in this region during 2006 and 2005, respectively. The amount of mobilization expenses recognized during a period is dependent upon the duration of the rig move and the contract period over which the mobilization costs are to be recognized.
     Europe/Africa/Mediterranean. Revenues generated by our intermediate semisubmersibles operating in this market increased $101.0 million in 2006 compared to 2005, primarily due to an increase in the average operating revenue per day earned by our rigs in this market. Excluding the Ocean Lexington, which began operating in this market sector during the fourth quarter of 2006 and contributed revenues of $5.6 million, the average operating revenue per day for our rigs operating in this market increased from $87,500 in 2005 to $144,500 in 2006. This increase in average revenue per day generated additional revenues of $70.6 million in 2006 compared to 2005. All three of our rigs operating in the U.K. sector of the North Sea received operating dayrate increases during 2006 and the Ocean Vanguard began a drilling program in the fourth quarter of 2006 at a higher dayrate than it previously earned.
     Average utilization for our rigs in the Europe/Africa region increased from 83% in 2005 to 94% in 2006, excluding the Ocean Lexington, generating $20.7 million in additional revenues. The increase in average utilization was primarily due to higher utilization in 2006 for the Ocean Vanguard, compared to 2005 when this unit incurred more than five months of downtime due to an anchor winch failure and for a 5-year survey and related repairs. Additionally, average utilization for our three rigs operating in the U.K. sector of the North Sea increased slightly, reflecting the nearly full utilization of the Ocean Nomad during 2006 compared to 2005, when the rig was ready-stacked for almost three weeks and incurred nearly a full month of downtime for repairs. These favorable utilization trends were partially offset by 48 days of downtime for the Ocean Princess which was in a shipyard for an intermediate survey during 2006. In comparison, the Ocean Princess operated for nearly all of 2005.
     During 2006, we also recognized $4.4 million in revenues related to the amortization of lump-sum fees received from customers for capital improvements to the Ocean Guardian and Ocean Vanguard.
     Contract drilling expenses for our intermediate semisubmersible rigs operating in the Europe/Africa region increased $16.5 million during 2006 compared to 2005, primarily due to the inclusion of $4.2 million of normal operating costs for the Ocean Lexington in Egypt and costs associated with scheduled surveys for the Ocean

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Guardian and Ocean Princess, including mobilization and related repair costs during 2006. Also contributing to the increase in costs during 2006 were higher personnel and related costs (including administrative and support personnel in the region), reflecting the impact of wage increases after September 2005 and higher overall other operating costs. These cost increases in 2006 were partially offset by lower maintenance costs for the Ocean Vanguard in 2006 compared to 2005 and the absence of mobilization costs in 2006 related to the Ocean Nomad‘s relocation from Gabon to the North Sea at the end of 2004, which were fully recognized in 2005, as well as the 2005 recognition of mobilization costs incurred in connection with the Ocean Guardian‘s first quarter 2006 survey.
     South America. Revenues generated by our two intermediate semisubmersible rigs operating in Brazil in 2006 increased $23.2 million to $76.7 million in 2006 from $53.6 million in 2005, primarily due to higher average operating dayrates earned by both of our rigs in this market. Average operating revenue per day rose from $75,100 in 2005 to $113,700 in 2006, contributing $26.4 million in additional revenues.
     Reduced utilization for our two intermediate semisubmersible rigs operating offshore Brazil during 2006, compared to 2005, was primarily the result of additional downtime for repairs during 2006, including 45 days of downtime for a thruster change-out on the Ocean Yatzy. This overall decrease in average utilization in 2006 resulted in a $3.2 million reduction in revenues compared to the prior year.
     Operating expenses for the Ocean Yatzy and Ocean Winner increased $11.5 million in 2006 compared to the prior year, primarily due to increased labor costs for our rig-based and shore-based personnel as a result of wage increases and other compensation enhancement programs implemented after the third quarter of 2005, higher revenue-based agency fees, as well as higher repair, maintenance and freight costs and increases in other routine operating costs in 2006 compared to 2005.
Jack-Ups.
                         
    Year Ended    
    December 31,   Favorable/
    2006   2005   (Unfavorable)
     
    (In thousands)
JACK-UPS:
                       
CONTRACT DRILLING REVENUE
                       
GOM
  $ 315,279     $ 222,365     $ 92,914  
Mexico
    15,966             15,966  
Australia/Asia/Middle East
    61,141       49,444       11,697  
Europe/Africa/Mediterranean
    42,808             42,808  
     
Total Contract Drilling Revenue
  $ 435,194     $ 271,809     $ 163,385  
     
CONTRACT DRILLING EXPENSE
                       
GOM
  $ 112,524     $ 98,866     $ (13,658 )
Mexico
    4,373             (4,373 )
Australia/Asia/Middle East
    27,721       24,967       (2,754 )
Europe/Africa/Mediterranean
    14,806             (14,806 )
     
Total Contract Drilling Expense
  $ 159,424     $ 123,833     $ (35,591 )
     
 
                       
     
OPERATING INCOME
  $ 275,770     $ 147,976     $ 127,794  
     
     GOM. Revenues generated by our jack-up rigs in the GOM increased $92.9 million in 2006 compared to 2005 primarily due to an improvement in average operating dayrates for our rigs in this region. Excluding the Ocean Warwick, which was declared a constructive total loss in the third quarter of 2005, our average operating revenue per day increased to $100,800 in 2006 from $59,100 in 2005, generating additional revenues of $141.9 million. GOM revenues were reduced $37.2 million due to changes in average utilization which fell to 79% in 2006 from 96% in 2005 (excluding the Ocean Warwick). During 2006, utilization in the GOM was negatively impacted primarily by the relocation of the Ocean Spur to Tunisia in the first quarter of 2006 and over five months of downtime for the Ocean Nugget for a special survey, related repairs and contract preparation work prior to its relocation to Mexico in the fourth

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quarter of 2006. Also during 2006, the Ocean Spartan underwent leg repairs and was ready-stacked from mid-September 2006 until mid-December 2006 for total downtime of approximately four months, and the Ocean Summit incurred over three months of downtime for a special survey and related repairs. During 2005, the Ocean Warwick generated revenues of $11.8 million.
     Contract drilling expense in the GOM during 2006 increased $13.7 million compared to 2005. The increase in 2006 operating costs was primarily due to higher labor and other personnel-related costs as a result of late 2005 and March 2006 wage increases, costs associated with special surveys and related repairs for the Ocean Summit and Ocean Nugget, leg repairs for the Ocean Nugget, leg/spud can repairs for the Ocean Spartan and higher overhead, catering and other miscellaneous operating expenses. The overall increase in contract drilling expenses was partially offset by the absence of operating costs for the Ocean Warwick during 2006 and reduced operating costs in the GOM for the Ocean Spur (which only operated in the GOM for 45 days in 2006 before relocating to Tunisia) and the Ocean Nugget (which was relocated to Mexico at the beginning of the fourth quarter of 2006). Both the Ocean Spur and Ocean Nugget operated solely in the GOM during 2005. Also partially offsetting these negative cost trends was a reduction in survey and related mobilization costs during 2006 associated with the Ocean Spartan‘s survey in late 2005. We also recognized a $1.0 million insurance deductible for a leg punchthrough incident on the Ocean Spartan in 2005.
     Mexico. Our jack-up rig the Ocean Nugget, which relocated to Mexico at the beginning of the fourth quarter of 2006, generated $16.0 million there in 2006. This unit is contracted to work for PEMEX through March 2009. Contract drilling expenses related to this rig were $4.4 million. We had no jack-up units operating in this market during 2005.
     Australia/Asia/Middle East. Revenues generated by our jack-up rigs in the Australia/Asia and Middle East regions were $61.1 million in 2006 compared to $49.4 million in 2005. The $11.7 million increase in revenues in this region during 2006 compared to the prior year was primarily attributable to higher average operating dayrates for both of our jack-up rigs in this region ($15.1 million). Average dayrates for our jack-up rigs in this region increased from $71,900 in 2005 to $95,600 in 2006. The favorable contribution to operating revenues by the increase in average operating dayrates was partially offset by the reduced recognition of deferred mobilization revenues in 2006, as compared to 2005 ($3.1 million), and the effect of slightly lower average utilization in this region in 2006 compared to 2005 ($0.3 million).
     Contract drilling expenses for our jack-up rigs in the Australia/Asia and Middle East regions increased slightly from $25.0 million in 2005 to $27.7 million in 2006. Higher labor costs in 2006 (resulting from late 2005 and early 2006 wage increases), higher maintenance, inspection costs and revenue-based agency fees were partially offset by the 2005 recognition of an insurance deductible for leg damage to the Ocean Heritage and the recognition of mobilization costs related to relocation of the Ocean Sovereign to locations offshore Bangladesh and Indonesia during 2005.
     Europe/Africa/Mediterranean. The Ocean Spur began operating offshore Tunisia in mid-March 2006 and generated $42.8 million in revenues, including the recognition of $5.3 million in deferred mobilization revenue, and incurred operating expenses of $14.8 million during 2006. We did not have any of our jack-up rigs working in this region during 2005.
Other Contract Drilling.
     Other contract drilling expenses increased $15.4 million during 2006 compared to 2005, primarily due to the inclusion of $12.7 million in costs related to anchor boat rental and other costs associated with our mooring enhancement and hurricane preparedness activities, which were implemented in response to mooring issues which arose during the 2005 hurricane season.
Reimbursable expenses, net.
     Revenues related to reimbursable items, offset by the related expenditures for these items, were $8.0 million and $6.4 million for 2006 and 2005, respectively. Reimbursable expenses include items that we purchase, and/or services we perform, at the request of our customers. We charge our customers for purchases and/or services performed on their behalf at cost, plus a mark-up where applicable. Therefore, net reimbursables fluctuate based on customer requirements, which vary.

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Depreciation.
     Depreciation expense increased $16.8 million to $200.5 million during 2006 compared to $183.7 million during the same period in 2005 primarily due to depreciation associated with capital additions in 2005 and 2006, partially offset by lower depreciation expense resulting from the declaration of a constructive total loss of the Ocean Warwick in the third quarter of 2005.
General and Administrative Expense.
     We incurred general and administrative expense of $41.6 million during 2006 compared to $37.2 million during 2005. The $4.4 million increase in overhead costs between the periods was primarily due to the recognition of stock-based compensation expense pursuant to our adoption of SFAS No. 123(R), effective January 1, 2006.
Gain (Loss) on Sale of Assets.
     We recognized a net loss of $1.1 million on the sale and disposal of assets, including disposal costs, during 2006 compared to a net gain of $14.8 million during 2005. The loss recognized in 2006 was primarily the result of costs associated with the removal of production equipment from the Ocean Monarch, which was subsequently sold to a third party, partially offset by a $1.1 million recovery from certain of our customers related to the involuntary conversion of assets damaged during the 2005 hurricanes. Results for 2005 included a gain of $8.0 million related to the June 2005 sale of the Ocean Liberator, $5.6 million in insurance proceeds related to the involuntary conversion of certain assets damaged during Hurricane Ivan in 2004 and gains on the sale of used drill pipe during the period, partially offset by a $1.4 million loss due to the retirement of equipment lost or damaged during Hurricanes Katrina and Rita in 2005.
Casualty Gain on Ocean Warwick.
     We recorded a $33.6 million casualty gain in 2005 as a result of the constructive total loss of the Ocean Warwick, resulting from damages sustained during Hurricane Katrina in August 2005. Subsequently in 2006, we revised our estimate of expected deductibles related to this incident and recorded a $0.5 million favorable adjustment to “Casualty Gain on Ocean Warwick.” See “—Overview—Impact of 2005 Hurricanes.”
Interest Income.
     We earned interest income of $37.9 million during 2006 compared to $26.0 million in 2005. The $11.9 million increase in interest income was primarily the result of the combined effect of slightly higher interest rates earned on higher average invested cash balances in 2006, as compared to 2005. See “— Liquidity and Capital Requirements” and “— Historical Cash Flows.”
Interest Expense.
     We recorded interest expense of $24.1 million during 2006, reflecting a $17.7 million decrease in interest cost compared to 2005. The decrease in interest cost was primarily attributable to lower interest expense in 2006 related to our Zero Coupon Debentures as a result of our June 2005 repurchase of $774.1 million in aggregate principal amount at maturity of Zero Coupon Debentures, the associated write-off of $6.9 million of debt issuance costs in June 2005 and the conversion of $22.4 million in aggregate principal amount at maturity of Zero Coupon Debentures into shares of our common stock during 2006. In addition we capitalized an additional $9.1 million in interest costs in connection with qualifying upgrades and construction projects during 2006 compared to 2005. The decrease in interest cost was partially offset by additional interest expense on our 4.875% Senior Notes due July 1, 2015, or 4.875% Senior Notes, which we issued in June 2005.
Other Income and Expense (Other, net).
     Included in “Other, net” are foreign currency translation adjustments and transaction gains and losses and other income and expense items, among other things, which are not attributable to our drilling operations. The components of “Other, net” fluctuate based on the level of activity, as well as fluctuations in foreign currencies. We recorded other income, net, of $12.1 million during 2006 and other expense, net, of $1.1 million in 2005.

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     Effective October 1, 2005, we changed the functional currency of certain of our subsidiaries operating outside the United States to the U.S. dollar to more appropriately reflect the primary economic environment in which these subsidiaries operate. Prior to this date, these subsidiaries utilized the local currency of the country in which they conducted business as their functional currency. During the years ended December 31, 2006 and 2005, we recognized net foreign currency exchange gains of $10.3 million and net foreign currency exchange losses of $0.8 million, respectively. Prior to the fourth quarter of 2005, we accounted for foreign currency translation gains and losses as a component of “Accumulated other comprehensive losses” in our Consolidated Balance Sheets included in Item 8 of this report.
Income Tax Expense.
     Our net income tax expense is a function of the mix of our domestic and international pre-tax earnings, as well as the mix of earnings from the international tax jurisdictions in which we operate. We recognized $259.5 million of tax expense on pre-tax income of $966.3 million for the year ended December 31, 2006 compared to tax expense of $96.1 million on a pre-tax income of $356.4 million in 2005.
     During 2006 we were able to utilize all of the foreign tax credits available to us and we had no foreign tax credit carryforwards as of December 31, 2006. At the end of 2005, we had a valuation allowance of $0.8 million for certain of our foreign tax credit carryforwards which was reversed during 2006 as the valuation allowance was no longer necessary. During 2005, we reversed $9.6 million of the previously established $10.3 million valuation allowance for certain of our foreign tax credit carryforwards.
     During 2006 we recorded an $8.3 million tax benefit related to the deduction allowable under Internal Revenue Code Section 199 for domestic production activities. During the second quarter of 2006, the Treasury Department and Internal Revenue Service issued guidelines regarding the deduction allowable under Internal Revenue Code Section 199 which was previously believed to be unavailable to the drilling industry with respect to qualified production activities income. The $8.3 million tax benefit recognized included $2.2 million related to the year 2005.
     During 2005, we reversed a previously established reserve of $8.9 million ($1.7 million included with Current Taxes Payable and $7.2 million in Other Liabilities in our Consolidated Balance Sheets) associated with exposure related to the disallowance of goodwill deductibility associated with a 1996 acquisition which we believed was no longer necessary.
     During 2005, we settled an income tax dispute in East Timor (formerly part of Indonesia) for approximately $0.2 million. At December 31, 2004, our books reflected an accrued liability of $4.4 million related to potential East Timor and Indonesian income tax liabilities covering the period 1992 through 2000. Subsequent to the tax settlement, we determined that the accrual was no longer necessary and reversed the accrued liability in the fourth quarter of 2005.
     During 2004 and 2005, the Internal Revenue Service, or IRS, examined our federal income tax returns for tax years 2000 and 2002. The examination was concluded during the fourth quarter of 2005. We and the IRS agreed to a limited number of adjustments for which we recorded additional income tax of $1.9 million in 2005.

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Sources of Liquidity and Capital Resources
     Our principal sources of liquidity and capital resources are cash flows from our operations and our cash reserves. We may also make use of our $285 million credit facility for cash liquidity. See “— $285 Million Revolving Credit Facility.”
     At December 31, 2007, we had $638.0 million in “Cash and cash equivalents” and $1.3 million in “Investments and marketable securities,” representing our investment of cash available for current operations.
     Cash Flows from Operations. Our internally generated cash flow is directly related to our business and the geographic regions in which we operate. Deterioration in the offshore drilling market or poor operating results may result in reduced cash flows from operations. The dayrates we receive for our drilling rigs and rig utilization rates are a function of rig supply and demand in the marketplace, which is generally correlated with the price of oil and natural gas. Demand for drilling services is dependent upon the level of expenditures by oil and gas companies for offshore exploration and development, a variety of political and economic factors and availability of rigs in a particular geographic region. As utilization rates increase, dayrates tend to increase as well reflecting the lower supply of available rigs, and vice versa. These external factors which affect our cash flows from operations are not within our control and are difficult to predict. For a description of other factors that could affect our cash flows from operations, see “— Overview — Industry Conditions,” “ — Forward-Looking Statements” and “Risk Factors” in Item 1A of this report.
     $285 Million Revolving Credit Facility. We maintain a $285 million syndicated, 5-year senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit.
     Loans under the Credit Facility bear interest at a rate per annum equal to, at our election, either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.
     The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.
     Based on our current credit ratings at December 31, 2007, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2007, there were no loans outstanding under the Credit Facility; however $54.2 million in letters of credit were issued and outstanding under the Credit Facility.
     Liquidity and Capital Requirements
     Our liquidity and capital requirements are primarily a function of our working capital needs, capital expenditures and debt service requirements. We determine the amount of cash required to meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements and by evaluating our ongoing rig equipment replacement and enhancement programs, including water depth and drilling capability upgrades. We believe that our operating cash flows and cash reserves will be sufficient to meet both our working capital requirements and our capital commitments over the next twelve months; however, we will continue to make periodic assessments based on industry conditions and will adjust capital spending programs if required.
     In addition, we may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to effect any such issuance will be dependent on our results of operations, our current financial condition, current market conditions and other factors beyond our control. Additionally, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes.

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     Contractual Cash Obligations. The following table sets forth our contractual cash obligations at December 31, 2007.
                                         
    Payments Due By Period
Contractual Obligations   Total   Less than 1 year   1—3 years   4—5 years   After 5 years
     
    (In thousands)
Long-term debt (principal and interest)
  $ 683,657     $ 28,642     $ 54,401     $ 50,125     $ 550,489  
Forward exchange contracts
    18,142       18,142                    
Purchase obligations related to rig upgrade/modifications
    198,752       198,752                    
Operating leases
    5,584       4,353       1,085       146        
     
 
Total obligations
  $ 906,135     $ 249,889     $ 55,486     $ 50,271     $ 550,489  
     
     As of December 31, 2007, the total unrecognized tax benefit related to uncertain tax positions was $34.5 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.
     Certain of our long-term debt payments may be accelerated due to certain rights that holders of our debt securities have to put the securities to us. See the discussion below related to our 1.5% Debentures and Zero Coupon Debentures.
     As of December 31, 2007, we had purchase obligations aggregating approximately $200 million related to the major upgrade of the Ocean Monarch and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We expect to complete funding of these projects in 2008. However, the actual timing of these expenditures will vary based on the completion of various construction milestones, which are generally beyond our control.
     We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2007, except for those related to our direct rig operations, which arise during the normal course of business.
     Other Commercial Commitments — Letters of Credit.
     We were contingently liable as of December 31, 2007 in the amount of $168.0 million under certain performance, bid, supersedeas and custom bonds and letters of credit, including $54.2 million in letters of credit issued under our Credit Facility. During 2007 and 2006, we purchased five of these bonds totaling $81.2 million from a related party after obtaining competitive quotes. Agreements relating to approximately $103.5 million of performance bonds can require collateral at any time. As of December 31, 2007 we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds. See Note 13 “Related-Party Transactions” to our Consolidated Financial Statements included in Item 8 of this report. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.
                         
    For the years ending December 31,
     
    Total   2008   2009—2010
     
    (In thousands)
Other Commercial Commitments
                       
Customs bonds
  $ 42,056     $ 42,056     $  
Performance bonds
    114,794       36,148       78,646  
Other
    11,127       3,850       7,277  
     
 
Total obligations
  $ 167,977     $ 82,054     $ 85,923  
     

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4.875% Senior Notes.
     On June 14, 2005, we issued $250.0 million aggregate principal amount of 4.875% Senior Notes at an offering price of 99.785% of the principal amount, which resulted in net proceeds to us of $247.6 million. These notes bear interest at 4.875% per year, payable semiannually in arrears on January 1 and July 1 of each year and mature on July 1, 2015. The 4.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. We have the right to redeem all or a portion of the 4.875% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.
5.15% Senior Notes.
     On August 27, 2004, we issued $250.0 million aggregate principal amount of 5.15% Senior Notes Due September 1, 2014, or 5.15% Senior Notes, at an offering price of 99.759% of the principal amount, which resulted in net proceeds to us of $247.6 million. These notes bear interest at 5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year and mature on September 1, 2014. The 5.15% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. We have the right to redeem all or a portion of the 5.15% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.
1.5% Debentures.
     On April 11, 2001, we issued $460.0 million principal amount of 1.5% Debentures, which are due April 15, 2031. The 1.5% Debentures are convertible into shares of our common stock at an initial conversion rate of 20.3978 shares per $1,000 principal amount of the 1.5% Debentures, or $49.02 per share, subject to adjustment in certain circumstances. Upon conversion, we have the right to deliver cash in lieu of shares of our common stock. Holders may require us to purchase all or a portion of their outstanding 1.5% Debentures on April 15, 2008, at a price equal to 100% of the principal amount of the 1.5% Debentures to be purchased plus accrued and unpaid interest. We may choose to pay the purchase price in cash or shares of our common stock or a combination of cash and common stock. In addition, we have the option to redeem all or a portion of the 1.5% Debentures at any time on or after April 15, 2008 at a price equal to 100% of the principal amount plus accrued and unpaid interest. See “1.5% Debentures” in Note 9 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The 1.5% Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.
     During 2007 and 2006, the holders of $456.4 million and $20,000, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock, resulting in the issuance of 9,309,616 shares and 404 shares of our common stock in 2007 and 2006, respectively.
Zero Coupon Debentures.
     We issued our Zero Coupon Debentures on June 6, 2000 at a price of $499.60 per $1,000 principal amount at maturity, which represents a yield to maturity of 3.50% per year. The Zero Coupon Debentures mature on June 6, 2020, and, as of December 31, 2007, the aggregate accreted value of our outstanding Zero Coupon Debentures was $3.9 million. We will not pay interest prior to maturity unless we elect to convert the Zero Coupon Debentures to interest-bearing debentures upon the occurrence of certain tax events. The Zero Coupon Debentures are convertible at the option of the holder at any time prior to maturity, unless previously redeemed, into our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. See “Zero Coupon Debentures” in Note 9 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.
     During 2007 and 2006, holders of $1.5 million and $13.7 million, respectively, in accreted, or carrying, value through the date of conversion of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 20,658 and 193,147 shares of our common stock upon conversion of these debentures during 2007 and 2006, respectively. The aggregate principal amount at maturity of our Zero Coupon Debentures converted during 2007 and 2006 was $2.4 million and $22.4 million, respectively.

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Credit Ratings.
     Our current credit rating is Baa1 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings would result in higher rates for borrowings under our Credit Facility and could also result in higher interest rates on future debt issuances.
Capital Expenditures.
     The newly upgraded Ocean Endeavor commenced drilling operations in the GOM in early July 2007. The aggregate cost of the upgrade was approximately $248 million of which $38.8 million was spent in 2007. In addition, the upgrade of the Ocean Monarch continues in Singapore with expected delivery of the upgraded rig late in the fourth quarter of 2008. We expect to spend approximately $305 million to modernize this rig of which $181.4 million had been spent through December 31, 2007.
     Construction of our two high-performance, premium jack-up rigs, the Ocean Scepter and Ocean Shield is nearing completion, and delivery of both units is expected in the second quarter of 2008. The aggregate expected cost for both rigs is approximately $320 million, including drill pipe and capitalized interest, of which $248.5 million had been spent through December 31, 2007.
     During 2007, we spent approximately $388.4 million on our continuing rig capital maintenance program (other than rig upgrades and new construction) and to meet other corporate capital expenditure requirements, including $62.9 million towards modification of certain of our rigs to meet contractual requirements. We have budgeted approximately $500 million in additional capital expenditures in 2008 associated with our ongoing rig equipment replacement and enhancement programs, equipment required for our long-term international contracts and other corporate requirements. We expect to finance our 2008 capital expenditures through the use of our existing cash balances or internally generated funds. From time to time, however, we may also make use of our Credit Facility to finance capital expenditures.
Off-Balance Sheet Arrangements.
     At December 31, 2007 and 2006, we had no off-balance sheet debt or other arrangements.
Current Credit Environment.
     Recent developments in the financial markets, including a series of rating agency downgrades of sub-prime U.S. mortgage-related assets and significant provisions for loan losses recorded by several major financial institutions, have caused the fair value of sub-prime-related investments to decline. This decline in fair value has become especially problematic for certain large financial institutions and has had an effect through the U.S. economy, including limiting access to capital markets to certain borrowers at reasonable rates and also affecting the market value of certain investments whether or not linked to sub-prime mortgages.
     The fair value of our investments in debt securities, comprised of U.S. government securities or U.S. government-backed mortgage securities, have not to date been materially negatively impacted by events in the current credit market. However, we cannot predict with any certainty whether or not any such investments will be impacted in the future or how our customers and/or suppliers will be affected by the current credit conditions. We believe that our cash flows from operations and cash reserves will be sufficient to fund our ongoing operations and capital projects for the next twelve months; however, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes. Our Credit Facility matures in 2011. We do not anticipate that these current credit market conditions will have a material adverse effect on our financial condition, results of operations and cash flows.

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Historical Cash Flows
     The following is a discussion of our historical cash flows from operating, investing and financing activities for the year ended December 31, 2007 compared to 2006.
Net Cash Provided by Operating Activities.
                         
    Year Ended December 31,    
    2007   2006   Change
     
    (In thousands)
Net income
  $ 846,541   $ 706,847   $ 139,694  
Net changes in operating assets and liabilities
    139,253       (154,068 )     293,321  
(Gain) loss on sale of marketable securities
    (1,796 )     31       (1,827 )
Depreciation and other non-cash items, net
    224,318       207,279       17,039  
     
 
  $ 1,208,316     $ 760,089     $ 448,227  
     
     Our cash flows from operations in 2007 increased $448.2 million or 59% over net cash generated by our operating activities in 2006. The increase in cash flow from operations in 2007 is primarily the result of higher average dayrates by our rigs as a result of continued high worldwide demand for offshore contract drilling services in 2007 compared to 2006. The favorable contribution to cash flows was partially offset by lower utilization of our offshore drilling units due to planned downtime for modifications to our rigs to meet customer requirements and regulatory surveys, as well as the ready-stacking of rigs within our GOM jack-up fleet between wells. In addition, the increase in cash flows from operations was augmented by a decrease in cash required to satisfy our working capital requirements. Trade and other receivables generated cash of $43.5 million during 2007 as the billing cycle for our trade receivables was completed compared to a $190.1 million usage of cash during 2006. During 2007, we also received insurance proceeds of $51.2 million related to the settlement of certain claims arising from the 2005 hurricanes (total insurance proceeds of $56.1 million were received of which $4.9 million is included as a reduction in net cash used in investing activities.) During 2007, we made estimated U.S. federal and state income tax payments and paid foreign income taxes, net of refunds, of $299.6 million and $31.7 million, respectively.
Net Cash Used in Investing Activities.
                         
    Year Ended December 31,    
    2007   2006   Change
     
    (In thousands)
Purchase of marketable securities
  $ (2,850,135 )   $ (2,472,431 )   $ (377,704 )
Proceeds from sale of marketable securities
    3,163,475       2,187,766       975,709  
Capital expenditures
    (647,101 )     (551,237 )     (95,864 )
Proceeds from disposition of assets
    10,861       4,731       6,130  
Proceeds from settlement of forward contracts
    8,109       7,289       820  
     
 
  $ (314,791 )   $ (823,882 )   $ 509,091  
     
     Our investing activities used $314.8 million in 2007, as compared to $823.9 million in 2006. During 2007, we sold marketable securities, net of purchases, of $313.3 million compared to net purchases of $284.7 million during 2006. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets.
     During 2007, we spent approximately $258.7 million related to the major upgrades of the Ocean Endeavor and Ocean Monarch and construction of the Ocean Scepter and Ocean Shield compared to $278.0 million during 2006. Expenditures for our ongoing capital maintenance programs, including rig modifications to meet contractual requirements, were $388.4 million in 2007 compared to $273.2 million in 2006. The increase in expenditures related to our ongoing capital maintenance program in 2007 compared to 2006 is related to an increase in discretionary funds available for capital spending in 2007, as well as a response to customer requirements. See “— Liquidity and Capital Requirements — Capital Expenditures.”

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As of December 31, 2007, we had foreign currency exchange contracts outstanding, which aggregated $18.1 million, that require us to purchase the equivalent of $17.9 million in British pounds sterling and $0.2 million in Mexican pesos at various times through April 2008.
Net Cash Used in Financing Activities.
                         
    Year Ended December 31,    
    2007   2006   Change
     
    (In thousands)
Payment of dividends
  $ (796,292 )   $ (258,155 )   $ (538,137 )
Proceeds from stock options exercised
    10,836       3,263       7,573  
Other
    5,194       793       4,401  
     
 
  $ (780,262 )   $ (254,099 )   $ (526,163 )
     
     During 2007, we paid cash dividends totaling $796.3 million (consisting of quarterly cash dividends aggregating $69.3 million, or $0.125 per share of our common stock per quarter, and special cash dividends of $4.00 and $1.25 per share of our common stock, totaling $553.4 million and $173.6 million, respectively). During 2006, we paid cash dividends totaling $258.2 million (consisting of quarterly dividends of $64.6 million in the aggregate, or $0.125 per share of our common stock per quarter, and a special cash dividend of $1.50 per share of our common stock, totaling $193.6 million).
     On February 6, 2008, we declared a regular quarterly cash dividend and a special cash dividend of $0.125 and $1.25, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on March 3, 2008 to stockholders of record on February 18, 2008.
     In the fourth quarter of 2007, our Board of Directors adopted a policy of considering paying special cash dividends, in amounts to be determined, on a quarterly basis, rather than annually. Our Board of Directors may, in subsequent quarters, consider paying additional special cash dividends, in amounts to be determined, if it believes that our financial position, earnings, earnings outlook, capital spending plans and other relevant factors warrant such action at that time.
     Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not repurchase any shares of our outstanding common stock during the years ended December 31, 2007 and 2006.
Other
     Currency Risk. Some of our subsidiaries conduct a portion of their operations in the local currency of the country where they conduct operations. Currency environments in which we have significant business operations include Mexico, Brazil, the U.K., Australia and Malaysia. When possible, we attempt to minimize our currency exchange risk by seeking international contracts payable in local currency in amounts equal to our estimated operating costs payable in local currency with the balance of the contract payable in U.S. dollars. At present, however, only a limited number of our contracts are payable both in U.S. dollars and the local currency.
     We also utilize foreign exchange forward contracts to reduce our forward exchange risk. A forward currency exchange contract obligates a contract holder to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specific dates.
     We record currency translation adjustments and transaction gains and losses as “Other income (expense)” in our Consolidated Statements of Operations. The effect on our results of operations from these translation adjustments and transaction gains and losses has not been material and are not expected to have a significant effect in the future.
Recent Accounting Pronouncements
     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” or SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements to facilitate comparisons between companies that

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choose different measurement attributes for similar types of assets and liabilities. Accounting principles generally accepted in the U.S., or GAAP, have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 159 on our financial statements and have determined that the adoption of SFAS 159 will not have a material impact on our consolidated results of operations, financial position and cash flows.
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” or SFAS 157, which establishes a separate framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 was issued to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS 157 does not require any new fair value measurements; however, its adoption may result in changes to current practice. Changes resulting from the application of SFAS 157 relate to the definition of fair value, the methods used to measure fair value and the expanded disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, rather than an entity-specific measurement. It also establishes a fair value hierarchy that distinguishes between (i) market participant assumptions developed based on market data obtained from independent sources and (ii) the reporting entity’s own assumptions about market participant assumptions developed based on the best information available under the circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 157 on our financial statements and have determined that the adoption of SFAS 157 will not have a material impact on our consolidated results of operations, financial position and cash flows.
Forward-Looking Statements
     We or our representatives may, from time to time, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. Statements made by us in this report that contain forward-looking statements include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:
    future market conditions and the effect of such conditions on our future results of operations (see “— Overview — Industry Conditions”);
 
    future uses of and requirements for financial resources (see “— Liquidity and Capital Requirements” and “— Sources of Liquidity and Capital Resources”);
 
    interest rate and foreign exchange risk (see “— Liquidity and Capital Requirements — Credit Ratings” and “Quantitative and Qualitative Disclosures About Market Risk”);
 
    future contractual obligations (see “— Overview — Industry Conditions,” “Business — Operations Outside the United States” and “— Liquidity and Capital Requirements”);
 
    future operations outside the United States including, without limitation, our operations in Mexico (see “— Overview — Industry Conditions” and “Risk Factors”);
 
    business strategy;
 
    growth opportunities;
 
    competitive position;
 
    expected financial position;
 
    future cash flows (see “ — Overview — Contract Drilling Backlog”);
 
    future regular or special dividends (see “ — Historical Cash Flows” and “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Dividend Policy”);
 
    financing plans;

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    tax planning (See “— Overview — Critical Accounting Estimates — Income Taxes,” “— Years Ended December 31, 2007 and 2006 — Income Tax Expense” and “— Years Ended December 31, 2006 and 2005 — Income Tax Expense”);
 
    budgets for capital and other expenditures (see “— Liquidity and Capital Requirements”);
 
    timing and cost of completion of rig upgrades and other capital projects (see “— Liquidity and Capital Requirements”);
 
    delivery dates and drilling contracts related to rig conversion and upgrade projects (see “— Overview — Industry Conditions” and “— Liquidity and Capital Requirements”);
 
    plans and objectives of management;
 
    performance of contracts (see “— Overview — Industry Conditions” and “Risk Factors”);
 
    outcomes of legal proceedings;
 
    compliance with applicable laws; and
 
    adequacy of insurance or indemnification (see “Risk Factors”).
     These types of statements inherently are subject to a variety of assumptions, risks and uncertainties that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following:
    general economic and business conditions;
 
    worldwide demand for oil and natural gas;
 
    changes in foreign and domestic oil and gas exploration, development and production activity;
 
    oil and natural gas price fluctuations and related market expectations;
 
    the ability of OPEC to set and maintain production levels and pricing, and the level of production in non-OPEC countries;
 
    policies of various governments regarding exploration and development of oil and gas reserves;
 
    advances in exploration and development technology;
 
    the worldwide political and military environment, including in oil-producing regions;
 
    casualty losses;
 
    operating hazards inherent in drilling for oil and gas offshore;
 
    industry fleet capacity;
 
    market conditions in the offshore contract drilling industry, including dayrates and utilization levels;
 
    competition;
 
    changes in foreign, political, social and economic conditions;
 
    risks of international operations, compliance with foreign laws and taxation policies and expropriation or nationalization of equipment and assets;
 
    risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;
 
    the risk that an LOI may not result in a definitive agreement;
 
    foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;
 
    risks of war, military operations, other armed hostilities, terrorist acts and embargoes;
 
    changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness;
 
    regulatory initiatives and compliance with governmental regulations;
 
    compliance with environmental laws and regulations;
 
    development and exploitation of alternative fuels;
 
    customer preferences;
 
    effects of litigation;
 
    cost, availability and adequacy of insurance;
 
    the risk that future regular or special dividends may not be declared;
 
    adequacy of our sources of liquidity;
 
    the availability of qualified personnel to operate and service our drilling rigs; and
 
    various other matters, many of which are beyond our control.
     The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings

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with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
     The information included in this Item 7A is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Forward-Looking Statements” in Item 7 of this report.
     Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2007 and December 31, 2006, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.
     Exposure to market risk is managed and monitored by our senior management. Senior management approves the overall investment strategy that we employ and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling instruments or entering into offsetting positions.
Interest Rate Risk
     We have exposure to interest rate risk arising from changes in the level or volatility of interest rates. Our investments in marketable securities are primarily in fixed maturity securities. We monitor our sensitivity to interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on stockholders’ equity. The analysis presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over a one-year period.
     The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on December 31, 2007 and December 31, 2006, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.
     The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.
     Loans under our $285 million syndicated, five-year senior unsecured revolving Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. As of and December 31, 2007 and 2006, there were no loans outstanding under the Credit Facility (however, as of December 31, 2007, $54.2 million in letters of credit were issued and outstanding under the Credit Facility).

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     Our long-term debt, as of December 31, 2007 and December 31, 2006, is denominated in U.S. dollars. Our debt has been primarily issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $35.8 million and $270.8 million as of December 31, 2007 and 2006, respectively. A 100-basis point decrease would result in an increase in market value of $11.6 million and $33.0 million as of December 31, 2007 and 2006, respectively.
Foreign Exchange Risk
     Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. During 2007 and 2006, we entered into various foreign currency forward exchange contracts that required us to purchase predetermined amounts of foreign currencies at predetermined dates. As of December 31, 2007, we had foreign currency exchange contracts outstanding, which aggregated $18.1 million, that require us to purchase the equivalent of $17.9 million in British pounds sterling and $0.2 million in Mexican pesos at various times through April 2008. As of December 31, 2006, we had foreign currency exchange contracts outstanding, which aggregated $22.5 million, that required us to purchase the equivalent of $5.7 million in Brazilian reais, $2.7 million in British pounds sterling, $10.3 million in Mexican pesos and $3.8 million in Norwegian kroner at various times through June 2007. At December 31, 2007, we have presented the $2,000 and $(93,000) fair value of our outstanding foreign currency forward exchange contracts in accordance with SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” as “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, in our Consolidated Balance Sheets included in Item 8 of this report. We have presented the $2.6 million fair value of our foreign currency forward exchange contracts at December 31, 2006 as “Prepaid expenses and other current assets” in our Consolidated Balance Sheets included in Item 8 or this report.
     The sensitivity analysis assumes an instantaneous 20% change in foreign currency exchange rates versus the U.S. dollar from their levels at December 31, 2007 and 2006.
     The following table presents our exposure to market risk by category (interest rates and foreign currency exchange rates):
                                 
    Fair Value Asset (Liability)   Market Risk
    December 31,   December 31,
    2007   2006   2007   2006
     
            (In thousands)        
Interest rate:
                               
Marketable securities
  $ 1,301 (a)   $ 301,159 (a)   $ 100 (c)   $ 400 (c)
Long-term debt
    (500,303 ) (b)     (1,231,689 ) (b)            
 
Foreign Exchange:
                               
Forward exchange contracts
    2 (d)     2,600 (d)     100 (e)     7,400 (e)
Forward exchange contracts
    (93 ) (d)     (d)     3,300 (e)     (e)
 
(a)   The fair market value of our investment in marketable securities, excluding repurchase agreements, is based on the quoted closing market prices on December 31, 2007 and 2006.
 
(b)   The fair values of our 4.875% Senior Notes, 5.15% Senior Notes, 1.5% Debentures and Zero Coupon Debentures are based on the quoted closing market prices on December 31, 2007 and 2006.
 
(c)   The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at December 31, 2007 and 2006.
 
(d)   The fair value of our foreign currency forward exchange contracts is based on the quoted market prices on December 31, 2007 and 2006.
 
(e)   The calculation of estimated foreign exchange risk is based on assumed adverse changes in the underlying reference price or index of an increase in foreign exchange rates of 20% at December 31, 2007 and 2006.

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Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Diamond Offshore Drilling, Inc. and Subsidiaries
Houston, Texas
     We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
     In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
     As discussed in Note 14 to the consolidated financial statements, the Company changed its method of accounting for uncertainty in income taxes in 2007.
     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.
Deloitte & Touche LLP
Houston, Texas
February 25, 2008

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Diamond Offshore Drilling, Inc. and Subsidiaries
Houston, Texas
     We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A of this Form 10-K under the heading “Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
     A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
     In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007 of the Company and our report dated February 25, 2008 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s change in its method of accounting for uncertainty in income taxes in 2007.
Deloitte & Touche LLP
Houston, Texas
February 25, 2008

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
                 
    December 31,  
    2007     2006  
 
               
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 637,961     $ 524,698  
Marketable securities
    1,301       301,159  
Accounts receivable
    522,808       567,474  
Prepaid expenses and other current assets
    103,120       88,216  
 
           
Total current assets
    1,265,190       1,481,547  
Drilling and other property and equipment, net of accumulated depreciation
    3,040,063       2,628,453  
Other assets
    36,212       22,839  
 
           
Total assets
  $ 4,341,465     $ 4,132,839  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Current portion of long-term debt
  $ 3,563     $  
Accounts payable
    132,243       122,000  
Accrued liabilities
    235,521       184,978  
Taxes payable
    81,684       26,531  
 
           
Total current liabilities
    453,011       333,509  
Long-term debt
    503,071       964,310  
Deferred tax liability
    397,629       448,227  
Other liabilities
    110,687       67,285  
 
           
Total liabilities
    1,464,398       1,813,331  
 
           
 
               
Commitments and contingencies
           
 
               
Stockholders’ equity:
               
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding)
           
Common stock (par value $0.01, 500,000,000 shares authorized; 143,787,206 shares issued and 138,870,406 shares outstanding at December 31, 2007; 134,133,776 shares issued and 129,216,976 shares outstanding at December 31, 2006)
    1,438       1,341  
Additional paid-in capital
    1,831,492       1,299,846  
Retained earnings
    1,158,535       1,137,151  
Accumulated other comprehensive (losses) gains
    15       (4,417 )
Treasury stock, at cost (4,916,800 shares at December 31, 2007 and 2006)
    (114,413 )     (114,413 )
 
           
Total stockholders’ equity
    2,877,067       2,319,508  
 
           
Total liabilities and stockholders’ equity
  $ 4,341,465     $ 4,132,839  
 
           
The accompanying notes are an integral part of the consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
                         
    Year Ended December 31,  
    2007     2006     2005  
Revenues:
                       
Contract drilling
  $ 2,505,663     $ 1,987,114     $ 1,179,015  
Revenues related to reimbursable expenses
    62,060       65,458       41,987  
 
                 
Total revenues
    2,567,723       2,052,572       1,221,002  
 
                 
 
                       
Operating expenses:
                       
Contract drilling
    1,011,193       812,057       638,540  
Reimbursable expenses
    52,857       57,465       35,549  
Depreciation
    235,251       200,503       183,724  
General and administrative
    53,483       41,551       37,162  
Casualty gain on Ocean Warwick
          (500 )     (33,605 )
(Gain) loss on disposition of assets
    (8,583 )     1,064       (14,767 )
 
                 
Total operating expenses
    1,344,201       1,112,140       846,603  
 
                 
 
                       
Operating income
    1,223,522       940,432       374,399  
 
                       
Other income (expense):
                       
Interest income
    33,566       37,880       26,028  
Interest expense
    (19,191 )     (24,096 )     (41,799 )
Gain (loss) on sale of marketable securities
    1,796       (31 )     (1,180 )
Other, net
    6,844       12,147       (1,053 )
 
                 
Income before income tax expense
    1,246,537       966,332       356,395  
 
                       
Income tax expense
    (399,996 )     (259,485 )     (96,058 )
 
                 
 
Net income
  $ 846,541     $ 706,847     $ 260,337  
 
                 
 
                       
Earnings per share:
                       
Basic
  $ 6.14     $ 5.47     $ 2.02  
 
                 
Diluted
  $ 6.12     $ 5.12     $ 1.91  
 
                 
 
                       
Weighted-average shares outstanding:
                       
Shares of common stock
    137,816       129,129       128,690  
Dilutive potential shares of common stock
    1,129       9,652       12,661  
 
                 
Total weighted-average shares outstanding assuming dilution
    138,945       138,781       141,351  
 
                 
The accompanying notes are an integral part of the consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except number of shares)
                                                                 
                                    Accumulated                        
                    Additional             Other                     Total  
    Common Stock     Paid-in     Retained     Comprehensive     Treasury Stock     Stockholders’  
    Shares     Amount     Capital     Earnings     Gains (Losses)     Shares     Amount     Equity  
     
January 1, 2005
    133,483,820     $ 1,335     $ 1,264,512     $ 476,382     $ (1,988 )     4,916,800     $ (114,413 )   $ 1,625,828  
     
Net income
                      260,337                         260,337  
Dividends to stockholders ($0.375 per share)
                      (48,260 )                       (48,260 )
Conversion of long-term debt.
    264             13                               13  
Stock options exercised
    358,345       3       13,409                               13,412  
Reversal of cumulative foreign currency translation loss
                            2,077                   2,077  
Loss on investments, net
                            (80 )                 (80 )
     
December 31, 2005
    133,842,429       1,338       1,277,934       688,459       9       4,916,800       (114,413 )     1,853,327  
     
Net income
                      706,847                         706,847  
Dividends to stockholders ($2.00 per share)
                      (258,155 )                       (258,155 )
Conversion of long-term debt.
    193,551       2       13,734                               13,736  
Stock options exercised
    97,796       1       3,295                               3,296  
Stock-based compensation, net
                4,883                               4,883  
Gain on investments, net
                            100                   100  
     
December 31, 2006, before adoption of SFAS 158
    134,133,776       1,341       1,299,846       1,137,151       109       4,916,800       (114,413 )     2,324,034  
     
Adjustment to initially apply SFAS 158, net of tax
                            (4,526 )                 (4,526 )
     
December 31, 2006
    134,133,776       1,341       1,299,846       1,137,151       (4,417 )     4,916,800       (114,413 )     2,319,508  
     
Cumulative effect of adopting FIN 48
                      (28,422 )                       (28,422 )
     
January 1, 2007
    134,133,776       1,341       1,299,846       1,108,729       (4,417 )     4,916,800       (114,413 )     2,291,086  
     
Net income
                      846,541                         846,541  
Dividends to stockholders ($5.75 per share)
                      (796,735 )                       (796,735 )
Conversion of long-term debt.
    9,330,274       94       459,654                               459,748  
Reversal of deferred tax liability related to imputed interest on converted debentures
                54,154                               54,154  
Stock options exercised
    323,156       3       10,707                               10,710  
Stock-based compensation, net
                7,131                               7,131  
Loss on investments, net
                            (94 )                 (94 )
Pension plan termination
                            4,526                   4,526  
     
December 31, 2007
    143,787,206     $ 1,438     $ 1,831,492     $ 1,158,535     $ 15       4,916,800     $ (114,413 )   $ 2,877,067  
     
The accompanying notes are an integral part of the consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
                         
    Year Ended December 31,  
    2007     2006     2005  
 
                       
Net income
  $ 846,541     $ 706,847     $ 260,337  
 
                       
Other comprehensive gains (losses), net of tax:
                       
Foreign currency translation gain
                2,077  
Pension plan termination
    4,526              
Unrealized holding gain on investments
    188       162       10  
Reclassification adjustment for gain included in net income
    (282 )     (62 )     (90 )
 
                 
Total other comprehensive gain
    4,432       100       1,997  
Comprehensive income before adoption of SFAS 158, net of tax
    850,973       706,947       262,334  
 
                 
Adjustment to initially apply SFAS 158, net of tax
          (4,526 )      
 
                 
Comprehensive income
  $ 850,973     $ 702,421     $ 262,334  
 
                 
The accompanying notes are an integral part of the consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
                         
    Year Ended December 31,
    2007   2006   2005
     
 
                       
Operating activities:
                       
Net income
  $ 846,541     $ 706,847     $ 260,337  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation
    235,251       200,503       183,724  
Casualty gain on Ocean Warwick
          (500 )     (33,605 )
(Gain) loss on disposition of assets
    (8,583 )     1,064       (14,767 )
(Gain) loss on sale of marketable securities, net
    (1,796 )     31       1,180  
Deferred tax provision
    1,770       610       65,159  
Accretion of discounts on marketable securities
    (11,830 )     (14,090 )     (7,683 )
Amortization of debt issuance costs
    9,649       848       7,742  
Amortization of debt discounts
    238       392       7,523  
Stock-based compensation expense
    4,454       3,106        
Excess tax benefits from stock-based payment arrangements
    (5,194 )     (1,313 )      
Deferred income, net
    28,461       13,373       935  
Deferred expenses, net
    (37,429 )     6,317       (1,010 )
Other items, net
    7,531       (3,031 )     3,942  
Changes in operating assets and liabilities:
                       
Accounts receivable
    43,467       (190,054 )     (174,659 )
Prepaid expenses and other current assets
    (1,341 )     (12,078 )     (4,752 )
Accounts payable and accrued liabilities
    33,174       58,762       66,011  
Taxes payable
    63,953       (10,698 )     28,494  
     
Net cash provided by operating activities
    1,208,316       760,089       388,571  
     
Investing activities:
                       
Capital expenditures (including rig acquisitions)
    (647,101 )     (551,237 )     (293,829 )
Proceeds from casualty loss of Ocean Warwick
                50,500  
Proceeds from sale/involuntary conversion of assets
    10,861       4,731       26,047  
Proceeds from sale and maturities of marketable securities
    3,163,475       2,187,766       5,610,907  
Purchase of marketable securities
    (2,850,135 )     (2,472,431 )     (4,956,560 )
Proceeds from maturities of Australian dollar time deposits
                11,761  
Proceeds from settlement of forward contracts
    8,109       7,289       1,136  
     
Net cash (used in) provided by investing activities
    (314,791 )     (823,882 )     449,962  
     
Financing activities:
                       
Issuance of 4.875% senior unsecured notes
                249,462  
Debt issuance costs and arrangement fees
          (520 )     (1,866 )
Redemption of zero coupon debentures
                (460,015 )
Payment of dividends
    (796,292 )     (258,155 )     (48,260 )
Payments under lease-leaseback agreement
                (12,818 )
Proceeds from stock options exercised
    10,836       3,263       11,547  
Excess tax benefits from share-based payment arrangements
    5,194       1,313        
     
Net cash used in financing activities
    (780,262 )     (254,099 )     (261,950 )
     
Net change in cash and cash equivalents
    113,263       (317,892 )     576,583  
Cash and cash equivalents, beginning of year
    524,698       842,590       266,007  
     
Cash and cash equivalents, end of year
  $ 637,961     $ 524,698     $ 842,590  
     
The accompanying notes are an integral part of the consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General Information
     Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a current fleet of 44 offshore rigs consisting of 30 semisubmersibles, 13 jack-ups and one drillship. In addition, we have two jack-up drilling units under construction at shipyards in Brownsville, Texas and Singapore, both of which we expect to be completed in the second quarter of 2008. Unless the context otherwise requires, references in these Notes to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.
     As of February 20, 2008, Loews Corporation, or Loews, owned 50.5% of the outstanding shares of our common stock.
Principles of Consolidation
     Our consolidated financial statements include the accounts of Diamond Offshore Drilling, Inc. and our subsidiaries after elimination of intercompany transactions and balances.
Cash and Cash Equivalents, Marketable Securities
     We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.
     We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in “Accumulated other comprehensive gains (losses)” until realized. The cost of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments are included in our Consolidated Statements of Operations in “Interest income.” The sale and purchase of securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific identification method. Realized gains or losses, as well as any declines in value that are judged to be other than temporary, are reported in our Consolidated Statements of Operations in “Other income (expense).”
Derivative Financial Instruments
     Our derivative financial instruments include foreign currency forward exchange contracts and a contingent interest provision that is embedded in our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, issued on April 11, 2001. See Note 5.
Supplementary Cash Flow Information
     We paid interest totaling $25.3 million, $32.5 million and $94.1 million on long-term debt for the years ended December 31, 2007, 2006 and 2005, respectively. The amount of interest paid in 2005 included $73.3 million in accreted interest paid in connection with the June 2005 partial redemption of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures. See Note 9.
     We paid $31.7 million, $10.8 million and $5.3 million in foreign income taxes, net of foreign tax refunds, during the years ended December 31, 2007, 2006 and 2005, respectively. We paid $299.0 million and $262.4 million in U.S. federal income taxes during the years ended December 31, 2007 and 2006, respectively. We received refunds of $25,000, $13.7 million and $7.7 million in U.S. income taxes during the years ended December 31, 2007, 2006 and 2005, respectively. We paid state income taxes of $0.6 million during the year ended December 31, 2007.

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     Cash payments for capital expenditures for the year ended December 31, 2007, included $41.4 million of capital expenditures that were accrued but unpaid at December 31, 2006. Cash payments for capital expenditures for the year ended December 31, 2006, included $53.7 million of capital expenditures that were accrued but unpaid at December 31, 2005. Capital expenditures that were accrued but not paid as of December 31, 2007, totaled $43.0 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2007.
     We recorded income tax benefits of $2.7 million, $1.7 million and $2.4 million related to the exercise of employee stock options in 2007, 2006 and 2005, respectively.
     During 2007 and 2006, holders of $1.5 million and $13.7 million, respectively, in accreted, or carrying, value through the date of conversion of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. Also during 2007 and 2006, the holders of $456.4 million and $20,000, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. See Note 9.
Drilling and Other Property and Equipment
     Our drilling and other property and equipment is carried at cost. We charge maintenance and routine repairs to income currently while replacements and betterments, which meet certain criteria, are capitalized. Costs incurred for major rig upgrades are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations. Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from three to 30 years.
Capitalized Interest
     We capitalize interest cost for the construction and upgrade of qualifying assets. In April 2005 and July 2006 we began capitalizing interest on expenditures related to the upgrades of the Ocean Endeavor and the Ocean Monarch, respectively, for ultra-deepwater service. In December 2005 and January 2006 we began capitalizing interest on expenditures related to the construction of two jack-up rigs, the Ocean Scepter and Ocean Shield, respectively.
     A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:
                         
    For the Year Ended December 31,
    2007   2006   2005
    (In thousands)
 
                       
Total interest cost including amortization of debt issuance costs
  $ 37,735     $ 33,892     $ 42,541  
Capitalized interest
    (18,544 )     (9,796 )     (742 )
     
Total interest expense as reported
  $ 19,191     $ 24,096     $ 41,799  
     

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Asset Retirement Obligations
     Statement of Financial Accounting Standards, or SFAS, No. 143, “Accounting for Asset Retirement Obligations” requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred. At December 31, 2007 and 2006, we had no asset retirement obligations.
Impairment of Long-Lived Assets
     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.
     2007. As of December 31, 2007, all of our drilling rigs were either under contract or were in shipyards for surveys, contract modifications or major upgrade, except for two of our jack-up drilling rigs located in the U.S. Gulf of Mexico. At December 31, 2007, one of these idle units was under contract but waiting to begin drilling operations while the other unit was being actively marketed. Based on this knowledge, we determined that an impairment test of our drilling equipment was not needed as we are currently marketing all of our drilling units. We did not have any cold-stacked rigs at December 31, 2007. We do not believe that current circumstances indicate that the carrying amount of our property and equipment may not be recoverable.
     2006. As of December 31, 2006, all of our drilling rigs were either under contract, in shipyards for surveys and/or life extension projects or undergoing a major upgrade. Based on this knowledge, we determined that an impairment test of our drilling equipment was not needed as we were currently marketing all of our drilling units. We did not have any cold-stacked rigs at December 31, 2006. We did not believe that circumstances at that time indicated that the carrying amount of our property and equipment was not recoverable.
     2005. In December 2005, we reviewed our single cold-stacked rig, the Ocean Monarch, for impairment. Based on our decision to upgrade this drilling unit to high-specification capabilities at an estimated cost of approximately $305 million and the low net book value of this rig, we did not consider this asset to be impaired.
     Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from those reported.
Fair Value of Financial Instruments
     We believe that the carrying amount of our current financial instruments approximates fair value because of the short maturity of these instruments. For non-current financial instruments we use quoted market prices, when available, and discounted cash flows to estimate fair value. See Note 12.
Debt Issuance Costs
     Debt issuance costs are included in our Consolidated Balance Sheets in “Other assets” and are amortized over the respective terms of the related debt. Interest expense for the years ended December 31, 2007, 2006 and 2005 includes $9.2 million, $0.2 million and $6.9 million, respectively, in debt issuance costs that we wrote off in connection with conversions of our 1.5% Debentures and Zero Coupon Debentures into shares of our common stock. See Note 9.

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Income Taxes
     We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” which requires the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. We make judgments regarding future events and related estimates especially as they pertain to the forecasting of our effective tax rate, the potential realization of deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.
     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.
     We adopted the provisions of Financial Accounting Standards Board, or FASB, Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48, on January 1, 2007. As a result of the implementation of FIN 48, we recognized a long-term tax receivable of $2.6 million and a long-term tax liability of $31.1 million for uncertain tax positions, the net of which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense. See Note 14.
Treasury Stock
     Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We account for the purchase of treasury stock using the cost method, which reports the cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated Balance Sheets. We did not repurchase any shares of our outstanding common stock during 2007, 2006 or 2005.
Comprehensive Income (Loss)
     Comprehensive income (loss) is the change in equity of a business enterprise during a period from transactions and other events and circumstances except those transactions resulting from investments by owners and distributions to owners. Comprehensive income (loss) for the three years ended December 31, 2007 includes net income (loss), foreign currency translation gains and losses, unrealized holding gains and losses on marketable securities and an adjustment to initially adopt SFAS No. 158, “Accounting for Defined Benefit Pension or Other Postretirement Plans,” or SFAS 158, in 2006. See Note 10.
Currency Translation
     Our functional currency is the U.S. dollar. Effective October 1, 2005, we changed the functional currency of certain of our subsidiaries operating outside the United States to the U.S. dollar to more appropriately reflect the primary economic environment in which our subsidiaries operate. Prior to this date, these subsidiaries utilized the local currency of the country in which they conduct business as their functional currency. As a result of this change, currency translation adjustments and transaction gains and losses, including gains and losses from the settlement of foreign currency forward exchange contracts, are reported as “Other income (expense)” in our Consolidated Statements of Operations. For the years ended December 31, 2007 and 2006, we recognized net foreign currency exchange gains of $2.9 million and $10.3 million, respectively. During the year ended December 31, 2005, we recognized net foreign currency exchange losses of $0.8 million. See Note 5.

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Revenue Recognition
     Revenue from our dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). Straight line amortization of mobilization revenues and related costs over the initial term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized as incurred.
     From time to time, we may receive fees from our customers for capital improvements to our rigs. We defer such fees received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the asset.
     We record reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement, for the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.
Use of Estimates in the Preparation of Financial Statements
     The preparation of financial statements in conformity with accounting principles generally accepted in the U.S., or GAAP, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.
Reclassifications
     Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings.
Recent Accounting Pronouncements
     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” or SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. GAAP has required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 159 on our financial statements and have determined that the adoption of SFAS 159 will not have a material impact on our consolidated results of operations, financial position and cash flows.
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” or SFAS 157, which establishes a separate framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 was issued to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS 157 does not require any new fair value measurements; however, its adoption may result in changes to current practice. Changes resulting from the application of SFAS 157 relate to the definition of fair value, the methods used to measure fair value and the expanded disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, rather than an entity-specific measurement. It also establishes a fair value hierarchy that distinguishes between (i) market participant assumptions developed based on market data obtained from independent sources and (ii) the reporting entity’s own assumptions about market participant assumptions developed based on the best information available under the

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circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We have completed our evaluation of the impact of applying SFAS 157 on our financial statements and have determined that the adoption of SFAS 157 will not have a material impact on our consolidated results of operations, financial position and cash flows.
2. Stock-Based Compensation
     Our Second Amended and Restated 2000 Stock Option Plan, as amended, or Stock Plan, provides for the issuance of either incentive stock options or non-qualified stock options to our employees, consultants and non-employee directors. Our Stock Plan also authorizes the award of stock appreciation rights, or SARs, in tandem with stock options or separately. The aggregate number of shares of our common stock for which stock options or SARs may be granted is 1,500,000 shares. The exercise price per share may not be less than the fair market value of the common stock on the date of grant. Generally, stock options and SARs vest ratably over a four year period and expire in ten years.
     Effective January 1, 2006, we adopted the FASB’s revised SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123(R), using the modified prospective application transition method. Prior to the adoption of SFAS 123(R) on January 1, 2006, we accounted for our Stock Plan in accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, no compensation expense was recognized for the options granted to our employees in periods prior to January 1, 2006. If compensation expense had been recognized for stock options granted to our employees based on the fair value of the options at the grant dates our net income and earnings per share, or EPS, would have been as follows:
         
    Year Ended December 31,  
    2005  
    (In thousands, except  
    per share data)  
 
Net income as reported
  $ 260,337  
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects
    (1,411 )
 
     
 
       
Pro forma net income
  $ 258,926  
 
     
 
       
Earnings per share of common stock:
       
As reported
  $ 2.02  
 
     
Pro forma
  $ 2.01  
 
     
 
       
Earnings per share of common stock-assuming dilution:
       
As reported
  $ 1.91  
 
     
Pro forma
  $ 1.90  
 
     
     Total compensation cost recognized for Stock Plan transactions for the years ended December 31, 2007 and 2006 was $4.5 million and $3.1 million, respectively. Tax benefits recognized for the years ended December 31, 2007 and 2006 related thereto were $1.5 million and $1.1 million, respectively.

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     For the years ended December 31, 2006 and 2005 the fair value of options and SARs granted under the Stock Plan was estimated using the Binomial Option pricing model. During the third quarter of 2007, we began using the Black Scholes model to value SARs that were granted during the period. The change in valuation technique was necessitated by our decision to change our stock option administrator. There was no material impact to our consolidated results of operations, financial position and cash flows as a result of the change in valuation techniques.
     The following are the weighted average assumptions used in estimating the fair value of our options and SARS:
                         
    Year Ended December 31,
    2007   2006   2005
Expected life of stock options/SARs (in years)
    5       6       7  
Expected volatility
    27.53 %     30.72 %     29.53 %
Dividend yield
    .48 %     .62 %     .56 %
Risk free interest rate
    4.28 %     4.85 %     4.16 %
     Expected life of stock options and SARs is based on historical data as is the expected volatility. The dividend yield is based on the current approved regular dividend rate in effect and the current market price at the time of grant. Risk free interest rates are determined using the U.S. Treasury yield curve at time of grant with a term equal to the expected life of the options and SARs.
     A summary of activity under the Stock Plan as of December 31, 2007 and changes during the year then ended is as follows:
                                 
                    Weighted-Average   Aggregate Intrinsic
            Weighted-Average   Remaining   Value
    Number of Awards   Exercise Price   Contractual Term   (In Thousands)
     
Awards outstanding at January 1, 2007
    595,290     $ 49.81                  
Granted
    194,450     $ 109.80                  
Exercised
    (346,809 )   $ 38.74                  
Forfeited
    (8,904 )   $ 61.79                  
Expired
    (1,250 )   $ 30.37                  
 
                               
Awards outstanding at December 31, 2007
    432,777     $ 85.44       8.7     $ 24,590  
 
                               
Awards exercisable at December 31, 2007
    31,665     $ 74.52       7.8     $ 2,168  
 
                               
     The weighted-average grant date fair values of options granted during the years ended December 31, 2007, 2006 and 2005 were $36.80, $39.24 and $25.80, respectively. The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005 was $20.6 million, $5.0 million and $10.5 million, respectively. The total fair value of stock options vested during the years ended December 31, 2007, 2006 and 2005 was $3.6 million, $2.7 million and $2.0 million, respectively. As of December 31, 2007 there was $10.9 million of total unrecognized compensation cost related to nonvested stock options and SARs granted under the Stock Plan which we expect to recognize over a weighted average period of 2.68 years.

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3. Earnings Per Share
     A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:
                         
    Year Ended December 31,
    2007   2006   2005
     
    (In thousands, except per share data)
 
                       
Net income — basic (numerator):
  $ 846,541     $ 706,847     $ 260,337  
Effect of dilutive potential shares
                       
Zero Coupon Debentures
    51       236       4,880  
1.5% Debentures
    3,087       3,293       4,583  
     
Net income including conversions — diluted (numerator):
  $ 849,679     $ 710,376     $ 269,800  
     
 
                       
Weighted-average shares — basic (denominator):
    137,816       129,129       128,690  
Effect of dilutive potential shares
                       
Zero Coupon Debentures
    54       119       3,114  
1.5% Debentures
    1,015       9,383       9,383  
Stock options and SARs
    60       150       164  
     
Weighted-average shares including conversions — diluted (denominator):
    138,945       138,781       141,351  
     
Earnings per share:
                       
Basic
  $ 6.14     $ 5.47     $ 2.02  
     
Diluted
  $ 6.12     $ 5.12     $ 1.91  
     
     Our computation of diluted EPS for the year ended December 31, 2007 excludes stock options representing 22,937 shares of common stock and 154,119 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.
     The computation of diluted EPS for the year ended December 31, 2006 excludes stock options representing 82,257 shares of common stock and 56,916 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.
     The computation of diluted EPS for the year ended December 31, 2005 excludes stock options representing 22,088 shares of common stock because the options’ exercise prices were higher than the average market price per share of our common stock for the period.

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4. Investments and Marketable Securities
     We report our investments as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations.
     Our other investments in marketable securities are classified as available for sale and are summarized as follows:
                         
    December 31, 2007
    Amortized   Unrealized   Market
    Cost   Gain   Value
     
    (In thousands)
U.S. government-backed mortgage securities
  $ 1,277     $ 24     $ 1,301  
     
                         
    December 31, 2006
    Amortized   Unrealized   Market
    Cost   Gain (Loss)   Value
     
    (In thousands)
Debt securities issued by the U.S. Treasury and other U.S. government agencies:
                       
Due within one year
  $ 299,252     $ 170     $ 299,422  
Mortgage-backed securities
    1,740       (3 )     1,737  
     
Total
  $ 300,992     $ 167     $ 301,159  
     
     Proceeds from maturities and sales of marketable securities and gross realized gains and losses are summarized as follows:
                         
    Year Ended December 31,
    2007   2006   2005
     
    (In thousands)
Proceeds from maturities
  $ 1,325,000     $ 950,000     $ 2,550,000  
Proceeds from sales
    1,838,475       1,237,766       3,060,907  
Gross realized gains
    1,856       188       220  
Gross realized losses
    (60 )     (219 )     (1,400 )
5. Derivative Financial Instruments
Forward Exchange Contracts
     Our international operations expose us to foreign exchange risk, primarily associated with our costs payable in foreign currencies for employee compensation and for purchases from foreign suppliers. We utilize foreign exchange forward contracts to reduce our forward exchange risk. A forward currency exchange contract obligates a contract holder to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specified dates.
     During 2007 and 2006, we entered into various foreign currency forward exchange contracts which resulted in net realized gains totaling $8.1 million and $7.3 million, respectively. As of December 31, 2007, we had foreign currency exchange contracts outstanding, which aggregated $18.1 million, that require us to purchase the equivalent of $17.9 million in British pounds sterling and $0.2 million in Mexican pesos at various times through April 2008.
     These forward contracts are derivatives as defined by SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” or SFAS 133. SFAS 133 requires that each derivative be stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for hedge accounting, the gains and losses are reflected in income in the same period as offsetting losses and gains on the qualifying hedged positions. The forward contracts we entered into in 2007 and 2006 did not qualify for hedge accounting. In accordance with SFAS 133, we recorded a net unrealized loss of $91,000 and a net unrealized gain of $2.6 million in our Consolidated Statements of Operations for the years ended December 31, 2007 and 2006, respectively, as “Other income (expense)” to adjust the carrying value of these derivative financial instruments to

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their fair value. At December 31, 2007, we have presented the $2,000 and $(93,000) fair value of our outstanding foreign currency forward exchange contracts as “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, in our Consolidated Balance Sheets. We have presented the $2.6 million fair value of our foreign currency forward exchange contracts at December 31, 2006 as “Prepaid expenses and other current assets” in our Consolidated Balance Sheets.
Contingent Interest
     Our 1.5% Debentures, of which an aggregate principal amount of $3.6 million were outstanding at December 31, 2007, contain a contingent interest provision. The contingent interest component is an embedded derivative as defined by SFAS 133 and accordingly must be split from the host instrument and recorded at fair value on the balance sheet. The contingent interest component had no fair value at issuance or at December 31, 2007 or at December 31, 2006.
6. Prepaid Expenses and Other Current Assets
     Prepaid expenses and other current assets consist of the following:
                 
    December 31,
    2007   2006
     
    (In thousands)
 
               
Rig spare parts and supplies
  $ 50,699     $ 48,801  
Deferred mobilization costs
    17,295       3,433  
Prepaid insurance
    11,444       5,891  
Deferred tax assets
    9,006       9,606  
Vendor prepayments
    7,296       12,251  
Deposits
    2,292       1,434  
Prepaid taxes
    1,681       1,958  
Forward exchange contracts
    2       2,594  
Other
    3,405       2,248  
     
Total
  $ 103,120     $ 88,216  
     
7. Drilling and Other Property and Equipment
     Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
                 
    December 31,
    2007   2006
     
    (In thousands)
 
               
Drilling rigs and equipment
  $ 4,540,797     $ 3,896,585  
Construction work-in-progress
    453,093       459,824  
Land and buildings
    24,123       17,353  
Office equipment and other
    29,742       27,132  
     
Cost
    5,047,755       4,400,894  
Less accumulated depreciation
    (2,007,692 )     (1,772,441 )
     
Drilling and other property and equipment, net
  $ 3,040,063     $ 2,628,453  
     
     Construction work-in-progress at December 31, 2007 consisted of $186.8 million related to the major upgrade of the Ocean Monarch to ultra-deepwater service and $266.3 million related to the construction of two new jack-up drilling units, the Ocean Scepter and the Ocean Shield, including accrued capital expenditures aggregating $23.2 million related to these projects. We anticipate that both the Ocean Scepter and Ocean Shield will be delivered in the second quarter of 2008. We expect the upgrade of the Ocean Monarch to be completed in late 2008. Construction work-in-progress related to these projects was $210.0 million at December 31, 2006 and $249.8 million for the Ocean Endeavor at December 31, 2006.

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8. Accrued Liabilities
     Accrued liabilities consist of the following:
                 
    December 31,
    2007   2006
     
    (In thousands)
 
               
Accrued project/upgrade expenses
  $ 95,778     $ 67,308  
Payroll and benefits
    52,975       42,496  
Deferred revenue
    36,134       13,887  
Interest payable
    10,413       11,823  
Personal injury and other claims
    8,692       9,934  
Hurricane-related expenses and deferred gains
    1,380       8,328  
Other
    30,149       31,202  
     
Total
  $ 235,521     $ 184,978  
     
9. Long-Term Debt
     Long-term debt consists of the following:
                 
    December 31,
    2007   2006
     
    (In thousands)
 
               
Zero Coupon Debentures (due 2020)
  $ 3,931     $ 5,302  
1.5% Debentures (due 2031)
    3,563       459,967  
5.15% Senior Notes (due 2014)
    249,566       249,513  
4.875% Senior Notes (due 2015)
    249,574       249,528  
     
 
    506,634       964,310  
Less: Current maturities
    3,563        
     
Total
  $ 503,071     $ 964,310  
     
     Certain of our long-term debt payments may be accelerated due to rights that the holders of our debt securities have to put the securities to us. The holders of our outstanding 1.5% Debentures and Zero Coupon Debentures have the right to require us to purchase all or a portion of their outstanding debentures on April 15, 2008 and June 6, 2010, respectively. See “Zero Coupon Debentures” and “1.5% Debentures” for further discussion of the rights that the holders of these debentures have to put the securities to us.
     The aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2007, are as follows:
         
(Dollars in thousands)
 
2008
  $ 3,563  
2009
     
2010
    3,931  
2011
     
2012
     
Thereafter
    499,140  
 
 
    506,634  
Less: Current maturities
    3,563  
 
Total
  $ 503,071  
 

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$285 Million Revolving Credit Facility.
     In November 2006, we entered into a $285 million syndicated, five-year senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit.
     Loans under the Credit Facility bear interest at a rate per annum equal to, at our election, either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.
     The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.
     Based on our current credit ratings at December 31, 2007, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2007, there were no loans outstanding under the Credit Facility. See Note 11 for a discussion of letters of credit issued under the Credit Facility.
4.875% Senior Notes
     Our 4.875% Senior Notes Due July 1, 2015, or 4.875% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at 4.875% per year, payable semiannually in arrears on January 1 and July 1 of each year and mature on July 1, 2015. The 4.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc., and they rank equal in right of payment to our existing and future unsecured and unsubordinated indebtedness, although the 4.875% Senior Notes will be effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of the 4.875% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.
5.15% Senior Notes
     Our 5.15% Senior Notes Due September 1, 2014, or 5.15% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at 5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year and mature on September 1, 2014. The 5.15% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc., and they rank equal in right of payment to our existing and future unsecured and unsubordinated indebtedness, although the 5.15% Senior Notes will be effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of the 5.15% Senior Notes for cash at any time or from time to time on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.
Zero Coupon Debentures
     We issued our Zero Coupon Debentures on June 6, 2000 at a price of $499.60 per $1,000 principal amount at maturity, which represents a yield to maturity of 3.50% per year. The Zero Coupon Debentures mature on June 6, 2020. We will not pay interest prior to maturity unless we elect to convert the Zero Coupon Debentures to interest-bearing debentures upon the occurrence of certain tax events. The Zero Coupon Debentures are convertible at the option of the holder at any time prior to maturity, unless previously redeemed, into our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. In addition, holders may require us to purchase, for cash, all or a portion of their Zero Coupon Debentures upon a change in control (as defined in the governing indenture) for a purchase price equal to the accreted value through the date of repurchase. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

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     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 2007 and 2006, holders of $1.5 million and $13.7 million, respectively, in accreted, or carrying, value through the date of conversion of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 20,658 and 193,147 shares of our common stock upon conversion of these debentures during 2007 and 2006, respectively. The aggregate principal amount at maturity of our Zero Coupon Debentures converted during 2007 and 2006 was $2.4 million and $22.4 million, respectively.
     As of December 31, 2007, the aggregate accreted value of our outstanding Zero Coupon Debentures was $3.9 million, which is classified as long-term debt in our Consolidated Balance Sheets. The aggregate principal amount at maturity of those Zero Coupon Debentures would be $6.0 million assuming no additional conversions or redemptions occur prior to the maturity date.
1.5% Debentures
     On April 11, 2001, we issued $460.0 million principal amount of 1.5% Debentures, which are due April 15, 2031. The 1.5% Debentures are convertible into shares of our common stock at an initial conversion rate of 20.3978 shares per $1,000 principal amount of the 1.5% Debentures, or $49.02 per share, subject to adjustment in certain circumstances. Upon conversion, we have the right to deliver cash in lieu of shares of our common stock. The 1.5% Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.
     We pay interest of 1.5% per year on the outstanding principal amount of the 1.5% Debentures, semiannually in arrears on April 15 and October 15 of each year. In addition we will pay contingent interest to holders of our 1.5% Debentures during any six-month period commencing after April 15, 2008, if the average market price of a 1.5% Debenture for a measurement period preceding such six-month period equals 120% or more of the principal amount of such 1.5% Debenture and we pay a regular cash dividend during such six-month period. The contingent interest payable per $1,000 principal amount of 1.5% Debentures, in respect of any quarterly period, will equal 50% of regular cash dividends we pay per share on our common stock during that quarterly period multiplied by the conversion rate. This contingent interest component is an embedded derivative, which had no fair value at issuance or at December 31, 2007 or December 31, 2006.
     Holders may require us to purchase all or a portion of their outstanding 1.5% Debentures on April 15, 2008, at a price equal to 100% of the principal amount of the 1.5% Debentures to be purchased plus accrued and unpaid interest. We may choose to pay the purchase price in cash or shares of our common stock or a combination of cash and common stock. In addition, holders may require us to purchase, for cash, all or a portion of their 1.5% Debentures upon a change in control (as defined in the governing indenture) for a purchase price equal to 100% of the principal amount plus accrued and unpaid interest. Additionally, we have the option to redeem all or a portion of the 1.5% Debentures at any time on or after April 15, 2008, at a price equal to 100% of the principal amount plus accrued and unpaid interest. Because the holders of the 1.5% Debentures have the right to require us to repurchase the outstanding debentures on April 15, 2008, the aggregate outstanding principal amount of $3.6 million is presented as “Current portion of long-term debt” in our Consolidated Balance Sheets at December 31, 2007.
     During 2007 and 2006, the holders of $456.4 million and $20,000, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock, resulting in the issuance of 9,309,616 shares and 404 shares of our common stock in 2007 and 2006, respectively.
     As a result of the conversions of our 1.5% Debentures, we reversed a $54.2 million non-current deferred tax liability during 2007 related to interest expense imputed on these debentures for U.S. federal income tax return purposes. See Note 14.

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10. Other Comprehensive Income (Loss)
     The income tax effects allocated to the components of our other comprehensive income (loss) are as follows:
                         
    Year Ended December 31, 2007
    Before Tax   Tax Effect   Net-of-Tax
     
            (In thousands)        
 
                       
Unrealized gain (loss) on investments:
                       
Gain arising during 2007
  $ 289     $ (101 )   $ 188  
Reclassification adjustment
    (434 )     152       (282 )
     
Net unrealized loss
    (145 )     51       (94 )
Pension plan termination
    6,963       (2,437 )     4,526  
     
Other comprehensive income
  $ 6,818     $ (2,386 )   $ 4,432  
     
                         
    Year Ended December 31, 2006
    Before Tax   Tax Effect   Net-of-Tax
     
            (In thousands)        
 
                       
Unrealized gain (loss) on investments:
                       
Gain arising during 2006
  $ 249     $ (87 )   $ 162  
Reclassification adjustment
    (95 )     33       (62 )
     
Net unrealized gain
    154       (54 )     100  
     
Other comprehensive income before adoption of SFAS 158
    154       (54 )     100  
Adjustment to initially apply SFAS 158
    (6,963 )     2,437       (4,526 )
     
Other comprehensive (loss)
  $ (6,809 )   $ 2,383     $ (4,426 )
     
                         
    Year Ended December 31, 2005
    Before Tax   Tax Effect   Net-of-Tax
     
            (In thousands)        
 
                       
Reversal of cumulative foreign currency translation loss
  $ 3,600     $ (1,523 )   $ 2,077  
Unrealized gain (loss) on investments:
                       
Gain arising during 2005
    15       (5 )     10  
Reclassification adjustment
    (138 )     48       (90 )
     
Net unrealized loss
    (123 )     43       (80 )
     
Other comprehensive income
  $ 3,477     $ (1,480 )   $ 1,997  
     
     The components of our accumulated other comprehensive income (loss) are as follows:
                                 
    Foreign Currency   Adjustment to   Unrealized Gain   Total Other
    Translation   Initially Apply   (Loss) on   Comprehensive
    Adjustments   SFAS 158, Net of Tax   Investments   Income (Loss)
     
Balance at January 1, 2005
  $ (2,077 )   $     $ 89     $ (1,988 )
Other comprehensive gain
    2,077             (80 )     1,997  
     
Balance at December 31, 2005
                9       9  
Other comprehensive loss
          (4,526 )     100       (4,426 )
     
Balance at December 31, 2006
          (4,526 )     109       (4,417 )
Other comprehensive gain
          4,526       (94 )     4,432  
     
Balance at December 31, 2007
  $     $     $ 15     $ 15  
     

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11. Commitments and Contingencies
     Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. In accordance with SFAS No. 5, “Accounting for Contingencies,” we have assessed each claim or exposure to determine the likelihood that the resolution of the matter might ultimately result in an adverse effect on our financial condition, results of operations and cash flows. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a reserve for the estimated loss at the time that both of these criteria are met. Our management believes that we have established adequate reserves for any liabilities that may reasonably be expected to result from these claims.
     Litigation. We are a defendant in a lawsuit filed in January 2005 in the U.S. District Court for the Eastern District of Louisiana on behalf of Total E&P USA, Inc. and several oil companies alleging that our semisubmersible rig, the Ocean America, damaged a natural gas pipeline in the Gulf of Mexico during Hurricane Ivan. The plaintiffs seek damages from us including, but not limited to, loss of revenue, that are currently estimated to be in excess of $100 million, together with interest, attorneys’ fees and costs. We deny any liability for plaintiffs’ alleged loss and do not believe that ultimate liability, if any, resulting from this litigation will have a material adverse effect on our financial condition, results of operations and cash flows.
     We are one of several unrelated defendants in lawsuits filed in the Circuit Courts of the State of Mississippi alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our offshore drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. We expect to receive complete defense and indemnity from Murphy Exploration & Production Company pursuant to the terms of our 1992 asset purchase agreement with them. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that ultimate liability, if any, resulting from this litigation will have a material adverse effect on our financial condition, results of operations and cash flows.
     Various other claims have been filed against us in the ordinary course of business. In the opinion of our management, no pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations and cash flows.
     Other. Our operations in Brazil have exposed us to various claims and assessments related to our personnel, customs duties and municipal taxes, among other things, that have arisen in the ordinary course of business. During 2007, we reviewed our estimated reserve for personnel taxes in Brazil based on current facts and circumstances and adjusted our estimated reserve in accordance with SFAS 5. Accordingly, we recorded a $6.5 million reduction in “Contract drilling” expense in our Consolidated Statements of Operations in 2007 as a result of our change in estimate. At December 31, 2007, our loss reserves related to our Brazilian operations aggregated $8.5 million, of which $1.9 million and $6.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. Loss reserves related to our Brazilian operations totaled $14.2 million at December 31, 2006, of which $0.5 million was recorded in “Accrued liabilities” and $13.7 million was recorded in “Other liabilities” in our Consolidated Balance Sheets.
     We intend to defend these matters vigorously; however, we cannot predict with certainty the outcome or effect of any litigation matters specifically described above or any other pending litigation or claims. There can be no assurance as to the ultimate outcome of these lawsuits.
     Personal Injury Claims. Our deductible for liability coverage for personal injury claims, which primarily results from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence (or $10.0 million if hurricane-related), with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage experts to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models. At December 31, 2007, our estimated liability for personal injury claims was $32.0 million, of which $8.5 million and $23.5 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2006, we had recorded loss reserves for personal injury claims aggregating $35.0 million, of which $9.9 million and $25.1 million were recorded in “Accrued liabilities” and “Other liabilities,”

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respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:
    the severity of personal injuries claimed;
 
    significant changes in the volume of personal injury claims;
 
    the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
 
    inconsistent court decisions; and
 
    the risks and lack of predictability inherent in personal injury litigation.
     Purchase Obligations. As of December 31, 2007, we had purchase obligations aggregating approximately $200 million related to the major upgrade of the Ocean Monarch and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We expect to complete funding of these projects in 2008. However, the actual timing of these expenditures will vary based on the completion of various construction milestones, which are beyond our control.
     We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2007 and 2006, except for those related to our direct rig operations, which arise during the normal course of business.
     Operating Leases. We lease office facilities and equipment under operating leases, which expire at various times through the year 2010. Total rent expense amounted to $4.6 million, $3.8 million and $3.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. Future minimum rental payments under leases are approximately $4.3 million, $0.9 million, $0.2 million, $0.1 million and $0.1 million for the years ending December 31, 2008, 2009, 2010, 2011 and 2012, respectively. There are no minimum future rental payments under leases after 2012.
     Letters of Credit and Other. We were contingently liable as of December 31, 2007 in the amount of $168.0 million under certain performance, bid, supersedeas and custom bonds and letters of credit, including $54.2 million in letters of credit issued under our Credit Facility. During 2007 and 2006, we purchased five of these bonds totaling $81.2 million from a related party after obtaining competitive quotes. Agreements relating to approximately $103.5 million of performance bonds can require collateral at any time. As of December 31, 2007 we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.
12. Financial Instruments
Concentrations of Credit and Market Risk
     Financial instruments which potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including mortgage-backed securities. We place our excess cash investments in high quality short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.
     Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies and government-owned oil companies. We provide allowances for potential credit losses when necessary. No such allowances were deemed necessary for the years presented and, historically, we have not experienced significant losses on our trade receivables.
     All of our investments in debt securities are U.S. government securities or U.S. government-backed with minimal credit risk. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.

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Fair Values
     The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents, marketable securities, accounts receivable, forward exchange contracts and accounts payable approximate fair value. Fair values and related carrying values of our debt instruments are shown below:
                                 
    Year Ended December 31,
    2007   2006
    Fair Value   Carrying Value   Fair Value   Carrying Value
            (In millions)        
 
                               
Zero Coupon Debentures
  $ 7.4     $ 3.9     $ 5.0     $ 5.3  
1.5% Debentures
    10.3       3.6       749.7       460.0  
4.875% Senior Notes
    238.6       249.6       234.9       249.5  
5.15% Senior Notes
    244.0       249.6       242.0       249.5  
     We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of December 31, 2007 and 2006, respectively. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange. The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it was practicable to estimate that value:
    Cash and cash equivalents — The carrying amounts approximate fair value because of the short maturity of these instruments.
 
    Marketable securities — The fair values of the debt securities, including mortgage-backed securities, available for sale were based on the quoted closing market prices on December 31, 2007 and 2006, respectively.
 
    Accounts receivable and accounts payable — The carrying amounts approximate fair value based on the nature of the instruments.
 
    Forward exchange contracts — The fair value of our foreign currency forward exchange contracts is based on the quoted market prices on December 31, 2007 and 2006, respectively.
 
    Long-term debt — The fair value of our 4.875% Senior Notes and 5.15% Senior Notes was based on the quoted closing market price on December 31, 2007 and 2006, respectively, from brokers of these instruments. The fair value of our Zero Coupon Debentures and 1.5% Debentures was based on the closing market price of our common stock on December 31, 2007 and 2006, respectively, and the stated conversion rates for these debentures.

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13. Related-Party Transactions
     Transactions with Loews. We are party to a services agreement with Loews, or the Services Agreement, pursuant to which Loews performs certain administrative and technical services on our behalf. Such services include personnel, telecommunications, purchasing, internal auditing, accounting, data processing and cash management services, in addition to advice and assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the provision of such services. The Services Agreement may be terminated at our option upon 30 days’ notice to Loews and at the option of Loews upon six months’ notice to us. In addition, we have agreed to indemnify Loews for all claims and damages arising from the provision of services by Loews under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. We were charged $0.4 million, $0.4 million and $0.4 million by Loews for these support functions during the years ended December 31, 2007, 2006 and 2005, respectively.
     In addition, during 2007 and 2006 we purchased four performance bonds in support of our drilling operations offshore Mexico and an appeals bond totaling $81.2 million from affiliates of a majority-owned subsidiary of Loews after obtaining competitive quotes. Premiums and fees associated with these bonds totaled $45,000 and $1.0 million in 2007 and 2006, respectively.
     Transactions with Other Related Parties. During 2006, we hired marine vessels and helicopter transportation services at the prevailing market rate from subsidiaries of SEACOR Holdings Inc. The Chairman of the Board of Directors, President and Chief Executive Officer of SEACOR Holdings Inc. is also a member of our Board of Directors. For the years ended December 31, 2007 and 2006, we paid $4.6 million and $0.7 million for the hire of such vessels and such services.
     During the years ended December 31, 2007, 2006 and 2005 we made payments of $1.1 million, $0.6 million and $1.2 million, respectively, to Ernst & Young LLP for tax and other consulting services. The wife of our President and Chief Operating Officer is an audit partner at this firm.
14. Income Taxes
     Our net income tax expense or benefit is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary which we wholly own. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of the subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes were provided on these earnings in years subsequent to 2002 except to the extent that such earnings were immediately subject to U.S. federal income taxes. In December 2007, this subsidiary made a non-recurring distribution of $850.0 million to its U.S. parent, a portion of which consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. We recognized $58.6 million of U.S. federal income tax expense as a result of the distribution. As of December 31, 2007, the amount of previously untaxed earnings of this subsidiary was zero. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest future earnings of this subsidiary to finance foreign activities
     We have certain other foreign subsidiaries for which U.S. taxes have been provided to the extent a U.S. tax liability could arise upon remittance of earnings from the foreign subsidiaries. As of December 31, 2007, we provided $0.4 million of U.S. taxes attributable to undistributed earnings of the foreign subsidiaries. On actual remittance, certain countries may impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.

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     The components of income tax expense (benefit) are as follows:
                         
    Year Ended December 31,
    2007   2006   2005
    (In thousands)
 
                       
Federal — current
  $ 338,638     $ 230,907     $ 28,106  
State — current
    950              
Foreign — current
    58,638       27,968       2,793  
     
Total current
    398,226       258,875       30,899  
     
 
                       
Federal — deferred
    7,594       5,006       63,408  
Foreign — deferred
    (5,824 )     (4,396 )     1,751  
     
Total deferred
    1,770       610       65,159  
     
 
                       
Total
  $ 399,996     $ 259,485     $ 96,058  
     
     The difference between actual income tax expense and the tax provision computed by applying the statutory federal income tax rate to income before taxes is attributable to the following:
                         
    Year Ended December 31,
    2007   2006   2005
    (In thousands)
 
                       
Income before income tax expense:
                       
U.S.
  $ 947,476     $ 765,583     $ 324,390  
Foreign
    299,061       200,749       32,005  
     
Worldwide
  $ 1,246,537     $ 966,332     $ 356,395  
     
 
                       
Expected income tax expense at federal statutory rate
  $ 436,288     $ 338,216     $ 124,738  
Foreign earnings of foreign subsidiaries (not taxed at the statutory federal income tax rate) net of related foreign taxes
    (70,800 )     (60,624 )     529  
Foreign taxes — domestic companies
    22,111       15,200       1,806  
Foreign tax credits
    (27,238 )     (15,087 )     (1,811 )
$850.0 million distribution from foreign subsidiary
    58,562              
Valuation allowance — foreign tax credits
          (831 )     (9,574 )
Reduction of deferred tax liability related to Arethusa goodwill deduction
    (8,850 )     (8,850 )     (8,850 )
Reduction of contingent tax liability related to Arethusa goodwill deduction
                (8,850 )
Domestic production activities deduction
    (12,740 )     (8,339 )      
Uncertain tax positions
    4,466              
East Timor — Indonesia tax settlement
                (4,365 )
Revision of estimated tax balance
    (130 )     1,039       843  
IRS audit adjustments
                1,931  
Amortization of deferred tax liability related to transfer of drilling rigs to different taxing jurisdictions
    (1,580 )     (1,580 )     (1,763 )
Other
    (93 )     341       1,424  
     
Income tax expense
  $ 399,996     $ 259,485     $ 96,058  
     

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     Significant components of our deferred income tax assets and liabilities are as follows:
                 
    December 31,
    2007   2006
    (In thousands)
Deferred tax assets:
               
Net operating loss carryforwards
  $ 1,831     $ 2,761  
Capital loss carryback/carryforward
          412  
Goodwill
    10,494       13,643  
Worker’s compensation and other current accruals (1)
    12,905       14,733  
Disputed receivables reserved
    4,831       3,603  
Deferred compensation
    3,730       2,152  
Foreign deferred taxes
    2,696        
Nonqualified stock options
    1,480       1,044  
Other
    2,450       1,186  
     
Total deferred tax assets
    40,417       39,534  
Valuation allowance for foreign tax credits
           
     
Net deferred tax assets
    40,417       39,534  
     
Deferred tax liabilities:
               
Depreciation
    (425,488 )     (418,703 )
Contingent interest
    (507 )     (53,399 )
Foreign deferred taxes
          (3,128 )
Other
    (3,045 )     (2,925 )
     
Total deferred tax liabilities
    (429,040 )     (478,155 )
     
Net deferred tax liability
  $ (388,623 )   $ (438,621 )
     
 
(1)   $9.0 million and $9.6 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance Sheets at December 31, 2007 and 2006, respectively. See Note 6.
     We adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, we recognized a long-term tax receivable of $2.6 million and a long-term tax liability of $31.1 million for uncertain tax positions, the net of which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. A reconciliation of the beginning and ending amount of unrecognized tax benefits including interest and penalties is as follows:
                         
                    Net Liability  
    Long term Tax     Long term Tax     for Uncertain Tax  
    Receivable     Payable     Positions  
    (In thousands)  
Balance at January 1, 2007
  $ 2,642     $ (31,064 )   $ (28,422 )
Additions based on tax positions related to the current year
    785       (6,908 )     (6,123 )
 
                 
Balance at December 31, 2007
  $ 3,427     $ (37,972 )   $ (34,545 )
 
                 
     At December 31, 2007 all $34.5 million of the net unrecognized tax benefits would affect the effective tax rate if recognized.
     We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense. During the year ended December 31, 2007, we recognized $1.7 million of interest expense related to uncertain tax positions. Penalty related tax expense for uncertain tax positions during the year ended December 31, 2007 was $0.8 million. At December 31, 2007, we had $14.2 million accrued for the payment of interest and penalties in our Consolidated Balance Sheets.

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     A reconciliation of the beginning and ending amount of unrecognized tax benefits excluding interest and penalties is as follows:
         
    Net Liability  
    for Uncertain Tax  
    Positions  
    (In thousands)  
Balance at January 1, 2007
  $ (16,635 )
Additions based on tax positions related to the current year
    (3,694 )
 
     
Balance at December 31, 2007
  $ (20,329 )
 
     
     In several of the international locations in which we operate, certain of our wholly owned subsidiaries enter into agreements with other of our wholly owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be charged for providing the services and equipment. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts. Taxing authorities in the various foreign locations in which we operate could apply one of the alternative transfer pricing methodologies that could result in an increase to our income tax liabilities with respect to tax returns that remain subject to examination. During the next twelve months certain income tax returns will no longer be subject to examination due to a lapse in the applicable statute of limitations. As a result, we anticipate that the amount of unrecognized tax benefits attributable to transfer pricing methodology will decrease by approximately $1.4 million through December 31, 2008.
     We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions include years 2000 to 2006. We are currently under audit in several of these jurisdictions including an audit by the Internal Revenue Service of years 2004 and 2005.
     The Brazilian tax authorities are auditing our income tax returns for the periods 2000 to 2005. We have received an initial audit report for tax year 2000 disallowing various deductions claimed in the tax return. The tax auditors have issued an assessment for tax year 2000 of approximately $1.5 million, including interest and penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal. We do not anticipate that any adjustments resulting from the tax audit will have a material impact on our consolidated results of operations, financial position and cash flows.
     During the year ended December 31, 2007, the holders of certain of our debentures elected to convert them into shares of our common stock. (See Note 9.) As a result of the conversions of our 1.5% Debentures, we reversed a non-current deferred tax liability of $54.2 million which was accounted for as an increase to “Additional paid-in capital.” The reversal related to interest expense imputed on these debentures for U.S. federal income tax return purposes.
     As of December 31, 2007, we had net operating loss, or NOL, carryforwards of approximately $5.2 million available to offset future taxable income. The NOL carryforwards consist entirely of losses that were acquired in our merger with Arethusa (Off-Shore) Limited, or Arethusa, in 1996. The utilization of the NOL carryforwards acquired in the Arethusa merger is limited pursuant to Section 382 of the Internal Revenue Code of 1986, as amended, or the Code. We expect to fully utilize all of the NOL carryforwards in future tax years. During 2007, we were able to utilize approximately $2.7 million of the NOL carryforwards.

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     We have recorded a deferred tax asset of $1.8 million for the benefit of the NOL carryforwards. The NOL carryforwards will expire as follows:
                 
            Tax
    Net   Benefit of Net
    Operating   Operating
Year   Losses   Losses
    (In millions)
 
               
2009
  $ 2.8     $ 1.0  
2010
    2.4       0.8  
     
Total
  $ 5.2     $ 1.8  
     
15. Employee Benefit Plans
Defined Contribution Plans
     We maintain defined contribution retirement plans for our U.S., U.K. and third-country national, or TCN, employees. The plan for our U.S. employees, or the 401k Plan, is designed to qualify under Section 401(k) of the Code. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. During the year ended December 31, 2007 we contributed 5.00% of a participant’s defined compensation and matched 100% of the first 6% of each employee’s compensation contributed to the 401k Plan. During 2006 and 2005 we contributed 3.75% of a participant’s defined compensation and matched 25% of the first 6% of each employee’s compensation contributed to the 401k Plan. Participants are fully vested immediately upon enrollment in the 401k Plan. For the years ended December 31, 2007, 2006 and 2005, our provision for contributions was $11.2 million, $9.0 million and $7.3 million, respectively.
     The defined contribution retirement plan for our U.K. employees, or U.K. Plan, provides that we make annual contributions in an amount equal to the employee’s contributions, generally up to a maximum of 5.25% of the employee’s defined compensation per year for employees working in the U.K. sector of the North Sea and up to a maximum of 9% of the employee’s defined compensation per year for U.K. nationals working in the Norwegian sector of the North Sea. Our provision for contributions was $1.5 million, $1.2 million and $0.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.
     The defined contribution retirement plan for our TCN employees, or TCN Plan, is similar to the 401k Plan. During 2007 we contributed 5.00% of a participant’s defined compensation and matched 100% of the first 6% of each employee’s compensation contributed to the TCN Plan. For the years ended December 31, 2006 and 2005 we contributed 3.75% of a participant’s defined compensation and matched 25% of the first 6% of each employee’s compensation contributed to the TCN Plan. Our provision for contributions was $1.2 million, $0.9 million and $0.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Deferred Compensation and Supplemental Executive Retirement Plan
     Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly compensated employees to compensate such employees for any portion of our base salary contribution and/or matching contribution under the 401k Plan that could not be contributed to that plan because of limitations within the Code. Prior to January 1, 2007, the Supplemental Plan also allowed participants to defer up to 10% of their base compensation and/or up to 100% of any performance bonus. Participants are fully vested in all amounts paid into the Supplemental Plan. Our provision for contributions to the Supplemental Plan for the years ended December 31, 2007, 2006 and 2005 was approximately $192,000, $65,000 and $77,000, respectively.

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